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 September 30, 2005 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 Incorporation or Organization)		(I.R.S. Employer 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 an accelerated filer (as defined in Exchange Act Rule 12b-2): Yes ý No 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

Registrant’s number of common shares outstanding as of October 31, 2005: 59,908,047

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(Expressed in thousands,
	except per share amounts)
Revenues:
Oil and gas	$	275,359		$	259,590		$	803,465		$	744,720
Other	7,816			121			21,426			821
Total	283,175			259,711			824,891			745,541

Operating Costs and Expenses:
Lease operating	31,345			24,536			93,530			70,869
General and administrative	23,173			17,866			60,218			47,709
Exploration	7,566			4,097			22,064			17,387
Dry hole and impairment	5,254			14,177			59,111			21,600
Depreciation, depletion and amortization	67,498			65,183			205,879			194,392
Production and other taxes	13,806			13,847			39,172			31,606
Transportation and other	5,506			5,123			15,754			14,765
Total	154,148			144,829			495,728			398,328

Operating Income	129,027			114,882			329,163			347,213
Interest:
Charges	(16,831		)	(6,044		)	(40,892		)	(22,115		)
Income	5,507			108			7,693			312
Capitalized	2,525			3,441			7,435			11,457
Commodity derivative expense	(18,739		)	—			(18,739		)	—
Loss on debt extinguishment	—			—			—			(10,893		)
Foreign Currency Transaction Gain (Loss)	(1		)	—			1			(3		)

Income From Continuing Operations Before Taxes	101,488			112,387			284,661			325,971
Income Tax Expense	(39,585		)	(43,383		)	(109,271		)	(123,186		)

Income From Continuing Operations	61,903			69,004			175,390			202,785
Income from Discontinued Operations, net of tax	411,625			17,608			460,813			20,656
Net Income	$	473,528		$	86,612		$	636,203		$	223,441

Earnings per Common Share:
Basic
Income from continuing operations	$	1.04		$	1.08		$	2.87		$	3.18
Income from discontinued operations, net of tax	6.92			0.28			7.53			0.32
Net income	$	7.96		$	1.36		$	10.40		$	3.50

Diluted
Income from continuing operations	$	1.03		$	1.07		$	2.84		$	3.15
Income from discontinued operations, net of tax	6.86			0.28			7.47			0.32
Net income	$	7.89		$	1.35		$	10.31		$	3.47

Dividends per Common Share	$	0.0625		$	0.05		$	0.1875		$	0.15

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
	2005			2004
	(Expressed in thousands,
	except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	58,025		$	86,456
Accounts receivable	145,502			120,466
Other receivables	20,129			20,875
Federal income tax receivable	3,004			10,708
Deferred tax asset	22,387			—
Inventories - product	6,492			—
Inventories - tubulars	19,840			9,112
Price hedge contracts	—			6,722
Assets from discontinued operations	—			187,084
Other	6,148			3,987
Total current assets	281,527			445,410

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	5,962,592			4,003,332
Unevaluated properties	847,395			76,890
Other, at cost	39,287			28,656
	6,849,274			4,108,878
Accumulated depreciation, depletion and amortization
Oil and gas	(1,752,618		)	(1,551,502		)
Other	(22,625		)	(19,194		)
	(1,775,243		)	(1,570,696		)
Property and equipment, net	5,074,031			2,538,182

Other Assets:
Assets from discontinued operations	—			480,097
Other	34,657			17,420
	34,657			497,517

	$	5,390,215		$	3,481,109

See accompanying notes to consolidated financial statements.

	September 30,			December 31,
	2005			2004
	(Expressed in thousands,
	except share amounts)
Liabilities and Shareholders’ Equity

Current Liabilities:
Accounts payable - operating activities	$	130,246		$	62,156
Accounts payable - investing activities	113,238			86,582
Income taxes payable	11,059			131
Accrued interest payable	10,421			4,550
Accrued payroll and related benefits	3,814			3,566
Price hedge contracts	97,817			—
Deferred income tax	—			4,919
Liabilities from discontinued operations	—			109,928
Other	13,307			8,187
Total current liabilities	379,902			280,019

Long-Term Debt	1,538,402			755,000

Deferred Income Tax	1,211,474			536,823

Price Hedge Contracts	47,943			2,119

Asset Retirement Obligation	110,780			74,046

Other Liabilities and Deferred Credits	35,200			19,248

Liabilities from Discontinued Operations	—			85,959
Total liabilities	3,323,701			1,753,214

Commitments and Contingencies	—			—

Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized	—			—
Common stock, $1 par; 200,000,000 shares authorized, 65,266,406 and 64,580,639 shares issued, respectively	65,266			64,581
Additional capital	978,467			943,690
Retained earnings	1,353,380			728,723
Deferred compensation	(19,211		)	(9,954		)
Accumulated other comprehensive income (loss)	(56,239		)	2,565
Treasury stock (5,365,359 and 55,359 shares, respectively), at cost	(255,149		)	(1,710		)
Total shareholders’ equity	2,066,514			1,727,895

	$	5,390,215		$	3,481,109

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30,
	2005			2004
	(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers	$	887,850		$	763,834
Operating, exploration, and general and administrative expenses paid	(222,355		)	(171,218		)
Interest paid	(33,924		)	(22,935		)
Income taxes paid	(134,803		)	(117,178		)
Other	10,879			6,970
Cash provided by continuing operations	507,647			459,473
Cash provided by discontinued operations	144,736			113,376
Net cash provided by operating activities	652,383			572,849

Cash Flows from Investing Activities:
Capital expenditures	(276,418		)	(212,452		)
Purchase of corporations (net of $36,637 cash on hand) and properties	(1,761,026		)	(148,242		)
Sale of current investments	122,250			—
Purchase of current investments	(16,750		)	—
Proceeds from the sale of corporations (net of $51,529 cash on hand) and properties	777,746			1,305
Cash used in continuing operations	(1,154,198		)	(359,389		)
Cash used in discontinued operations	(57,816		)	(149,869		)
Net cash used in investing activities	(1,212,014		)	(509,258		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	3,310,000			945,000
Payments under senior debt agreements	(3,324,000		)	(883,000		)
Proceeds from 2015 and 2017 Notes	797,303			—
Purchase of Company stock	(235,664		)	—
Redemption of 2009 Notes	—			(157,782		)
Payments of cash dividends on common stock	(11,546		)	(9,581		)
Payments from (to) discontinued operations	137,982			(28,905		)
Payment of debt issue costs	(13,688		)	—
Proceeds from exercise of stock options	10,701			8,623
Cash provided by (used in) continuing operations	671,088			(125,645		)
Cash provided by (used in) discontinued operations	(139,630		)	28,905
Net cash provided by (used in) financing activities	531,458			(96,740		)
Effect of exchange rate changes on cash	(258		)	2,282
Net decrease in cash and cash equivalents	(28,431		)	(30,867		)
Cash and cash equivalents from continuing operations, beginning of the year	33,488			55,759
Cash and cash equivalents from discontinued operations, beginning of the year	52,968			48,715
Cash and cash equivalents at the end of the period	$	58,025		$	73,607

