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 June 30, 2005

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

Exchange Act of 1934

For the transition period from to

Commission file number 1-7792

POGO PRODUCING COMPANY

(Exact Name of Registrant as Specified in Its Charter)

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

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

(713) 297-5000
(Registrant’s Telephone Number, Including Area Code)

Not Applicable
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2): Yes ý No o

Registrant’s number of common shares outstanding as of July 28, 2005:

59,713,614

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(Expressed in thousands,
	except per share amounts)
Revenues:
Oil and gas	$	274,044		$	250,479		$	528,106		$	485,130
Other	520			218			13,610			700
Total	274,564			250,697			541,716			485,830

Operating Costs and Expenses:
Lease operating	33,464			22,864			62,185			46,333
General and administrative	18,320			14,674			37,045			29,843
Exploration	3,319			4,836			14,498			13,290
Dry hole and impairment	6,502			5,027			53,857			7,423
Depreciation, depletion and amortization	67,923			66,210			138,381			129,209
Production and other taxes	14,190			10,009			25,366			17,759
Transportation and other	4,409			4,760			10,248			9,642
Total	148,127			128,380			341,580			253,499

Operating Income	126,437			122,317			200,136			232,331
Interest:
Charges	(13,850		)	(6,627		)	(24,061		)	(16,071		)
Income	1,369			86			2,186			204
Capitalized	2,713			3,468			4,910			8,016
Loss on debt extinguishment	—			(10,893		)	—			(10,893		)
Foreign Currency Transaction Gain (Loss)	(8		)	(1		)	2			(3		)

Income From Continuing Operations Before Taxes	116,661			108,350			183,173			213,584
Income Tax Expense	(42,683		)	(41,270		)	(69,686		)	(79,803		)

Income From Continuing Operations	73,978			67,080			113,487			133,781
Income (Loss) from Discontinued Operations, net of tax	29,461			(1,891		)	49,188			3,048
Net Income	$	103,439		$	65,189		$	162,675		$	136,829

Earnings per Common Share:
Basic
Income from continuing operations	$	1.23		$	1.05		$	1.83		$	2.10
Income (loss) from discontinued operations, net of tax	0.48			(0.03		)	0.80			0.05
Net income	$	1.71		$	1.02		$	2.63		$	2.15

Diluted
Income from continuing operations	$	1.22		$	1.04		$	1.82		$	2.08
Income (loss) from discontinued operations, net of tax	0.48			(0.03		)	0.78			0.05
Net income	$	1.70		$	1.01		$	2.60		$	2.13

Dividends per Common Share	$	0.0625		$	0.05		$	0.125		$	0.10

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
	2005			2004
	(Expressed in thousands,
	except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	242,631		$	86,456
Accounts receivable	115,120			120,466
Other receivables	17,301			20,875
Federal income tax receivable	3,164			10,708
Inventories - tubulars	14,521			9,112
Price hedge contracts	—			6,722
Assets from discontinued operations	89,238			187,084
Other	2,198			3,987
Total current assets	484,173			445,410

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	4,117,637			4,003,332
Unevaluated properties	92,955			76,890
Other, at cost	33,496			28,656
	4,244,088			4,108,878
Accumulated depreciation, depletion and amortization
Oil and gas	(1,686,575		)	(1,551,502		)
Other	(21,412		)	(19,194		)
	(1,707,987		)	(1,570,696		)
Property and equipment, net	2,536,101			2,538,182

Other Assets:
Assets from discontinued operations	477,059			480,097
Other	17,904			17,420
	494,963			497,517

	$	3,515,237		$	3,481,109

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

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

Current Liabilities:
Accounts payable - operating activities	$	73,915		$	62,156
Accounts payable - investing activities	33,284			86,582
Income taxes payable	865			131
Accrued interest payable	9,387			4,550
Accrued payroll and related benefits	3,710			3,566
Price hedge contracts	11,503			—
Deferred income tax	839			4,919
Liabilities from discontinued operations	130,922			109,928
Other	9,816			8,187
Total current liabilities	274,241			280,019

Long-Term Debt	880,354			755,000

Deferred Income Tax	524,236			536,823

Price Hedge Contracts	4,975			2,119

Asset Retirement Obligation	71,457			74,046

Other Liabilities and Deferred Credits	20,891			19,248

Liabilities from discontinued operations	82,950			85,959
Total liabilities	1,859,104			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, 64,749,340 and 64,580,639 shares issued, respectively	64,749			64,581
Additional capital	950,483			943,690
Retained earnings	883,611			728,723
Deferred compensation	(8,833		)	(9,954		)
Accumulated other comprehensive income (loss)	(10,492		)	2,565
Treasury stock (4,808,259 and 55,359 shares, respectively), at cost	(223,385		)	(1,710		)
Total shareholders’ equity	1,656,133			1,727,895

	$	3,515,237		$	3,481,109

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
	2005			2004
	(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers	$	571,207		$	492,178
Operating, exploration, and general and administrative expenses paid	(151,942		)	(108,930		)
Interest paid	(18,550		)	(21,499		)
Income taxes paid	(72,083		)	(81,177		)
Other	3,820			3,485
Cash provided by continuing operations	332,452			284,057
Cash provided by discontinued operations	104,881			64,200
Net cash provided by operating activities	437,333			348,257

