POGO PRODUCING CO - 10-Q Quarterly Report

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, 2004 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. Employee 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 requirement 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 30, 2004: 63,908,026

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(Expressed in thousands, except per share amounts)

Revenues:
Oil and gas	$	326,659		$	297,077		$	633,986		$	608,863
Other	234			69			789			956
Total	326,893			297,146			634,775			609,819

Operating Costs and Expenses:
Lease operating	32,350			29,752			67,225			60,543
General and administrative	16,774			15,054			34,006			28,426
Exploration	4,916			1,827			13,387			3,659
Dry hole and impairment	24,842			3,920			36,465			6,098
Depreciation, depletion and amortization	93,114			84,347			180,453			164,766
Production and other taxes	14,236			10,231			23,774			19,185
Transportation and other	5,032			8,099			10,157			15,392
Total	191,264			153,230			365,467			298,069

Operating Income	135,629			143,916			269,308			311,750
Interest:
Charges	(6,627		)	(12,984		)	(16,071		)	(26,679		)
Income	443			547			895			934
Capitalized	3,468			4,117			8,016			8,131
Loss on Debt Extinguishment	(10,893		)	—			(10,893		)	—
Foreign Currency Transaction Gain	1,196			336			1,152			562
Income Before Taxes and Cumulative Effect of Change in Accounting Principle	123,216			135,932			252,407			294,698
Income Tax Expense	(58,027		)	(56,213		)	(115,578		)	(122,336		)
Income Before Cumulative Effect of Change in Accounting Principle	65,189			79,719			136,829			172,362
Cumulative Effect of Change in Accounting Principle	—			—			—			(4,166		)
Net Income	$	65,189		$	79,719		$	136,829		$	168,196

Earnings Per Common Share
Basic:
Income before cumulative effect of change in accounting principle	$	1.02		$	1.29		2.15			2.80
Cumulative effect of change in accounting principle	—			—			—			(0.07		)
Net income	$	1.02		$	1.29		$	2.15		$	2.73

Diluted:
Income before cumulative effect of change in accounting principle	$	1.01		$	1.24		2.13			2.67
Cumulative effect of change in accounting principle	—			—			—			(0.06		)
Net income	$	1.01		$	1.24		$	2.13		$	2.61
Dividends Per Common Share	$	0.05		$	0.05		$	0.10		$	0.10

Weighted Average Number of Common Shares and Potential Common Shares Outstanding:
Basic	63,738			61,961			63,703			61,559
Diluted	64,333			65,376			64,273			65,252

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	June 30, 2004			December 31, 2003
	(Expressed in thousands, except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	180,315		$	178,754
Accounts receivable	116,806			116,970
Other receivables	33,378			39,497
Inventories - product	6,468			5,951
Inventories - tubulars	14,388			7,735
Other	10,557			5,448
Total current assets	361,912			354,355

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	4,142,238			3,919,138
Unevaluated properties	122,236			107,708
Other, at cost	31,473			30,046
	4,295,947			4,056,892
Accumulated depreciation, depletion and amortization
Oil and gas	(1,839,261		)	(1,661,584		)
Other	(21,608		)	(19,467		)
	(1,860,869		)	(1,681,051		)
Property and equipment, net	2,435,078			2,375,841

Other Assets:
Deferred income tax	2,147			2,416
Foreign value added taxes receivable	7,451			4,188
Other	22,025			25,236
	31,623			31,840

	$	2,828,613		$	2,762,036

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	June 30, 2004			December 31, 2003
	(Expressed in thousands, except share amounts)
Liabilities and Shareholders’ Equity

Current Liabilities:
Accounts payable - operating activities	$	68,701		$	55,543
Accounts payable - investing activities	85,048			73,179
Income taxes payable	6,450			20,220
Accrued interest payable	3,934			9,950
Accrued payroll and related benefits	3,475			3,242
Deferred income tax	5,324			5,324
Other	10,681			16,126
Total current liabilities	183,613			183,584

Long-Term Debt	395,000			487,261

Deferred Income Tax	550,240			546,709

Asset Retirement Obligation	87,719			70,790

Other Liabilities and Deferred Credits	21,929			20,039

Total liabilities	1,238,501			1,308,383

Commitments and Contingencies	—			—

Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized	—			—
Common stock, $1 par; 200,000,000 shares authorized, 63,963,385 and 63,813,283 shares issued, respectively	63,963			63,813
Additional capital	920,035			914,492
Retained earnings	611,020			480,576
Deferred compensation	(3,196		)	(3,518		)
Accumulated other comprehensive income (loss)	—			—
Treasury stock (55,359 shares), at cost	(1,710		)	(1,710		)
Total shareholders’ equity	1,590,112			1,453,653

	$	2,828,613		$	2,762,036

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
	2004			2003
	(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers	$	643,537		$	622,061
Operating, exploration, and general and administrative expenses paid	(150,534		)	(119,795		)
Interest paid	(21,499		)	(25,520		)
Income taxes paid	(124,593		)	(75,686		)
Value added taxes paid	(3,263		)	(1,294		)
Price hedge contracts	—			(13,004		)
Other	4,609			5,462
Net cash provided by operating activities	348,257			392,224