Reconciliation of net income to net cash provided by operating activities:
Net income	$	636,203		$	223,441
Adjustments to reconcile net income to net cash provided by operating activities -
Income from discontinued operations, net of tax	(460,813		)	(20,656		)
(Gains) losses from the sales of properties	(227		)	73
Depreciation, depletion and amortization	205,879			194,392
Dry hole and impairment	59,111			21,600
Interest capitalized	(7,435		)	(11,457		)
Price hedge contracts	21,147			372
Other	6,998			17,635
Deferred income taxes	(11,521		)	8,963
Change in operating assets and liabilities	58,305			25,110
Net cash provided by continuing operating activities	507,647			459,473
Net cash provided by discontinued operating activities	144,736			113,376
Net cash provided by operating activities	$	652,383		$	572,849

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Equity (Unaudited)

	For the Nine Months Ended September 30,
	2005					2004
	Shareholders’					Shareholders’
	Equity					Equity
	Shares		Amount			Shares		Amount
	(Expressed in thousands, except share amounts)
Common Stock:
$1.00 par-200,000,000 shares authorized
Balance at beginning of year	64,580,639		$	64,581		63,813,283		$	63,813
Stock option activity and other	350,267		350			346,486		347
Shares issued as compensation	335,500		335			298,919		299
Issued at end of period	65,266,406		65,266			64,458,688		64,459

Additional Capital:
Balance at beginning of year			943,690					914,492
Stock option activity and other			16,345					12,335
Shares issued as compensation			18,432					12,184
Balance at end of period			978,467					939,011

Retained Earnings:
Balance at beginning of year			728,723					480,576
Net income			636,203					223,441
Dividends ($0.1875 and $0.15 per common share, respectively)			(11,546		)			(9,581		)
Balance at end of period			1,353,380					694,436

Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year			2,565					—
Cumulative foreign currency translation adjustment			23,308					—
Change in fair value of price hedge contracts			(96,975		)			(2,371		)
Reclassification adjustment for losses included in net income			14,863					241
Balance at end of period			(56,239		)			(2,130		)

Deferred Compensation
Balance at beginning of year			(9,954		)			(3,518		)
Activity during the period			(9,257		)			(7,104		)
Balance at end of period			(19,211		)			(10,622		)

Treasury Stock:
Balance at beginning of year	(55,359	)	(1,710		)	(55,359	)	(1,710		)
Activity during the period	(5,310,000	)	(253,439		)	—		—
Balance at end of period	(5,365,359	)	(255,149		)	(55,359	)	(1,710		)

Common Stock Outstanding, at the End of the Period	59,901,047					64,403,329

Total Shareholders’ Equity			$	2,066,514				$	1,683,444

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 Current Report on Form 8-K filed on August 25, 2005.

The Company’s results for all periods presented 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 activities only.

(2) ACQUISITIONS –

On September 27, 2005, the Company completed the acquisition of Northrock Resources Ltd. (“Northrock”), a Canadian company and an indirect wholly owned subsidiary of Unocal Corporation (“Unocal”), for approximately $1.7 billion. The Company purchased all of the outstanding shares of Northrock pursuant to a share purchase agreement that was entered into on July 8, 2005 with Unocal and certain of its affiliates. As of June 30, 2005, Northrock owned approximately 300,000 net producing acres, plus approximately 1.1 million net acres of undeveloped leasehold. Northrock’s exploitation and development 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 Northrock operations did not have a material effect on the Company’s results of operations in the third quarter of 2005 but will become a reporting segment of the Company in the fourth quarter of 2005. The following is a calculation and allocation of purchase price to the acquired assets and liabilities based on their relative fair values:

CALCULATION OF PURCHASE PRICE (IN THOUSANDS)
Cash paid, including transaction costs	$	1,734,036

Plus fair market value of liabilites assumed:
Other liabilites	103,837
Asset retirement obligation	38,810
Deferred income taxes	706,153
Total purchase price for assets acquired	$	2,582,836

ALLOCATION OF PURCHASE PRICE (IN THOUSANDS)
Proved oil and gas properties	$	1,724,377
Unproved oil and gas properties	734,361
Other assets	124,098
Total	$	2,582,836

The purchase price allocation noted above is subject to change based on the Company’s final analysis of the oil and gas properties it has acquired.

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 and nine months ended September 30, 2005 and 2004 for the Company’s continuing operations as if the acquisitions of Northrock and the corporations had each

occurred as of January 1, 2004. The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results of Northrock and the corporations, 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 effect of these adjustments. The unaudited pro forma information (presented in thousands 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:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Revenues	$	392,024	$	363,202	$	1,124,852	$	1,040,082
Income from continuing operations	87,863		77,498		214,868		217,555
Earnings per share:
Basic -	$	1.48	$	1.21	$	3.51	$	3.41
Diluted -	$	1.46	$	1.20	$	3.48	$	3.38

(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 they have received appropriate approvals by the Company’s management or Board of Directors and when they meet other criteria. As of September 30, 2005, the Company had 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 financial results and financial position data of the discontinued operations were as follows (amounts expressed in 000’s):

Operating Results Data

	Three months ended							Nine months ended
	September 30,							September 30,
	2005				2004			2005			2004
Revenues	$		38,308		$	104,486		$	252,840		$	253,431
Costs and expenses	(14,124			)	(64,340		)	(126,496		)	(176,308		)
Other income	831				766			4,962			2,612
Income before income taxes	25,015				40,912			131,306			79,735
Income taxes	(16,159			)	(23,304		)	(78,456		)	(59,079		)
Income before gain from discontinued operations, net of tax	8,856				17,608			52,850			20,656
Gain on sale, net of tax of $9,736	402,769				—			407,963			—
Income from discontinued operations, net of tax	$	411,625			$	17,608		$	460,813		$	20,656

Financial Position Data

	December 31,
	2004
Assets of Discontinued Operations
Current investments	$	135,000
Accounts receivable	36,876
Inventories	13,800
Other current assets	1,408
Total current assets	187,084
Property, plant and equipments, net	471,012
Other long-term assets	9,085
Total assets	$	667,181

Liabilities of Discontinued Operations
Accounts payable	$	51,565
Income taxes payable	34,645
Other current liabilities	23,718
Total current liabilities	109,928
Deferred income tax	64,865
Asset retirement obligation	21,094
Total liabilities	$	195,887

(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 thousands, except per share amounts.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004

Income (numerator):
Income from continuing operations	$	61,903	$	69,004	$	175,390	$	202,785
Income from discontinued operations, net of tax	411,625		17,608		460,813		20,656

Net Income - basic and diluted	$	473,528	$	86,612	$	636,203	$	223,441

Weighted average shares (denominator):
Weighted average shares - basic	59,512		63,846		61,176		63,780
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	521		488		550		543