Cash Flows from Investing Activities:
Capital expenditures	(207,965		)	(124,855		)
Purchase of properties	(35,141		)	(42,996		)
Sale of current investments	122,250			—
Purchase of current investments	(16,750		)	—
Proceeds from the sale of properties and companies	7,837			269
Cash used in continuing operations	(129,769		)	(167,582		)
Cash used in discontinued operations	(48,103		)	(76,805		)
Net cash used in investing activities	(177,872		)	(244,387		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	1,165,000			550,000
Payments under senior debt agreements	(1,337,000		)	(494,000		)
Proceeds from 2015 Notes	297,303			—
Redemption of 2009 Notes	—			(157,782		)
Purchase of Company stock	(221,675		)	—
Payments of cash dividends on common stock	(7,787		)	(6,385		)
Payments from (to) discontinued operations	109,560			(20,782		)
Payment of debt issue costs	(3,205		)	—
Proceeds from exercise of stock options	4,264			3,260
Cash provided by (used in) continuing operations	6,460			(125,689		)
Cash provided by (used in) discontinued operations	(109,560		)	20,782
Net cash used in financing activities	(103,100		)	(104,907		)
Effect of exchange rate changes on cash	(186		)	378
Net (decrease) increase in cash and cash equivalents	156,175			(659		)
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	$	242,631		$	103,815

Reconciliation of net income to net cash provided by operating activities:
Net income	$	162,675		$	136,829
Adjustments to reconcile net income to net cash provided by operating activities - Income from discontinued operations, net of tax	(49,188		)	(3,048		)
Gains from the sales of properties	(250		)	(268		)
Depreciation, depletion and amortization	138,381			129,209
Dry hole and impairment	53,857			7,423
Interest capitalized	(4,910		)	(8,016		)
Price hedge contracts	993			—
Other	5,831			14,858
Deferred income taxes	(9,057		)	4,898
Change in operating assets and liabilities	34,120			2,172
Net cash provided by continuing operating activities	332,452			284,057
Net cash provided by discontinued operating activities	104,881			64,200
Net cash provided by operating activities	$	437,333		$	348,257

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Equity (Unaudited)

	For the Six Months Ended June 30,
	2005								2004
	Shareholders’								Shareholders’
	Equity					Comprehensive			Equity					Comprehensive
	Shares		Amount			Income			Shares		Amount			Income
	(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	162,801		162						150,102		150
Shares issued as compensation	5,900		6						—		—
Issued at end of period	64,749,340		64,749						63,963,385		63,963

Additional Capital:
Balance at beginning of year			943,690								914,492
Stock option activity and other			5,802								5,543
Shares issued as compensation			991								—
Balance at end of period			950,483								920,035

Retained Earnings:
Balance at beginning of year			728,723								480,576
Net income			162,675			$	162,675				136,829			$	136,829
Dividends ($0.0625 and $0.05 per common share, respectively)			(7,787		)						(6,385		)
Balance at end of period			883,611								611,020

Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year			2,565								—
Change in fair value of price hedge contracts			(12,064		)	(12,064		)			—			—
Reclassification adjustment for losses (gains) included in net income			(993		)	(993		)			—			—
Balance at end of period			(10,492		)						—

Deferred Compensation
Balance at beginning of year			(9,954		)						(3,518		)
Activity during the period			1,121								322
Balance at end of period			(8,833		)						(3,196		)

Comprehensive Income (Loss)						$	149,618							$	136,829

Treasury Stock:
Balance at beginning of year	(55,359	)	(1,710		)				(55,359	)	(1,710		)
Activity during the period	(4,752,900	)	(221,675		)				—		—
Balance at end of period	(4,808,259	)	(223,385		)				(55,359	)	(1,710		)

Common Stock Outstanding, at the End of the Period	59,941,081								63,908,026

Total Shareholders’ Equity			$	1,656,133							$	1,590,112

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. Certain prior year amounts have been reclassified related to the Company’s discontinued operations. Such reclassifications had no effect on the Company’s net income or shareholders’ equity. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

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) 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 June 30, 2005, the Company had completed, or was in the process of completing, the sale of the assets discussed below.

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 $5.2 million on the sale of Pogo Hungary.

Thaipo Ltd. and B8/32 Partners Ltd.—

On June 17, 2005, the Company entered into a stock purchase agreement providing for 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 expects to complete the sale of the Thailand Entities during the third quarter of 2005.

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						Six months ended
	June 30,						June 30,
	2005			2004			2005			2004
Revenues	$	112,894		$	76,196		$	214,532		$	148,945
Costs and expenses	(57,421		)	(62,884		)	(112,372		)	(111,968		)
Other income	3,569			1,554			4,131			1,846
Income before income taxes	59,042			14,866			106,291			38,823
Income taxes	(34,775		)	(16,757		)	(62,297		)	(35,775		)
Income (loss) before gain from discontinued operations, net of tax	24,267			(1,891		)	43,994			3,048
Gain on sale of Pogo Hungary, net of tax	5,194			—			5,194			—
Income (loss) from discontinued operations, net of tax	$	29,461		$	(1,891	)	$	49,188		$	3,048