Cash Flows from Investing Activities:
Capital expenditures	(199,437		)	(157,826		)
Purchase of properties	(42,996		)	—
Proceeds from the sale of properties	266			8
Net cash used in investing activities	(242,167		)	(157,818		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	550,000			200,012
Payments under senior debt agreements	(494,000		)	(360,000		)
Redemption of 2007 Notes	(157,782		)	—
Payments of cash dividends on common stock	(6,385		)	(6,164		)
Payment of debt issue costs	—			(100		)
Proceeds from exercise of stock options	3,260			26,999
Net cash used in financing activities	(104,907		)	(139,253		)
Effect of exchange rate changes on cash	378			166

Net increase in cash and cash equivalents	1,561			95,319
Cash and cash equivalents at the beginning of the year	178,754			134,449
Cash and cash equivalents at the end of the period	$	180,315		$	229,768

Reconciliation of net income to net cash provided by operating activities:
Net income	$	136,829		$	168,196
Adjustments to reconcile net income to net cash provided by operating activities -
Cumulative effect of change in accounting principle	—			4,166
(Gains) losses from the sales of properties	(265		)	90
Depreciation, depletion and amortization	180,453			164,766
Dry hole and impairment	36,465			6,098
Interest capitalized	(8,016		)	(8,131		)
Price hedge contracts	—			2,506
Other	14,207			7,283
Deferred income taxes	4,751			7,269
Change in operating assets and liabilities	(16,167		)	39,981
Net cash provided by operating activities	$	348,257		$	392,224

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,
	2004							2003
	Shareholders’ Equity					Compre- hensive		Shareholders’ Equity					Compre- hensive
	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	63,813,283		$	63,813				61,061,888		$	61,062
Stock option activity and other	150,102		150					1,303,304		1,303
Issued at end of period	63,963,385		63,963					62,365,192		62,365

Additional Capital:
Balance at beginning of year			914,492							822,526
Stock option activity and other			5,543							34,806
Balance at end of period			920,035							857,332

Retained Earnings:
Balance at beginning of year			480,576							202,155
Net income			136,829			$	136,829			168,196			$	168,196
Dividends ($0.05 per common share)			(6,385		)					(6,164		)
Balance at end of period			611,020							364,187

Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year			—							(6,249		)
Change in fair value of price hedge contracts			—			—				(12,199		)	(12,199		)
Reclassification adjustment for losses (gains) included in net income			—			—				9,756			9,756
Balance at end of period			—							(8,692		)

Deferred Compensation
Balance at beginning of year			(3,518		)					—
Activity during the period			322							—
Balance at end of period			(3,196		)					—

Comprehensive Income (Loss)						$	136,829						$	165,753

Treasury Stock:
Balance at beginning of year	(55,359	)	(1,710		)			(55,359	)	(1,710		)
Activity during the period	—		—					—		—
Balance at end of period	(55,359	)	(1,710		)			(55,359	)	(1,710		)

Common Stock Outstanding, at the End of the Period	63,908,026							62,309,833

Total Shareholders’ Equity			$	1,590,112						$	1,273,482

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 recl assified to conform to current year presentation. Such reclassifications had no effect on the Company’s operating income, 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, 2003.

(2) EARNINGS PER SHARE -

Earnings per common share (b asic 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. Amounts are expressed in thousands, except per share amounts.

	Three Months Ended June 30, 2004						Six Months Ended June 30, 2004
	Income			Shares	Per Share		Income		Shares	Per Share
Basic earnings per share -	$		65,189	63,738	$	1.02	$	136,829	63,703	$	2.15
Effect of dilutive securities:
Options to purchase common shares				595					570
Diluted earnings per share	$	65,189		64,333	$	1.01	$	136,829	64,273	$	2.13
Antidilutive securities -
Options to purchase common shares	—			25	$	49.02	—		25	$	49.02

	Three Months Ended June 30, 2003					Six Months Ended June 30, 2003
	Income		Shares	Per Share		Income (a)		Shares	Per Share
Basic earnings per share -	$	79,719	61,961	$	1.29	$	172,362	61,559	$	2.80
Effect of dilutive securities:
Options to purchase common shares	—		689			—		967
2006 Notes (b)	1,028		2,726			2,056		2,726
Diluted earnings per share	$	80,747	65,376	$	1.24	$	174,418	65,252	$	2.67
Antidilutive securities -
Options to purchase common shares	—		10	$	43.46	—		81	$	41.23

(a) Reflects income before cumulative effect of change in accounting principle.

(b) Redeemed on July 7, 2003.

(3) ASSET RETIREMENT OBLIGATION –

The Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), as of January 1, 2003. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost (“ARC”) was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, a cumulative effect of a change in accounting principle was also required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. This periodic accretion expense is recorded as “Transportation and other” in the consolidated statement of income. Upon settlement of the liability, the Company will settle the obligation against its recorded amount and will record any resulting gain or loss.

