POGO PRODUCING CO - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

Exchange Act of 1934

For the quarterly period ended March 31, 2005 or

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

Exchange Act of 1934

For the transition period from to

Commission file number 1-7792

POGO PRODUCING COMPANY

(Exact Name of Registrant as Specified in Its Charter)

Delaware		74-1659398
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. 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 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 May 2, 2005:

60,996,981

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended March 31,
	2005			2004
	(Expressed in thousands, except per share amounts)

Revenues:
Oil and gas	$	355,700		$	307,327
Other	13,090			555
Total	368,790			307,882

Operating Costs and Expenses:
Lease operating	40,249			34,875
General and administrative	20,727			17,232
Exploration	11,285			8,471
Dry hole and impairment	47,403			11,623
Depreciation, depletion and amortization	100,645			87,339
Production and other taxes	21,799			9,538
Transportation and other	6,296			5,125
Total	248,404			174,203

Operating Income	120,386			133,679
Interest:
Charges	(10,211		)	(9,444		)
Income	1,210			452
Capitalized	2,197			4,548
Foreign Currency Transaction Gain (Loss)	179			(44		)
Income Tax Expense	(54,525		)	(57,551		)
Net Income	$	59,236		$	71,640

Earnings Per Common Share
Basic	$	0.93		$	1.13
Diluted	$	0.93		$	1.12

Dividends Per Common Share	$	0.0625		$	0.05

Weighted Average Number of Common Shares and Potential Common Shares Outstanding:
Basic	63,506			63,668
Diluted	64,067			64,213

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	March 31, 2005			December 31, 2004
	(Expressed in thousands, except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	231,060		$	86,456
Current investments	—			135,000
Accounts receivable	173,436			140,988
Other receivables	48,503			37,229
Federal income tax receivable	—			10,708
Inventories - product	4,234			5,062
Inventories - tubulars	20,442			17,850
Price hedge contracts	—			6,722
Other	2,894			5,395
Total current assets	480,569			445,410

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	5,017,575			4,931,264
Unevaluated properties	94,182			83,196
Other, at cost	38,986			36,492
	5,150,743			5,050,952
Accumulated depreciation, depletion and amortization
Oil and gas	(2,114,959		)	(2,017,900		)
Other	(25,061		)	(23,858		)
	(2,140,020		)	(2,041,758		)
Property and equipment, net	3,010,723			3,009,194

Other Assets:
Foreign value added taxes receivable	5,927			8,471
Other	18,959			18,034
	24,886			26,505

	$	3,516,178		$	3,481,109

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

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

Current Liabilities:
Accounts payable - operating activities	$	84,963		$	72,228
Accounts payable - investing activities	114,119			128,075
Income taxes payable	77,712			34,776
Accrued interest payable	9,156			4,550
Accrued payroll and related benefits	3,751			3,609
Price hedge contracts	14,663			—
Deferred income tax	1,582			4,919
Other	43,390			31,862
Total current liabilities	349,336			280,019

Long-Term Debt	777,305			755,000

Deferred Income Tax	597,374			601,688

Price Hedge Contracts	4,478			2,119

Asset Retirement Obligation	93,129			95,140

Other Liabilities and Deferred Credits	20,101			19,248

Total liabilities	1,841,723			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, 64,677,440 and 64,580,639 shares issued, respectively	64,677			64,581
Additional capital	947,479			943,690
Retained earnings	783,962			728,723
Deferred compensation	(9,217		)	(9,954		)
Accumulated other comprehensive income (loss)	(12,117		)	2,565
Treasury stock (2,169,159 and 55,359 shares, respectively), at cost	(100,329		)	(1,710		)
Total shareholders’ equity	1,674,455			1,727,895

	$	3,516,178		$	3,481,109

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
	2005			2004
	(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers	$	351,212		$	292,206
Operating, exploration, and general and administrative expenses paid	(84,858		)	(61,117		)
Interest paid	(5,320		)	(9,202		)
Income taxes paid	—			(1,000		)
Value added taxes (paid)/received	2,544			(700		)
Other	100			882
Net cash provided by operating activities	263,678			221,069

