UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý Quarterly report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934

For the quarterly period ended March 31, 2006 or

o Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934

For the transition period from to

Commission file number 1-7792

POGO PRODUCING COMPANY

(Exact Name of Registrant as Specified in Its Charter)

Delaware		74-1659398
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

5 Greenway Plaza, Suite 2700
Houston, Texas		77046-0504
(Address of principal executive offices)		(Zip Code)

(713) 297-5000

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.: Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). :

Yes o No ý

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Common Stock, par value $1.00 per share:

57,962,947 shares as of April 24, 2006

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended
	March 31,
	2006			2005
	(Expressed in millions,
	except per share amounts)
Revenues:
Oil and gas	$	354.4		$	254.1
Other	19.1			1.7
Total	373.5			255.8

Operating Costs and Expenses:
Lease operating	57.1			28.7
General and administrative	28.7			18.7
Exploration	2.7			11.2
Dry hole and impairment	25.6			47.4
Depreciation, depletion and amortization	110.1			70.5
Production and other taxes	13.5			11.2
Transportation and other	25.5			(5.6		)
Total	263.2			182.1

Operating Income	110.3			73.7
Interest:
Charges	(28.3		)	(10.2		)
Income	0.5			0.8
Capitalized	16.2			2.2
Commodity derivative income (expense)	3.3			—
Foreign Currency Transaction Gain (Loss)	(0.2		)	—

Income From Continuing Operations Before Taxes	101.8			66.5
Income Tax Expense	(34.3		)	(27.0		)

Income From Continuing Operations	67.5			39.5
Income from Discontinued Operations, net of tax	—			19.7
Net Income	$	67.5		$	59.2

Earnings per Common Share:
Basic
Income from continuing operations	$	1.18		$	0.62
Income from discontinued operations, net of tax	—			0.31
Net income	$	1.18		$	0.93

Diluted
Income from continuing operations	$	1.16		$	0.62
Income from discontinued operations, net of tax	—			0.31
Net income	$	1.16		$	0.93

Dividends per Common Share	$	0.0750		$	0.0625

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
	2006			2005
	(Expressed in millions)

Assets
Current Assets:
Cash and cash equivalents	$	23.7		$	57.7
Accounts receivable	166.1			198.8
Other receivables	26.8			19.9
Federal income tax receivable	—			21.7
Deferred tax asset	21.2			12.2
Inventories - product	14.5			13.2
Inventories - tubulars	21.6			19.1
Other	3.2			4.2
Total current assets	277.1			346.8

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	6,411.1			6,254.5
Unevaluated properties	887.9			872.2
Other, at cost	42.1			40.5
	7,341.1			7,167.2
Accumulated depreciation, depletion and amortization
Oil and gas	(1,965.6		)	(1,858.3		)
Other	(26.4		)	(24.5		)
	(1,992.0		)	(1,882.8		)
Property and equipment, net	5,349.1			5,284.4

Other Assets:
Other	43.0			44.5
	43.0			44.5

	$	5,669.2		$	5,675.7

See accompanying notes to consolidated financial statements.

	March 31,			December 31,
	2006			2005
	(Expressed in millions,
	except share amounts)
Liabilities and Shareholders’ Equity

Current Liabilities:
Accounts payable - operating activities	$	149.1		$	167.3
Accounts payable - investing activities	138.7			137.1
Income taxes payable	63.2			2.0
Accrued interest payable	27.5			20.2
Accrued payroll and related benefits	3.8			3.7
Price hedge contracts	25.7			52.3
Other	10.2			12.5
Total current liabilities	418.2			395.1

Long-Term Debt	1,577.5			1,643.4

Deferred Income Tax	1,291.5			1,316.9

Asset Retirement Obligation	150.3			149.4

Other Liabilities and Deferred Credits	60.9			72.3
Total liabilities	3,498.4			3,577.1

Commitments and Contingencies	—			—

Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized	—			—
Common stock, $1 par; 200,000,000 shares authorized, 65,328,306 and 65,275,106 shares issued, respectively	65.3			65.3
Additional capital	955.3			977.9
Retained earnings	1,527.3			1,464.2
Deferred compensation	—			(17.5		)
Accumulated other comprehensive income (loss)	(15.8		)	(30.0		)
Treasury stock (7,365,359 shares, at cost)	(361.3		)	(361.3		)
Total shareholders’ equity	2,170.8			2,098.6

	$	5,669.2		$	5,675.7

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
	2006			2005
	(Expressed in millions)
Cash Flows from Operating Activities:
Cash received from customers	$	371.0		$	256.6
Operating, exploration, and general and administrative expenses paid	(105.5		)	(68.2		)
Interest paid	(20.4		)	(5.3		)
Income taxes paid	(3.2		)	—
Income tax refund	1.6			—
Other	(3.1		)	3.0
Cash provided by continuing operations	240.4			186.1
Cash provided by discontinued operations	—			73.2
Net cash provided by operating activities	240.4			259.3

Cash Flows from Investing Activities:
Capital expenditures	(176.1		)	(127.5		)
Purchase of corporations and property	(23.4		)	(20.9		)
Sale of current investments	—			122.3
Purchase of current investments	—			(16.8		)
Insurance proceeds	2.5			4.4
Other	(1.1		)	0.2
Cash used in continuing operations	(198.1		)	(38.3		)
Cash used in discontinued operations	—			(13.2		)
Net cash used in investing activities	(198.1		)	(51.5		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	183.0			669.0
Payments under senior debt agreements	(249.0		)	(944.0		)
Proceeds from 2015 Notes	—			297.3
Purchase of Company stock	(7.7		)	(81.5		)
Payments of cash dividends on common stock	(4.3		)	(4.0		)
Payments from discontinued operations	—			82.5
Payment of debt issue costs	(0.1		)	(2.6		)
Proceeds from exercise of stock options	1.6			2.8
Cash provided by (used in) continuing operations	(76.5		)	19.5
Cash provided by (used in) discontinued operations	—			(82.5		)
Net cash used in financing activities	(76.5		)	(63.0		)
Effect of exchange rate changes on cash	0.2			(0.2		)
Net decrease in cash and cash equivalents	(34.0		)	144.6
Cash and cash equivalents from continuing operations, beginning of the year	57.7			33.5
Cash and cash equivalents from discontinued operations, beginning of the year	—			53.0
Cash and cash equivalents at the end of the period	$	23.7		$	231.1