Weighted average shares - diluted	60,033		64,334		61,726		64,323

Earnings per share:
Basic:
Income from continuing operations	$	1.04	$	1.08	$	2.87	$	3.18
Income from discontinued operations	6.92		0.28		7.53		0.32
Basic earnings per share	$	7.96	$	1.36	$	10.40	$	3.50

Diluted:
Income from continuing operations	$	1.03	$	1.07	$	2.84	$	3.15
Income from discontinued operations	6.86		0.28		7.47		0.32
Diluted earnings per share	$	7.89	$	1.35	$	10.31	$	3.47

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	—		30		—		30
Average price	$	—	$	48.50	$	—	$	48.50

(5) LONG-TERM DEBT –

Long-term debt at September 30, 2005 and December 31, 2004, consists of the following (dollars expressed in thousands):

	September 30,			December 31,
	2005			2004
Senior debt -
Bank revolving credit agreement:
LIBOR based loans, borrowings at September 30, 2005 and December 31, 2004 at interest rates of 5.389% and 3.665%, respectively	$	501,000		$	515,000
LIBOR Rate Advances, borrowings at September 30, 2005 and December 31, 2004 at interest rates of 4.8541% and 3.5275%, respectively	40,000			40,000
Total senior debt	541,000			555,000
Subordinated debt -
8 1/4% Senior subordinated notes, due 2011	200,000			200,000
6 5/8% Senior subordinated notes, due 2015	300,000			—
6 7/8% Senior subordinated notes, due 2017	500,000			—
Total subordinated debt	1,000,000			200,000
Unamortized discount on 2015 Notes	(2,598		)	—
Total debt	1,538,402			755,000
Amount due within one year	—			—
Long-term debt	$	1,538,402		$	755,000

On September 23, 2005, the Company issued $500,000,000 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 7/8%, 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 bank revolving credit agreement 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 103.438% of their principal value 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 $300,000,000 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 5/8%, 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 bank revolving credit agreement 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 value 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 assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

(6) INCOME TAXES –

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 U.S. Treasury department recently released guidance interpreting numerous limitations under the Act and the Company completed its analysis and elected to adopt 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 September 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 has recorded an additional U.S. tax liability of $14.3 million as of September 30, 2005.

No deferred U.S. income tax liability has been recognized on the remaining 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 nine-month period ended September 30, 2005 is as follows (in thousands):

	2005
ARO as of January 1,	$	74,046
Liabilities incurred during the nine months ended September 30,	42,011		(a)
Liabilities settled during the nine months ended September 30,	(5,737		)
Accretion expense	4,129
Balance of ARO as of September 30,	$	114,449
Less: current portion of ARO	(3,669		)
Long-term ARO as of September 30,	$	110,780

(a) Includes $38,810 related to the Northrock acquisition.

For the three months ended September 30, 2005 and 2004 the Company recognized depreciation expense related to its Asset Retirement Cost (“ARC”) of $660,000 and $698,000, respectively. For the nine months ended September30, 2005 and 2004 the Company recognized depreciation expense related to its ARC of $2,570,000 and $2,823,000, respectively.

(8) COMMODITY DERIVATIVES AND HEDGING ACTIVITIES -

As of September 30, 2005, the Company held various derivative instruments. During 2004 and 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 both the three-month and nine-month periods ended September 30, 2005, the Company recognized $3,143,000 of losses related to settled contracts in its oil and gas revenues from its price hedge contracts. The Company also recognized pre-tax losses of $531,000 and $1,524,000 due to ineffectiveness on these hedge contracts during the third quarter and first nine months of 2005, respectively. During the three-month and nine-month periods ended September 30, 2004, the Company did not recognize any gains or losses from the settlement of price hedge contracts. However, the Company recognized a pre-tax loss of $372,000 due to ineffectiveness on its hedge contracts during the third quarter and first nine months of 2004. Unrealized losses on derivative instruments of $79,547,000, net of deferred taxes of $45,724,000, have been reflected as a component of other comprehensive income at September 30, 2005. Based on the fair market value of the hedge contracts as of September 30, 2005, the Company would reclassify additional pre-tax losses of approximately $78,394,000 (approximately $49,780,000 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 September 30, 2005 are as follows:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)

Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
November 2005 - December 2005	615	$	5.50	$	8.00	$	(3,861,000	)
November 2005 - December 2008	610	$	6.00	$	9.25	$	(3,014,000	)
October 2005 - December 2005	460	$	6.00	$	10.25	$	(1,650,000	)
October 2005 - December 2005	920	$	6.00	$	10.30	$	(3,260,000	)
January 2006 - December 2006	5,475	$	5.00	$	7.50	$	(23,136,000	)
January 2006 - December 2006	1,825	$	5.50	$	8.25	$	(6,139,000	)
January 2006 - December 2006	3,650	$	5.75	$	8.27	$	(13,173,000	)
January 2006 - December 2006	10,950	$	6.00	$	13.50	$	(11,724,000	)
January 2006 - December 2006	1,825	$	6.00	$	13.55	$	(1,930,000	)
January 2006 - December 2006	3,650	$	6.00	$	13.60	$	(3,812,000	)
January 2006 - December 2006	10,950	$	6.00	$	14.00	$	(10,354,000	)
January 2007 - December 2007	5,475	$	6.00	$	12.00	$	(3,956,000	)
January 2007 - December 2007	9,125	$	6.00	$	12.15	$	(6,307,000	)
January 2007 - December 2007	3,650	$	6.00	$	12.20	$	(2,485,000	)
January 2007 - December 2007	9,125	$	6.00	$	12.50	$	(5,677,000	)

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2005 - December 2005	567,500	$	40.00	$	62.50	$	(3,793,000	)
December 2005	15,500	$	43.50	$	72.00	$	(47,000	)
December 2005	62,000	$	43.50	$	72.50	$	(179,000	)
January 2006 - December 2006	1,460,000	$	50.00	$	78.00	$	(3,616,000	)
January 2006 - December 2006	365,000	$	50.00	$	79.00	$	(819,000	)
January 2006 - December 2006	1,460,000	$	50.00	$	81.00	$	(2,654,000	)
January 2006 - December 2006	365,000	$	50.00	$	81.04	$	(660,000	)
January 2006 - December 2006	1,825,000	$	50.00	$	82.00	$	(2,960,000	)
January 2007 - December 2007	1,460,000	$	50.00	$	75.00	$	(4,029,000	)
January 2007 - December 2007	365,000	$	50.00	$	75.25	$	(984,000	)
January 2007 - December 2007	3,650,000	$	50.00	$	77.50	$	(6,804,000	)

(a) MMBtu means million British Thermal Units.

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. As a result, in September 2005 the Company recorded as an expense $18,739,000 of losses previously deferred in accumulated other comprehensive income. The Company will now recognize 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 expense.”