Cash Flows from Investing Activities:
Capital expenditures	(170,255		)	(93,767		)
Purchase of properties	(20,934		)	(20,727		)
Sale of current investments	151,750			22,597
Purchase of current investments	(16,750		)	(42,756		)
Proceeds from the sale of properties	250			229
Net cash used in investing activities	(55,939		)	(134,424		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	669,000			113,000
Payments under senior debt agreements	(944,000		)	(209,000		)
Proceeds from 2015 Notes	297,303			—
Purchase of Company stock	(81,451		)	—
Payments of cash dividends on common stock	(3,997		)	(3,191		)
Payment of debt issue costs	(2,553		)	—
Proceeds from exercise of stock options	2,765			1,824
Net cash used in financing activities	(62,933		)	(97,367		)
Effect of exchange rate changes on cash	(202		)	(21		)

Net (decrease) increase in cash and cash equivalents	144,604			(10,743		)
Cash and cash equivalents at the beginning of the year	86,456			104,474
Cash and cash equivalents at the end of the period	$	231,060		$	93,731

Reconciliation of net income to net cash provided by operating activities:
Net income	$	59,236		$	71,640
Adjustments to reconcile net income to net cash provided by operating activities -
Gains from the sales of properties	(250		)	(228		)
Depreciation, depletion and amortization	100,645			87,339
Dry hole and impairment	47,403			11,623
Interest capitalized	(2,197		)	(4,548		)
Price hedge contracts	1,156			—
Other	3,000			2,041
Deferred income taxes	882			1,439
Change in operating assets and liabilities	53,803			51,763
Net cash provided by operating activities	$	263,678		$	221,069

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Equity (Unaudited)

	For the Three Months Ended March 31,
	2005								2004
	Shareholders’ Equity					Comprehensive			Shareholders’ 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	95,401		95						76,534		77
Shares issued as compensation	1,400		1						—		—
Issued at end of period	64,677,440		64,677						63,889,817		63,890

Additional Capital:
Balance at beginning of year			943,690								914,492
Stock option activity and other			3,715								2,733
Shares issued as compensation			74								—
Balance at end of period			947,479								917,225

Retained Earnings:
Balance at beginning of year			728,723								480,576
Net income			59,236			$	59,236				71,640			$	71,640
Dividends ($0.0625 and $0.05 per common share, respectively)			(3,997		)						(3,191		)
Balance at end of period			783,962								549,025

Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year			2,565								—
Change in fair value of price hedge contracts			(13,526		)	(13,526		)			—			—
Reclassification adjustment for losses (gains) included in net income			(1,156		)	(1,156		)			—			—
Balance at end of period			(12,117		)						—

Deferred Compensation
Balance at beginning of year			(9,954		)						(3,518		)
Activity during the period			737								245
Balance at end of period			(9,217		)						(3,273		)

Comprehensive Income (Loss)						$	44,554							$	71,640

Treasury Stock:
Balance at beginning of year	(55,359	)	(1,710		)				(55,359	)	(1,710		)
Activity during the period	(2,113,800	)	(98,619		)				—		—
Balance at end of period	(2,169,159	)	(100,329		)				(55,359	)	(1,710		)

Common Stock Outstanding, at the End of the Period	62,508,281								63,834,458

Total Shareholders’ Equity			$	1,674,455							$1,525,157

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), whic h are, in the opinion of management, necessary for the fair presentation of interim results. The interim results are not necessarily indicative of results for the entire year. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

Revision in the Classification of Certain Securities—

In connection with the preparation of the December 31, 2004 10-K, the Company concluded that it was appropriate to classify our auction rate municipal bonds and variable rate municipal demand notes as current investments. Previously, such investments had been classified as cash and cash equivalents. Accordingly, the classification in the March 31, 2004 Condensed Consolidated Statement of Cash Flows has been revised to report sales of current investments of $22.6 million and purchases of current investments of $42.8 million as investing activities rather than as cash and cash equivalents. For the quarter ended March 31, 2004 net cash used in investing activities related to these current investments of $20.2 million was previously included in cash and cash equivalents in the Condensed Consolidated Statement of Cash Flows. This change in classification does not affect previously reported cash flows from operating or financing activities, or the previously reported Condensed Consolidated Statement of Income.