Reconciliation of net income to net
cash provided by operating activities:
Net income	$	67.5		$	59.2
Adjustments to reconcile net income to net cash provided by operating activities -
Income from discontinued operations, net of tax	—			(19.7		)
(Gains) losses from the sales of properties	—			(0.3		)
Depreciation, depletion and amortization	110.1			70.5
Dry hole and impairment	25.6			47.4
Interest capitalized	(16.2		)	(2.2		)
Price hedge contracts	0.3			1.2
Other	1.2			(1.9		)
Deferred income taxes	1.0			(6.9		)
Change in operating assets and liabilities	50.9			38.8
Net cash provided by continuing operating activities	240.4			186.1
Net cash provided by discontinued operating activities	—			73.2
Net cash provided by operating activities	$	240.4		$	259.3

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Equity (Unaudited)

		For the Three Months Ended March 31,
		2006					2005
		Shareholders’					Shareholders’
		Equity					Equity
		Shares		Amount			Shares		Amount
		(Expressed in millions, except share amounts)
Common Stock:
$	1.00 par-200,000,000 shares authorized
Balance at beginning of year		65,275,106		$	65.3		64,580,639		$	64.6
Stock option activity and other		53,200		—			96,801		0.1
Issued at end of period		65,328,306		65.3			64,677,440		64.7

Additional Capital:
Balance at beginning of year				977.9					943.7
Stock options exercised-proceeds				1.6					2.7
Stock based compensation-federal tax benefit				0.7					0.7
Stock based compensation expense-stock options				0.3					0.3
Stock based compensation expense-restricted stock				2.5					0.1
Cumulative effect of change in accounting principle				(27.7		)			—
Balance at end of period				955.3					947.5

Retained Earnings:
Balance at beginning of year				1,464.2					728.7
Net income				67.5					59.2
Dividends ($0.075 and $0.0625 per common share, respectively)				(4.4		)			(4.0		)
Balance at end of period				1,527.3					783.9

Accumulated Other
Comprehensive Income (Loss):
Balance at beginning of year				(30.0		)			2.6
Cumulative foreign currency translation adjustment				(7.9		)			—
Change in fair value of price hedge contracts				21.9					(13.5		)
Reclassification adjustment for losses included in net income				0.2					(1.2		)
Balance at end of period				(15.8		)			(12.1		)

Deferred Compensation
Balance at beginning of year				(17.5		)			(9.9		)
Activity during the period				—					0.7
Cumulative effect of change in accounting principle				17.5					—
Balance at end of period				—					(9.2		)

Treasury Stock:
Balance at beginning of year		(7,365,359	)	(361.3		)	(55,239	)	(1.7		)
Activity during the period		—		—			(2,113,800	)	(98.6		)
Balance at end of period		(7,365,359	)	(361.3		)	(2,169,039	)	(100.3		)

Common Stock Outstanding, at the End of the Period		57,962,947					62,508,401

Total Shareholders’ Equity				$	2,170.8				$	1,674.5

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(1) GENERAL INFORMATION -

The consolidated financial statements included herein have been prepared by Pogo Producing Company (the “Company”) without audit and include all adjustments (of a normal and recurring nature), which are, in the opinion of management, necessary for the fair presentation of interim results. The interim results are not necessarily indicative of results for the entire year. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

The Company’s results for 2005 reflect its oil and gas exploration, development and production activities in the Kingdom of Thailand and in Hungary as discontinued operations. Except where noted and for pro forma earnings per share, the discussions in the following notes relate to the Company’s continuing operations only.

(2) ACQUISITIONS –

2006 - On February 21, 2006, the Company completed the corporate acquisition of a Canadian company for cash consideration totaling approximately $18.5 million. The Company recorded the estimated fair value of assets and liabilities that consisted primarily of $25.7 million of oil and gas properties and deferred tax liabilities of $7.8 million. No goodwill was recorded in connection with the transaction.

2005 - On September 27, 2005, the Company completed the acquisition of Northrock Resources Ltd. (“Northrock”) for approximately $1.7 billion in cash. 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 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		757.3
Total purchase price for assets acquired		2,634.1

ALLOCATION OF PURCHASE PRICE (IN MILLIONS)
Proved oil and gas properties		1,715.8
Unproved oil and gas properties		799.0
Other assets		119.3
Total		2,634.1

In addition to the Northrock acquisition, during 2005 the Company 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 that 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.

Pro Forma Information

The following summary presents unaudited pro forma consolidated results of operations for the three months ended March 31, 2005 for the Company’s continuing operations as if the acquisition of Northrock (which is the only acquisition occurring since January 1, 2005 considered material for pro forma purposes) had occurred as of January 1, 2005. The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results of Northrock, 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.

Pro Forma for the three months ended March 31, 2005:

Revenues	$	350.3
Income from continuing operations	48.2
Earnings per share:
Basic -	$	0.76
Diluted -	$	0.75

(3) 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 appropriate approvals by the Company’s management or Board of Directors have occurred and other criteria are met. During 2005, the Company completed the sale of the assets discussed below.

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.

The Thailand Entities and Pogo Hungary are classified as discontinued operations in the Company’s financial statements for all periods presented. The summarized results of the discontinued operations were as follows (amounts expressed in millions):

Operating Results Data

	Three months ended
	March 31, 2005

Revenues	$	101.6
Costs and expenses	(55.0		)
Other income	0.6
Income before income taxes	47.2
Income taxes	(27.5		)
Income from discontinued operations, net of tax	$	19.7

(4) 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. Earnings per share and potential common shares (diluted earnings per share) consider the effect of dilutive securities as set out below. This disclosure reflects net income from both continuing and discontinued operations. Amounts are expressed in millions, except per share amounts.

	Three Months Ended
	March 31,
	2006		2005

Income (numerator):
Income from continuing operations	$	67.5	$	39.5
Income from discontinued operations, net of tax	—		19.7

Net Income - basic and diluted	$	67.5	$	59.2

Weighted average shares (denominator):
Weighted average shares - basic	57.3		63.5
Shares assumed issued from the exercise of options to purchase common shares and unvested restricted stock, net of treasury shares assumed purchased from the proceeds, at the average market price for the period	0.6		0.6

Weighted average shares - diluted	57.9		64.1

Earnings per share:
Basic:
Income from continuing operations	$	1.18	$	0.62
Income from discontinued operations	—		0.31
Basic earnings per share	$	1.18	$	0.93

Diluted:
Income from continuing operations	$	1.16	$	0.62
Income from discontinued operations	—		0.31
Diluted earnings per share	$	1.16	$	0.93

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	—		0.03
Average price	$	—	$	49.02

(5) LONG-TERM DEBT –

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

	March 31,			December 31,
	2006			2005
Senior debt -
Bank revolving credit agreement:
LIBOR based loans, borrowings at March 31, 2006 and December 31, 2005 at interest rates of 5.824% and 5.837%, respectively	$	540.0		$	606.0
LIBOR Rate Advances, borrowings at March 31, 2006 and December 31, 2005 at interest rates of 6.003% and 5.618%, respectively	40.0			40.0
Total senior debt	580.0			646.0
Subordinated debt -
8.25% Senior subordinated notes, due 2011	200.0			200.0
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	1,000.0			1,000.0
Unamortized discount on 2015 Notes	(2.5		)	(2.5		)
Total debt	1,577.5			1,643.5
Amount due within one year	—			—
Long-term debt	$	1,577.5		$	1,643.5

(6) INCOME TAXES –

As of March 31, 2006 no deferred U.S. income tax liability has been recognized on the $50.7 million of undistributed earnings of certain foreign subsidiaries as they have been deemed permanently invested outside the U.S., and it is not practicable to estimate the deferred tax liability related to such undistributed earnings.