As of September 30, 2005, the Company had the following collar contracts that no longer qualify for hedge accounting. The details are as follows:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)

Natural Gas Contracts (MMBtu)
Collar Contracts:
October 2005 - November 2005	765	$	5.50	$	8.00	$	(4,096,000	)
October 2005 - December 2005	460	$	6.00	$	9.30	$	(2,066,000	)
October 2005 - December 2005	770	$	6.00	$	9.25	$	(3,251,000	)
January 2006 - November 2006	1,825	$	5.50	$	8.25	$	(7,121,000	)

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2005 - November 2005	352,500	$	40.00	$	62.50	$	(1,968,000	)
October 2005 - November 2005	30,500	$	43.50	$	72.00	$	(50,000	)
October 2005 - November 2005	122,000	$	43.50	$	72.50	$	(185,000	)

(9) 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 nine months of 2005 and does not expect to make a contribution during the remainder of 2005.

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 thousands of dollars):

	Retirement Plan
	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2005				2004			2005			2004

Service cost	$		891		$	719		$	2,545		$	1,973
Interest cost	482				459			1,552			1,313
Expected return on plan assets	(634			)	(653		)	(1,944		)	(1,979		)
Amortization of prior service cost	21				10			65			34
Amortization of net loss	264				238			898			542
	$	1,024			$	773		$	3,116		$	1,883

	Post-Retirement Medical Plan
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005				2004		2005		2004

Service cost	$		181		$	351	$	1,029	$	1,039
Interest cost	146				241		778		783
Amortization of transition obligation	46				76		228		228
Amortization of net loss	(161			)	31		23		143
	$	212			$	699	$	2,058	$	2,193

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, 2004.

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. In May 2004, the FASB issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” (FSP No. 106-2), which addresses the accounting and disclosure requirements associated with the effects of the Act.

In 2004, the Company elected not to reflect changes in the Act in its financials since the Company concluded that the effects of the Act were not a significant event that called for remeasurement under SFAS 106. At this time the Company has not remeasured the effects of the Act.

(10) 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 (collectively, “Stock Awards”). 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.

The following table illustrates the effect on the Company’s net income and earnings per share if the fair value recognition provisions of SFAS 123 for employee stock-based compensation had been applied to all Stock Awards outstanding during the three-month and nine-month periods ended September 30, 2005 and 2004 (in thousands of dollars, except per share amounts):

			Three Months Ended						Nine Months Ended
			September 30 ,						September 30 ,
			2005			2004			2005			2004

Net income, as reported			$	473,528		$	86,612		$	636,203		$	223,441
Add:	Employee stock-based compensation expense, net of related tax effects, included in net income, as reported		1,541			855			3,564			1,979
Deduct:	Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects		(1,754		)	(1,665		)	(5,091		)	(4,975		)
Net income, pro forma			$	473,315		$	85,802		$	634,676		$	220,445

Earnings per share:
		Basic - as reported	$	7.96		$	1.36		$	10.40		$	3.50
		Basic - pro forma	$	7.95		$	1.34		$	10.37		$	3.46
		Diluted - as reported	$	7.89		$	1.35		$	10.31		$	3.47
		Diluted - pro forma	$	7.88		$	1.33		$	10.28		$	3.43

(11) COMPREHENSIVE INCOME –

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

	Three Months Ended						Nine Months Ended
	September 30 ,						September 30 ,
	2005			2004			2005			2004

Net income	$	473,528		$	86,612		$	636,203		$	223,441
Foreign currency translation adjustment, net of tax	23,308			—			23,308			—
Change in fair value of price hedge contracts, net of tax	(84,549		)	(2,371		)	(96,975		)	(2,371		)
Reclassification adjustment for hedge contract losses included in net income, net of tax	15,494			241			14,863			241
Comprehensive income	$	427,781		$	84,482		$	577,399		$	221,311

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 Current Report on Form 8-K filed on August 25, 2005. 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, 2004, 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

Acquisition of Northrock Resources

On September 27, 2005, the Company completed the acquisition of Northrock Resources Ltd., a Canadian company and an indirect wholly owned subsidiary of Unocal Corporation (“Unocal”), for approximately $1.7 billion. The purchase price of Northrock was funded using available cash on hand, the net proceeds from the Company’s offering of $500 million of senior subordinated notes and additional borrowings under the credit facility.

As of June 30, 2005, Northrock owned 604 Bcfe of estimated proven reserves on approximately 300,000 net acres, plus approximately 1.1 million net acres of undeveloped leasehold. Northrock’s exploitation and development activities are concentrated in Saskatchewan and Alberta with key exploration plays in Canada’s Northwest Territories, British Columbia and the Alberta Foothills. The purchase of Northrock is expected to have a significant impact on the Company’s future results of operations but, due to the transaction closing late in the 3^rd quarter of 2005, it did not materially affect the Company’s results of operations for the three and nine-month periods ended September 30, 2005.

Sale of Thailand

On August 17, 2005, the Company closed the sale to PTTEP Offshore Investment Company Limited and Mitsui Oil Exploration Co., Ltd. of its wholly owned subsidiary Thaipo Ltd. and its 46.34% interest in B8/32 Partners Ltd. for a purchase price of $820 million. The company recognized an after-tax gain from discontinued operations of approximately $403 million on the transaction.

Hurricanes Katrina and Rita Update

On August 29, 2005, after passing through the Gulf of Mexico, Hurricane Katrina made landfall near New Orleans, Louisiana and caused one of the worst natural disasters in U.S. history. On September 24, 2005, Hurricane Rita, one of the strongest measured hurricanes to have entered the Gulf of Mexico, made landfall between Sabine Pass, Texas and Johnson’s Bayou, Louisiana.

As of October 25, 2005, approximately 13,000 barrels of oil and 45 million cubic feet of natural gas of the Company’s net daily production is shut-in as a result of the storms. Based on inspections to date, only one Company-operated platform, located in Main Pass Block 123, appears to have sustained major damage. Significant damage to platforms and pipelines operated by others has also occurred, including facilities that are located in Viosca Knoll Block 823, Eugene Island Block 330, and South Marsh Island Block 128. Also, damage to processing plants and other onshore infrastructure owned and operated by others will likely delay some of the Company’s shut-in production from coming back “on-line.” The full extent of damage from the hurricanes to the Company’s facilities and to those owned by others is still not completely known.

The Company maintains business interruption insurance on some of its blocks in the Gulf of Mexico. Coverage commences 60 days after the blocks are shut-in and will continue for a period of one year unless the production is fully restored earlier. The daily indemnity amount the Company expects to be paid is approximately $800,000, which will be reduced as production is partially restored.

Derivatives Hedging Charge

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 the hurricane activity described above) caused certain of the gas and crude oil collar contracts to lose their qualification for hedge accounting. The Company recognized an $18.8 million non-cash charge related to these contracts in the third quarter of 2005.

Senior Subordinated Notes Issuance

On September 23, 2005, the Company issued and sold $500 million aggregate principal amount of 6.875% Senior Subordinated Notes due 2017 (the “2017 Notes”). The 2017 Notes were issued in a private placement pursuant to an Indenture, dated as of September 23, 2005, between the Company and The Bank of New York Trust Company, N.A., as trustee.