(2) EARNINGS PER SHARE -

Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. 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 March 31, 2005
	Income		Shares	Per Share
Basic earnings per share -	$	59,236	63,506	$	0.93
Effect of dilutive securities:
Options to purchase common shares			561
Diluted earnings per share	$	59,236	64,067	$	0.93
Antidilutive securities - Options to purchase common shares			25	$	49.02

	Three Months Ended March 31, 2004
	Income		Shares	Per Share
Basic earnings per share -	$	71,640	63,668	$	1.13
Effect of dilutive securities:
Options to purchase common shares			545
Diluted earnings per share	$	71,640	64,213	$	1.12
Antidilutive securities - Options to purchase common shares			—	$	—

(3) LONG-TERM DEBT –

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

	March 31, 2005			December 31, 2004
Senior debt -
Bank revolving credit agreement:
LIBOR based loans, borrowings at March 31, 2005 and December 31, 2004 at interest rates of 3.8105% and 3.665%, respectively	$	190,000		$	515,000
Prime based loans, borrowings at March 31, 2005 at an interest rate of 5.75%	50,000				—
LIBOR Rate Advances, borrowings at March 31, 2005 and December 31, 2004 at interest rates of 3.93% and 3.5275%, respectively	40,000			40,000
Total senior debt	280,000			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	(2,695		)	—
Total debt	777,305			755,000
Amount due within one year	—			—
Long-term debt	$	777,305		$	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, 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.

(4) 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 May 4, 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 $212.5 million of the cash and cash equivalents held by international subsidiaries as of March 31, 2005, with an associated tax liability of approximately $11.2 million (assuming 15% of such cash is subject to tax at the U.S. statutory rate).

(5) ASSET RETIREMENT OBLIGATION –

The Company’s liability for expected future costs associated with site reclamation, facilities dismantlement, and plugging and abandonment of wells for the three-month periods ended March 31, 2005 and 2004 is as follows (in thousands):

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	2005			2004
ARO as of January 1,	$	95,140		$	70,790
Liabilities incurred during the three months ended March 31,	3,226			12,249
Liabilities settled during the three months ended March 31,	(3,317		)	—
Accretion expense	1,625			1,306
Balance of ARO as of March 31,	$	96,674		$	84,345
Less: current portion of ARO	(3,545		)	—
Long-term ARO as of March 31,	$	93,129		$	84,345

For the three months ended March 31, 2005 and 2004 the Company recognized depreciation expense related to its ARC of $1,611,000 and $1,098,000, respectively.

(6) HEDGING ACTIVITIES -

As of March 31, 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 period ended March 31, 2005, activity from the Company’s price hedge contracts had no effect on oil and gas revenues. The Company did recognize a pre-tax loss of $1,156,000 due to ineffectiveness on these hedge contracts during the first quarter of 2005. Net unrealized losses on derivative instruments of $12,117,000, net of deferred taxes of $6,523,000, have been reflected as a component of other comprehensive income for the three months ended March 31, 2005. During the three-month period ended March 31, 2004, the Company held no derivative instruments and there were no hedging activities during the first quarter of 2004. Based on the fair market value of the hedge contracts as of March 31, 2005, the Company would reclassify additional pre-tax losses of approximately

$14,663,000 (approximately $9,531,000 after taxes) from accumulated other comprehensive income (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 March 31, 2005 are as follows:

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

Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
April 2005 - December 2005	4,125	$	5.50	$	8.00	$	(2,223,459	)
April 2005 - December 2005	1,375	$	6.00	$	9.30	$	(247,817	)
April 2005 - December 2005	1,375	$	6.00	$	9.25	$	(258,776	)
April 2005 - December 2005	2,750	$	6.00	$	9.25	$	(517,553	)
April 2005 - December 2005	1,375	$	6.00	$	10.25	$	(97,380	)
April 2005 - December 2005	2,750	$	6.00	$	10.30	$	(183,692	)
January 2006 - December 2006	5,475	$	5.00	$	7.50	$	(5,069,822	)
January 2006 - December 2006	3,650	$	5.50	$	8.25	$	(2,121,749	)
January 2006 - December 2006	3,650	$	5.75	$	8.27	$	(1,925,689	)

Crude Oil Contracts (Barrels)
Collar Contracts:
April 2005 - December 2005	2,750,000	$	40.00	$	62.50	$	(6,281,972	)
April 2005 - December 2005	137,500	$	43.50	$	72.00	$	(48,025	)
April 2005 - December 2005	550,000	$	43.50	$	72.50	$	(165,210	)

(a) MMBtu means million British Thermal Units.

