Edgar Filing: POGO PRODUCING CO

e10-q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

[X] Quarterly report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended March 31, 2002 or
[ ] 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 (State or Other Jurisdiction of Incorporation or Organization)		74-1659398 (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 [X] No [ ]


Registrant’s number of common shares outstanding as of May 3, 2002:			54,311,820

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION
	ITEM 1. FINANCIAL STATEMENTS
		Consolidated Statements of Income (Unaudited)
		Consolidated Balance Sheets (Unaudited)
		Consolidated Balance Sheets (Unaudited)
		Condensed Consolidated Statements of Cash Flows (Unaudited)
		Consolidated Statements of Shareholders’ Equity (Unaudited)
		Notes to Consolidated Financial Statements (Unaudited)
	ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	ITEM 3. Quantitative and Qualitative Disclosure about Market Risk.
Part II. Other Information
	Item 6. Exhibits and Reports on Form 8-K
Signatures

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)


			Three Months Ended
			March 31,

			2002			2001

			(Expressed in thousands,
			except per share amounts)
Revenues:
	Oil and gas		$	142,297		$	163,913
	Pipeline sales			78			4,226
	Gains (losses) on sales and other			535			1,723

		Total		142,910			169,862

Operating Costs and Expenses:
	Lease operating			31,283			25,827
	Pipeline operating and natural gas purchases			181			4,020
	General and administrative			11,542			8,208
	Exploration			(176	)		6,948
	Dry hole and impairment			4,995			10,767
	Depreciation, depletion and amortization			65,806			37,068

		Total		113,631			92,838

Operating Income				29,279			77,024

Interest:
	Charges			(14,588	)		(11,304	)
	Income			378			1,302
	Capitalized			6,653			4,526
Minority Interest — Dividends and costs associated with preferred securities of a subsidiary trust				(2,502	)		(2,497	)
Foreign Currency Transaction Gain (Loss)				672			(585	)

Income Before Taxes				19,892			68,466
Income Tax Expense				(10,867	)		(28,520	)

Net income			$	9,025		$	39,946

Earnings Per Common Share
	Basic		$	0.17		$	0.93

	Diluted		$	0.17		$	0.80

Dividends Per Common Share			$	0.03		$	0.03

Weighted Average Number of Common Shares and Potential Common Shares Outstanding:
		Basic		53,750			43,145
		Diluted		54,487			53,122

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)


					March 31,			December 31,
					2002			2001

					(Expressed in thousands
					except share amounts)
				Assets
Current Assets:
		Cash and cash equivalents			$	99,985		$	94,294
		Accounts receivable				70,838			52,440
		Other receivables				31,636			32,159
		Federal income tax receivable				3,549			27,441
		Deferred income tax				20,915			25,712
		Inventories — Product				4,715			3,129
		Inventories — Tubulars				9,117			8,430
		Price hedge contracts				14,091			34,275
		Other				2,104			1,970

			Total current assets			256,950			279,850

Property and Equipment:
		Oil and gas, on the basis of successful efforts accounting
			Proved properties			2,995,403			2,956,673
			Unevaluated properties			259,305			257,158
		Pipelines, at cost				775			775
		Other, at cost				22,935			21,638

						3,278,418			3,236,244

		Accumulated depreciation, depletion and amortization
			Oil and gas			(1,182,615	)		(1,133,560	)
			Pipelines			(748	)		(739	)
			Other			(11,868	)		(11,217	)

						(1,195,231	)		(1,145,516	)

	Property and equipment, net					2,083,187			2,090,728

Other Assets:
		Deferred income tax				11,728			13,359
		Debt issue expenses				15,113			15,565
		Foreign value added taxes receivable				8,560			6,200
		Other				19,841			20,706

						55,242			55,830

					$	2,395,379		$	2,426,408

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)


				March 31,			December 31,
				2002			2001

				(Expressed in thousands
				except share amounts)
			Liabilities and Shareholders’ Equity
Current Liabilities:
	Accounts payable — operating activities			$	33,675		$	34,962
	Accounts payable — investing activities				65,059			94,523
	Accrued interest payable				15,227			11,450
	Foreign income taxes payable				11,285			7,966
	Accrued dividends associated with preferred securities of a subsidiary trust				813			813
	Accrued payroll and related benefits				2,905			2,670
	Deferred income tax				5,324			3,875
	Other				1,471			1,892

		Total current liabilities			135,759			158,151

Long-Term Debt					789,989			794,990
Deferred Income Tax					482,347			488,639
Deferred Credits					13,718			14,657

		Total liabilities			1,421,813			1,456,437

Minority Interest:
	Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust, net of unamortized issue expenses				145,146			145,086

Shareholders’ Equity:
	Preferred stock, $1 par; 2,000,000 shares authorized				—			—
	Common stock, $1 par; 200,000,000 shares authorized, 54,027,463 and 53,690,827 shares issued, respectively				54,027			53,691
	Additional capital				666,402			659,227
	Retained earnings				109,433			102,019
	Accumulated other comprehensive income (loss)				(1,118	)		10,272
	Treasury stock (15,575 shares), at cost				(324	)		(324	)

		Total shareholders’ equity			828,420			824,885

				$	2,395,379		$	2,426,408

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)