Share Repurchase

During the first quarter of 2005, the Company announced a share repurchase plan. The Company announced that it expected to expend not less than $275 million nor more than $375 million dollars to effect the repurchases. The repurchase could represent approximately 9% to 12% of the shares outstanding at December 31, 2004. As of October 27, 2005, 6.4 million shares of company stock have been repurchased for approximately $316 million.

Third Quarter Results

Total revenue for the third quarter of 2005 was $283 million and net income from continuing operations totaled $61.9 million, or $1.04 per share. Cash provided by continuing operations totaled $508 million. As of September 30, 2005, long-term debt was $1,541 million, increasing from the second quarter by $658 million due primarily to debt issued in connection with the Northrock acquisition.

Production Outlook Update

The Company currently expects its production volumes to average approximately 76,000 barrels of oil equivalent per day (“Boepd”) during the fourth quarter of 2005 and expects a 2005 exit rate of approximately 87,000 Boepd. In addition, the Company currently expects its production volumes to average approximately 100,000 Boepd during 2006. The Company’s updated guidance for the fourth quarter of 2005 and 2006 reflect the deferral of production from recent hurricane damage and is based on the assumption, among others, that approximately 10,000 Boepd of the Company’s Gulf of Mexico production will remain shut-in until late 2006. These estimates are subject to change, and actual results could differ materially, depending upon the amount of Gulf of Mexico production that remains shut-in, the timing of any such production coming back on-line, acquisitions, divestitures and many other factors that are beyond the Company’s control. Please read “Forward-Looking Statements” in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004.

2005 Capital Budget

The Company has established a $525 million exploration and development budget (excluding acquisitions). The Company expects to spend approximately $258 million on exploration and $267 million on development activities. The capital budget calls for the drilling of approximately 350 wells during 2005, including wells in the United States, Canada and the Kingdom of Thailand.

During the third quarter of 2005, the Company spent $119 million on its exploratory and development activities related to continuing operations and, as of September 30, 2005, had spent approximately 75% of its $525 million 2005 capital budget (including discontinued operations). During the third quarter of 2005, in the Company’s continuing operations, 43 wells were drilled with 42 successfully completed, a 98% success rate.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for the third quarter of 2005 were $275,359,000, an increase of approximately 6% from oil and gas revenues of $259,590,000 for the third quarter of 2004. The Company’s oil and gas revenues for the first nine months of 2005 were $803,465,000, an increase of approximately 8% from oil and gas revenues of $744,720,000 for the first nine months of 2004. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in thousands) between 2005 and 2004.

	3rd Qtr. 2005			1st 9 Mos. 2005
	Compared to			Compared to
	3rd Qtr. 2004			1st 9 Mos. 2004

Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	57,303		$	77,561
Production	(24,551		)	(1,945		)
	32,752			75,616
Crude oil and condensate -
Price	35,304			94,572
Production	(55,153		)	(116,210		)
	(19,849		)	(21,638		)

Natural gas liquids	2,866			4,767
Increase in oil and gas revenues	$	15,769		$	58,745

The increase in the Company’s oil and gas revenues in the third quarter and first nine months of 2005, compared to the third quarter and first nine months of 2004, is related to increases in the average prices that the Company received for its natural gas, crude oil and condensate, partially offset by a decrease in the Company’s hydrocarbon production volumes. The most significant causes for the reduction in hydrocarbon production were the shut-in of all of the Company’s offshore fields due to the infrastructure damage caused by Hurricanes Katrina and Rita in the third quarter of 2005, the shut-in of several of the Company’s offshore fields due to the infrastructure damage caused by Hurricane Ivan in mid-September of 2004 (the majority of fields that were shut-in as a result of Hurricane Ivan were brought back online late in the first quarter of 2005) and, to a lesser extent, natural production declines.

					% Change						% Change
Comparison of Increases in:	3rd Quarter				2005 to		1st Nine Months				2005 to
Natural Gas —	2005		2004		2004		2005		2004		2004
Average prices (a)	$	7.95	$	5.52	44	%	$	6.75	$	5.60	21	%

Average daily production volumes (MMcf per day) (a):	222.5		256.0		(13	)%	245.1		245.3		(0	)%

(a) Price hedging activity reduced the average price of the Company’s natural gas production during the third quarter and first nine months of 2005 by $0.07 per Mcf and $0.02 per Mcf, respectively. The Company had no price hedging activity during the third quarter or first nine months of 2004 related to 2004 production. “MMcf” is an abbreviation for million cubic feet.

% Change

% Change

Comparison of Increases (Decreases) in:

3rd Quarter

2005 to

1st Nine Months

2005 to

Crude Oil and Condensate —

2005

2004

2005

2004

Average prices (a)

58.11

44.85

48.60

37.96

Average daily production volumes (Bbls per day) (a):

18,630

28,951

(36

23,813

32,454

(27

Total Liquid Hydrocarbons —

Company-wide average daily production (Bbls per day)

22,831

32,671

(30

27,930

36,755

(24

(a) Price hedging activity reduced the average price of the Company’s crude oil and condensate production during the third quarter and first nine months of 2005 by $0.97 per barrel and $0.26 per barrel, respectively. The Company had no price hedging activity during the third quarter and first nine months of 2004 related to 2004 production. “Bbls” is an abbreviation for barrels.

Natural Gas Production

The decrease in the Company’s natural gas production during the third quarter of 2005, compared to the comparable 2004 period, was primarily related to shut-in offshore production caused by Hurricanes Katrina and Rita and natural production declines, partially offset by the addition of production from fields purchased by the Company subsequent to the third quarter of 2004. The decrease in the Company’s natural gas production during the first nine months of 2005, compared to the comparable 2004 period, was primarily related to shut-in offshore production caused by Hurricanes Ivan, Katrina and Rita and natural production declines, partially offset by the addition of production from fields purchased by the Company subsequent to the third quarter of 2004.

Crude Oil and Condensate Production

The decrease in the Company’s crude oil and condensate production during the third quarter 2005, compared to the third quarter of 2004, resulted primarily from shut-in offshore production caused by Hurricanes Katrina and Rita and natural production declines. The decrease in the Company’s crude oil and condensate production during the first nine months of 2005, compared to the first nine months of 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 and, to a lesser extent, natural production declines.

Other Revenues

Other revenue is derived from sources other than the current production of hydrocarbons. This revenue includes, among other items, insurance proceeds (excluding those related to operating expenses, which are credited against the appropriate expense category),

pipeline imbalance settlements and revenue from salt water disposal activities. The increase in the Company’s other revenues in the third quarter and first nine months of 2005, compared to the comparable 2004 periods, is related primarily to $7.4 million and $18.8 million of business interruption insurance recorded in the third quarter and first nine months of 2005, respectively, with no comparable insurance claims in 2004. The business interruption insurance claim relates to the shut-in of a significant portion of the Company’s Gulf of Mexico production during the fourth quarter of 2004 and first quarter of 2005 as a result of the infrastructure damage caused by Hurricane Ivan in 2004. The Company currently anticipates that it will have additional business interruption claims to file related to shut-in production resulting from Hurricanes Katrina and Rita, but is not currently in a position to quantify the magnitude of the potential claims.