The Company’s liability for expected future costs associated with site reclamation, facilities dismantlement, and plugging and abandonment of wells for the six-month periods ended June 30, 2004 and 2003 is as follows (in thousands):

	2004		2003
ARO as of January 1,	$	70,790	$	63,643
Liabilities incurred during the six months ended June 30,	14,174		1,459
Accretion expense	2,755		2,395
Balance of ARO as of June 30,	$	87,719	$	67,497

For the three months ended June 30, 2004 and 2003 the Company recognized depreciation expense related to its ARO of $1,719,000 and $972,000, respectively. For the six months ended June 30, 2004 and 2003 the Company recognized depreciation expense related to its ARO of $2,817,000 and $1,028,000, respectively. As a result of the adoption of SFAS 143 on January 1, 2003, the Company recorded a $56,769,000 increase in the net capitalized cost of its oil and gas properties and recognized an after-tax charge of $4,166,000 for the cumulative effect of the change in accounting principle.

(4) GEOGRAPHIC INFORMATION –

Financial information by geographic segment is presented below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(Expressed in thousands)

Revenues:
United States	$	250,697		$	222,154		$	485,830		$	458,641
Kingdom of Thailand	76,189			74,971			148,938			151,155
Other	7			21			7			23
Total	$	326,893		$	297,146		$	634,775		$	609,819

Operating Income (Loss):
United States	$	124,068		$	109,322		$	232,873		$	236,196
Kingdom of Thailand	33,619			35,483			68,381			77,204
Other (a)	(22,058		)	(889		)	(31,946		)	(1,650		)
Total	$	135,629		$	143,916		$	269,308		$	311,750

(a) The 2004 amounts primarily reflect dry hole and impairment costs in Hungary and the Danish North Sea.

(5) 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 2004 and does not expect to make a contribution during the remainder of 2004.

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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

Service cost	$	627		$	563		$	1,254		$	1,126
Interest cost	427			383			854			766
Expected return on plan assets	(663		)	(551		)	(1,326		)	(1,102		)
Amortization of prior service cost	12			10			24			20
Amortization of net loss	152			235			304			470
	$	555		$	640		$	1,110		$	1,280

	Post-Retirement Medical Plan
	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003

Service cost	$	344	$	293	$	688	$	586
Interest cost	271		254		542		508
Amortization of transition obligation	76		76		152		152
Amortization of net loss	56		45		112		90
	$	747	$	668	$	1,494	$	1,336

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, 2003.

(6) 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 42,000 shares during the three and six-month period ended June 30, 2004. The Company granted Stock Awards covering 10,000 shares during the three and six-month period ended June 30, 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 and six-month periods ending June 30, 2004 and 2003 (in thousands of dollars, except per share amounts):

		Three Months Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003

Net income, as reported		$	65,189		$	79,719		$	136,829		$	168,196
Add:	Employee stock-based compensation expense, net of related tax effects, included in net income, as reported	568			3			1,124			3
Deduct:	Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects	(1,696		)	(1,540		)	(3,439		)	(3,063		)
Net income, pro forma		$	64,061		$	78,182		$	134,514		$	165,136

Earnings per share:
Income before the cumulative effect of change in accounting principle
	Basic - as reported	$	1.02		$	1.29		$	2.15		$	2.80
	Basic - pro forma	$	1.01		$	1.26		$	2.11		$	2.75
	Diluted - as reported	$	1.01		$	1.24		$	2.13		$	2.67
	Diluted - pro forma	$	1.00		$	1.21		$	2.09		$	2.63
Net income
	Basic - as reported	$	1.02		$	1.29		$	2.15		$	2.73
	Basic - pro forma	$	1.01		$	1.26		$	2.11		$	2.68
	Diluted - as reported	$	1.01		$	1.24		$	2.13		$	2.61
	Diluted - pro forma	$	1.00		$	1.21		$	2.09		$	2.56

(7) HEDGING ACTIVITIES -

As of June 30, 2004, the Company held no derivative instruments and there were no hedging activities during the first six months of 2004. During 2003, the Company was a party to 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 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. During the three and six-month periods ended June 30, 2003, the Company recognized a pre-tax loss of $4,035,000 ($2,623,000 after taxes) and $14,810,000 ($9,627,000 after taxes) from its price hedge contracts, which were included in oil and gas revenues. Unrealized losses on derivative instruments of $2,443,000, net of deferred taxes of $1,315,000, were reflected as a component of other comprehensive income for the six months ended June 30, 2003.

(8) REDEMPTION OF 2009 NOTES -

The Company gave notice on March 18, 2004 of its intent to redeem all $150,000,000 of its 10³/₈% Senior Subordinated Notes due 2009 (the “2009 Notes”) at 105.188% of their face amount. On April 19, 2004, the Company paid $157,782,000 (excluding accrued interest) in cash to holders of the 2009 Notes. The cash redemption payment was funded through borrowings under the Company’s existing bank credit facility. The Company recorded a pre-tax expense on the redemption of the 2009 Notes of $10,893,000 in the quarter ended June 30, 2004.

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, 2003. 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, 2003, 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

Total revenue for the second quarter of 2004 was $326.9 million and net income totaled $65.2 million or $1.02 per share. Cash flow from operations totaled $127.2 million.

