POGO PRODUCING CO - 10-Q Quarterly Report

	Three Months Ended June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
	(Expressed in thousands, except per share amounts)
Revenues:
Oil and gas	$	185,241		$	164,412		$	327,538		$	328,325
Pipeline sales		1			4,473			79			8,699
Gains (losses) on sales and other		(857	)		509			(322	)		2,232

Total		184,385			169,394			327,295			339,256

Operating Costs and Expenses:
Lease operating		34,585			29,696			65,868			55,523
Pipeline operating and natural gas purchases		—			4,400			181			8,420
General and administrative		10,828			9,650			22,370			17,858
Exploration		1,352			5,486			1,176			12,434
Dry hole and impairment		3,500			12,277			8,495			23,044
Depreciation, depletion and amortization		73,942			53,464			139,748			90,532

Total		124,207			114,973			237,838			207,811

Operating Income		60,178			54,421			89,457			131,445

Interest:
Charges		(14,500	)		(14,988	)		(29,088	)		(26,292	)
Income		534			694			912			1,996
Capitalized		6,859			10,303			13,512			14,829
Minority Interest—Dividends and costs associated
with preferred securities of a subsidiary trust		(1,638	)		(2,501	)		(4,140	)		(4,998	)
Foreign Currency Transaction Gain (Loss)		659			(421	)		1,331			(1,006	)

Income Before Taxes		52,092			47,508			71,984			115,974
Income Tax Expense		(23,474	)		(16,529	)		(34,341	)		(45,049	)

Net Income	$	28,618		$	30,979		$	37,643		$	70,925

Earnings Per Common Share
Basic	$	0.51		$	0.58		$	0.68		$	1.46

Diluted	$	0.48		$	0.53		$	0.66		$	1.31

Dividends Per Common Share	$	0.03		$	0.03		$	0.06		$	0.06

Weighted Average Number of Common Shares and Potential Common Shares Outstanding:
Basic		56,192			53,575			54,972			48,425
Diluted		64,340			63,494			61,210			58,373

	June 30, 2002			December 31, 2001
	Expressed in thousands, except share amounts)
ASSETS
Current Assets:
Cash and cash equivalents	$	110,500		$	94,294
Accounts receivable		76,985			52,440
Other receivables		26,146			32,159
Federal income tax receivable		—			27,441
Deferred income tax		26,111			25,712
Inventories—Product		4,684			3,129
Inventories—Tubulars		9,471			8,430
Price hedge contracts		8,665			34,275
Other		9,760			1,970

Total current assets		272,322			279,850

Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties		3,100,241			2,956,673
Unevaluated properties		249,995			257,158
Pipelines, at cost		775			775
Other, at cost		24,039			21,638

		3,375,050			3,236,244

Accumulated depreciation, depletion and amortization
Oil and gas		(1,246,423	)		(1,133,560	)
Pipelines		(733	)		(739	)
Other		(12,897	)		(11,217	)

		(1,260,053	)		(1,145,516	)

Property and equipment, net		2,114,997			2,090,728

Other Assets:
Deferred income tax		8,465			13,359
Debt issue expenses		14,560			15,565
Foreign value added taxes receivable		10,698			6,200
Other		19,729			20,706

		53,452			55,830

	$	2,440,771		$	2,426,408

	June 30, 2002			December 31, 2001
	(Expressed in thousands, except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable—operating activities	$	41,445		$	34,962
Accounts payable—investing activities		74,069			94,523
Accrued interest payable		11,259			11,450
Foreign income taxes payable		17,987			7,966
Accrued dividends associated with preferred securities of a subsidiary trust		—			813
Accrued payroll and related benefits		2,933			2,670
Deferred income tax		5,324			3,875
Other		1,613			1,892

Total current liabilities		154,630			158,151
Long-Term Debt		769,987			794,990
Deferred Income Tax		492,204			488,639
Deferred Credits		13,874			14,657

Total liabilities		1,430,695			1,456,437

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

Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized		—			—
Common stock, $1 par; 200,000,000 shares authorized, 60,754,237 and 53,690,827 shares issued, respectively		60,754			53,691
Additional capital		814,604			659,227
Retained earnings		136,422			102,019
Accumulated other comprehensive income (loss)		(1,380	)		10,272
Treasury stock (15,575 shares), at cost		(324	)		(324	)

Total shareholders’ equity		1,010,076			824,885

	$	2,440,771		$	2,426,408

	Six Months Ended June 30,
	2002			2001
	(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers	$	301,784		$	365,015
Operating, exploration, and general and administrative expenses paid		(96,328	)		(91,077	)
Interest paid		(28,156	)		(19,255	)
Federal income taxes paid		(4,059	)		(14,807	)
Federal income taxes received		25,884			—
Value added taxes paid		(4,498	)		(2,129	)
Price hedge contracts		15,683			—
Other		527			2,051