Costs and Expenses

	3rd Quarter						% Change		1st Nine Months						% Change
Comparison of Increases (Decreases) in:	2005			2004			2005 to 2004		2005			2004			2005 to 2004

Lease Operating Expenses	$	31,345,000		$	24,536,000		28	%	$	93,530,000		$	70,869,000		32	%
General and Administrative Expenses	$	23,173,000		$	17,866,000		30	%	$	60,218,000		$	47,709,000		26	%
Exploration Expenses	$	7,566,000		$	4,097,000		85	%	$	22,064,000		$	17,387,000		27	%
Dry Hole and Impairment Expenses	$	5,254,000		$	14,177,000		(63	)%	$	59,111,000		$	21,600,000		174	%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	67,948,000		$	65,183,000		4	%	$	205,879,000		$	194,392,000		6	%
DD&A rate	$	2.05		$	1.57		31	%	$	1.83		$	1.52		20	%
Mcfe produced (a)	33,068,506			41,584,406			(20	)%	112,671,957			127,636,013			(12	)%
Production and Other Taxes	$	13,806,000		$	13,847,000		(0	)%	$	39,172,000		$	31,606,000		24	%
Transportation and Other	$	5,506,000		$	5,123,000		7	%	$	15,754,000		$	14,765,000		7	%
Interest—
Charges	$	(16,831,000	)	$	(6,044,000	)	178	%	$	(40,892,000	)	$	(22,115,000	)	85	%
Interest Income	$	5,507,000		$	108,000		N/M		$	7,693,000		$	312,000		N/M
Capitalized Interest	$	2,525,000		$	3,441,000		(27	)%	$	7,435,000		$	11,457,000		(35	)%
Commodity Derivative Expense	$	(18,739,000	)	$	—		N/M		$	(18,739,000	)	$	—		N/M
Income Tax Expense	$	(39,585,000	)	$	(43,383,000	)	(9	)%	$	(109,271,000	)	$	(123,186,000	)	(11	)%

(a) “Mcfe” stands for thousands of cubic feet equivalent

Lease Operating Expenses

The increase in lease operating expenses for the third quarter of 2005, compared to the third quarter 2004, is related to increased expenses incurred related to onshore properties acquired by the Company after the third quarter of 2004, in addition to higher costs being charged by service companies in 2005. The increase in lease operating expenses for the first nine months of 2005, compared to the first nine months of 2004, is related primarily to increased maintenance expenses on several of the Company’s significant offshore properties due to damage from Hurricane Ivan (which were only partially offset by insurance recoveries), increased expenses incurred related to onshore properties acquired by the Company after the third quarter of 2004 and also to higher costs being charged by service companies in 2005. The Company currently expects lease operating expenses to increase in future periods with the addition of Northrock related expenses for an entire reporting period.

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.59 and $0.56 per Mcfe for the third quarter and first nine months of 2004, respectively, to $0.95 and $0.83 per Mcfe for the third quarter and first nine months of 2005, respectively. These increases in unit costs are related to the reduced hydrocarbon production described above, while costs on the Company’s offshore production platforms (such as crew costs, compressor rentals and helicopter and marine transportation) have not decreased proportionately as repair work is being performed.

General and Administrative Expenses

The increase in general and administrative expenses for the third quarter and first nine months of 2005, compared with the respective 2004 periods, is related primarily to increases in the size of the Company’s workforce due to acquisitions over the preceding year, increased benefit expenses and normal increases in compensation. The Company currently expects general and administrative expenses to increase in future periods with the addition of Northrock related expenses for an entire reporting period. On a per unit of production basis, the Company’s general and administrative expenses increased to $0.70 and $0.53 per Mcfe in the third quarter and first nine months of 2005, respectively, from $0.43 and $0.37 per Mcfe in the third quarter and first nine months of 2004, respectively. In addition to the overall increase in general and administrative expenses, unit costs increased due to the reductions in hydrocarbon production discussed above.

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 third quarter of 2005 resulted primarily from $6.1 million of seismic activity in the Company’s Gulf Coast division and delay rentals in the United States. The increase in the Company’s exploration expense for the first nine months of 2005 compared to the same period of 2004 is primarily related to approximately $9.4 million of exploration expenses in New Zealand incurred during the first nine months of 2005. No comparable exploration activities occurred in New Zealand during the third quarter or first nine months of 2004. Exploration expenses for the third quarter and first nine months of 2004 consisted of $4.0 million and $15.2 million, respectively, primarily from 3-D seismic activity in the Company’s Gulf of Mexico and Gulf Coast divisions 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 third quarter of 2005, compared to the third quarter of 2004, was primarily the result of approximately $8.9 million of exploratory dry hole costs incurred during the 2004 period compared to approximately $1.2 million incurred in the 2005 period. The increase in dry hole and impairment expense for the first nine months of 2005, compared to the first nine months of 2004, was primarily the result of costs incurred in the first quarter of 2005 related to unsuccessful domestic exploratory wells located primarily in the Gulf of Mexico, totaling approximately $52.3 million. 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 third quarter and first nine months of both 2005 and 2004, the Company recognized miscellaneous impairments on various non-producing prospects and leases.

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 creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico. 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 increase in the Company’s DD&A expenses for the third quarter and first nine months of 2005 compared to the respective 2004 period resulted from an increase in the Company’s composite DD&A rate, which was only partially offset by a decrease 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 third quarter and first nine months of 2005, compared to the respective 2004 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 Main Pass Block 61/62 which was 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 domestic onshore properties acquired over the last 12 months).

Production and Other Taxes

The increase in production and other taxes during the first nine months of 2005, compared to the respective 2004 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 onshore 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, ineffectiveness on hedge contracts, allowances for uncollectible accounts and various other operating expenses none of which represents more than 5% of this expense category in either the third quarter and first nine months of 2005 or the third quarter and first nine months of 2004. The increase in other expense for third quarter and first nine months of 2005, compared to the third quarter and first nine months of 2004, relates to approximately $0.5 million and $1.5 million of hedge ineffectiveness incurred in the third quarter and first nine months of 2005, respectively, compared to $0.4 million in each of the corresponding 2004 periods. This was partially offset by a reduction in the Company’s transportation expenses between the comparative periods. The Company incurred transportation expense of $3,314,000 and $9,150,000 in the third quarter and first nine months of 2005, respectively, and $3,402,000 and $9,515,000 in the third quarter and first nine months of 2004, respectively.

Interest

Interest Charges. The increase in the Company’s interest charges for the third quarter of 2005, compared to the third quarter of 2004, resulted from an increase in the average amount of the Company’s outstanding debt. For the first nine months of 2005, compared to the first nine months of 2004, the increase in the Company’s interest charges were the result of an increase in the average amount of the Company’s debt that was partially offset by a reduction in the Company’s weighted average interest rate. See “-Liquidity and Capital Resources” below.