				Three Months Ended
				March 31,

				2002			2001

				(Expressed in thousands)
Cash Flows from Operating Activities:
	Cash received from customers			$	115,219		$	182,097
	Operating, exploration, and general and administrative expenses paid				(42,624	)		(34,531	)
	Interest paid				(10,252	)		(8,326	)
	Federal income taxes received (paid)				25,103			(6,500	)
	Value added taxes paid				(2,360	)		(1,313	)
	Price hedge contracts				11,672			—
	Other				(692	)		3,621

		Net cash provided by operating activities			96,066			135,048

Cash Flows from Investing Activities:
	Capital expenditures				(87,491	)		(80,150	)
	Acquisition of NORIC, net of $21,235 cash acquired				—			(323,476	)
	Proceeds from the sale of properties				14			2,748

		Net cash used in investing activities			(87,477	)		(400,878	)

Cash Flows from Financing Activities:
	Borrowings under senior debt agreements				183,999			668,000
	Payments under senior debt agreements				(189,000	)		(337,000	)
	Payment of North Central senior debt acquired				—			(78,600	)
	Payments of cash dividends on common stock				(1,611	)		(1,223	)
	Payments of preferred dividends of a subsidiary trust				(2,438	)		(2,438	)
	Payment of financing issue expenses				(111	)		(4,583	)
	Proceeds from exercise of stock options and other				6,300			5,330

		Net cash provided by (used in) financing activities			(2,861	)		249,486

Effect of exchange rate changes on cash					(37	)		(770	)

Net increase (decrease) in cash and cash equivalents					5,691			(17,114	)
Cash and cash equivalents at the beginning of the year					94,294			81,510

Cash and cash equivalents at the end of the period				$	99,985		$	64,396

Reconciliation of net income to net cash provided by operating activities:
	Net income			$	9,025		$	39,946
		Adjustments to reconcile net income to net cash provided by operating activities -
			Minority interest		2,502			2,497
			Foreign currency transaction (gains) losses		(672	)		585
			(Gains) losses from the sales of properties		262			(2,672	)
			Depreciation, depletion and amortization		65,806			37,068
			Dry hole and impairment		4,995			10,767
			Interest capitalized		(6,653	)		(4,526	)
			Price hedge contracts		2,662			720
			Deferred federal income taxes		7,546			20,622
			Change in operating assets and liabilities		10,593			30,041

Net cash provided by operating activities				$	96,066		$	135,048

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,

		2002									2001

		Shareholders'									Shareholders'
		Equity						Compre-			Equity						Compre-
								hensive									hensive
		Shares			Amount			Income			Shares			Amount			Income

					(Expressed in thousands, except share amounts)
Common Stock:
	$1.00 par-200,000,000 and 100,000,000 shares authorized, respectively
	Balance at beginning of year		53,690,827		$	53,691						40,659,591		$	40,660
	Shares issued for acquisition of NORIC		—			—						12,615,816			12,616
	Stock options exercised		336,636			336						308,829			309

	Issued at end of period		54,027,463			54,027						53,584,236			53,585

Additional Capital:
	Balance at beginning of year					659,227									298,885
	Shares issued for acquisition of NORIC					—									351,729
	Stock options exercised					7,175									6,428

	Balance at end of period					666,402									657,042

Retained Earnings:
	Balance at beginning of year					102,019									20,112
	Net income					9,025		$	9,025						39,946		$	39,946
	Dividends ($0.03 per common share)					(1,611	)								(1,223	)

	Balance at end of period					109,433									58,835

Accumulated Other Comprehensive Income (Loss):
	Balance at beginning of year					10,272									(1,062	)
	Exchange gains on Canadian currency								—						609			609
	Unrealized loss on price hedge contracts					(11,390	)		(11,390	)					(820	)		(820	)
	Cumulative effect of change in accounting principle					—			—						(2,438	)		(2,438	)

	Balance at end of period					(1,118	)								(3,711	)

Comprehensive Income (Loss)								$	(2,365	)							$	37,297

Treasury Stock:
	Balance at beginning of year		(15,575	)		(324	)					(15,575	)		(324	)
	Activity during the period		—			—						—			—

	Balance at end of period		(15,575	)		(324	)					(15,575	)		(324	)

Common Stock Outstanding, at the End of the Period			54,011,888									53,568,661

Total Shareholders’ Equity					$	828,420								$	765,427

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(1) GENERAL INFORMATION -

The consolidated financial statements included herein have been prepared by Pogo Producing Company (the “Company”) without audit and include all adjustments (of a normal and recurring nature) which are, in the opinion of management, necessary for the fair presentation of interim results. The interim results are not necessarily indicative of results for the entire year. Certain prior year amounts have been reclassified to conform with current year presentation. Refer to the Consolidated Statements of Shareholders’ Equity for an analysis of Other Comprehensive Income (Loss), which was ($2,365,000) and $37,297,000, respectively, for the three months ended March 31, 2002 and 2001. 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, 2001.

(2) INCOME TAXES -

The Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries where the Company’s present intention is to reinvest the unremitted earnings in its foreign operations. Unremitted earnings of foreign subsidiaries for which U.S. income taxes have not been provided are approximately $63,000,000 at March 31, 2002. It is not practical to determine the amount of U.S. income taxes that would be payable upon remittance of the assets that represent those earnings.

(3) HEDGING ACTIVITIES -

In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). In June 2000, the FASB issued SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS 133 effective January 1, 2001. Based on the nature of the Company’s derivative instruments currently outstanding and the historical volatility of oil and gas commodity prices, the Company expects that SFAS 133 could increase volatility in the Company’s earnings and other comprehensive income for future periods.