The Company increased its capital budget from $415 million to $565 million, one of the largest budgets in the Company’s history. This budget represents an increase of more than 50% over 2003’s exploration and development expenditures. Roughly $55 million of the budget increase is earmarked for development drilling and facilities to follow up on successes during the first half of 2004. More than $50 million of the increase is allocated to exploration projects in the Gulf of Mexico and approximately $40 million of the increase was used to purchase additional interests in existing Company fields. During the second quarter of 2004, the Company spent $110 million on exploratory and developmental activities and year-to-date the Company has spent 43% of its 2004 capital budget. The budget calls for the drilling of 390 wells during 2004, a record number. During the second quarter of 2004, 93 wells were drilled with 86 successfully completed, a 92% success rate. Year-to-date, 148 wells have been drilled, with 51 wells that were either being drilled or being completed.

During the most recent quarter, the Company announced that it would recognize approximately $17 million in expense for four wells that were drilled in its Hungary concession area. The expense was incurred due to encountering only modest amounts of hydrocarbons. Additionally, during the most recent quarter Pogo expensed an additional $4.2 million for the Fasan #1 well located in the Danish North Sea, which encountered limited amounts of hydrocarbons and was deemed to be noncommercial.

The Company was an active participant in the Gulf of Mexico Outer Continental Shelf Lease Sale 190 in March 2004. The Company was the high bidder on and was awarded fourteen leases. Prospects contained on several of these leases are currently expected to be drilled during the second half of 2004.

In April, the Company redeemed all $150 million of its 10³/₈% Senior Subordinated Notes due 2009 (“the 2009 Notes”). The Company recognized a $10.9 million charge on the extinguishment of this debt. The Company’s bank credit facility was used to refinance the redemption. This action is projected to save the Company over $11 million in annual interest expense.

2004 Production Outlook

The Company currently expects that full-year 2004 company wide equivalent hydrocarbon production should reach within 3% of the Company’s 2003 production levels, subject to changes in circumstances, acquisitions and many other factors.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for the second quarter of 2004 were $326,659,000, an increase of approximately 10% from oil and gas revenues of $297,077,000 for the second quarter of 2003. The Company’s oil and gas revenues for the first six months of 2004 were $633,986,000, an increase of approximately 4% from oil and gas revenues of $608,863,000 for the first six months of 2003. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in thousands) between 2004 and 2003.

	2nd Qtr 2004 Compared to 2nd Qtr 2003			1st Half 2004 Compared to 1st Half 2003

Increase (decrease) in oil and gas revenues resulting in variances in:
Natural gas -
Price	$	10,488		$	14,050
Production	16,230			15,276
	26,718			29,326
Crude oil and condensate -
Price	49,404			65,409
Production	(50,499		)	(74,148		)
	(1,095)			(8,739		)

Natural gas liquids	3,959			4,536
Increase in oil and gas revenues	$	29,582		$	25,123

The increase in the Company’s oil and gas revenues in the second quarter and first six months of 2004, compared to the second quarter and first six months of 2003, is related to increases in both natural gas production volumes and 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 crude oil and condensate production volumes.

	2nd Quarter				% Change 2004 to 2003		1st Six Months				% Change 2004 to
	2004		2003		% Change 2004 to 2003		2004		2003		2003
Comparison of Increases (Decreases) in:
Natural Gas —
Average prices
United States (a)	$	5.79	$	5.38	8	%	$	5.64	$	5.51	2	%
Kingdom of Thailand (b)	$	2.40	$	2.48	(3	)%	$	2.44	$	2.40	2	%
Company-wide average price	$	4.90	$	4.51	9	%	$	4.85	$	4.59	6	%
Average daily production volumes (MMcf per day):
United States (a)	249.3		211.9		18	%	239.9		213.8		12	%
Kingdom of Thailand	88.8		89.8		(1	)%	79.0		89.4		(12	)%
Company-wide average daily production	338.1		301.7		12	%	318.9		303.2		5	%

(a) United States average prices reflect the impact of the Company’s price hedging activity for 2003. The Company had no price hedging activity during the first six months of 2004. Price hedging activity reduced the average price of the Company’s United States natural gas production during the second quarter and first six months of 2003 by $0.15 and $0.27 per Mcf, respectively. “MMcf” is an abbreviation for million cubic feet.

(b) The Company is paid for its natural gas production in the Kingdom of Thailand in Thai Baht. The average prices are presented in U.S. dollars based on the revenue recorded in the Company’s financial records.