(7) ASSET RETIREMENT OBLIGATION –

The Company’s liability for expected future costs associated with site reclamation, facilities dismantlement, and plugging and abandonment of wells for the three-month period ended March 31, 2006 is as follows (in millions):

	2006
ARO as of January 1,	$	156.3
Liabilities incurred during the three months ended March 31,	0.6
Liabilities settled during the three months ended March 31,	(1.7		)
Accretion expense	2.6
Balance of ARO as of March 31,	157.8
Less: current portion of ARO	(7.5		)
Long-term ARO as of March 31,	$	150.3

For the three months ended March 31, 2006 and 2005 the Company recognized depreciation expense related to its asset retirement cost of $2.2 million and $0.9 million, respectively.

(8) GEOGRAPHIC INFORMATION

The Company’s reportable geographic information is identified below. The Company evaluates performance based on operating income (loss). Financial information by geographic region is presented below:

	2006			2005
	(Expressed in millions)
Long-Lived Assets:
As of March 31,
United States	$	2,634.6		$	2,545.0
Canada	2,714.5			—
Total	$	5,349.1		$	2,545.0

Capital Expenditures:
(including interest capitalized)
For the three months ended March 31,
United States	$	96.9		$	124.7
Canada	116.9			—
Total	$	213.8		$	124.7

Revenues:
For the three months ended March 31,
United States	$	243.7		$	255.8
Canada	129.8			—
Total	$	373.5		$	255.8

Depreciation, depletion, and amortization expense:
For the three months ended March 31,
United States	$	63.3		$	70.5
Canada	46.8			—
Total	$	110.1		$	70.5

Operating income (loss):
For the three months ended March 31,
United States	$	82.1		$	81.6
Canada	29.2			—
Other	(1.0		)	(7.9		)
Total	$	110.3		$	73.7

(9) COMMODITY DERIVATIVES AND HEDGING ACTIVITIES -

As of March 31, 2006, the Company held various derivative instruments. During 2005, the Company 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 these contracts as cash flow hedges designed to achieve a more predictable cash flow, as well as to reduce its 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.

During the three-month period ended March 31, 2006 the Company recognized $4.4 million of pre-tax losses related to settled contracts in its oil and gas revenues from its price hedge contracts. Price hedging activity had no effect on the Company’s oil and gas revenues during the first quarter of 2005. The Company recognized pre-tax losses of $0.3 million and $1.3 million due to ineffectiveness on hedge contracts during the first quarter of 2006 and 2005, respectively. Unrealized losses on derivative instruments of $30.9 million, net of deferred taxes of $17.7 million, have been reflected as a component of other comprehensive income at March 31, 2006. Based on the fair market value of the hedge contracts as of March 31, 2006, the Company would reclassify additional pre-tax losses of approximately $24.8 million (approximately $15.7 million after taxes) from accumulated other comprehensive income (shareholders’ equity) to net income during the next twelve months.

The gas derivative contracts are generally settled based upon the average of the reported 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 March 31, 2006 are as follows:

		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:
April 2006 - December 2006	4,125	$	5.00	$	7.50	$	(4.4	)
April 2006 - December 2006	1,530	$	5.50	$	8.25	$	(1.4	)
April 2006 - December 2006	2,750	$	5.75	$	8.27	$	(2.0	)
April 2006 - December 2006	8,250	$	6.00	$	13.50	$	0.1
April 2006 - December 2006	1,375	$	6.00	$	13.55	$	—
April 2006 - December 2006	2,750	$	6.00	$	13.60	$	0.1
April 2006 - December 2006	8,250	$	6.00	$	14.00	$	0.3
January 2007 - December 2007	5,475	$	6.00	$	12.00	$	(3.4	)
January 2007 - December 2007	9,125	$	6.00	$	12.15	$	(5.3	)
January 2007 - December 2007	3,650	$	6.00	$	12.20	$	(2.1	)
January 2007 - December 2007	9,125	$	6.00	$	12.50	$	(4.7	)

Crude Oil Contracts (Barrels)
Collar Contracts:
April 2006 - December 2006	1,100,000	$	50.00	$	78.00	$	(1.9	)
April 2006 - December 2006	275,000	$	50.00	$	79.00	$	(0.4	)
April 2006 - December 2006	1,100,000	$	50.00	$	81.00	$	(1.3	)
April 2006 - December 2006	275,000	$	50.00	$	81.04	$	(0.3	)
April 2006 - December 2006	1,375,000	$	50.00	$	82.00	$	(1.5	)
January 2007 - December 2007	1,460,000	$	50.00	$	75.00	$	(6.4	)
January 2007 - December 2007	365,000	$	50.00	$	75.25	$	(1.5	)
January 2007 - December 2007	3,650,000	$	50.00	$	77.50	$	(13.3	)

(a) MMBtu means million British Thermal Units.

Although all of the Company’s collars are effective as economic hedges, 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 under SFAS 133. For the collar contracts that no longer qualify for hedge accounting, the Company now recognizes changes in the fair value of these contracts in the consolidated statement of income for the period in which the change occurs under the caption “Commodity derivative income (expense).” As of March 31, 2006, the Company had the following open collar contracts that no longer qualify for hedge accounting:

NYMEX

Contract

Fair Value

Contract Period and

Price

Type of Contract

Volume

Floor

Ceiling

Liability

(in millions)

Natural Gas Contracts (MMBtu)

Collar Contracts:

April 2006 - November 2006

1,220

5.50

8.25

(0.6

)

In April 2006, the Company entered into additional natural gas and crude oil collars to establish floor and ceiling prices on anticipated future natural gas and crude oil production. The Company has designated these contracts as cash flow hedges. Further details related to these hedging activities are as follows:

		NYMEX
		Contract
Contract Period and		Price
Type of Contract	Volume	Floor		Ceiling

Natural Gas Contracts (MMBtu)
Collar Contracts:
July 2006 - December 2006	920	$	7.00	$	10.60
July 2006 - December 2006	920	$	7.00	$	10.62
July 2006 - December 2006	920	$	7.00	$	10.70
January 2007 - December 2007	913	$	8.00	$	13.40
January 2007 - December 2007	2,738	$	8.00	$	13.50
January 2007 - December 2007	913	$	8.00	$	13.52
January 2007 - December 2007	913	$	8.00	$	13.65
January 2008 - December 2008	1,830	$	8.00	$	12.05
January 2008 - December 2008	2,745	$	8.00	$	12.10
January 2008 - December 2008	915	$	8.00	$	12.25