Financial Position Data

	June 30,		December 31,
	2005		2004
Assets of Discontinued Operations
Current investments	$	—	$	135,000
Accounts receivable	75,691		36,876
Inventories	13,156		13,800
Other current assets	391		1,408
Total current assets	89,238		187,084
Property, plant and equipments, net	472,650		471,012
Other long-term assets	4,409		9,085
Total assets	$	566,297	$	667,181

Liabilities of Discontinued Operations
Accounts payable	$	48,773	$	51,565
Income taxes payable	59,957		34,645
Other current liabilities	22,192		23,718
Total current liabilities	130,922		109,928
Deferred income tax	58,265		64,865
Asset retirement obligation	24,685		21,094
Total liabilities	$	213,872	$	195,887

(3) 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					Six Months Ended
	June 30,					June 30,
	2005		2004			2005		2004

Income (numerator):
Income from continuing operations	$	73,978	$	67,080		$	113,487	$	133,781
Income (loss) from discontinued operations, net of tax	29,461		(1,891		)	49,188		3,048

Net Income - basic and diluted	$	103,439	$	65,189		$	162,675	$	136,829

Weighted average shares (denominator):
Weighted average shares - basic	60,342		63,738			61,925		63,703
Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period	567		595			564		570

Weighted average shares - diluted	60,909		64,333			62,489		64,273

Earnings per share:
Basic:
Income from continuing operations	$	1.23	$	1.05		$	1.83	$	2.10
Income (loss) from discontinued operations	0.48		(0.03		)	0.80		0.05
Basic earnings per share	$	1.71	$	1.02		$	2.63	$	2.15

Diluted:
Income from continuing operations	$	1.22	$	1.04		$	1.82	$	2.08
Income (loss) from discontinued operations	0.48		(0.03		)	0.78		0.05
Diluted earnings per share	$	1.70	$	1.01		$	2.60	$	2.13

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	25		25			25		25
Average price	$	49.02	$	49.02		$	49.02	$	49.02

(4) LONG-TERM DEBT –

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

	June 30,			December 31,
	2005			2004
Senior debt -
Bank revolving credit agreement:
LIBOR based loans, borrowings at June 30, 2005 and December 31, 2004 at interest rates of 4.273% and 3.665%, respectively	$	343,000		$	515,000
LIBOR Rate Advances, borrowings at June 30, 2005 and December 31, 2004 at interest rates of 4.335% and 3.5275%, respectively	40,000			40,000
Total senior debt	383,000			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			—
Total subordinated debt	500,000			200,000
Unamortized discount on 2015 Notes	(2,646		)	—
Total debt	880,354			755,000
Amount due within one year	—			—
Long-term debt	$	880,354		$	755,000

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 currently 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.

(5) INCOME TAXES –

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”). The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, as of July 28, 2005, uncertainty remains as to how to interpret numerous provisions of the Act. As a result, the Company is not yet in a position to decide whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S. from its foreign subsidiaries. If certain technical corrections to the Act are passed, the Company may consider repatriating an amount up to $214.8 million of the cash and cash equivalents held by international subsidiaries as of June 30, 2005, with an associated tax liability of approximately $8.1 million (assuming 15% of such cash is subject to tax at the U.S. statutory rate).

(6) 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 six-month period ended June 30, 2005 is as follows (in thousands):

	2005
ARO as of January 1,	$	74,046
Liabilities incurred during the six months ended June 30,	3,058
Liabilities settled during the six months ended June 30,	(4,633		)
Accretion expense	2,588
Balance of ARO as of June 30,	$	75,059
Less: current portion of ARO	(3,602		)
Long-term ARO as of June 30,	$	71,457

For the three months ended June 30, 2005 and 2004 the Company recognized depreciation expense related to its ARC of $969,000 and $1,361,000, respectively. For the six months ended June 30, 2005 and 2004 the Company recognized depreciation expense related to its ARC of $1,910,000 and $2,125,000, respectively.

(7) HEDGING ACTIVITIES -

As of June 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 the three-month and six-month periods ended June 30, 2005, the Company recognized no impact to its oil and gas revenues from its price hedge contracts. The Company did recognize a pre-tax loss of $993,000 due to ineffectiveness on these hedge contracts during the first six months of 2005. During the three-month and six-month periods ended June 30, 2004, the Company had no price hedging activity. Unrealized losses on derivative instruments of $10,492,000, net of deferred taxes of $5,650,000, have been reflected as a component of other comprehensive income for the six months ended June 30, 2005. Based on the fair market value of the hedge contracts as of June 30, 2005, the Company would reclassify additional pre-tax losses of approximately $11,179,000 (approximately $7,098,000 after taxes) from accumulated other comprehensive loss (shareholders’ equity) to net income during the next twelve months.

The gas hedging transactions 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 hedging 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 June 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:
July 2005 - December 2005	2,760	$	5.50	$	8.00	$	(826,328	)
July 2005 - December 2005	920	$	6.00	$	9.30	$	(54,185	)
July 2005 - December 2005	920	$	6.00	$	9.25	$	(58,493	)
July 2005 - December 2005	1,840	$	6.00	$	9.25	$	(116,985	)
July 2005 - December 2005	920	$	6.00	$	10.25	$	4,495
July 2005 - December 2005	1,840	$	6.00	$	10.30	$	13,257
January 2006 - December 2006	5,475	$	5.00	$	7.50	$	(5,732,254	)
January 2006 - December 2006	3,650	$	5.50	$	8.25	$	(2,454,822	)
January 2006 - December 2006	3,650	$	5.75	$	8.27	$	(2,315,831	)

Crude Oil Contracts (Barrels)
Collar Contracts:
July 2005 - December 2005	1,840,000	$	40.00	$	62.50	$	(4,669,551	)
July 2005 - December 2005	92,000	$	43.50	$	72.00	$	(57,091	)
July 2005 - December 2005	368,000	$	43.50	$	72.50	$	(209,893	)

(a) MMBtu means million British Thermal Units.