SFAS 133, in part, allows special hedge accounting. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.

SFAS 133 requires that as of the date of initial adoption, the difference between the market value of derivative instruments and the previous carrying amount of these derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. Based on interpretive guidance issued during the first quarter of 2001, the Company determined that the cumulative effect of adopting SFAS 133 should be recorded in other comprehensive income. As such, effective January 1, 2001, the Company recorded an unrealized loss of $2,438,000, net of deferred taxes of $1,313,000, in other comprehensive income (loss). Unrealized losses on derivative instruments arising during the three months ended March 31, 2002 of $11,390,000, net of deferred taxes of $6,133,000, have been reflected as a component of other comprehensive income (loss). Based on the fair market value of the hedge contracts as of March 31, 2002, the Company would reclassify additional pre-tax losses of approximately $1,720,000 (approximately $1,118,000 net of taxes) from other comprehensive income (loss) in shareholders’ equity, to net income during the next nine months.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(3) HEDGING ACTIVITIES (continued) -

As of March 31, 2002, the Company held options to sell 70 million cubic feet of natural gas production per day for the period from April 1, 2002 through December 31, 2002, at a sales price of $4.00 per MMBtu. The Company has designated these contracts as cash flow hedges designed to give the Company the right, but not the obligation, to sell natural gas. These contracts are designed to guarantee the Company a minimum “floor” price for the contracted volumes of production without limiting the Company’s participation in price increases during the covered period. As of March 31, 2002, the Company was a party to the following hedging arrangements:

NYMEX

Volume

Contract

Fair

Price per

Market

Contract Period

MMBtu(a)

Value (b)

April 2002 - December 2002

19,250

4.00

14,091,000

(a)		MMBtu means million British Thermal Units.

(b)		Fair Market value is calculated using prices derived from NYMEX futures contract prices existing at March 31, 2002.

These hedging transactions are settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days, or occasionally the penultimate trading day, of a particular contract month. For any particular floor transaction, the counter-party 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. The Company is not required to make any payment in connection with the settlement of a floor transaction.

As of March 31, 2002 the Company was not a party to any commodity price hedging contracts with respect to any of its current or future crude oil and condensate production.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(4) BUSINESS SEGMENT INFORMATION -

Financial information by operating segment is presented below:


				Company		Oil and Gas		Pipelines		Other

						(Expressed in thousands)
Long-Lived Assets:
		As of March 31, 2002:
			United States	$	1,746,262	$	1,738,744	$	27	$	7,491
			Kingdom of Thailand		336,541		333,249		—		3,292
			Other		384		384		—		—

			Total	$	2,083,187	$	2,072,377	$	27	$	10,783

		As of December 31, 2001:
			United States	$	1,748,046	$	1,741,035	$	36	$	6,975
			Kingdom of Thailand		342,411		338,965		—		3,446
			Other		271		271		—		—

			Total	$	2,090,728	$	2,080,271	$	36	$	10,421

Capital Expenditures:
	(including interest capitalized)
		For the three months ended March 31, 2002
			United States	$	45,353	$	44,211	$	—	$	1,142
			Kingdom of Thailand		11,721		11,721		—		—
			Other		140		140		—		—

			Total	$	57,214	$	56,072	$	—	$	1,142

		For the year ended December 31, 2001
			United States	$	1,458,549	$	1,453,756	$	—	$	4,793
			Kingdom of Thailand		73,192		73,192		—		—
			Canada and other		3,071		3,071		—		—

			Total	$	1,534,812	$	1,530,019	$	—	$	4,793

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(4) BUSINESS SEGMENT INFORMATION (continued)-


			Company			Oil and Gas			Pipelines			Other

						(Expressed in thousands)
Revenues:
	For the three months ended March 31, 2002
		United States	$	101,695		$	101,079		$	78		$	538
		Kingdom of Thailand		41,217			41,218			—			(1	)
		Other		(2	)		—			—			(2	)

		Total	$	142,910		$	142,297		$	78		$	535

	For the three months ended March 31, 2001
		United States	$	119,472		$	113,572		$	4,226		$	1,674
		Kingdom of Thailand		47,994			47,945			—			49
		Canada and other		2,396			2,396			—			—

		Total	$	169,862		$	163,913		$	4,226		$	1,723

Depreciation, depletion and amortization expense:
	For the three months ended March 31, 2002
		United States	$	49,279		$	48,644		$	9		$	626
		Kingdom of Thailand		16,495			16,330			—			165
		Other		32			—			—			32

		Total	$	65,806		$	64,974		$	9		$	823

	For the three months ended March 31, 2001
		United States	$	22,739		$	22,387		$	59		$	293
		Kingdom of Thailand		13,427			13,341			—			86
		Canada and other		902			893			—			9

		Total	$	37,068		$	36,621		$	59		$	388

Operating Income (Loss):
	For the three months ended March 31, 2002
		United States	$	13,673		$	13,257		$	(122	)	$	538
		Kingdom of Thailand		16,120			16,121			—			(1	)
		Other		(514	)		(512	)		—			(2	)

		Total	$	29,279		$	28,866		$	(122	)	$	535

	For the three months ended March 31, 2001
		United States	$	58,647		$	56,985		$	(12	)	$	1,674
		Kingdom of Thailand		23,747			23,698			—			49
		Canada and other		(5,370	)		(5,370	)		—			—