Crude Oil Contracts (Barrels)
Collar Contracts:
June 2006 - December 2006	428,000	$	60.00	$	84.00
June 2006 - December 2006	107,000	$	60.00	$	85.25
January 2007 - December 2007	182,500	$	60.00	$	82.75
January 2007 - December 2007	547,500	$	60.00	$	83.00
January 2007 - December 2007	182,500	$	60.00	$	84.00
January 2008 - December 2008	183,000	$	60.00	$	80.00
January 2008 - December 2008	183,000	$	60.00	$	80.05
January 2008 - December 2008	183,000	$	60.00	$	80.10
January 2008 - December 2008	366,000	$	60.00	$	80.25

(10) EMPLOYEE BENEFIT PLANS -

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 that produce the highest average compensation. The Company did not make a contribution to the plan during the first three months of 2006 and does not expect to make a contribution during the remainder of 2006.

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 Company’s net periodic benefit cost for its benefit plans is comprised of the following components (in millions of dollars):

	Retirement Plan
	Three Months Ended
	March 31,
	2006			2005

Service cost	$	1.1		$	0.8
Interest cost	0.6			0.5
Expected return on plan assets	(0.7		)	(0.6		)
Amortization of prior service cost	—			—
Amortization of net loss	0.5			0.3
	$	1.5		$	1.0

	Post-Retirement Medical Plan
	Three Months Ended
	March 31,
	2006		2005

Service cost	$	0.4	$	0.4
Interest cost	0.3		0.3
Amortization of transition obligation	—		0.1
Amortization of net loss	0.1		0.1
	$	0.8	$	0.9

The assumptions used in the valuation of the Company’s employee benefit plans and the target investment allocations have remained the same as those disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

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 financial statements since the Company has concluded that the effects of the Act are not a significant event that calls for remeasurement under SFAS 106.

(11) ACCOUNTING FOR STOCK-BASED COMPENSATION -

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 becomes exercisable in four installments. The number of shares of Company common stock available for future issuance was 3,656,324, as of March 31, 2006. 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 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 three months ended March 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, stock options and other stock-based compensation 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 for the quarters ended March 31, 2006 and 2005 would have resulted in additional pre-tax compensation expense of $0.5 million and $0.8 million, 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 three-month period ended March 31, 2005 (in millions of dollars, except per share amounts):

	Three Months Ended March 31, 2005

Net income, as reported	$	59.2
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported	1.0
Deduct: Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects	(1.6		)
Net income, pro forma	$	58.6

Earnings per share:
Basic - as reported	$	0.93
Basic - pro forma	$	0.92
Diluted - as reported	$	0.93
Diluted - pro forma	$	0.92

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. A summary of the status of the Company’s unvested restricted stock as of March 31, 2006 and the changes in the three months ended March 31, 2006 is presented below:

	Shares		Average Grant Date Fair Value

Unvested restricted stock:
Unvested at December 31, 2005	630,600		$	51.57

Granted	2,000		$	52.81
Vested	(18,350	)	$	43.89
Forfeited	(5,700	)	$	48.26

Unvested at March 31, 2006	608,550		$	51.80

As of March 31, 2006, there was approximately $24.3 million of total unrecognized compensation cost related to unvested restricted stock that is expected to be recognized over a weighted average period of 2.9 years. Total compensation expense for restricted stock during the three months ended March 31, 2006 and 2005 was $2.5 million ($1.6 million, net of tax) and $1.2 million ($0.8 million, net of tax), respectively. The total fair value of shares that vested and were distributed during the three months ended March 31, 2006 was $1.0 million, which resulted in tax deductions to realize benefits of $0.1 million. No restricted stock shares vested or were distributed during the three months ended March 31, 2005.

Stock Options

No stock options were granted during 2005 or in the first three months of 2006. The fair value of previous stock option grants that either vested in 2005 or will vest in 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 during the three months ended March 31, 2006 and 2005 was $0.3 million ($0.2 million, net of tax) and $0.3 million ($0.2 million, net of tax), respectively. The total intrinsic value of stock options exercised during the three months ended March 31, 2006 and 2005, was $1.7 million, resulting in tax deductions of $0.6 million and $2.0 million, resulting in tax deductions of $0.7 million, respectively. As of March 31, 2006, there was approximately $0.5 million in unrecognized compensation cost related to unvested stock options that is expected to be recognized over a weighted average period of 6 months. The Company’s current practice is to issue new shares to satisfy stock option exercises. A summary of the status of the Company’s stock option activity as of March 31, 2006 and changes during the quarter ended March 31, 2006 is presented below:

	Number of Awards		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value (millions)(a)

Outstanding, December 31, 2005	1,782,236		$	29.69
Exercised	(56,900	)	$	28.50
Canceled	(9,667	)	$	46.92
Outstanding, March 31, 2006	1,715,669		$	29.64	4.7 years	$	34.9
Exercisable, March 31, 2006	1,579,301		$	28.51	5.1 years	$	33.9

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

Restricted Stock Units

On November 1, 2005 the Company awarded 135,000 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 based on the average fair market value of Company common stock for the last five trading days of the period. For the three months ended March 31, 2006, the Company recognized compensation expense of $0.6 million related to the Units.

(12) COMPREHENSIVE INCOME-

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

	Three Months Ended March 31,
	2006			2005

Net income	$	67.5		$	59.2
Foreign currency translation adjustment, net of tax	(7.9		)	—
Change in fair value of price hedge contracts, net of tax	21.9			(13.5		)
Reclassification adjustment for hedge contract losses included in net income, net of tax	0.2			(1.2		)
Comprehensive income	$	81.7		$	44.5

(13) SUBSEQUENT EVENTS-

On April 13, 2006, the Company entered into a definitive agreement to acquire all of the stock of Latigo Petroleum, Inc. (“Latigo”) for $750 million. Latigo, headquartered in Tulsa, Oklahoma, is a privately owned exploration and production company that owns approximately 404,700 net acres of oil and gas properties located principally in the Texas Panhandle and the Permian Basin. The acquisition is expected to close in the second quarter of 2006.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 as well as the risk factors therein and herein. The Thailand Entities and Pogo Hungary are classified as discontinued operations in the Company’s financial statements for all periods presented. Except where noted, discussions in this report relate to the Company’s continuing operations. Some of the statements in the discussion are “Forward Looking Statements” and are thus prospective. As further discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, 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.

Executive Overview

Pending Acquisition of Latigo Petroleum Inc.