	2nd Quarter				% Change 2004 to 2003		1st Six Months				% Change 2004 to
	2004		2003		% Change 2004 to 2003		2004		2003		2003
Comparison of Increases (Decreases) in:
Crude Oil and Condensate —
Average prices (a)
United States	$	34.76	$	28.05	24	%	$	35.02	$	30.08	16	%
Kingdom of Thailand	$	37.27	$	26.28	42	%	$	36.02	$	28.84	25	%
Company-wide average price	$	35.58	$	27.44	30	%	$	35.35	$	29.66	19	%
Average daily production volumes
(Bbls per day):
United States (a)	34,401		43,863		(22	)%	34,225		41,937		(18	)%
Kingdom of Thailand (b)	19,346		21,807		(11	)%	17,515		22,446		(22	)%
Company-wide average daily production	53,747		65,670		(18	)%	51,740		64,383		(20	)%

Total Liquid Hydrocarbons —
Company-wide average daily production (Bbls per day)(b)	58,423		69,137		(15	)%	56,334		68,373		(18	)%

(a) Average prices are computed on production that is actually sold during the period and include the impact of the Company’s price hedging activity. The Company had no price hedging activity during the first six months of 2004. Price hedging activity reduced the average price of the Company’s United States crude oil and condensate production by $0.28 per barrel and $0.58 per barrel during the second quarter and first six months of 2003, respectively. For United States average prices, sales volumes equate to actual production. However, in the Gulf of Thailand, crude oil and condensate sold may be more or less than actual production. See footnote (b) below. “Bbls” is an abbreviation for barrels.

(b) Oil and condensate production in the Gulf of Thailand is produced and stored on the FPSO and FSO pending sale and is sold in tanker loads that typically average between 300,000 and 750,000 barrels per sale. Therefore, oil and condensate sales volumes for a given period in the Gulf of Thailand may not equate to actual production. In accordance with generally accepted accounting principles, reported revenues are based on sales volumes. However, the Company believes that actual production volumes also provide a meaningful measure of the Company’s operating results. The Company produced 237,000 barrels more than it sold in the second quarter of 2004 and 98,000 barrels less than it sold in the second quarter of 2003. The Company produced 31,000 barrels more than it sold in the first six months of 2004 and 170,000 barrels more than it sold in the first six months of 2003.

Natural Gas

Thailand Prices. The price that the Company receives under the gas sales agreement with the Petroleum Authority of Thailand (“PTT”) is based upon a formula that takes into account a number of factors including, among other items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore. The contract price is also subject to adjustments for quality.

Production. The increase in the Company’s natural gas production during the second quarter and first six months of 2004, compared to the comparable 2003 periods, was primarily related to increased natural gas production from the continuing success of the Company’s exploration program at the Los Mogotes field in South Texas, increased production from the Madden field in Wyoming and production from fields purchased by the Company during the latter part of 2003. These increases for the six-month comparative periods were partially offset by decreased production resulting from a temporary shutdown of the Benchamas field in the Gulf of Thailand during the first quarter of 2004 to upgrade the Benchamas central processing platform.

Crude Oil and Condensate

Thailand Prices. Since the inception of production from the Tantawan Field, crude oil and condensate have been stored on the FPSO until an economic quantity is accumulated for offloading and sale. The first such sale of crude oil and condensate from the Tantawan Field occurred in July 1997. Commencing in July 1999 when production began from the Benchamas Field, crude oil and condensate from that field has been stored on the FSO and sold as economic quantities are accumulated. A typical sale ranges from 300,000 to 750,000 barrels. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, typically as a differential to Malaysian TAPIS crude, and are denominated in U.S. dollars.

Production. The decrease in the Company’s crude oil and condensate production during the second quarter and first six months of 2004, compared to the second quarter and first six months of 2003, resulted primarily from the temporary shutdown of, and subsequent processing issues at, the Benchamas field in the Gulf of Thailand, natural production decline at the Company’s Main Pass Block 61/62 field and, to a lesser extent, natural production declines at other properties.

In accordance with generally accepted accounting principles, the Company records its oil production in the Kingdom of Thailand at the time of sale, rather than when produced. At the end of each quarter, the crude oil and condensate stored on board the FSO and FPSO pending sale is accounted for as inventory at cost. Reported revenues are based on sales volumes. When a tanker load of oil is sold in Thailand, the entire amount will be accounted for as production sold, regardless of when it was produced. As of June 30, 2004, the Company had approximately 526,000 net barrels stored on board the FPSO and FSO.

NGL Production. The Company’s oil and gas revenues, and its total liquid hydrocarbon production, also reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for the second quarter and first six months of 2004, compared with the second quarter and first six months of 2003, primarily related to an increase in volumes extracted and, to a lesser extent, an increase in NGL prices received from $20.37 and $22.56 per barrel in the second quarter and first six months of 2003, respectively, to $24.41 and $24.91 per barrel in the second quarter and first six months of 2004, respectively.

Costs and Expenses

	2nd Quarter						% Change		1st Six Months						% Change
Comparison of Increases (Decreases) in:	2004			2003			2004 to 2003		2004			2003			2004 to 2003
Lease Operating Expenses
United States	$	22,864,000		$	18,267,000		25	%	$	46,336,000		$	39,423,000		18	%
Kingdom of Thailand	$	9,486,000		$	11,485,000		(17	)%	$	20,889,000		$	21,120,000		(1	)%
Total Lease Operating Expenses	$	32,350,000		$	29,752,000		9	%	$	67,225,000		$	60,543,000		11	%