Interest Income. The increase in the Company’s interest income for the third quarter and first nine months of 2005, compared to the comparable 2004 periods, resulted from an increase in the amount of cash and cash equivalents temporarily invested. The cash and cash equivalents invested during the 2005 periods increased primarily due to the sales proceeds from the sale of the Thailand Entities. These proceeds were subsequently used to fund a portion of the Northrock Resources purchase.

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 decrease in capitalized interest for the third quarter and first nine months of 2005, compared to the comparable 2004 period, resulted primarily from a decrease in the amount of oil and gas projects in progress subject to interest capitalization during the third quarter and first nine months of 2005 (approximately $177,000,000 and $174,000,000, respectively), compared to the third quarter and first nine months of 2004 (approximately $219,000,000 and $216,000,000, respectively).

Commodity Derivative Expense

Commodity derivative expense for the third quarter and first nine months of 2005 represents unrealized 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 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. As a result, in September of 2005 the Company recorded as an expense $18,739,000 of losses previously deferred in accumulated other comprehensive income. No such expense was incurred during the third quarter and first nine months of 2004, as all of the Company’s derivative contracts qualified for hedge accounting at that time. The forecasted hydrocarbon production used to identify those derivative contracts that qualify for hedge accounting is subject to change based on the condition of third party infrastructure including pipelines and onshore facilities and many other factors. If hydrocarbon production is deferred beyond the currently forecast schedule, additional contracts may lose their qualification for hedge accounting and further adjustments may be necessary.

Income Tax Expense

Changes in the Company’s income tax expense are a function of the Company’s consolidated effective tax rate and its pre-tax income. The decrease in the Company’s tax expense for the third quarter and first nine months of 2005, compared to the third quarter and first nine months of 2004, resulted from decreased pre-tax income during the 2005 periods. The Company’s consolidated effective tax rate was 39% and 38% for the third quarter and first nine months of 2005, respectively, and 39% and 38% for the third quarter and first nine months of 2004, respectively.

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 000’s):

Operating Results Data

	Three months ended							Nine months ended
	September 30,							September 30,
	2005				2004			2005			2004
Revenues	$		38,308		$	104,486		$	252,840		$	253,431
Costs and expenses	(14,124			)	(64,340		)	(126,496		)	(176,308		)
Other income	831				766			4,962			2,612
Income before income taxes	25,015				40,912			131,306			79,735
Income taxes	(16,159			)	(23,304		)	(78,456		)	(59,079		)
Income before gain from discontinued operations, net of tax	8,856				17,608			52,850			20,656
Gain on sale of , net of tax of $9,736	402,769				—			407,963			—
Income from discontinued operations, net of tax	$	411,625			$	17,608		$	460,813		$	20,656

No meaningful comparison of the three months ended September 30,2005 compared to the three months ended September 30, 2004 is practicable due to the sale of the Thailand Entities in August 2005. The decrease in costs and expenses for the first nine months of 2005 compared with the respective 2004 period is primarily related to $33 million of dry hole and impairment costs (incurred primarily in Hungary) during the first nine months of 2004, respectively, for which no comparable expenses were incurred in 2005. The Company recognized no tax benefit for the costs in Hungary, resulting in a high effective tax rate for the 2004 period.

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 nine months of 2005 was $652,383,000 compared to cash flow from operating activities of $572,849,000 in the first nine months of 2004. The increase is attributable primarily to higher oil and gas prices, partially offset by higher expenses and decreased production volumes discussed under “Results of Operations” above. Cash flow from operating activities during the first nine months of 2005 was more than adequate to fund $397,861,000 in cash expenditures ($340,045,000 for continuing operations and $57,816,000 for discontinued operations) for capital and exploration projects and property acquisitions, excluding the Northrock transaction. The Northrock transaction was funded using available cash on hand, proceeds from the sale of the company’s Thailand Entities, the net proceeds from the Company’s offering of the 2017 Notes and additional borrowings under the revolving credit facility. During the first nine months of 2005, the Company issued $300,000,000 principal amount of 2015 Notes and $500,000,000 principal amount 2017 Notes (see descriptions below) and repaid other debt obligations using cash of approximately $14,000,000 (net of borrowings). During the first nine months of 2005 the Company also paid for the repurchase of $235,664,000 of its common stock and paid $11,546,000 of common stock dividends. As of September 30, 2005, the Company had cash and cash equivalents of $58,025,000 and long-term debt obligations of $1,541,000,000 (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 September 27, 2005, the Company’s lenders redetermined the borrowing base under its Credit Agreement at $1,100,000,000. As of October 27, 2005, the Company had an outstanding balance of $583,000,000 under its Credit Agreement. As such, the available borrowing capacity under the Credit Agreement is currently $417,000,000.

Purchase of Northrock Resources Ltd.

On September 27, 2005, the Company completed the acquisition of Northrock Resources Ltd. (“Northrock”), a Canadian company and an indirect wholly owned subsidiary of Unocal Corporation, for approximately $1.7 billion. Pogo Canada, ULC, a Canadian company and wholly owned subsidiary of the Company, purchased all of the outstanding shares of Northrock pursuant to a share purchase agreement that was entered into on July 8, 2005 with Unocal and certain of its affiliates. As of June 30, 2005, Northrock owned 604 billion cubic feet of gas equivalent (Bcfe) of estimated proven reserves on approximately 300,000 net acres, plus approximately 1.1 million net acres of undeveloped leasehold. Northrock’s exploitation and development 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.

2017 Notes

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 bank revolving credit agreement 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 103.438% of their principal value 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.

2015 Notes

On March 29, 2005, the Company issued $300,000,000 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 ⁵/₈%, 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 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 value 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 assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

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 reborrow such amounts 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 as senior debt. The Promissory Note Agreements permit either party to terminate the letter agreements at any time upon three-business days notice. As of October 27, 2005, there was $40,000,000 outstanding under these agreements.

American Jobs Creation Act of 2004

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 Company currently expects the net effect of the phase in of this new deduction to result in a decrease in the effective tax rate for fiscal years 2005 and 2006 of approximately 1 to 2 percentage-points, based on current earnings levels.

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 U.S. Treasury department recently released guidance interpreting numerous limitations under the Act and the Company completed its analysis and elected to adopt 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 September 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 an additional U.S. tax liability of $14.3 million as of September 31, 2005.

Future Capital and Other Expenditure Requirements

The Company’s capital and exploration budget for 2005, 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 July 2005 to $525 million, of which approximately $393.6 million was incurred in the nine months ended September 30, 2005. The Company has included 350 gross wells in its 2005 capital and exploration budget (209 of which were drilled in the first nine months of 2005), including wells in the United States, Canada and the Kingdom of Thailand

The Company currently anticipates that 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. See “Purchase of Northrock Resources Ltd.” above.