On April 17, 2006, the Company announced that it had entered into a definitive agreement to acquire Latigo Petroleum, Inc. (“Latigo”), a privately held exploration and production company for approximately $750 million. The purchase price will be funded using proceeds from the pending sale of the Company’s Gulf of Mexico interests, existing bank credit capacity and capital market transactions.

As of April 1, 2006, Latigo owned 275 Bcfe of estimated proven reserves on approximately 100,000 net acres, plus approximately 304,600 net acres of undeveloped leasehold. Latigo currently produces approximately 3,300 bopd and 20 MMcf/d and operates 90% of the aforementioned production. Latigo’s exploration and development activities are concentrated in the Permian Basin and Texas panhandle areas. The purchase of Latigo is expected to have a significant impact on the Company’s future results of operations and cash flows. The Company expects to close the transaction during the second quarter of 2006.

Pending Sale of Gulf of Mexico Interests

On April 21, 2006, the Company announced that it had entered into a definitive agreement to sell an undivided 50 percent interest of each and all of its Gulf of Mexico oil and gas leasehold interests to an affiliate of Mitsui & Co., Ltd., for $500 million, subject to adjustment. The sale of the 50 percent interest in the Company’s Gulf of Mexico assets is equivalent to approximately 8,000 bopd of oil production and 24 MMcf per day of natural gas production. As of December 31, 2005, the reserves sold represent approximately 143 Bcfe of net estimated proven oil and gas reserves.

First Quarter Results

Total revenue for the first quarter of 2006 was $373.5 million and net income totaled $67.5 million, or $1.18 per share. Cash flow from operations totaled $240.4 million. As of March 31, 2006, long-term debt was $1,580 million, while cash and cash equivalents decreased by $34 million during the first quarter to $23.7 million.

2006 Capital Budget

The Company has established a $800 million exploration and development budget (excluding acquisitions). The Company expects to spend approximately $240 million on exploration and $560 million on development activities. The capital budget calls for the drilling of approximately 525 wells during 2006, including wells in the United States and Canada.

During the first quarter of 2006, the company spent $193 million on its exploratory and development activities and, as of March 31, 2006, had spent approximately 24% of its $800 million 2006 capital budget. During the first quarter of 2006, 107 wells were drilled with 94 successfully completed, an 88% success rate.

2006 Production Outlook Update

The Company currently expects its production volumes, including the effects of the Latigo purchase and the Gulf of Mexico sale, to average approximately 96,000 barrels of oil equivalent per day (“Boepd”) during 2006. In addition, the Company currently expects its production volumes to exit 2006 at approximately 108,000 Boepd. These estimates assume that the Latigo purchase closes in May 2006 and that the Gulf of Mexico disposition closes by May 31, 2006. Furthermore, these estimates are subject to change, and actual results could differ materially, depending upon the production levels from the Latigo purchase, the amount of Gulf of Mexico production that remains shut-in, the timing of any such production coming back on-line, the availability of oilfield services, acquisitions, divestitures and many other factors that are beyond the Company’s control.

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 during 2005 and the first quarter of 2006. The market for oil field services is currently very competitive and

shortages or delays in delivery or availability of equipment or fabrication yards could impact the Company’s ability to conduct oil and gas drilling and completion operations.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for the first quarter of 2006 were $354.4 million, an increase of approximately 39% from oil and gas revenues of $254.1 million for the first quarter of 2005. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in millions) between 2006 and 2005.

	1st Qtr. 2006 Compared to 1st Qtr. 2005

Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	15.3
Production	31.3
	46.6
Crude oil and condensate -
Price	14.5
Production	30.4
	44.9

Natural gas liquids	8.8
Increase in oil and gas revenues	$	100.3

The most significant cause for the increase in hydrocarbon production was the acquisition of Northrock on September 27, 2005. The increased Canadian hydrocarbon production from Northrock was partially offset by decreased production in the Company’s Gulf of Mexico region resulting from the curtailment of approximately 15 MMcf per day and 5,000 barrels per day of production in the first quarter of 2006 due to the infrastructure damage caused by Hurricanes Katrina and Rita in the third quarter of 2005 and natural production declines. The following tables reflect the relative changes in hydrocarbon volumes and prices by geographic area:

					% Change
	1st Quarter				2005 to
	2006		2005		2006
Comparison of Increases (Decreases) in:
Natural Gas —
Average prices (per Mcf)
United States (a)	$	7.13	$	5.97	19	%
Canada	$	7.82	$	—	N/M
Company-wide average price	$	7.31	$	5.97	22	%

Average daily production volumes
(MMcf per day):
United States (a)	207.7		258.9		(20	)%
Canada	74.5		—		N/M
Company-wide average daily production	282.2		258.9		9	%

(a) Price hedging activity reduced the average price of the Company’s United States natural gas production during the first quarter of 2006 by $0.17 per Mcf. Price hedging activity had no effect on the average price of the Company’s United States natural gas production during the first quarter of 2005. “MMcf” is an abbreviation for million cubic feet.

					% Change
	1st Quarter				2005 to
	2006		2005		2006
Comparison of Increases (Decreases) in:
Crude Oil and Condensate —
Average prices (per Bbl)
United States (a)	$	54.60	$	43.76	25	%
Canada	$	43.29	$	—	N/M
Company-wide average price	$	49.83	$	43.76	14	%

Average daily production volumes
(Bbls per day) (a):
United States	19,274		26,595		(28	)%
Canada	14,111		—		N/M
Company-wide average daily production	33,385		26,595		26	%

Total Liquid Hydrocarbons —
Company-wide average daily production (Bbls per day)	39,561		30,594		29	%

(a) Price hedging activity had no effect on the average price of the Company’s United States crude oil and condensate production during the first quarters of 2006 or 2005. “Bbls” is an abbreviation for barrels.

Other Revenues

Other revenue is derived from sources other than the current production of hydrocarbons. This revenue includes, among other items, natural gas inventory sales, pipeline imbalance settlements and revenue from salt-water disposal activities. The increase in the Company’s other revenues in the first quarter of 2006, compared to same period of 2005, is related primarily to $18.3 million of natural gas inventory sales from the Company’s Canadian operations in the first quarter of 2006. No gas inventory sales were made in the first quarter of 2005.