General and Administrative Expenses	$	16,774,000		$	15,054,000		11	%	$	34,006,000		$	28,426,000		20	%
Exploration Expenses	$	4,916,000		$	1,827,000		169	%	$	13,387,000		$	3,659,000		266	%
Dry Hole and Impairment Expenses	$	24,842,000		$	3,920,000		534	%	$	36,465,000		$	6,098,000		498	%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	93,114,000		$	84,347,000		10	%	$	180,453,000		$	164,766,000		10	%
DD&A rate	$	1.52		$	1.28		19	%	$	1.51		$	1.29		17	%
Mcfe sold (a)	61,246,000			65,790,000			(7	)%	119,367,000			128,116,000			(7	)%
Production and Other Taxes	$	14,236,000		$	10,231,000		39	%	$	23,774,000		$	19,185,000		24	%
Transportation and Other	$	5,032,000		$	8,099,000		(38	)%	$	10,157,000		$	15,392,000		(34	)%
Interest—
Charges	$	(6,627,000	)	$	(12,984,000	)	(49	)%	$	(16,071,000	)	$	(26,679,000	)	(40	)%
Capitalized Interest Expense	$	3,468,000		$	4,117,000		(16	)%	$	8,016,000		$	8,131,000		(1	)%
Loss on Debt Extinguishment	$	(10,893,000	)	$	—		N/M		$	(10,893,000	)	$	—		N/M
Income Tax Expense	$	(58,027,000	)	$	(56,213,000	)	3	%	$	(115,578,000	)	$	(122,336,000	)	(6	)%

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

Lease Operating Expenses

The increase in United States lease operating expenses for the second quarter and first six months of 2004, compared to the respective 2003 periods, is related primarily to increased maintenance expenses on several of the Company’s significant offshore properties, expenses incurred on the properties acquired by the Company during the latter part of 2003 and also to increased expenses incurred as the Company continues to expand production in the Los Mogotes field in South Texas.

The decrease in lease operating expenses in the Kingdom of Thailand for the second quarter of 2004, compared to second quarter of 2003, primarily related to decreased billings by the operator of the field for operating expenses during the 2004 period. However, the Company does not currently anticipate a similar decrease in the operator’s billings during the third quarter of 2004. A substantial portion of the Company’s lease operating expenses in the Kingdom of Thailand are fixed costs related to the lease payments made in connection with the bareboat charters of the FPSO for the Tantawan field and the FSO for the Benchamas field. Collectively, these lease payments accounted for approximately $3.6 million and $7.2 million (net to the Company’s interest) of the Company’s Thailand lease operating expenses for the second quarter and first six months, respectively, of 2004 and 2003. The Company currently expects these lease payments to remain relatively constant at approximately $14.5 million per year (net to the Company’s interest) for the next several years.

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.46 and $0.47 per Mcfe for the second quarter and first six months of 2003 to $0.52 and $0.56 per Mcfe for the second quarter and first six months of 2004. The per unit of production increase for the first six months of 2004 is primarily related to the Benchamas production shutdown

during the first quarter 2004 which significantly reduced crude oil and condensate production while operating expenses on the Benchamas field did not decrease proportionately due to the factors discussed above.

General and Administrative Expenses

The increase in general and administrative expenses for the second quarter and first six months of 2004 compared with the respective 2003 periods, is primarily related to increases in compensation and related benefit expense and increased professional fees (due in part to compliance with Sarbanes-Oxley legislation) and, to a lesser extent, increased billings from the operator of the Company’s Thailand concession. On a per unit of production basis, the Company’s general and administrative expenses increased to $0.27 per Mcfe in the second quarter of 2004 from $0.23 per Mcfe in the second quarter of 2003. The Company’s general and administrative expenses increased to $0.28 per Mcfe in the first six months of 2004 from $0.22 per Mcfe in the first six months of 2003.

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. The increase in exploration expenses for the second quarter of 2004, compared to the second quarter of 2003, resulted primarily from the acquisition of approximately $3.3 million of 3-D seismic data in the Company’s Gulf Coast division. The increase in exploration expenses for the first six months of 2004, compared to the first six months of 2003, resulted primarily from the acquisition of approximately $7 million of 3-D seismic data covering approximately 1.4 million acres of the Gulf of Mexico during the first quarter of 2004. The Company used this seismic data to identify prospective lease blocks for bid at the March 2004 federal oil and gas lease sale. The Company was the high bidder on fifteen of the lease blocks at the March sale, fourteen of which have been awarded to the Company. There were no expenditures of comparable size to those discussed above incurred during the second quarter or first six months of 2003.

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 2004, compared to the respective 2003 periods, was primarily the result of the previously announced unsuccessful exploratory wells in the Company’s Hungary acreage, which were evaluated during 2004, totaling approximately $17.1 million and $26.5 million in the second quarter and first six months of the year, respectively. During the second quarter of 2004, the Company also recognized dry hole and impairment expense of approximately $4.2 million related to an unsuccessful exploratory well drilled in the Danish North Sea. 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 reserves 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 2004 and 2003, 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 and Gulf of Thailand. 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 2004 compared to the respective 2003 periods resulted primarily from an increase in the Company’s composite DD&A rate, partially offset by a decrease in the Company’s equivalent natural gas and liquid 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 2004, compared to the respective 2003 periods, 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 the Benchamas field and properties in the Gulf of Mexico) and a corresponding increase in the percentage of the Company’s production coming from fields that have DD&A rates that are higher than the Company’s recent historical composite rate (principally increased production from properties acquired by acquisition).