Net cash provided by operating activities		210,837			239,798

Cash Flows from Investing Activities:
Capital expenditures		(175,673	)		(179,114	)
Purchase of proved reserves		—			(2,714	)
Proceeds from the sale of properties		5			4,348
Acquisition of NORIC, net of $21,235 cash acquired		—			(323,476	)

Net cash used in investing activities		(175,668	)		(500,956	)

Cash Flows from Financing Activities:
Proceeds from the issuance of new debt		—			200,000
Borrowings under senior debt agreements		364,997			833,997
Payments under senior debt agreements		(390,000	)		(684,000	)
Payments of cash dividends on common stock		(3,240	)		(2,830	)
Payments of preferred dividends of a subsidiary trust		(4,850	)		(4,875	)
Payment of financing issue costs		(130	)		(8,625	)
Payment of North Central senior debt acquired		—			(78,600	)
Proceeds from exercise of stock options and other		14,174			5,472

Net cash (used in) provided by financing activities		(19,049	)		260,539

Effect of exchange rate changes on cash		86			(948	)

Net increase (decrease) in cash and cash equivalents		16,206			(1,567	)
Cash and cash equivalents at the beginning of the year		94,294			81,510

Cash and cash equivalents at the end of the period	$	110,500		$	79,943

Reconciliation of net income to net cash provided by operating activities:
Net income	$	37,643		$	70,925
Adjustments to reconcile net income to net cash provided by operating activities—
Minority interest		4,140			4,998
Foreign currency transaction (gains) losses		(1,331	)		1,006
(Gains) losses from the sales of properties		303			(2,672	)
Depreciation, depletion and amortization		139,748			90,532
Dry hole and impairment		8,495			23,044
Interest capitalized		(13,512	)		(14,829	)
Price hedge contracts		7,685			2,469
Deferred federal income taxes		15,611			21,784
Change in operating assets and liabilities		12,055			42,541

Net cash provided by operating activities	$	210,837		$	239,798

	For the Six Months Ended June 30,
	2002								2001
	Shareholders’ Equity					Compre- hensive Income			Shareholders’ Equity					Compre- hensive Income
	Shares		Amount			Compre- hensive Income			Shares		Amount			Compre- hensive Income
	(Expressed in thousands, except share amounts)
Common Stock:
$1.00 par-200,000,000 shares authorized
Balance at beginning of year	53,690,827		$	53,691					40,659,591		$	40,660
Shares issued for Trust Preferred Securities conversion	6,309,972			6,310					—			—
Stock options exercised	753,438			753					319,129			319
Shares issued for acquisition of NORIC	—			—					12,615,816			12,615

Issued at end of period	60,754,237			60,754					53,594,536			53,594


Additional Capital:
Balance at beginning of year				659,227								298,885
Shares issued for Trust Preferred Securities conversion				138,720								—
Stock options exercised				16,657								6,617
Shares issued for acquisition of NORIC				—								351,729

Balance at end of period				814,604								657,231


Retained Earnings:
Balance at beginning of year				102,019								20,112
Net income				37,643		$	37,643					70,925
Dividends ($0.06 per common share)				(3,240	)							(2,830	)	$	70,925

Balance at end of period				136,422								88,207


Accumulated Other
Comprehensive Income (Loss):
Balance at beginning of year				10,272								(1,062	)
Exchange gains on Canadian currency							—					389			389
Unrealized gain (loss) on price hedge contracts				(6,453	)		(6,453	)				14,504			14,504
Cumulative effect of change in accounting principle				—			—					(2,438	)		(2,438	)
Reclassification adjustment for losses included in net income				(5,199	)		(5,199	)				(1,521	)		(1,521	)

Balance at end of period				(1,380	)							9,872

Comprehensive Income						$	25,991							$	81,859


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	60,738,662								53,578,961

Total Shareholders’ Equity			$	1,010,076							$	808,580

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 $25,991,000 and $81,859,000, respectively, for the six months ended June 30, 2002 and 2001 ($28,356,000 and $44,562,000, respectively, for the three months ended June 30, 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.

Pogo Trust I, a subsidiary of the Company, called its 6½% Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the “Trust Preferred Securities”) for redemption on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities converted their Trust Preferred Securities, representing $149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares of the Company’s common stock. In connection with the redemption, Pogo Trust I paid a total of $147,000 to former holders of the Trust Preferred Securities. As of June 4, 2002, there were no Trust Preferred Securities outstanding.

The Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) effective January 1, 2001. 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. Unrealized losses on derivative instruments arising during the six months ended June 30, 2002 of $6,453,000, net of deferred taxes of $3,475,000, have been reflected as a component of other comprehensive income. Based on the fair market value of the hedge contracts as of June 30, 2002, the Company would reclassify additional pre-tax losses of approximately $2,123,000 (approximately $1,380,000 net of taxes) from accumulated other comprehensive income, to net income during the remainder of 2002.