		Total	$	77,024		$	75,313		$	(12	)	$	1,723

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(5) 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						Three Months Ended
		March 31, 2002						March 31, 2001

		Income		Shares		Per Share		Income		Shares		Per Share

Basic earnings per share -		$	9,025		53,750	$	0.17	$	39,946		43,145		$	0.93

Effect of dilutive securities:
	Options to purchase common shares		—		737				—		935
	2006 Notes		—		—				1,028		2,726
	Trust Preferred Securities		—		—				1,584		6,316

Diluted earnings per share		$	9,025		54,487	$	0.17	$	42,558		53,122		$	0.80

Antidilutive securities -
	Options to purchase common shares		—		262	$	33.82		—		270		$	27.93
	2006 Notes	$	1,028		2,726	$	0.38		—		—			—
	Trust Preferred Securities	$	1,584		6,316	$	0.25		—		—			—

(6) RECENT ACCOUNTING PRONOUNCEMENT -

The Financial Accounting Standards Board has recently issued a new pronouncement, Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations”. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount a gain or loss is recognized. The Company currently intends to adopt this standard on January 1, 2003. Adoption of the standard will result in recording a cumulative effect of a change in accounting principle to earnings in the period of adoption. SFAS 143 will impact the way in which the Company, and most of the oil and gas industry, accounts for its future abandonment obligations. The Company has not yet quantified the financial statement impact from adoption of this new standard.

(7) ACQUISITION -

On March 14, 2001, the merger of the Company and NORIC Corporation was consummated. As a result of the merger, the Company acquired all of the outstanding capital stock of North Central Oil Company, which was the principal asset of NORIC. North Central was an independent domestic oil and gas exploration and production company. The merger was accounted for using the purchase method of accounting. Accordingly, the purchase price was allocated to the net assets acquired based upon their estimated fair market values at the date of acquisition. Commencing March 14, 2001, North Central’s operations are consolidated with the operations of the Company. Pursuant to the merger agreement among the Company and NORIC and certain NORIC shareholders dated as of November 19, 2000, former shareholders received 12,615,816 shares of the Company’s common stock and approximately $344,711,000 in cash. In addition, at the closing the Company repaid all $78,600,000 principal amount of North Central’s existing bank debt. The sources of funds used in connection with the merger included cash on hand at the Company and NORIC and borrowings under the Company’s credit agreement.

The following summary presents unaudited pro forma consolidated results of operations as if the acquisition had occurred at the beginning of 2001. The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results of North Central, such as increased depreciation, depletion and amortization expense resulting from the allocation of

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(7) ACQUISITION (continued)-

fair market value to oil and gas properties acquired and increased interest expense on acquisition debt. The unaudited pro forma financial information is not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor are they necessarily indicative of future operating results.


		Three Months
		Ended
		March 31, 2001

Revenues		$	232,842
Net income		$	56,864
Earnings per share
	Basic -	$	1.07
	Diluted -	$	0.94

POGO PRODUCING COMPANY AND SUBSIDIARIES

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, 2001. Certain statements contained herein are prospective and therefore should be considered “Forward Looking Statements.” As further discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, 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.

On March 14, 2001, the previously announced merger of Pogo Producing Company (the “Company”) and NORIC Corporation (“NORIC”) was consummated. As a result of the merger, the Company acquired all of the outstanding capital stock of North Central Oil Corporation (“North Central”), an independent domestic oil and gas exploration and production company, which was the principal asset of NORIC. The merger was accounted for using the purchase method of accounting. Commencing March 14, 2001, the results of North Central’s operations are consolidated with the Company’s. Pursuant to the merger agreement among the Company, NORIC and certain NORIC shareholders dated as of November 19, 2000, former shareholders of NORIC received 12,615,816 shares of the Company’s common stock and approximately $344,711,000 in cash. In addition, at the closing the Company repaid all $78,600,000 principal amount of North Central’s existing bank debt. The sources of funds used in connection with the merger included cash on hand at the Company and NORIC and borrowings under the Company’s revolving credit agreement.

Results of Operations

Net Income

The Company reported net income for the first quarter of 2002 of $9,025,000 or $0.17 per share (on both a basic and a diluted basis), compared to net income for the first quarter of 2001 of $39,946,000 or $0.93 per share ($42,558,000 or $0.80 per share on a diluted basis). This decrease in net income was primarily related to decreases in the average prices that the Company received for its natural gas, crude oil and condensate production volumes, partially offset by increased production from the Company’s Gulf of Mexico and Thailand properties, as well as production from properties acquired in the North Central acquisition which closed on March 14, 2001.

Earnings per common share are based on the weighted average number of common shares outstanding for the first quarter of 2002 of 53,750,000 (54,487,000 on a diluted basis), compared to 43,145,000 (53,122,000 on a diluted basis) for the first quarter of 2001. The increase in the weighted average number of common shares outstanding for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from the issuance of common stock in connection with the merger with NORIC on March 14, 2001 and, to a much lesser extent, the exercise of stock options pursuant to the Company’s incentive plans. Earnings per share computations on a diluted basis for both periods reflect additional shares of common stock issuable upon the assumed exercise of options to purchase common shares under the Company’s incentive plans, less treasury shares that are assumed to have been purchased by the Company from the option proceeds. Earnings per share computations on a diluted basis for the first quarter of 2001 also reflects additional shares of common stock issuable upon the assumed conversion of Pogo Trust I’s 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the “Trust Preferred Securities”) and the Company’s 5 1/2% Convertible Subordinated Notes due 2006 (the “2006 Notes”).