Production and Other Taxes

The increase in production and other taxes during the second quarter and first six months of 2004, compared to the respective 2003 periods, relates primarily to increased severance taxes due to higher onshore prices. The Company also recognized $4,227,000 and $1,852,000 during the second quarters of 2004 and 2003, respectively, of the Special Remuneration Benefit (SRB) obligation related to the Company’s Kingdom of Thailand concession. The Company recognized $6,015,000 and $4,226,000 during the first six months of 2004 and 2003, respectively, related to the SRB. SRB is a payment to the Thai government required by the Company’s concession agreement after certain specified revenue, expenditure and drilling criteria have been achieved. It is currently anticipated that the Company will continue to pay SRB for the foreseeable future.

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 obligation, a valuation allowance placed on an accounts receivable relating to a potential insurance settlement, a royalty settlement reserve on one of the Company’s offshore blocks, tubular inventory valuation write-offs and allowances, adjustments to the Company’s post-retirement benefit plan obligation and various other operating expenses, none of which represents more than 5% of this expense category. The decrease in transportation and other expense for the second quarter and first six months of 2004, compared to the second quarter and first six months of 2003, relates primarily to a reduction in the Company’s transportation expense, and the inclusion in 2003 of $2.9 million of valuation allowances and reserves on items discussed above, for which no comparable expenses were incurred in 2004. The Company incurred transportation expense of $2,988,000 and $6,113,000 in the second quarter and first six months of 2004, respectively. The Company incurred transportation expense of $3,279,000 and $7,496,000 in the second quarter and first six months of 2003, respectively.

Interest

Interest Charges. The decrease in the Company’s interest charges for the second quarter and first six months of 2004, compared to the second quarter and first six months of 2003, resulted primarily from a decrease in the average amount of the Company’s outstanding debt.

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 2004, compared to the respective 2003 periods, resulted primarily from 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. The decreased weighted average interest rate was partially offset by an increase in the amount of oil and gas projects in progress subject to interest capitalization during the second quarter and first six months of 2004 (approximately $215,000,000 in each period), compared to the second quarter and first six months of 2003 (approximately $186,000,000 and $196,000,000, respectively).

Loss on Debt Extinguishment

The Company gave notice in the first quarter of 2004 of its intent to redeem all $150,000,000 of its 2009 Notes at 105.188% of their face amount. On April 19, 2004, the Company paid $157,782,000 (excluding accrued interest) in cash to holders of the 2009 Notes. The cash redemption payment was funded through borrowings under the Company’s existing bank credit facility. The Company recorded a pre-tax loss on debt extinguishment related to the redemption of the 2009 Notes of $10,893,000 in the second quarter of 2004.

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 2004, compared to the second quarter of 2003, resulted primarily from an increase in the Company’s effective tax rate, partially offset by decreased pre-tax income during the 2004 period. The Company’s consolidated effective tax rate for the second quarter of 2004 was 47%, compared to an effective tax rate for the second quarter of 2003 of 41%. The higher effective tax rate during the 2004 period was primarily the result of significant exploratory dry hole costs incurred in foreign jurisdictions, where deductions for those costs are not currently realizable.

The decrease in the Company’s tax expense for the first six months of 2004, compared to the first six months of 2003, resulted primarily from decreased pre-tax income during the 2004 period, partially offset by an increase in the Company’s effective tax rate. The Company’s consolidated effective tax rate for the first six months of 2004 was 46%, compared to an effective tax rate for the first six months of 2003 of 42%. The higher effective tax rate was the result of a higher percentage of the Company’s pre-tax income being derived from its Thailand operations during the 2004 period as compared to the 2003 period. The Thailand income is taxed at a rate higher than the U.S. statutory rate.

Cumulative Effect of Change in Accounting Principle

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) as of January 1, 2003, which required the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, the Company recorded an after-tax charge to recognize the cumulative effect of a change in accounting principle of $4,166,000. This charge was required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, and also to increase the carrying amount of the associated long-lived asset and its accumulated depreciation.

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 2004 was $348,257,000 compared to cash flow from operating activities of $392,224,000 in the first six months of 2003. The decrease is attributable primarily to higher expenses (principally income taxes), partially offset by the higher oil and gas prices discussed under “Results of Operations” above. Cash flow from operating activities during the first six months of 2004 was more than adequate to fund $242,167,000 in cash expenditures for capital and exploration projects for the year. The Company also repaid approximately $102,000,000 of cash (net of borrowings) to settle debt obligations (including the repayment of the 2009 Notes mentioned above) and paid $6,385,000 of dividends on the Company’s common stock during the first six months of 2004. As of June 30, 2004, the Company had cash and cash equivalents of $180,315,000 (including $163,340,000 in international subsidiaries which the Company intends to reinvest in its foreign operations) and long-term debt obligations of $395,000,000 with no repayment obligations until 2006. On April 19, 2004, the Company redeemed all $150,000,000 of its 2009 Notes for $157,782,000 in cash. The Company may determine to repurchase additional 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 23, 2004, the Company’s lenders redetermined the borrowing base under its Credit Agreement at $900,000,000. The available borrowing capacity under the Credit Agreement is currently $515,000,000. As of July 30, 2004, the Company had an outstanding balance of $112,000,000 under its Credit Agreement.