Costs and Expenses

	1st Quarter								% Change
	2006				2005				2005
	(Expressed in millions, except DD&A statistics)
Comparison of Increases (Decreases) in:
Lease Operating Expenses:
United States	$		39.2		$		28.7		37	%
Canada	$		17.9		$		—		N/M
Total	$		57.1		$		28.7		99	%

General and Administrative Expenses	$		28.7		$		18.7		53	%
Exploration Expenses	$		2.7		$		11.2		(76	)%
Dry Hole and Impairment Expenses	$		25.6		$		47.4		(46	)%
Depreciation, Depletion and Amortization (DD&A) Expenses	$		110.1		$		70.5		56	%
DD&A rate	$		2.36		$		1.77		33	%
MMcfe produced	46,761				39,818				17	%
Production and Other Taxes	$	13.5			$	11.2			21	%
Transportation and Other	$	25.4			$	(5.6		)	(554	)%
Interest—
Charges	$	(28.3		)	$	(10.2		)	177	%
Capitalized Interest	$	16.2			$	2.2			636	%
Commodity Derivative Income (Expense)	$	3.3			$	—			N/M
Income Tax Expense	$	(34.3		)	$	(27.0		)	27	%

Lease Operating Expenses

The increase in lease operating expenses for the first quarter of 2006, compared to the first quarter 2005, is related to the addition of Northrock in September of 2005 and higher costs being charged by service companies in 2006 relative to the 2005 period, and, to a lesser extent, increased maintenance expenses on the Company’s offshore properties due to damage from Hurricanes Katrina and Rita (which were only partially offset by insurance recoveries).

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.72 per Mcfe for the first quarter of 2005 to $1.22 per Mcfe for the first quarter of 2005. This increase in unit costs is related to the higher oilfield service costs being charged in 2006, in addition to the Company’s increased hurricane repair related operating expenses compounded by the associated reduced offshore hydrocarbon production and natural production declines.

General and Administrative Expenses

The increase in general and administrative expenses for the first quarter of 2006, compared with the respective 2005 period, is related primarily to increases in the size of the Company’s workforce due to acquisitions over the preceding year, increased benefit expenses and increases in compensation. On a per unit of production basis, the Company’s general and administrative expenses increased to $0.61 per Mcfe in the first quarter of 2006, from $0.47per Mcfe in the first quarter of 2005.

Exploration Expenses

Exploration expenses consist primarily of rental payments required under oil and gas leases to hold non-producing properties (“delay rentals”) and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses for the first quarter of 2006 resulted primarily from $1.5 million of seismic activity in the Company’s Canadian and Gulf Coast divisions and delay rentals in the United States. Exploration expenses for the first quarter of 2005 consisted primarily of $7.6 million and $3.3 million from 3-D seismic activity in New Zealand and the Company’s Gulf of Mexico divisions, respectively, and delay rentals in the United States.

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. The decrease in dry hole and impairment expense for the first quarter of 2006, compared to the first quarter of 2005, was primarily the result of decreased dry hole costs. The Company incurred approximately $19.4 million of exploratory dry hole costs incurred during the 2006 period compared to approximately $42.5 million incurred in the 2005 period. The Company had approximately $24.4 million of cost attributable to exploratory wells in progress as of March 31, 2006 that, as of April 24, 2006 were either still in progress or pending evaluation.

Generally accepted accounting principles also require that if the expected future cash flow of the Company’s reserves on a property fall below the cost that is recorded on the Company’s books, these properties 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 Company’s 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, impairment could be required on some of the Company’s properties and this impairment could have a material negative non-cash impact on the Company’s earnings and balance sheet. During the first quarter of both 2006 and 2005, the Company recognized miscellaneous impairments on various prospects and leases in the amount of $6.2 million and $4.9 million, respectively.

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. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its onshore oil and gas activities. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico. The increase in the Company’s DD&A expenses for the first quarter of 2006 compared to the respective 2005 period resulted from an increase in the Company’s composite DD&A rate, in addition to an increase in the Company’s equivalent hydrocarbon sales.

The increase in the composite DD&A rate for all of the Company’s producing fields for the first quarter of 2006, compared to the corresponding 2005 period, 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 Northrock acquisition).

Production and Other Taxes

The increase in production and other taxes during the first quarter of 2006, compared to the corresponding 2005 period, relates primarily to increased severance, property and franchise taxes resulting from the higher product prices received by the Company and increased production from the Company’s domestic onshore and Canadian properties.

Transportation and Other

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

	For the Quarter Ended March 31,
	2006			2005
Gas inventory purchases	$	17.9		$	—
Business interruption insurance	(3.0		)	(11.4		)
Transportation costs	5.9			2.9
Accretion expense	2.6			1.3
Other	2.1			1.6
Total	$	25.5		$	(5.6	)

Gas inventory purchases are related solely to the Company’s Canadian operations and were therefore not present in the first quarter of 2005. The business interruption insurance relates to claims from the shut-in of a significant portion of the Company’s Gulf of Mexico production as a result of the infrastructure damage caused by Hurricanes Ivan, Katrina and Rita. Transportation costs increased in the first quarter of 2006 compared to the first quarter of 2005 due to the acquisition of Northrock in the third quarter of 2005. Accretion expense increased in the first quarter of 2006 compared to the first quarter of 2005 due to increased estimates of future liabilities due to rising service costs and the acquisition of Northrock.

Interest

Interest Charges. The increase in the Company’s interest charges for the first quarter of 2006, compared to the first quarter of 2005, resulted primarily from an increase in the average amount of the Company’s outstanding debt and, to a lesser extent, an increase in the average interest rate on the Company’s revolving credit facility. See “-Liquidity and Capital Resources” below.

Capitalized Interest. Interest costs related to financing major oil and gas projects in progress are 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 the first quarter of 2006, compared to the comparable 2005 period, resulted primarily from an increase in the dollar amount of oil and gas projects in progress subject to interest capitalization during the first quarter of 2006 (approximately $938.5 million), compared to the first quarter of 2005 (approximately $168.6 million). The increase is primarily attributable to unproved property acquired in the Northrock transaction in September 2005.

Commodity Derivative Income (Expense)

Commodity derivative income for the first quarter of 2006 represents realized and unrealized gains on derivative contracts that no longer qualify for hedge accounting treatment. Although all of the Company’s collars are effective as economic hedges, 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 under SFAS 133. No such income was incurred during the first quarter of 2005, as all of the Company’s derivative contracts qualified for hedge accounting at that time.

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 increase in the Company’s tax expense for the first quarter of 2006, compared to the first quarter of 2005, resulted from increased pre-tax income during the 2006 period. The Company’s consolidated effective tax rate was 33.7% for the first quarter of 2006 and 40.6% for the first quarter of 2005. The Company currently expects its annual effective tax rate to continue to decrease over the next two years, based on current earnings levels. This reduction is expected due to the favorable impact of cross-border financing related to the acquisition of Northrock Resources, reductions in the statutory federal income tax rates in Canada from approximately 26% to 22%, proposed reductions in provincial tax rates in Canada, the phase-in of a deduction in Canada for Crown royalties, and the phase-in of the deduction for qualified domestic production activities in the United States.