Total Revenues

The Company’s total revenues for the first quarter of 2002 were $142,910,000, a decrease of approximately 16% from total revenues of $169,862,000 for the first quarter of 2001. The decrease in the Company’s total revenues resulted primarily from decreased oil and gas revenues and, to a much lesser extent, a decrease in pipeline sales revenue and a loss on sales of properties, both of which are attributable to the Company’s sale of certain non-strategic properties.

Oil and Gas Revenues

The Company’s oil and gas revenues for the first quarter of 2002 were $142,297,000, a decrease of approximately 13% from oil and gas revenues of $163,913,000 for the first quarter of 2001. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in thousands) between 2002 and 2001:


		1st Qtr 2002
Increase (decrease) in oil and gas revenues		Compared to
resulting from variances in:		1st Qtr 2001

Natural gas —
	Price	$	(48,047	)
	Production		19,502

			(28,545	)

Crude oil and condensate —
	Price		(17,245	)
	Production		22,093

			4,848

Natural Gas Liquids (“NGL”)			2,081

	Decrease in oil and gas revenues	$	(21,616	)

The decrease in the Company’s oil and gas revenues in the first quarter of 2002, compared to the first quarter of 2001, was related to a decrease in the average prices that the Company received for its natural gas, crude oil and condensate production, that was partially offset by an increase in its natural gas, crude oil and condensate production and, to a much lesser extent, increased production of NGL.


Comparison of Increases (Decreases) in:			1st Qtr		1st Qtr		% Change
Natural Gas —			2002		2001		2002 to 2001

Average prices
	North America (a)		$	2.80	$	7.02		(60	)%
	Kingdom of Thailand (b)		$	2.32	$	2.45		(5	)%
		Company-wide average price	$	2.67	$	5.59		(52	)%
Average daily production volumes (MMcf per day)
	North America (a)			190.9		125.3		52	%
	Kingdom of Thailand			73.1		57.4		27	%

		Company-wide average daily production		264.0		182.7		45	%

(a)		North American average prices and production reflect production from the United States and Canada and the impact of the Company’s price hedging activity. The Company sold its operations in Canada effective August 31, 2001, as part of an asset rationalization process. Consequently, results for the first quarter of 2002 do not reflect any production from Canada. “MMcf” stand 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.


Comparison of Increases (Decreases) in:					1st Qtr		1st Qtr		% Change
Crude Oil and Condensate —					2002		2001		2002 to 2001

	Average prices
			North America (a)		$	20.24	$	28.02		(28	)%
			Kingdom of Thailand		$	19.67	$	25.22		(22	)%
				Company-wide average price	$	20.04	$	26.54		(24	)%
	Average daily production volumes (Bbls per day)
			North America (a)			27,045		13,916		94	%
			Kingdom of Thailand (b)			16,519		13,918		19	%

				Company-wide average daily production (b)		43,564		27,834		57	%

Total Liquid Hydrocarbons —
		Company-wide average daily production (Bbls per day)(b)				47,175		28,538		65	%

(a)		North American average prices and production reflect production from the United States and Canada. The Company sold its operations in Canada effective August 31, 2001, as part of an asset rationalization process. Consequently, results for the first quarter of 2002 do not reflect any production from Canada. “Bbls” stand for million 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, as currently interpreted, reported revenues are based on sales volumes. However, the Company believes that actual production volumes are a more meaningful measure of the Company’s operating results and therefore reports production volumes as part of its operating results. The Company produced 166,737 barrels more than it sold in the first quarter of 2002 and produced 146,000 barrels less than it sold in the first quarter of 2001.

Natural Gas

Thailand Prices. The price that the Company receives under the gas sales agreement with PTT Public Company Limited (“PTT”) is based upon a formula which 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 price that the Company receives from PTT under a memorandum of understanding that it executed in 2001 for certain volumes it produces in excess of the contractual amount under the gas sales agreement is equal to 88% of the then current price under the gas sales agreement. The decrease in the average price that the Company received for its natural gas production in the Kingdom of Thailand for the first quarter of 2002, compared to the first quarter of 2001, reflects positive adjustments under the gas sales agreement that were more than offset by a portion of the production being sold under the memorandum of understanding.

North American Production. The increase in the Company’s domestic natural gas production during the first quarter of 2002, compared to the first quarter of 2001, was primarily related to production from properties acquired in the North Central acquisition and, to a lesser extent, successful development programs in the Company’s Gulf of Mexico properties, including its Mississippi Canyon Blocks 661/705 Field, that was partially offset by natural production declines at certain other properties.

Thailand Production. The increase in the Company’s Thailand natural gas production during the first quarter of 2002, compared to the first quarter of 2001, was primarily related to increased production under the memorandum of understanding.

Crude Oil and Condensate

Thailand Prices. Since the inception of production from the Company’s properties located in the Gulf of Thailand, crude oil and condensate have been stored on storage vessels (an FPSO in the Tantawan field and an FSO in the Benchamas field) until an economic quantity was accumulated for offloading and sale. 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 dollars. In addition, the Company is generally paid for its crude oil and condensate production from Thailand in dollars.