In July 2005, the Company entered into additional natural gas and crude oil collars to establish floor and ceiling prices on anticipated future natural gas and crude oil production. The Company has designated these contracts as cash flow hedges. Further details related to these hedging activities are as follows:

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

Natural Gas Contracts (MMBtu)
Collar Contracts:
January 2006 - December 2006	10,950	$	6.00	$	13.50
January 2006 - December 2006	1,825	$	6.00	$	13.55
January 2006 - December 2006	3,650	$	6.00	$	13.60
January 2006 - December 2006	10,950	$	6.00	$	14.00
January 2007 - December 2007	5,475	$	6.00	$	12.00
January 2007 - December 2007	9,125	$	6.00	$	12.15
January 2007 - December 2007	3,650	$	6.00	$	12.20
January 2007 - December 2007	9,125	$	6.00	$	12.50

Crude Oil Contracts (Barrels)
Collar Contracts:
January 2006 - December 2006	1,460,000	$	50.00	$	78.00
January 2006 - December 2006	365,000	$	50.00	$	79.00
January 2006 - December 2006	1,460,000	$	50.00	$	81.00
January 2006 - December 2006	365,000	$	50.00	$	81.04
January 2006 - December 2006	1,825,000	$	50.00	$	82.00
January 2007 - December 2007	1,460,000	$	50.00	$	75.00
January 2007 - December 2007	365,000	$	50.00	$	75.25
January 2007 - December 2007	3,650,000	$	50.00	$	77.50

(8) 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 six 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						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004

Service cost	$	827		$	627		$	1,654		$	1,254
Interest cost	535			427			1,070			854
Expected return on plan assets	(655		)	(663		)	(1,310		)	(1,326		)
Amortization of prior service cost	22			12			44			24
Amortization of net loss	317			152			634			304
	$	1,046		$	555		$	2,092		$	1,110

	Post-Retirement Medical Plan
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004

Service cost	$	424	$	344	$	848	$	688
Interest cost	316		271		632		542
Amortization of transition obligation	76		76		152		152
Amortization of net loss	92		56		184		112
	$	908	$	747	$	1,816	$	1,494

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 for the effects of the Act.

(9) 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 Company granted Stock Awards covering

17,000 shares and 19,000 shares during the three and six month periods ended June 30, 2005, respectively. The Company granted Stock Awards covering 42,000 shares during the three and six month periods ended June 30, 2004.

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 six-month periods ended June 30, 2005 and 2004 (in thousands of dollars, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30 ,						June 30 ,
	2005			2004			2005			2004

Net income, as reported	$	103,439		$	65,189		$	162,675		$	136,829
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported	1,096			568			2,107			1,124
Deduct: Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects	(1,715		)	(1,696		)	(3,337		)	(3,439		)
Net income, pro forma	$	102,820		$	64,061		$	161,445		$	134,514

Earnings per share:
Basic - as reported	$	1.71		$	1.02		$	2.63		$	2.15
Basic - pro forma	$	1.70		$	1.01		$	2.61		$	2.11
Diluted - as reported	$	1.70		$	1.01		$	2.60		$	2.13
Diluted - pro forma	$	1.69		$	1.00		$	2.58		$	2.09

(10) ACQUISITIONS –

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 to be 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 corporations had an estimated 133 billion cubic feet of gas equivalent proven reserves (Bcfe) as of the dates of acquisition. 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. These acquisitions added approximately 119 Bcfe to the Company’s proved reserves.

Pro Forma Information

The following summary presents unaudited pro forma consolidated results of operations for the three and six months ended June 30, 2004 for the Company’s continuing operations as if the acquisition of the corporations had 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 the corporations, such as increased depreciation, depletion and amortization expense resulting from the allocation of fair value to oil and gas properties acquired and increased interest expense on acquisition debt. 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		Six Months
	Ended		Ended
	June 30, 2004		June 30, 2004
Revenues	$	266,131	$	516,699
Net income	69,591		138,803
Earnings per share:
Basic -	$	1.09	$	2.18
Diluted -	$	1.08	$	2.16

(11) SUBSEQUENT EVENT –

On July 11, 2005, the Company announced that it had entered into a definitive agreement to acquire all of the stock of Northrock Resources Ltd. (“Northrock”), a wholly owned Canadian subsidiary of Unocal Corporation, for $1.8 billion in cash, subject to adjustment under the terms of the agreement. Under the agreement, the Company would acquire 644 Bcfe of estimated proven reserves on approximately 300,000 net acres, plus approximately 1.1 million net acres of undeveloped leasehold. Northrock’s properties are located in the western provinces of Canada. The closing is expected to occur in the third quarter of 2005 and is subject to obtaining regulatory approvals.

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

This discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. 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

Purchase of Northrock Resources Ltd.