(7) GEOGRAPHIC INFORMATION –

Financial information by geographic segment is presented below:

	Three Months Ended March 31,
	2005			2004
	(Expressed in thousands)
Revenues:
United States	$	267,152		$	235,133
Kingdom of Thailand	101,638			72,749
Other	—			—
Total	$	368,790		$	307,882

Operating Income (Loss):
United States	$	78,715		$	108,805
Kingdom of Thailand	50,103			34,762
Other	(8,432		)	(9,888		)
Total	$	120,386		$	133,679

(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 three 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 March 31,
	2005			2004

Service cost	$	827		$	627
Interest cost	535			427
Expected return on plan assets	(655		)	(663		)
Amortization of prior service cost	22			12
Amortization of net loss	317			152
	$	1,046		$	555

	Post-Retirement Medical Plan
	Three Months Ended March 31,
	2005		2004

Service cost	$	424	$	344
Interest cost	316		271
Amortization of transition obligation	76		76
Amortization of net loss	92		56
	$	908	$	747

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 FAS 106. At this time, the Company has not remeasured 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 2,000 shares during the three-month period ended March 31, 2005. The Company did not grant any Stock Awards during the three-month period ended March 31, 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 periods ending March 31, 2005 and 2004 (in thousands of dollars, except per share amounts):

		Three Months Ended March 31,
		2005			2004

Net income, as reported		$	59,236		$	71,640
Add:	Employee stock-based compensation expense, net of related tax effects, included in net income, as reported	1,010			485
Deduct:	Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects	(1,622		)	(1,672		)
Net income, pro forma		$	58,624		$	70,453

Earnings per share:
Basic - as reported		$	0.93		$	1.13
Basic - pro forma		$	0.92		$	1.11
Diluted - as reported		$	0.93		$	1.12
Diluted - pro forma		$	0.92		$	1.10

(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 quarter ended March 31, 2004 as if the acquisitions 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:

Revenues	$	319,253
Net income	74,310
Earnings per share:
Basic -	$	1.17
Diluted -	$	1.16

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. 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

Total revenue for the first quarter of 2005 was $368.7 million and net income totaled $59.2 million, or $0.93 per share. Cash flow from operations totaled $263.7 million.

The Company continues to have a strong balance sheet. During the first quarter, the Company issued $300 million of 6 5/8% Senior Subordinated Notes due 2015. Proceeds from the offering were used to reduce outstanding senior indebtedness under the Company’s revolving credit facility. Cash and current investments increased by $10 million to $231 million at March 31, 2005.

2005 Capital Budget

The Company has established a $345 million exploration and development budget (excluding property acquisitions). The Company expects to spend approximately $187 million on exploration and $158 million on development activities. The capital budget calls for the drilling of approximately 226 wells during 2005.

During the first quarter of 2005, the Company spent $146 million on exploratory and development activities and, as of March 31, 2005, had spent 42% of its 2005 capital budget. During the first quarter of 2005, 88 wells were drilled with 80 successfully completed, a 91% success rate.

Thailand and Hungary Disposition

The Company announced during the first quarter of 2005 that it would consider the sale or swap of the Company’s operations in Thailand and Hungary and has retained Goldman, Sachs & Co. to advise it on the potential transactions. International asset sale proceeds could be favorably treated by the tax provisions of the “American Jobs Creation Act of 2004”, if completed by year-end 2005. Exploration activities in Thailand and development activities in both Thailand and Hungary will run concurrently with the Company’s consideration of the sale of its operations.

Hurricane Ivan Update

Company operated Gulf of Mexico platforms did not sustain major damage as a result of Hurricane Ivan. However, damages to outside owned and operated platforms, pipelines and onshore terminals caused a meaningful component of the Company’s Gulf of Mexico production to be shut-in during the first quarter. In order to protect its cash flow, the Company has business interruption insurance for certain of the blocks affected by the shut-in. The majority of shut-in volumes were brought back online late in the first quarter. The Company recorded $11.4 million in revenue related to the business interruption insurance claim, during the first quarter.