Discontinued Operations-

The Thailand Entities (sold August 17, 2005) and Pogo Hungary (sold June 7, 2005) are classified as discontinued operations in the Company’s financial statements. The summarized financial results of the discontinued operations were as follows (amounts expressed in millions):

Operating Results Data

For the three months ended March 31, 2005:

Revenues	$	101.6
Costs and expenses	(55.0		)
Other income	0.6
Income before income taxes	47.2
Income taxes	(27.5		)
Income from discontinued operations, net of tax	$	19.7

Liquidity and Capital Resources

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

The Company’s cash flow provided by operating activities for the first three months of 2006 was $240.4 million compared to cash flow from continuing operating activities of $186.1 million in the first three months of 2005. The increase is attributable primarily to increased production volumes and higher oil and gas prices, partially offset by higher expenses discussed under “Results of Operations” above. Cash flow from operating activities during the first three months of 2006 was more than adequate to fund $199.5 million in cash expenditures for capital and exploration projects and acquisition activities. During the first three months of 2006, the Company repaid debt obligations using cash of approximately $66 million (net of borrowings). During the first three months of 2006 the Company paid $7.7 million for purchases of Company stock made in late December 2005 and also paid $4.3 million of common stock dividends. As of March 31, 2006, the Company had cash and cash equivalents of $23.7 million and long-term debt obligations of $1.58 billion (excluding debt discount) with no repayment obligations until 2009. The Company may determine to repurchase outstanding debt in the future, including in market transactions, privately negotiated transactions or otherwise, depending on market conditions, liquidity requirements, contractual restrictions and other factors.

Effective December 15, 2005, the Company’s lenders redetermined the borrowing base under its revolving credit facility at $1.5 billion. As of April 24, 2006, the Company had an outstanding balance of $595 million under its facility. As such, the available borrowing capacity under the facility was $405 million.

Latigo Acquisition

The Company obtained a commitment from Goldman Sachs Credit Partners L.P. in April 2006 for unsecured, senior bridge loans of up to $500 million as a possible source of financing for the acquisition. The commitment is conditioned on, among other things, the absence of certain adverse developments.

LIBOR Rate Advances

Under separate Promissory Note Agreements dated May 8, 2004 and September 13, 2004, two of the Company’s lenders make available to the Company LIBOR rate advances on an uncommitted basis up to $50,000,000. 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 refinance such amounts through borrowings under its Credit Agreement. The Company’s 2011 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 April 24, 2006, there was $40,000,000 outstanding under these agreements.

Future Capital and Other Expenditure Requirements

The Company’s capital and exploration budget for 2006, 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 increased by the Company’s Board of Directors in April 2006 to $800 million, of which approximately $193 million was incurred in the three months ended March 31, 2006. The Company has included 525 gross wells in its 2006 capital and exploration budget (107 of which were drilled in the first three months of 2006), including wells in the United States and Canada.

The Company currently anticipates that, excluding the acquisition of Latigo discussed above, its available cash and cash investments, cash provided by operating activities and funds available under its Credit Agreement will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses, capital expenditures, 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.

Share Repurchase

On January 25, 2005, the Company announced a plan to repurchase, through open market or privately negotiated transactions, not less than $275 million nor more than $375 million of its common stock. As of April 24, 2006, the Company had completed the purchase of 7,310,000 shares at a total cost of $359.5 million. There were no repurchases of the Company’s equity securities during the three months ended March 31, 2006.

ITEM 3. 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 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. The Company makes 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.

Current Hedging Activity

As of March 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 its 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.

		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:
April 2006 - December 2006	4,125	$	5.00	$	7.50	$	(4.4	)
April 2006 - December 2006	1,530	$	5.50	$	8.25	$	(1.4	)
April 2006 - December 2006	2,750	$	5.75	$	8.27	$	(2.0	)
April 2006 - December 2006	8,250	$	6.00	$	13.50	$	0.1
April 2006 - December 2006	1,375	$	6.00	$	13.55	$	—
April 2006 - December 2006	2,750	$	6.00	$	13.60	$	0.1
April 2006 - December 2006	8,250	$	6.00	$	14.00	$	0.3
January 2007 - December 2007	5,475	$	6.00	$	12.00	$	(3.4	)
January 2007 - December 2007	9,125	$	6.00	$	12.15	$	(5.3	)
January 2007 - December 2007	3,650	$	6.00	$	12.20	$	(2.1	)
January 2007 - December 2007	9,125	$	6.00	$	12.50	$	(4.7	)

Crude Oil Contracts (Barrels)
Collar Contracts:
April 2006 - December 2006	1,100,000	$	50.00	$	78.00	$	(1.9	)
April 2006 - December 2006	275,000	$	50.00	$	79.00	$	(0.4	)
April 2006 - December 2006	1,100,000	$	50.00	$	81.00	$	(1.3	)
April 2006 - December 2006	275,000	$	50.00	$	81.04	$	(0.3	)
April 2006 - December 2006	1,375,000	$	50.00	$	82.00	$	(1.5	)
January 2007 - December 2007	1,460,000	$	50.00	$	75.00	$	(6.4	)
January 2007 - December 2007	365,000	$	50.00	$	75.25	$	(1.5	)
January 2007 - December 2007	3,650,000	$	50.00	$	77.50	$	(13.3	)

(a) MMBtu means million British Thermal Units.

As of March 31, 2006, the Company had the following open collar contracts that no longer qualify for hedge accounting.

NYMEX

Contract

Fair Value

Contract Period and

Price

Type of Contract

Volume

Floor

Ceiling

Liability

(in millions)

Natural Gas Contracts (MMBtu)

Collar Contracts:

April 2006 — November 2006

220

5.50

8.25

(0.7

)

		NYMEX
		Contract
Contract Period and		Price
Type of Contract	Volume	Floor		Ceiling

Natural Gas Contracts (MMBtu)
Collar Contracts:
July 2006 - December 2006	920	$	7.00	$	10.60
July 2006 - December 2006	920	$	7.00	$	10.62
July 2006 - December 2006	920	$	7.00	$	10.70
January 2007 - December 2007	913	$	8.00	$	13.40
January 2007 - December 2007	2,738	$	8.00	$	13.50
January 2007 - December 2007	913	$	8.00	$	13.52
January 2007 - December 2007	913	$	8.00	$	13.65
January 2008 - December 2008	1,830	$	8.00	$	12.05
January 2008 - December 2008	2,745	$	8.00	$	12.10
January 2008 - December 2008	915	$	8.00	$	12.25

Crude Oil Contracts (Barrels)
Collar Contracts:
June 2006 - December 2006	428,000	$	60.00	$	84.00
June 2006 - December 2006	107,000	$	60.00	$	85.25
January 2007 - December 2007	182,500	$	60.00	$	82.75
January 2007 - December 2007	547,500	$	60.00	$	83.00
January 2007 - December 2007	182,500	$	60.00	$	84.00
January 2008 - December 2008	183,000	$	60.00	$	80.00
January 2008 - December 2008	183,000	$	60.00	$	80.05
January 2008 - December 2008	183,000	$	60.00	$	80.10
January 2008 - December 2008	366,000	$	60.00	$	80.25