On July 11, 2005, the Company announced that it had entered into a definitive agreement to acquire all of the stock of Northrock Resources Ltd., a wholly owned Canadian subsidiary of Unocal Corporation, for $1.8 billion in cash. The acquisition is expected to add approximately 644 Bcfe (“Billion cubic feet equivalent”) of proven reserves and approximately 30,000 Boepd (“Barrels of oil equivalent per day”) of production.

The Company expects to use cash on hand and proceeds from its international asset sales of approximately $1 billion as the primary funding source and to finance the balance of the purchase through its revolving bank credit facility and through capital market transactions. The acquisition is expected to close late in the third quarter of 2005.

Thailand and Hungary Disposition

On June 7, 2005, the Company completed the sale of its wholly owned subsidiary Pogo Hungary, Ltd. for a purchase price of $9 million. The Company recognized a gain of $5.2 million on the sale of Pogo Hungary.

On June 17, 2005, the Company announced 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 preferential purchase rights held by the other owners of the Thailand concession expired without exercise on July 19, 2005. The Company expects to complete the sale of the Thailand entities during the third quarter of 2005 and currently expects to realize an after-tax gain from discontinued operations of approximately $400 million on the transaction.

Second Quarter Results

Total revenue for the second quarter of 2005 was $274.6 million and net income totaled $103.4 million, or $1.71 per share. Cash flow from operations totaled $173.7 million. As of June 30, 2005, long-term debt was $880 million, while cash and cash equivalents increased by $12 million during the second quarter to $243 million.

2005 Capital Budget

The Company has established a $525 million exploration and development budget (excluding property 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. The Company has resumed its discretionary development drilling program, which had been curtailed due to high drilling and service costs and the shortage of experienced and efficient crews. The Company now believes that drilling efficiencies have improved and acceptable profit margins have been restored.

During the second quarter of 2005, the Company spent $80.5 million on its exploratory and development activities related to continuing operations and, as of June 30, 2005, had spent approximately 50% of its 2005 capital budget. During the second quarter of 2005, in the Company’s continuing operations, 57 wells were drilled with 53 successfully completed, a 93% success rate.

Share Repurchase

During the first quarter of 2005, the Company announced a share repurchase plan. The Company expects to expend not less than $275 million nor more than $375 million to effect the repurchases. As of July 28, 2005, the Company had repurchased 5 million shares for approximately $236 million.

Production Outlook Update

The Company currently expects its production volumes, including the volumes added by the Northrock Resources acquisition, to average approximately 110,000 Boepd during 2006 or 6% higher than the Company’s anticipated yearend 2005 exit rate. In addition, the

Company currently expects its production volumes to average approximately 117,000 Boepd during 2007. These estimates are subject to change depending upon acquisitions, divestitures and many other factors.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for the second quarter of 2005 were $274,044,000, an increase of approximately 9% from oil and gas revenues of $250,479,000 for the second quarter of 2004. The Company’s oil and gas revenues for the first six months of 2005 were $528,106,000, an increase of approximately 9% from oil and gas revenues of $485,130,000 for the first six 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.

	2nd Qtr. 2005			1st 6 Mos. 2005
	Compared to			Compared to
	2nd Qtr. 2004			1st 6 Mos. 2004

Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	15,628		$	25,453
Production	3,098			17,411
	18,726			42,864
Crude oil and condensate -
Price	37,133			63,385
Production	(34,361		)	(65,174		)
	2,772			(1789		)

Natural gas liquids	2,067			1,901
Increase in oil and gas revenues	$	23,565		$	42,976

The increase in the Company’s oil and gas revenues in the second quarter and first six months of 2005, compared to the second quarter and first six months of 2004, is related to increases in the average prices that the Company received for its natural gas, crude oil and condensate and increases in natural gas production volumes, partially offset by a decrease in the Company’s crude oil and condensate production volumes. The most significant causes for the reduction in crude oil and condensate production was 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 and natural production declines. The majority of shut-in volumes were brought back online late in the first quarter of 2005.

					% Change						% Change
	2nd Quarter				2005 to		1st Six Months				2005 to
	2005		2004		2004		2005		2004		2004

Comparison of Increases in:
Natural Gas —
Average prices (a)	$	6.48	$	5.79	12	%	$	6.22	$	5.64	10	%

Average daily production volumes (MMcf per day) (a):	254.5		249.3		2	%	256.7		239.9		7	%

(a) Price hedging activity had no effect on the average price of the Company’s natural gas production during the second quarter or first six months of 2005. The Company had no price hedging activity during the second quarter or first six months of 2004. “MMcf” is an abbreviation for million cubic feet.

% Change

% Change

2nd Quarter

2005 to

1st Six Months

2005 to

2005

2004

2005

2004

Comparison of Increases (Decreases) in:

Crude Oil and Condensate —

Average prices (a)

46.62

34.76

45.19

35.01

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

26,303

34,403

(24

26,448

34,228

(23

Total Liquid Hydrocarbons —

Company-wide average daily production (Bbls per day)

30,450

39,079

(22

30,521

38,822

(21

(a) Price hedging activity had no effect on the average price of the Company’s crude oil and condensate production during the second quarter and first six months of 2005. The Company had no price hedging activity during the second quarter and first six months of 2004. “Bbls” is an abbreviation for barrels.