North American Production. The increase in the Company’s domestic crude oil and condensate production during the first quarter of 2002, compared to the first quarter of 2001, primarily related to commencement of production from the Company’s Main Pass Block 61/62 Field and its Ewing Bank Block 871 Field, that was partially offset by natural production decline at certain of the Company’s other properties.

Thailand Production. The increase in the Company’s Thailand production for the first quarter of 2002, compared to the first quarter of 2001, primarily related to the continuing success of the Company’s development program in the Benchamas field and, to a lesser extent, increased crude oil and condensate production associated with the increased natural gas production permitted by the memorandum of understanding. Due to a change in interpretation of an accounting principle, the Company now records its oil production in Thailand at the time of sale, rather than when produced, as it had previously. In accordance with generally accepted accounting principles, as currently interpreted, 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. The Company believes that actual production volumes are a more meaningful measure of the Company’s operating results than sales volumes and therefore reports production volumes as part of its operating results. The Company produced 166,737 barrels more than it sold in the first quarter of 2002 and produced 146,000 barrels less than it sold in the first quarter of 2001. As of March 31, 2002, the Company had approximately 427,000 net barrels stored on board the FPSO and FSO.

NGL Production. The Company’s oil and gas revenues, and its total liquid hydrocarbon production, reflect the production and sale by the Company of NGL, which are liquid products extracted from natural gas production. The increase in NGL revenues for the first quarter of 2002, compared with the first quarter of 2001, primarily related to NGL removed from the Company’s natural gas production from its Mississippi Canyon Blocks 661/705 Field and, to a lesser extent the decision by the Company to extract NGL from more of its other natural gas production due to the economics that favor removing the NGL from the natural gas stream when prices are lower, and leaving it in the natural gas stream when prices are higher.

Costs and Expenses


			1st Qtr			1st Qtr		% Change
Comparison of Increases (Decreases) in:			2002			2001		2002 to 2001

Lease Operating Expenses
	North America (a)		$	22,766,000		$	17,050,000		34	%
	Kingdom of Thailand		$	8,517,000		$	8,777,000		(3	)%

		Total Lease Operating Expenses	$	31,283,000		$	25,827,000		21	%

Pipeline Operating and Natural Gas Purchases			$	181,000		$	4,020,000		(96	)%
General and Administrative Expenses			$	11,542,000		$	8,208,000		41	%
Exploration Expenses			$	(176,000	)	$	6,948,000		N/A
Dry Hole and Impairment Expenses			$	4,995,000		$	10,767,000		(54	)%

(Table Continued on Next Page)


			1st Qtr			1st Qtr			% Change
Comparison of Increases (Decreases) in:			2002			2001			2002 to 2001

Depreciation, Depletion and Amortization (DD&A) Expenses			$	65,806,000		$	37,068,000			78	%
	DD&A Rate		$	1.35		$	1.12			21	%
	Mcfe Produced (b)			48,234,000			31,854,000			51	%
Interest —
		Charges	$	(14,588,000	)	$	(11,304,000	)		29	%
		Income	$	378,000		$	1,302,000			(71	)%
		Capitalized Interest	$	6,653,000		$	4,526,000			47	%
Minority Interest — Dividends and Costs			$	2,502,000		$	2,497,000			0	%
Foreign Currency Transaction Gain (Loss)			$	672,000		$	(585,000	)		N/A
Income Tax Expense			$	(10,867,000	)	$	(28,520,000	)		(62	)%

(a)		The Company sold its operations in Canada effective August 31, 2001, as part of an asset rationalization process. Consequently, results for the first quarter of 2002 do not reflect any production from Canada.

(b)		“Mcfe” stands for thousand of cubic feet equivalent.

Lease Operating Expenses

The increase in North American lease operating expenses for the first quarter of 2002, compared to the first quarter of 2001, primarily related to increased costs associated with the acquisition of North Central and increased product transportation and processing expenses related to increased production from the Company’s Gulf of Mexico properties, that were partially offset by decreased severance taxes and lease maintenance costs in the Gulf of Mexico and the Company’s Western Division properties. The slight decrease in lease operating expenses in the Kingdom of Thailand for the first quarter of 2002, compared to the first quarter of 2001, related to decreased maintenance and workover activity in the Benchamas Field. A substantial portion of the Company’s lease operating expenses in the Kingdom of Thailand relates to the lease payments made in connection with the bareboat charter of the FPSO for the Tantawan field and the FSO for the Benchamas field. Collectively, these lease payments accounted for $3,393,000 and $3,716,000 of the Company’s Thailand lease operating expenses for the first quarter of 2002 and the first quarter of 2001, respectively.

Notwithstanding the overall increase in lease operating expenses, on a per unit of production basis, the Company’s total lease operating expenses decreased from an average of $0.81 per Mcfe for the first quarter of 2001 to $0.65 per Mcfe for the first quarter of 2002.

Pipeline Operating and Natural Gas Purchases

Revenue from the sale of natural gas purchased for resale is reported as revenue under “Pipeline sales and other.” The cost of purchasing natural gas for resale, together with the costs of operating the pipeline carrying the natural gas is recorded as an expense under “Pipeline operating and natural gas purchases.” Primarily all of the natural gas purchased and resold by the Company was transported on Pogo Onshore Pipeline Company’s Saginaw pipeline, which was sold during the fourth quarter of 2001 as part of the Company’s ongoing asset rationalization process. Consequently, there is no meaningful comparison between the first quarter of 2001 and the first quarter of 2002.