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 April 24, 2006, 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 March 31, 2006:

	2005		2006		2007		2008		2009			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0.0	$	0.0	$	0.0	$	0.0	$	580.0		$	0.0		$	580.0		$	580.0
Average Interest Rate	—		—		—		—		5.84		%	—			5.84		%	—
Fixed Rate	$	0.0	$	0.0	$	0.0	$	0.0	$	0.0		$	1,000.0		$	1,000.0		$	1,000.0
Average Interest Rate	—		—		—		—		—			7.08		%	7.08		%	—

Foreign Currency Exchange Rate Risk

The Company does not actively manage foreign currency risk in its foreign subsidiaries where the U.S. dollar is not the functional currency, primarily Canada, since the majority of transactions are denominated in the local currency. A substantial amount of the Company’s cash is located in Canada, in Canadian dollars, which provides a natural hedge against foreign currency risk. Exposure from market rate fluctuations related to activities in New Zealand and Vietnam is not material at this time. As of April 24, 2006, the Company had no foreign currency financial derivatives.

ITEM 4. Controls and Procedures.

The Company has established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation as of the end of the period covered by this quarterly report, the Company’s Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

ITEM 1A. Risk Factors.

Please read “Risk Factors” in the Company’s Annual Report on Form 10-K for the fiscal year end December 31, 2005, some of which are updated below.

The Company’s recent and pending acquisitions are significant and may not be successful.

The completion of the Company’s $750 million acquisition of Latigo is subject to various conditions, some of which are beyond its control. It is possible that the Company will not complete the acquisition or that it will be delayed beyond its expected closing date. If the Company does not complete the acquisition, it will not have the opportunity to develop Latigo’s assets and to attempt to realize the benefits the Company believes the acquisition will afford it.

In September 2005, the Company completed the acquisition of Northrock, the largest acquisition in its history. The Company may not be able to realize anticipated economic, operational and other benefits from the recent acquisitions due to the following risks and difficulties, among others:

• the acquired properties may not produce revenues, earnings or cash flow at anticipated levels;

• the Company may have exposure to unanticipated liabilities and costs as a result of the acquisitions, some of which may materially exceed its estimates;

• the Company may lose key employees on whom management is substantially dependent in the operation of Northrock’s or Latigo’s assets;

• the Company may lose customers, suppliers, partners and agents of Northrock or Latigo;

• the Company may experience material difficulties and additional costs in integrating Northrock’s or Latigo’s operations, systems and personnel with its own.

The Company has substantial capital requirements.

The Company requires substantial capital to replace its reserves and generate sufficient cash flow to meet its financial obligations. If the Company cannot generate sufficient cash flow from operations or raise funds externally in the amounts and at the times needed, it may not be able to replace its reserves or meet its financial obligations. The Company recently paid approximately $1.7 billion in cash to acquire Northrock and will be obligated to pay approximately $750 million in cash upon the closing of the pending Latigo acquisition. The Company’s ongoing capital requirements consist primarily of the following items:

• funding its 2006 capital and exploration budget of $800 million;

• other allocations for acquisition, development, production, exploration and abandonment of oil and natural gas reserves;

• future dividends and stock repurchases.

The Company plans to finance anticipated ongoing expenses and capital requirements with funds generated from the following resources:

• available cash and cash investments;

• cash provided by operating activities;

• funds available under its credit facility;

• bridge loan financing;

• its uncommitted bank line(s) of credit;

• proceeds from the pending disposition of its Gulf of Mexico assets; and

• capital it believes it can raise through opportunistic capital market transactions.

Accordingly, these acquisitions reduce the availability of those resources for other capital requirements. Moreover, the uncertainties and risks associated with future performance and revenues will ultimately determine the Company’s liquidity and ability to meet anticipated capital requirements.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

There were no repurchases of the Company’s equity securities during the three months ended March 31, 2006.

ITEM 5. Other Information

On April 25, 2006, the Company, pursuant to authorization of its Board of Directors, entered into an indemnification agreement with each member of the Board of Directors. Each indemnification agreement provides that the Company will indemnify the director to the fullest extent permitted by applicable law against losses, liabilities, claims and expenses, incurred in connection with threatened, pending or completed legal proceedings, that arise out of any event or occurrence related to the fact that the director is or was a director or officer of the Company or serving at the request of the Company in another corporate status. Each agreement also provides that the Company will advance expenses to a director as the director incurs them during the course of a proceeding and before it is resolved so long as the director undertakes to repay the advance if it is later determined the director is not entitled to indemnification.

The foregoing summary of the indemnification agreements is qualified in its entirety by reference to the text of the Indemnification Agreements attached as Exhibits 10.1 through 10.9 to this Form 10-Q and incorporated by reference herein.

ITEM 6. Exhibits

*3.1 Restated Certificate of Incorporation of Pogo Producing Company, as filed on April 28, 2004 (Exhibit 3.1, Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 1-7796).

*3.2 Bylaws of Pogo Producing Company, as amended and restated through July 16, 2002 (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-7792).

10.1 Indemnification Agreement by and between Pogo Producing Company and Jerry M. Armstrong, dated April 25, 2006.

10.2 Indemnification Agreement by and between Pogo Producing Company and Robert H. Campbell, dated April 25, 2006.

10.3 Indemnification Agreement by and between Pogo Producing Company and William L. Fisher, dated April 25, 2006.

10.4 Indemnification Agreement by and between Pogo Producing Company and Thomas A. Fry, III, dated April 25, 2006.

10.5 Indemnification Agreement by and between Pogo Producing Company and Gerrit W. Gong, dated April 25, 2006.

10.6 Indemnification Agreement by and between Pogo Producing Company and Charles G. Groat, dated April 25, 2006.

10.7 Indemnification Agreement by and between Pogo Producing Company and Carroll W. Suggs, dated April 25, 2006.

10.8 Indemnification Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated April 25, 2006.

10.9 Indemnification Agreement by and between Pogo Producing Company and Stephen A. Wells, dated April 25, 2006.

12.1 Statement showing computation of ratios of earnings to fixed charges.

31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer.

32.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer.

* Asterisk indicates an exhibit incorporated by reference as shown.

Signatures

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 thereunto duly authorized.

	Pogo Producing Company
		(Registrant)


		/s/ Thomas E. Hart
		Thomas E. Hart
		Vice President and Chief
		Accounting Officer


		/s/ James P. Ulm, II
		James P. Ulm, II
		Senior Vice President and Chief
		Financial Officer


Date: April 28, 2006