LIBOR Rate Advances

Under a Promissory Note Agreement dated May 8, 2004, one of the Company’s lenders makes available to the Company LIBOR rate advances on an uncommitted basis up to $25,000,000. Advances drawn under this agreement 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 may restrict all or a portion of the amounts that may be borrowed under the Promissory Note Agreement as senior debt. The Promissory Note Agreement permits either party to terminate the letter agreement at any time upon three-business days notice. As of July 30, 2004, there was $25,000,000 outstanding under this agreement.

Future Capital and Other Expenditure Requirements

The Company’s capital and exploration budget for 2004, which does not include any amounts that may be expended for future acquisitions or any interest which may be capitalized resulting from projects in progress, was recently increased by the Company’s Board of Directors to $565,000,000 from the previously established budget of $415,000,000. The Company has included 390 gross wells in its 2004 capital and exploration budget (148 of which were drilled in the first six months of 2004), including wells in the United States, the Kingdom of Thailand, Hungary and Denmark. 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, its authorized capital budget, and dividend payments at current levels for the foreseeable future. The declaration and amount of future dividends on the Company’s common stock will depend upon, among other things, the Company’s future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends and other payments under covenants contained in its remaining debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company’s Board of Directors.

Recent Accounting Developments

The Company has been made aware that an issue has arisen regarding the application of provisions of SFAS No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”). Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.

On July 19, 2004, the Financial Accounting Standards Board (“FASB”) staff proposed FSP FAS 142-b “Application of SFAS 142 to Oil and Gas Producing Entities.” The comment period on the proposed FSP ends on August 17, 2004. The proposed FSP clarifies that the exception in paragraph 8(b) of SFAS 142, includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. Accordingly, the FASB staff believes that the scope exception extends to the disclosure provision of SAS 142 for drilling and mineral rights of oil and gas entities.

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. As of July 30, 2004, the Company held no commodity derivative contracts.

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 30, 2004, 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, 2004:

	2004		2005		2006			2007		2008		Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0	$	0	$	195,000		$	0	$	0	$	0		$	195,000		$	195,000
Average Interest Rate	—		—		2.43		%	—		—		—			2.43		%	—
Fixed Rate	$	0	$	0	$	0		$	0	$	0	$	200,000		$	200,000		$	219,000
Average Interest Rate	—		—		—			—		—		8.25		%	8.25		%	—

Foreign Currency Exchange Rate Risk

In addition to the U.S. dollar, the Company and certain of its subsidiaries conduct their business in Thai Baht and Hungarian Forint and are therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. The Company conducts a substantial portion of its oil and gas production and sales in Southeast Asia. Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties in the recent past, including sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. The economic situation in Thailand and the volatility of the Thai Baht against the dollar could have a material impact on the Company’s Thailand operations and prices that the Company receives for its oil and gas production there. Although the Company’s sales to PTT under the Gas Sales Agreement are denominated in Baht, because predominantly all of the Company’s crude oil sales and its capital and most other expenditures in the Kingdom of Thailand are denominated in U.S. dollars, the dollar is the functional currency for the Company’s operations in the Kingdom of Thailand. As of July 30, 2004, the Company is not a party to any foreign currency exchange agreement.

Exposure from market rate fluctuations related to activities in Hungary, where the Company’s functional currency is the U.S. dollar, is not material at this time.

ITEM 4. Controls and Procedures.

The Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this quarterly report. Based upon that evaluation, the Company’s Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic Securities and Exchange Commission filings.

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 4. Submission of Matters to Vote of Security Holders

The registrant held its annual meeting of stockholders in Houston, Texas on April 27, 2004. Each of the individuals nominated for election was elected and each of the proposals 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 two directors, each for a term of three years. The vote tabulation for each nominee was as follows:

Nominee	For	Withheld
Jerry M. Armstrong	58,900,342	1,208,332
Paul G. Van Wagenen	58,757,695	1,350,979

(B) a proposal to approve the Company’s 2004 Incentive Plan, with 48,487,648 votes cast in favor, 3,798,488 votes cast against approval, 137,434 votes abstained and 7,685,104 were determined to be broker non-votes.

(C) a proposal to ratify the appointment of PricewaterhouseCoopers LLP, independent accountants, to audit the financial statements of the Company for the year 2004, with 58,988,101 votes cast for ratification, 1,097,990 votes cast against ratification and 22,583 votes abstained.

ITEM 6. Exhibits and Reports on Form 8-K.

(A) Exhibits

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

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

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.

(B) Reports on Form 8-K

During the quarter for which this report is filed, the following report on Form 8-K was filed:

Report dated April 27, 2004 (Items 7 and 12 (furnished material only; not filed for purposes of Section 18 of the Securities Exchange Act or any other purpose)) relating to the Company’s results for the quarter ended June 30, 2004.

Report dated April 29, 2004 (Items 5 and 7) relating to an amendment to the Company’s Rights Agreement.

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 4, 2004