General and Administrative Expenses

The increase in general and administrative expenses for the first quarter of 2002, compared with the first quarter of 2001, primarily related to a $1,889,000 retroactive adjustment for the over accrual of certain payroll costs in the first quarter of 2001 for which no comparable adjustments were recorded in the first quarter of 2002, by increased expenses associated with the Company’s acquisition of North Central and its employees, as well as an increase in the size of the Company’s work force and normal salary and concomitant benefit expense adjustments. Notwithstanding the overall increase in general and administrative expenses, on a per unit of production basis, the Company’s general and administrative expenses declined from $0.25 per Mcfe for the first quarter of 2001 to $0.24 per Mcfe for the first quarter of 2002.

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 which are expensed as incurred. The credit for exploration expenses for the first quarter of 2002 resulted from the rebate of a delay rental ($1,327,000 net to the Company) that was paid by the Company’s Thai subsidiary to the Kingdom of Thailand, which was returned when certain contractual obligations under the Company’s concession license were satisfied. In addition, exploration expenses for the first quarter of 2001 included the cost of conducting two major 3-D projects in Hungary, seismic operations in Canada and in the Gulf of Mexico, for which no comparable expenses were experienced during the first quarter of 2002.

Dry Hole and Impairment

The decrease in the Company’s dry hole and impairment expense for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from the absence of any dry hole expenses during the first quarter of 2002. This improvement was partially offset by increased impairment expenses related to miscellaneous impairments taken on twenty-four of the Company’s minor prospects and leases.

Depreciation, Depletion and Amortization Expenses

The increase in the Company’s Depreciation, Depletion and Amortization (“DD&A”) expense for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from an increase in the Company’s liquid hydrocarbon and natural gas production and, to a lesser extent, an increase in the Company’s composite DD&A rate.

The increase in the composite DD&A rate for all of the Company’s producing fields for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from production from fields acquired in the North Central acquisition that, because they were valued at fair market value in connection with the acquisition, contribute a DD&A rate which is higher than the Company’s recent historic average. The increase was partially offset by an increased percentage of the Company’s production coming from certain of the Company’s fields that have DD&A rates that are lower than the Company’s recent historical composite rate (principally the Company’s new Main Pass Block 61/62 Field and its Benchamas Field) and a corresponding decrease 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 DD&A rate.

Interest

Interest Charges. The increase in the Company’s interest charges for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from an increase in the average amount of the Company’s outstanding debt related to the acquisition of North Central, partially offset by a decline in the average interest rate on the outstanding debt.

Interest Income. The decrease in the Company’s interest income for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from a decrease in the amount of the cash and cash equivalents temporarily invested and, to a lesser extent, a decline in the interest rate received on such investments. Except for working capital needs, a significant portion of the Company’s cash and cash and cash equivalents on hand during the first quarter of 2001 were used to fund the North Central acquisition. The cash and cash equivalents on the Company’s balance sheet at March 31, 2002, are primarily held by the Company’s international subsidiaries for future investment overseas, in part due to the negative tax effects that would result from the repatriation of these funds.

Capitalized Interest. The increase in capitalized interest for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from an increase in the amount of capital expenditures subject to interest capitalization during the first quarter of 2002 (approximately $377,000,000), compared to the first quarter of 2001 (approximately $226,409,000), partially offset by a decrease in the weighted average borrowing rate that the Company applies to its capital expenditures to arrive at the total amount of capitalized interest. A substantial percentage of the Company’s capitalized interest related to unevaluated properties acquired in the North Central acquisition and capital expenditures for the development of the Benchamas field in the Gulf of Thailand and several development projects in the Gulf of Mexico. The Company currently expects the amount of capital expenditures subject to interest capitalization to decrease during 2002 due to completion of platforms and facilities construction in the Gulf of Thailand and the Gulf of Mexico.

Minority Interest — Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust

Pogo Trust I, a subsidiary trust, issued $150,000,000 of Trust Preferred Securities on June 2, 1999. The amounts recorded for the first quarter of 2002 and the first quarter of 2001, respectively, under “Minority Interest - Dividends and costs associated with preferred securities of a subsidiary trust” principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities.

Foreign Currency Transaction Gain (Loss)

The foreign currency transaction gain reported for the first quarter of 2002 and the loss reported for the first quarter of 2001 each resulted primarily from the fluctuation against the U.S. dollar of cash and other monetary assets and liabilities denominated in Thai Baht that were on the Company’s Thai subsidiaries financial statements during the respective periods. The Company cannot predict what the Thai Baht to U.S. dollar exchange rate will be in the future. As of March 31, 2002, the Company was not a party to any financial instrument that was intended to constitute a foreign currency hedging arrangement.

Income Tax Expense

The decrease in the Company’s income tax expense for the first quarter of 2002, compared to the first quarter of 2001, resulted primarily from decreased pre-tax income from North American operations, that was partially offset by increased pre-tax income from the Company’s operations in the Kingdom of Thailand. Management currently expects that its foreign taxes will constitute a substantial portion of its overall tax burden for the foreseeable future.

Liquidity and Capital Resources

Cash Flows

The Company’s Condensed Consolidated Statement of Cash Flows for the first quarter of 2002 reflects net cash provided by operating activities of $96,066,000. In addition to net cash provided by operating activities, the Company received $6,300,000, primarily from the exercise of stock options, and $14,000 from the sale of certain non-strategic properties. The Company also borrowed a net $5,001,000 under its revolving credit facility.