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. Based on recent stock prices, the repurchase could represent approximately 9% to 12% of the shares outstanding at December 31, 2004. As of May 2, 2005, the Company had repurchased 3.6 million shares for approximately $170 million.

2005 Production Outlook Update

The Company currently expects that 2005 equivalent hydrocarbon production should reach within 2% of the Company’s 2004 production levels, subject to changes in circumstances, acquisitions, divestitures and many other factors.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for the first quarter of 2005 were $355,700,000, an increase of approximately 16% from oil and gas revenues of $307,327,000 for the first quarter 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.

	1st Qtr 2005 Compared to 1st Qtr 2004

Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	11,234
Production	15,039
	26,273
Crude oil and condensate -
Price	47,402
Production	(25,136		)
	22,266

Natural gas liquids	(166		)
Increase in oil and gas revenues	$	48,373

The increase in the Company’s oil and gas revenues in the first quarter of 2005, compared to the first quarter 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 cause 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. The majority of shut-in volumes were brought back online late in the first quarter.

Other Revenues

Other revenue is revenue 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 quarter of 2005, compared to the first quarter of 2004, is related primarily to $11.4 million of business interruption insurance recorded in 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.

					% Change
	1st Quarter				2005 to
	2005		2004		2004
Comparison of Increases in:
Natural Gas —
Average prices
United States (a)	$	5.97	$	5.48	9	%
Kingdom of Thailand (b)	$	2.61	$	2.50	4	%
Company-wide average price	$	5.20	$	4.79	9	%
Average daily production volumes (MMcf per day):
United States (a)	258.9		230.5		12	%
Kingdom of Thailand	76.2		69.1		10	%
Company-wide average daily production	335.1		299.6		12	%

(a) Price hedging activity had no effect on the average price of the Company’s United States natural gas production during the first quarter of 2005. The Company had no price hedging activity during the first three months of 2004. “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.

					% Change
	1st Quarter				2005 to
	2005		2004		2004
Comparison of Increases (Decreases) in:
Crude Oil and Condensate —
Average prices (a)
United States	$	43.75	$	35.28	24	%
Kingdom of Thailand	$	47.02	$	34.86	35	%
Company-wide average price	$	45.15	$	35.13	29	%
Average daily production volumes (Bbls per day):
United States (a)	26,600		34,049		(22	)%
Kingdom of Thailand (b)	18,168		15,684		16	%
Company-wide average daily production	44,768		49,733		(10	)%

Total Liquid Hydrocarbons —
Company-wide average daily production (Bbls per day)(b)	48,767		54,245		(10	)%

(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. Price hedging activity had no effect on the average price of the Company’s United States crude oil and condensate production during the first quarter of 2005. The Company had no price hedging activity during the first three months of 2004. 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 146,000 barrels less than it sold in the first quarter of 2005 and 206,000 barrels more than it sold in the first quarter of 2004.

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 first 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 first quarter of 2004. The Company also experienced increases in natural gas production volumes from the Los Mogotes field in South Texas, the Benchamas field in the Gulf of Thailand, at the Madden field in Wyoming and from the Company’s Main Pass Block 68 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

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. 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 either Malaysian TAPIS or Dated Brent crude, and are denominated in U.S. dollars.

Production. The decrease in the Company’s crude oil and condensate production during the first quarter of 2005, compared to the first quarter of 2004, resulted primarily from the shut-in of Gulf of Mexico platforms due to the effects of Hurricane Ivan and, to a lesser extent, natural production declines. These decreases were partially offset by increased crude oil and condensate production from the Company’s Kingdom of Thailand concession. The increase in Thailand crude oil and condensate production during the first quarter of 2005, compared to the first quarter of 2004, primarily reflects the shut-in of production from the Benchamas field during the first quarter of 2004 to install additional production capacity for the field.

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 March 31, 2005, the Company had approximately 254,000 net barrels stored on board the FPSO and FSO.