Natural Gas

Production. The increase in the Company’s natural gas production during the second quarter of 2005, compared to the comparable 2004 period, was primarily related to the addition of production from fields purchased by the Company subsequent to the second quarter of 2004. The Company also experienced increases in natural gas production volumes from the Company’s Eugene Island Block 280 in the Gulf of Mexico. These increases were partially offset by natural production declines. The increase in the Company’s natural gas production during the first six months of 2005, compared to the comparable 2004 period, was primarily related to the addition of production from fields purchased by the Company subsequent to June 2004. The Company also experienced increases in natural gas production volumes from the Los Mogotes field in South Texas and from the Company’s Main Pass Block 68 and Eugene Island Block 280 in the Gulf of Mexico. These increases were partially offset by decreased production due to the effects of Hurricane Ivan and, to a lesser extent, natural production declines.

Crude Oil and Condensate

Production. The decrease in the Company’s crude oil and condensate production during the second quarter 2005, compared to the second quarter of 2004, resulted primarily from natural production declines. The decrease in the Company’s crude oil and condensate production during the first six months of 2005, compared to the first six months of 2004, resulted primarily from the shut-in of Gulf of Mexico platforms due to the effects of Hurricane Ivan (including Main Pass Block 61/62) in the first quarter of 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 first six months of 2005, compared to the first six months of 2004, is related primarily to $11.4 million of business interruption insurance recorded in the first quarter of 2005 with no comparable insurance claim 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 first quarter of 2005 as a result of the infrastructure damage caused by Hurricane Ivan in 2004.

Costs and Expenses

	2nd Quarter						% Change		1st Six Months						% Change
	2005			2004			2005 to 2004		2005			2004			2005 to 2004
Comparison of Increases (Decreases) in:
Lease Operating Expenses	$	33,464,000		$	22,864,000		46	%	$	62,185,000		$	46,333,000		34	%
General and Administrative Expenses	$	18,320,000		$	14,674,000		25	%	$	37,045,000		$	29,843,000		24	%
Exploration Expenses	$	3,319,000		$	4,836,000		(31	)%	$	14,498,000		$	13,290,000		9	%
Dry Hole and Impairment Expenses	$	6,502,000		$	5,027,000		29	%	$	53,857,000		$	7,423,000		626	%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	67,923,000		$	66,210,000		3	%	$	138,381,000		$	129,209,000		7	%
DD&A rate	$	1.71		$	1.50		14	%	$	1.74		$	1.50		16	%
Mcfe produced (a)	39,785,000			44,020,000			(10	)%	79,603,000			86,052,000			(7	)%
Production and Other Taxes	$	14,190,000		$	10,009,000		42	%	$	25,366,000		$	17,759,000		43	%
Transportation and Other	$	4,409,000		$	4,760,000		(7	)%	$	10,248,000		$	9,642,000		6	%
Interest—
Charges	$	(13,850,000	)	$	(6,627,000	)	109	%	$	(24,061,000	)	$	(16,071,000	)	50	%
Capitalized Interest Expense	$	2,713,000		$	3,468,000		(22	)%	$	4,910,000		$	8,016,000		(39	)%
Income Tax Expense	$	(42,683,000	)	$	(41,270,000	)	3	%	$	(69,686,000	)	$	(79,803,000	)	(13	)%

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

Lease Operating Expenses

The increase in lease operating expenses for the second quarter of 2005, compared to the second quarter 2004, is related to increased expenses incurred on onshore properties acquired by the Company after the second quarter of 2004, in addition to higher costs being charged by service companies in 2005. The increase in lease operating expenses for the first six months of 2005, compared to the first six 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 in the third quarter of 2004 (which were only partially offset by insurance recoveries), increased expenses incurred on onshore properties acquired by the Company after the second quarter of 2004 and also to higher costs being charged by service companies in 2005.

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.52 and $0.54 per Mcfe for the second quarter and first six months of 2004, respectively, to $0.84 and $0.78 per Mcfe for the second quarter and first six months of 2005, respectively.

General and Administrative Expenses

The increase in general and administrative expenses for the second quarter and first six months of 2005 compared with the respective 2004 periods, is primarily related to increases in compensation and related benefit expense and to increased professional fees (due in part to compliance with Sarbanes-Oxley legislation). On a per unit of production basis, the Company’s general and administrative expenses increased to $0.46 and $0.47 per Mcfe in the second quarter and first six months of 2005, respectively, from $0.33 and $0.35 per Mcfe in the second quarter and first six months of 2004, respectively.

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 second quarter and first six months of 2005 resulted primarily from exploration activities in New Zealand, including the acquisition and processing of a of 3-D seismic survey over prospective acreage in the Company’s New Zealand concession and delay rentals in the United States. The Company incurred approximately $1.7 million and $9.2 million of exploration expenses in New Zealand during the second quarter and first six months of 2005, respectively. No comparable from exploration activities occurred in New Zealand during the second quarter and first six months of 2004. Exploration expenses for the second quarter and first six months of 2004 resulted 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 increase in dry hole and impairment expense for the second quarter and first six months of 2005, compared to the second quarter and first six months of 2004, was primarily the result of costs related to unsuccessful domestic exploratory wells located primarily in the Gulf of Mexico, totaling approximately $48.2 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 second quarter and first six 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 second quarter and first six 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 second quarter and first six 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 recently acquired).