During the first quarter of 2002, the Company invested $87,491,000 in capital projects, paid $111,000 in debt issuance expenses, paid $2,438,000 in cash distributions to holders of its Trust Preferred Securities and paid $1,611,000 ($0.03 per share) in cash dividends to holders of the Company’s common stock. Effective May 3, 2002, the borrowing base under the Company’s revolving credit facility was set at $400,000,000. As of such date, the Company’s cash and cash equivalents were $104,904,000, its long-term debt stood at $792,989,000 and it had $172,011,000 of availability under its revolving credit facility.

Future Capital Requirements

The Company’s capital and exploration budget for 2002, which does not include any amounts that may be expended for the purchase of proved reserves or any interest which may be capitalized resulting from projects in progress, was established by the Company’s Board of Directors at $340,000,000. The Company currently anticipates that its available cash and cash equivalents, cash provided by operating activities and funds available under its credit agreement and banker’s acceptance facility will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses, any currently anticipated costs associated with the Company’s projects during 2002, and future dividend and distribution payments at current levels (including a dividend payment of $0.03 per share to be paid on May 24, 2002 to shareholders of record on May 10, 2002). The declaration of future dividends on the Company’s equity securities will depend upon, among other things, the Company’s future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends and distributions under certain covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company’s Board of Directors.

On May 3, 2002, Pogo Trust I announced that the Trust Preferred Securities were being called for redemption on June 3, 2002 at 104.55% of their liquidation preference, or approximately $52.27 per Trust Preferred Security for an aggregate total of $156,825,000 based on the 3,000,000 Trust Preferred Securities then outstanding. Each Trust Preferred Security is convertible at any time at the option of the holder for 2.1053 shares of the Company’s common stock. So long as the market price of the Company’s common stock is greater than approximately $24.83 per share, the market value of the common stock issuable upon conversion of the Trust Preferred Securities will exceed the amount receivable upon redemption. On May 3, 2002, the closing sales price of the Company’s common stock on the New York Stock Exchange

Composite Tape was $34.80. If, as a result of a decline in the market price of the Company’s common stock, a substantial number of Trust Preferred Securities are not converted prior to the redemption date and are required to be redeemed by the Company, the necessary borrowings to fund the redemption price would substantially reduce the Company’s borrowing capacity under its revolving credit agreement and adversely impact liquidity.

ITEM 3. Quantitative and Qualitative Disclosure about Market Risk.

The Company is exposed to market risk, including adverse changes in commodity prices, interest rates and foreign currency exchange rates. In addition to the information contained in this “Item 3. Quantitative and Qualitative Disclosure About Market Risk”, the information contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, and should be read in conjunction with the following.

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 1, 2002, 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, 2002:


																			Fair
		2002		2003		2004		2005		2006			Thereafter			Total			Value

Liabilities Long-Term Debt:
	Variable Rate	$	0	$	0	$	0	$	0	$	224,989		$	0		$	224,989		$	225,000
	Average Interest Rate		—		—		—		—		3.1	%		—			3.1	%		—
	Fixed Rate	$	0	$	0	$	0	$	0	$	115,000		$	450,000		$	565,000		$	586,902
	Average Interest Rate		—		—		—		—		5.5	%		9.07	%		8.34	%		—

Foreign Currency Exchange Rate Risk

The Company conducts business in Thai Baht and Hungarian Forint and is therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. As of May 1, 2002, the Company is not a party to any foreign currency exchange agreement.

Current Hedging Activity

From time to time, the Company has used and expects to continue to use hedging transactions with respect to a portion of its oil and gas production to achieve a more predictable cash flow, as well as to reduce its exposure to price fluctuations.

Natural Gas

As of March 31, 2002, the Company held options to sell 70 million cubic feet of natural gas production per day through December 31, 2002 at a sales price of $4.00 per MMBtu. These contracts give the Company the right, but not the obligation, to sell natural gas. These contracts are designed to guarantee a minimum “floor” price for the contracted volumes of production without limiting the Company’s participation in price increases during the covered period. As of March 31, 2002, the Company was a party to the following hedging arrangements:

Volume

NYMEX Contract

Fair Market

Contract Period

in MMBtu (a)

Price per MMBtu(a)

Value(b)

April 2002 - December 2002

19,250

4.00

14,091,000

(a)		MMBtu means million British Thermal Units.

(b)		Fair Market Value is calculated using prices derived from NYMEX futures contract prices existing at March 31, 2002.

These hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days, or occasionally the penultimate trading day, of a particular contract month. For any particular floor 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. The Company is not required to make any payment in connection with the settlement of a floor transaction.

Crude Oil

As of March 31, 2002, the Company was not a party to any commodity price hedging contracts with respect to any of its current or future crude oil and condensate production.

Part II. Other Information

Item 6. Exhibits and Reports on Form 8-K

	(A)		Exhibits

			None

	(B)		Reports on Form 8-K

Report filed on January 25, 2002, relating to the date of the Company’s 2002 Annual Meeting of Shareholders (Item 5).

Report filed on April 17, 2002, relating to a change in the Company’s independent accountants (Item 4).

POGO PRODUCING COMPANY AND SUBSIDIARIES

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 8, 2002