Costs and Expenses

	1st Quarter								% Change
	2005				2004				2005 to 2004
Comparison of Increases (Decreases) in:
Lease Operating Expenses
United States	$	28,721,000			$	23,472,000			22	%
Kingdom of Thailand	$		11,528,000		$		11,403,000		1	%
Total Lease Operating Expenses	$		40,249,000		$		34,875,000		15	%

General and Administrative Expenses	$	20,727,000			$	17,232,000			20	%
Exploration Expenses	$	11,285,000			$	8,471,000			33	%
Dry Hole and Impairment Expenses	$		47,403,000		$		11,623,000		308	%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	100,645,000			$	87,339,000			15	%
DD&A rate	$	1.75			$	1.50			17	%
Mcfe sold (a)	57,366,000				58,121,000				(1	)%
Production and Other Taxes	$	21,799,000			$	9,538,000			129	%
Transportation and Other	$	6,296,000			$	5,125,000			23	%
Interest—
Charges	$	(10,211,000		)	$	(9,444,000		)	8	%
Capitalized Interest Expense	$	2,197,000			$	4,548,000			(52	)%
Income Tax Expense	$	(54,525,000		)	$	(57,551,000		)	(5	)%

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

Lease Operating Expenses

The increase in United States lease operating expenses for the first quarter of 2005, compared to the first quarter 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 and also to increased expenses incurred on onshore properties acquired by the Company in 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 $3.4 million (net to the Company’s interest) of the Company’s Thailand lease operating expenses for the first quarters of 2005 and 2004. 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 two years.

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.61 per Mcfe for the first quarter of 2004 to $0.71 for the first quarter of 2005. The per unit of production increase is primarily related to the shut-in of domestic production due to Hurricane Ivan during the first quarter of 2005, which both increased costs and lowered production volumes for the Company during the period.

General and Administrative Expenses

The increase in general and administrative expenses for the first quarter of 2005 compared with the respective 2004 period, 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 and the related increased audit costs). On a per unit of production basis, the Company’s general and administrative expenses increased to $0.37 per Mcfe in the first quarter of 2005 from $0.30 per Mcfe in the first quarter of 2004.

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 first quarter of 2005, compared to the first quarter of 2004, resulted primarily from the commencement of 3-D seismic activity over

prospective acreage in the Company’s New Zealand concession. The Company incurred approximately $7.5 million of seismic costs in New Zealand during the first quarter of 2005. No comparable expenses were incurred in New Zealand during the first quarter of 2004.

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 first quarter of 2005, compared to the first quarter of 2004, was primarily the result of costs related to unsuccessful domestic exploratory wells located primarily in the Gulf of Mexico, totaling approximately $42.5 million. In the first quarter of 2004, the Company expensed costs related to unsuccessful exploratory wells in its Hungary concession totaling approximately $9.3 million.

Generally accepted accounting principles also require that if the expected future cash flow of the Company’s reserves on a property fall below the cost that is recorded on the Company’s books, these properties must be impaired and written down to the property’s fair value. Depending on market conditions, including the prices for oil and natural gas, and the Company’s results of operations, a similar test may be conducted at any time to determine whether impairments are appropriate. Depending on the results of this test, impairment could be required on some of the Company’s properties and this impairment could have a material negative non-cash impact on the Company’s earnings and balance sheet. During the first quarters 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 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 first quarter 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 first quarter 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 first quarter of 2005, compared to the respective 2004 period, relates primarily to Special Remuneration Benefit (SRB) taxes in the Kingdom of Thailand and to increased severance, property and franchise taxes in the United States resulting from the higher product prices received by the Company. The 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. The Company recognized SRB obligations of $10,623,000 and $1,788,000 during the first quarters of 2005 and 2004, respectively. Subject to the sale of its Thailand concession, 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 obligations, ineffectiveness on hedge contracts and various other operating expenses, none of which represents more than 10% of this expense category in either the first quarter of 2005 or the first quarter of 2004. The increase in transportation and other expense for the first quarter of 2005, compared to the first quarter of 2004, relates primarily to 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 $2,886,000 and $3,125,000 in the first quarters of 2005 and 2004, respectively.

Interest

Interest Charges. The increase in the Company’s interest charges for the first quarter of 2005, compared to the first quarter 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.