Production and Other Taxes

The increase in production and other taxes during the second quarter and first six 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 and various other operating expenses none of which represents more than 5% of this expense category in either the second quarter and first six months of 2005 or the second quarter and first six months of 2004. The increase in other expense for first six months of 2005, compared to the first six months of 2004, relates primarily to approximately $1 million of hedge ineffectiveness incurred in 2005 with no comparable expense in 2004. This was partially offset by a reduction in the Company’s transportation expenses between the comparative periods. The Company incurred transportation expense of $2,950,000 and $5,836,000 in the second quarter and first six months of 2005 and $2,988,000 and $6,113,000 in the second quarter and first six months of 2004.

Interest

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

Capitalized Interest. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are substantially complete and ready for their intended use if projects are evaluated as successful. The decrease in capitalized interest for the second quarter and first six 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 second quarter and first six months of 2005 (approximately $176,000,000 and $173,000,000, respectively), compared to the second quarter and first six months of 2004 (approximately $215,000,000 in each period) in addition to a decrease in the weighted average interest rate on the Company’s outstanding borrowings. The interest rates on borrowings repaid during the prior year were above the rates of the borrowings currently remaining, resulting in a lower weighted average rate to be applied to the cost of oil and gas projects in progress.

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 increase in the Company’s tax expense for the second quarter of 2005, compared to the second quarter of 2004, resulted from increased pre-tax income during the 2005 period. The decrease in the Company’s tax expense for the first six months of 2005, compared to the first six months of 2004, resulted from decreased pre-tax income during the 2005 period. The Company’s consolidated effective tax rate was 37% and 38% for the second quarter and first six months of 2005 and 38% and 37% for the second quarter and first six months of 2004, respectively.

Discontinued Operations-

The Thailand Entities and Pogo Hungary 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						Six months ended
	June 30,						June 30,
	2005			2004			2005			2004
Revenues	$	112,894		$	76,196		$	214,532		$	148,945
Costs and expenses	(57,421		)	(62,884		)	(112,372		)	(111,968		)
Other income	3,569			1,554			4,131			1,846
Income before income taxes	59,042			14,866			106,291			38,823
Income taxes	(34,775		)	(16,757		)	(62,297		)	(35,775		)
Income (loss) before gain from discontinued operations, net of tax	24,267			(1,891		)	43,994			3,048
Gain on sale of Pogo Hungary, net of tax	5,194			—			5,194			—
Income (loss) from discontinued operations, net of tax	$	29,461		$	(1,891	)	$	49,188		$	3,048

The increase in income from discontinued operations for the second quarter and first six months of 2005 compared with the respective 2004 periods, is primarily related to $19.7 million and $29.0 million of dry hole and impairment costs (incurred primarily in Hungary) during the second quarter and first six 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 each of the 2004 periods.

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 six months of 2005 was $437,333,000 compared to cash flow from operating activities of $348,257,000 in the first six months of 2004. The increase is attributable primarily to higher oil and gas prices, partially offset by higher expenses (principally lease operating expenses and production and other taxes) discussed under “Results of Operations” above. Cash flow from operating activities during the first six months of 2005 was more than adequate to fund $291,209,000 in cash expenditures ($243,106,000 for continuing operations and $48,103,000 for discontinued operations) for capital and exploration projects and property acquisitions for the first six months of 2005. The Company also issued $300,000,000 principal amount of 2015 Notes (see description below) and repaid other debt obligations using cash of approximately $172,000,000 (net of borrowings). The Company also paid $7,787,000 of dividends on its common stock during the first six months of 2005. As of June 30, 2005, the Company had cash and cash equivalents of $242,631,000 (including $214,805,000 in international subsidiaries which the Company intends to reinvest in its foreign operations subject to its evaluation of the new tax provisions of the American Jobs Creation Act of 2004, discussed below) and long-term debt obligations of $883,000,000 (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 April 25, 2005, the Company’s lenders redetermined the borrowing base under its Credit Agreement at $1,000,000,000. As of July 28, 2005, the Company had an outstanding balance of $489,000,000 under its Credit Agreement. As such, the available borrowing capacity under the Credit Agreement is currently $261,000,000.

Purchase of Northrock Resources Ltd.

On July 11, 2005, the Company announced that it had entered into a definitive agreement to acquire all of the stock of Northrock Resources Ltd., a wholly owned Canadian subsidiary of Unocal Corporation, for $1.8 billion in cash. The acquisition will add 644 Bcfe of proven reserves and approximately 30,000 Boepd of production. The Company expects to use cash on hand and proceeds from its international asset sales of approximately $1 billion as the primary funding source and will finance the balance of the purchase through its revolving bank credit facility and through capital market transactions or a bridge loan. The acquisition is expected to close late in the third quarter of 2005.