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 October 27, 2005, the Company had completed the purchase of 6,420,000 shares at a total cost of $315.5 million.

The table in Item 2, Part II sets forth certain information with respect to repurchases of the Company’s equity securities during the three months ended September 30, 2005.

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 September 30, 2005, 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)

Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
November 2005 - December 2005	615	$	5.50	$	8.00	$	(3,861,000	)
November 2005 - December 2008	610	$	6.00	$	9.25	$	(3,014,000	)
October 2005 - December 2005	460	$	6.00	$	10.25	$	(1,650,000	)
October 2005 - December 2005	920	$	6.00	$	10.30	$	(3,260,000	)
January 2006 - December 2006	5,475	$	5.00	$	7.50	$	(23,136,000	)
January 2006 - December 2006	1,825	$	5.50	$	8.25	$	(6,139,000	)
January 2006 - December 2006	3,650	$	5.75	$	8.27	$	(13,173,000	)
January 2006 - December 2006	10,950	$	6.00	$	13.50	$	(11,724,000	)
January 2006 - December 2006	1,825	$	6.00	$	13.55	$	(1,930,000	)
January 2006 - December 2006	3,650	$	6.00	$	13.60	$	(3,812,000	)
January 2006 - December 2006	10,950	$	6.00	$	14.00	$	(10,354,000	)
January 2007 - December 2007	5,475	$	6.00	$	12.00	$	(3,956,000	)
January 2007 - December 2007	9,125	$	6.00	$	12.15	$	(6,307,000	)
January 2007 - December 2007	3,650	$	6.00	$	12.20	$	(2,485,000	)
January 2007 - December 2007	9,125	$	6.00	$	12.50	$	(5,677,000	)

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2005 - December 2005	567,500	$	40.00	$	62.50	$	(3,793,000	)
December 2005	15,500	$	43.50	$	72.00	$	(47,000	)
December 2005	62,000	$	43.50	$	72.50	$	(179,000	)
January 2006 - December 2006	1,460,000	$	50.00	$	78.00	$	(3,616,000	)
January 2006 - December 2006	365,000	$	50.00	$	79.00	$	(819,000	)
January 2006 - December 2006	1,460,000	$	50.00	$	81.00	$	(2,654,000	)
January 2006 - December 2006	365,000	$	50.00	$	81.04	$	(660,000	)
January 2006 - December 2006	1,825,000	$	50.00	$	82.00	$	(2,960,000	)
January 2007 - December 2007	1,460,000	$	50.00	$	75.00	$	(4,029,000	)
January 2007 - December 2007	365,000	$	50.00	$	75.25	$	(984,000	)
January 2007 - December 2007	3,650,000	$	50.00	$	77.50	$	(6,804,000	)

(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. The Company will now recognize 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 expense.”

As of September 30, 2005, the Company had the following collar contracts that no longer qualify for hedge accounting. The details are as follows:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)

Natural Gas Contracts (MMBtu)
Collar Contracts:
October 2005 - November 2005	765	$	5.50	$	8.00	$	(4,096,000	)
October 2005 - December 2005	460	$	6.00	$	9.30	$	(2,066,000	)
October 2005 - December 2005	770	$	6.00	$	9.25	$	(3,251,000	)
January 2006 - November 2006	1,825	$	5.50	$	8.25	$	(7,121,000	)

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2005 - November 2005	352,500	$	40.00	$	62.50	$	(1,968,000	)
October 2005 - November 2005	30,500	$	43.50	$	72.00	$	(50,000	)
October 2005 - November 2005	122,000	$	43.50	$	72.50	$	(185,000	)

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 October 27, 2005, 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 thousands) and related average interest rates by year of maturity for the Company’s debt obligations and their indicated fair market value at September 30, 2005:

	2005		2006		2007		2008		2009			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0	$	0	$	0	$	0	$	541,000		$	0		$	541,000		$	541,000
Average Interest Rate	—		—		—		—		5.35		%	—			5.35		%	—
Fixed Rate	$	0	$	0	$	0	$	0	$	0		$	1,000,000		$	1,000,000		$	1,023,250
Average Interest Rate	—		—		—		—		—			7.08		%	7.08		%	—

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 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth certain information with respect to repurchases of the Company’s equity securities during the three months ended September 30, 2005.

				Maximum Dollar Value
	Total Number	Average		of Shares that May
	of Shares	Price Paid		Yet Be Purchased
Period	Purchased (a)	per Share		Under the Plan

July 1-31 2005	257,100	$	54.37	$	139,336,025
August 1-31 2005	—	$	—	$	139,336,025
September 1-30 2005	300,000	$	59.21	$	121,560,605

Total	557,100

(a) All of these shares were purchased under the plan announced on January 25, 2005.

ITEM 6. Exhibits

*2.1		Share Purchase Agreement dated July 8, 2005 among Unocal Canada Limited, Unocal Canada Alberta Hub Limited, Unocal Corporation, Pogo Canada, ULC and Pogo Producing Company (a copy of any omitted schedule will be furnished supplementally to the Commission upon request)(Exhibit 10.1 of the Company’s Current Report on Form 8-K filed July 12, 2005, File No. 1-7792).
*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).
*4.1		Indenture dated as of September 23, 2005 between Pogo Producing Company and The Bank of New York Trust Company N.A. (Exhibit 4.1 of the Company’s Current Report on Form 8-K filed September 23, 2005, File No. 1-7792).
*4.2		Registration Rights Agreement dated as of September 23, 2005 among Pogo Producing Company and the initial purchasers named therein (Exhibit 4.2 of the Company’s Current Report on Form 8-K filed September 23, 2005, File No. 1-7792).
*4.3		First Amendment to Credit Agreement dated as of August 31, 2005 but effective as of September 27, 2005, among Pogo Producing Company, the various financial institutions which are or may become parties to the Credit Agreement, as amended thereby (collectively, the “Lenders”), Bank of Montreal, as administrative agent for the Lenders, Bank of America N.A., Toronto Dominion (Texas) LLC and BNP Paribas, as Co-Syndication Agents for the Lenders, Wachovia Bank, National Association, as Documentation Agent for the Lenders, and Citibank N.A., and Bank of Nova Scotia, as managing agents for the Lenders (Exhibit 4.3 of the Company’s Current Report on Form 8-K filed September 23, 2005, File No. 1-7792).
10.1		Purchase Agreement dated September 21, 2005, by and between Pogo Producing Company and Goldman, Sachs & Co. and the other initial purchasers named therein.
10.2		Commitment Letter dated July 5, 2005, by and between Pogo Producing Company and Goldman Sachs Credit Partners L.P.
*10.3		Form of Restricted Stock Award Agreement Under Incentive Plans (Exhibit 10.2 of the Company’s Current Report on Form 8-K filed August 1, 2005, File No. 1-7792).
10.4		Pogo Producing Company Retention Incentive Plan effective September 27, 2005.
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.
32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer.
32.3		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: November 2, 2005