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 first quarter 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 first quarter of 2005 (approximately $169,000,000), compared to the first quarter of 2004 (approximately $216,000,000) 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 decrease in the Company’s tax expense for the first quarter of 2005, compared to the first quarter of 2004, resulted from decreased pre-tax income during the 2005 period. The Company’s consolidated effective tax rate was 48% and 45% for the first quarters of 2005 and 2004, respectively. 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 2005 period as compared to the 2004 period. The Thailand income is taxed at a rate higher than the U.S. statutory rate.

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 quarter of 2005 was $263,678,000 compared to cash flow from operating activities of $221,069,000 in the first quarter 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 quarter of 2005 was more than adequate to fund $191,189,000 in cash expenditures for capital and exploration projects for the quarter. The Company also issued $300,000,000 principal amount of 2015 Notes (see description below) and repaid other debt obligations using cash of approximately $275,000,000 (net of borrowings). The Company also paid $3,997,000 of dividends on its common stock during the first quarter of 2005. As of March 31, 2005, the Company had cash and cash equivalents of $231,060,000 (including $212,513,000 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 $780,000,000 (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 May 2, 2005, the Company had an outstanding balance of $312,000,000 under its Credit Agreement. As such, the available borrowing capacity under the Credit Agreement is currently $438,000,000.

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, 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 May 2, 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 May 4, 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 $212.5 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 $11.2 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 and Hungarian 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, has been established by the Company’s Board of Directors at $345,000,000, of which approximately $146,400,000 was incurred in the three-months ended March 31, 2005. The Company has included 226 gross wells in its 2005 capital and exploration budget (88 of which were drilled in the first quarter of 2005), including wells in the United States 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.

Stock 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 May 2, 2005, the Company had completed the purchase of 3,640,400 shares at a total cost of $170 million.

The following table sets forth certain information with respect to repurchases of the Company’s equity securities during the three months ended March 31, 2005.

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

January 26-31 2005	373,000	$	42.89	$	358,988,919
February 1-28 2005	517,200	$	44.70	$	335,852,282
March 1-31 2005	1,223,600	$	48.57	$	276,380,624

Total	2,113,800

(a) All of these shares were purchased under the plan announced on January 25, 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 March 31, 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:
April 2005 - December 2005	4,125	$	5.50	$	8.00	$	(2,223,459	)
April 2005 - December 2005	1,375	$	6.00	$	9.30	$	(247,817	)
April 2005 - December 2005	1,375	$	6.00	$	9.25	$	(258,776	)
April 2005 - December 2005	2,750	$	6.00	$	9.25	$	(517,553	)
April 2005 - December 2005	1,375	$	6.00	$	10.25	$	(97,380	)
April 2005 - December 2005	2,750	$	6.00	$	10.30	$	(183,692	)
January 2006 - December 2006	5,475	$	5.00	$	7.50	$	(5,069,822	)
January 2006 - December 2006	3,650	$	5.50	$	8.25	$	(2,121,749	)
January 2006 - December 2006	3,650	$	5.75	$	8.27	$	(1,925,689	)

Crude Oil Contracts (Barrels)
Collar Contracts:
April 2005 - December 2005	2,750,000	$	40.00	$	62.50	$	(6,281,972	)
April 2005 - December 2005	137,500	$	43.50	$	72.00	$	(48,025	)
April 2005 - December 2005	550,000	$	43.50	$	72.50	$	(165,210	)

(a) MMBtu means million British Thermal Units.

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 May 2, 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 March 31, 2005:

	2005		2006		2007		2008		2009			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0	$	0	$	0	$	0	$	280,000		$	0		$	280,000		$	280,000
Average Interest Rate	—		—		—		—		4.17		%	—			4.17		%	—
Fixed Rate	$	0	$	0	$	0	$	0	$	0		$	500,000		$	500,000		$	512,125
Average Interest Rate	—		—		—		—		—			7.28		%	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 6. Exhibits

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).

4.1 Indenture, dated as of March 29, 2005 between Pogo Producing Company and The Bank of New York Trust Company, N.A., as Trustee.

4.2 Form of 6.625% Senior Subordinated Note (included as Exhibit A to Exhibit 4.1).

4.3 Registration Rights Agreement dated March 29, 2005, by and among Pogo Producing Company and the parties thereto.

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: May 4, 2005