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 currently 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 and 2015 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 July 28, 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 creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, as of July 28, 2005, uncertainty remains as to how to interpret numerous provisions of the Act. As a result, the Company is not yet in a position to decide whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S., therefore if technical corrections to the Act are passed the Company may repatriate in 2005 an amount up to approximately $214.8 million of the cash and cash equivalents held by international subsidiaries discussed in “Liquidity and Capital Resources” above. The repatriation would be subject to a tax liability of approximately $8.1 million (assuming 15% of such cash is subject to tax at the U.S. statutory rate). This amount excludes any proceeds that may be realized from the potential sale of the Company’s Thailand operations

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 $525,000,000, of which approximately $260,651,000 was incurred in the six months ended June 30, 2005. The Company has included 350 gross wells in its 2005 capital and exploration budget (166 of which were drilled in the first six 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 July 28, 2005, the Company had completed the purchase of 5,010,000 shares at a total cost of $235.7 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 June 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 limited use of a variety of derivative financial instruments only for non-trading purposes as a hedging strategy to manage commodity prices associated with oil and gas sales and to reduce the impact of commodity price fluctuations.

Current Hedging Activity

As of June 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 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 hedging 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 hedging 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:
July 2005 - December 2005	2,760	$	5.50	$	8.00	$	(826,328	)
July 2005 - December 2005	920	$	6.00	$	9.30	$	(54,185	)
July 2005 - December 2005	920	$	6.00	$	9.25	$	(58,493	)
July 2005 - December 2005	1,840	$	6.00	$	9.25	$	(116,985	)
July 2005 - December 2005	920	$	6.00	$	10.25	$	4,495
July 2005 - December 2005	1,840	$	6.00	$	10.30	$	13,257
January 2006 - December 2006	5,475	$	5.00	$	7.50	$	(5,732,254	)
January 2006 - December 2006	3,650	$	5.50	$	8.25	$	(2,454,822	)
January 2006 - December 2006	3,650	$	5.75	$	8.27	$	(2,315,831	)

Crude Oil Contracts (Barrels)
Collar Contracts:
July 2005 - December 2005	1,840,000	$	40.00	$	62.50	$	(4,669,551	)
July 2005 - December 2005	92,000	$	43.50	$	72.00	$	(57,091	)
July 2005 - December 2005	368,000	$	43.50	$	72.50	$	(209,893	)

(a) MMBtu means million British Thermal Units.

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

Natural Gas Contracts (MMBtu)
Collar Contracts:
January 2006 - December 2006	10,950	$	6.00	$	13.50
January 2006 - December 2006	1,825	$	6.00	$	13.55
January 2006 - December 2006	3,650	$	6.00	$	13.60
January 2006 - December 2006	10,950	$	6.00	$	14.00
January 2007 - December 2007	5,475	$	6.00	$	12.00
January 2007 - December 2007	9,125	$	6.00	$	12.15
January 2007 - December 2007	3,650	$	6.00	$	12.20
January 2007 - December 2007	9,125	$	6.00	$	12.50

Crude Oil Contracts (Barrels)
Collar Contracts:
January 2006 - December 2006	1,460,000	$	50.00	$	78.00
January 2006 - December 2006	365,000	$	50.00	$	79.00
January 2006 - December 2006	1,460,000	$	50.00	$	81.00
January 2006 - December 2006	365,000	$	50.00	$	81.04
January 2006 - December 2006	1,825,000	$	50.00	$	82.00
January 2007 - December 2007	1,460,000	$	50.00	$	75.00
January 2007 - December 2007	365,000	$	50.00	$	75.25
January 2007 - December 2007	3,650,000	$	50.00	$	77.50

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 July 28, 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 June 30, 2005:

	2005		2006		2007		2008		2009			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0	$	0	$	0	$	0	$	383,000		$	0		$	383,000		$	383,000
Average Interest Rate	—		—		—		—		4.28		%	—			4.28		%	—
Fixed Rate	$	0	$	0	$	0	$	0	$	200,000		$	300,000		$	500,000		$	520,500
Average Interest Rate	—		—		—		—		8.25		%	6.63		%	7.28		%	—

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 June 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

April 1-30 2005	1,526,600	$	46.75	$	204,954,659
May 1-31 2005	848,200	$	44.90	$	166,843,317
June 1-30 2005	264,300	$	51.11	$	153,324,685

Total	2,639,100

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

ITEM 4. Submission of Matters to Vote of Security Holders

The registrant held its annual meeting of stockholders in Midland, Texas on April 26, 2005. Each of the individuals nominated for election was elected and the proposal before the meeting was approved. The following sets forth the items that were submitted to a vote of the stockholders and the results thereof:

(A) election of three directors, each for a term of three years. The vote tabulation for each nominee was as follows:

Nominee	For	Withheld
Robert H. Campbell	59,152,055	890,284
Thomas A. Fry, III	59,150,729	891,610
Stephen A. Wells	58,891,046	1,151,293

(B) a proposal to ratify the appointment of PricewaterhouseCoopers LLP, independent accountants, to audit the financial statements of the Company for the year 2005, with 59,429,903 votes cast for ratification, 595,842 votes cast against ratification and 16,594 votes abstained.

ITEM 6. Exhibits

2.1		Stock Purchase Agreement dated as of June 17, 2005 among Pogo Producing Company, Pogo Overseas Production B.V., PTTEP Offshore Investment Company Limited, Mitsui Oil Exploration Co., Ltd. and PTT Exploration and Production Public Company Limited (a copy of any omitted schedule will be furnished supplementally to the Commission upon request).

* 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).

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

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

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

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

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

* Asterisk indicates an exhibit incorporated by reference as shown.

Signatures

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

	Pogo Producing Company
			(Registrant)


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


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


Date: August 2, 2005