As of June 30, 2002, the Company held options to sell 70 million cubic feet of natural gas production per day for the period from July 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. Further details related to the Company’s hedging activities are as follows:

	Company		Oil and Gas		Pipelines		Other
	(Expressed in thousands)
Long-Lived Assets:
As of June 30, 2002:
United States	$	1,770,394	$	1,762,571	$	42	$	7,781
Kingdom of Thailand		344,229		340,972		—		3,257
Other		374		270		—		104

Total	$	2,114,997	$	2,103,813	$	42	$	11,142

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 six months ended June 30, 2002
United States	$	127,373	$	127,373	$	—	$	—
Kingdom of Thailand		42,746		42,746		—		—
Other		2,288		—		—		2,288

Total	$	172,407	$	170,119	$	—	$	2,288

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

Revenues:
For the three months ended June 30, 2002
United States	$	134,188	$	135,063	$	1	$	(876	)
Kingdom of Thailand		50,194		50,178		—		16
Other		3		—		—		3

Total	$	184,385	$	185,241	$	1	$	(857	)

For the three months ended June 30, 2001
United States	$	129,618	$	124,661	$	4,473	$	484
Kingdom of Thailand		38,077		38,067		—		10
Canada and other		1,699		1,684		—		15

Total	$	169,394	$	164,412	$	4,473	$	509

For the six months ended June 30, 2002
United States	$	235,884	$	236,142	$	79	$	(337	)
Kingdom of Thailand		91,411		91,396		—		15
Other		—		—		—		—

Total	$	327,295	$	327,538	$	79	$	(322	)

For the six months ended June 30, 2001
United States	$	249,090	$	238,211	$	8,699	$	2,180
Kingdom of Thailand		86,071		86,012		—		59
Canada and other		4,095		4,102		—		(7	)

Total	$	339,256	$	328,325	$	8,699	$	2,232

	Company			Oil and Gas			Pipelines			Other
	(Expressed in thousands)
Depreciation, depletion and amortization expense:
For the three months ended June 30, 2002
United States	$	54,023		$	53,376		$	(15	)	$	662
Kingdom of Thailand		19,909			19,744			—			165
Other		10			—			—			10

Total	$	73,942		$	73,120		$	(15	)	$	837

For the three months ended June 30, 2001
United States	$	39,957		$	39,330		$	63		$	564
Kingdom of Thailand		12,682			12,536			—			146
Canada and other		825			816			—			9

Total	$	53,464		$	52,682		$	63		$	719

For the six months ended June 30, 2002
United States	$	103,302		$	102,020		$	(6	)	$	1,288
Kingdom of Thailand		36,404			36,074			—			330
Other		42			—			—			42

Total	$	139,748		$	138,094		$	(6	)	$	1,660

For the six months ended June 30, 2001
United States	$	62,696		$	61,735		$	122		$	839
Kingdom of Thailand		26,109			25,877			—			232
Canada and other		1,727			1,709			—			18

Total	$	90,532		$	89,321		$	122		$	1,089

Operating Income (Loss):
For the three months ended June 30, 2002
United States	$	41,504		$	42,400		$	(20	)	$	(876	)
Kingdom of Thailand		19,114			19,098			—			16
Other		(440	)		—			—			(440	)

Total	$	60,178		$	61,498		$	(20	)	$	(1,300	)

For the three months ended June 30, 2001
United States	$	40,664		$	40,298		$	(52	)	$	418
Kingdom of Thailand		17,027			17,017			—			10
Canada and other		(3,270	)		(3,285	)		—			15

Total	$	54,421		$	54,030		$	(52	)	$	443

For the six months ended June 30, 2002
United States	$	55,178		$	55,657		$	(142	)	$	(337	)
Kingdom of Thailand		35,234			35,219			—			15
Other		(955	)		—			—			(955	)

Total	$	89,457		$	90,876		$	(142	)	$	(1,277	)

For the six months ended June 30, 2001
United States	$	99,311		$	97,261		$	(130	)	$	2,180
Kingdom of Thailand		40,774			40,715			—			59
Canada and other		(8,640	)		(8,633	)		—			(7	)

Total	$	131,445		$	129,343		$	(130	)	$	2,232

	Three Months Ended June 30, 2002					Six Months Ended June 30, 2002
	Income		Shares	Per Share		Income		Shares	Per Share
Basic earnings per share—	$	28,618	56,192	$	0.51	$	37,643	54,972	$	0.68

Effect of dilutive securities:
Options to purchase common shares		—	1,005				—	871
2006 Notes		1,028	2,726				—	—
Trust Preferred Securities		1,108	4,417				2,693	5,367

Diluted earnings per share	$	30,754	64,340	$	0.48	$	40,336	61,210	$	0.66

Antidilutive securities—
Options to purchase common shares		—	138	$	38.19		—	173	$	36.77
2006 Notes		—	—		—		2,056	2,726	$	0.75

	Three Months Ended June 30, 2001					Six Months Ended June 30, 2001
	Income		Shares	Per Share		Income		Shares	Per Share
Basic earnings per share—	$	30,979	53,575	$	0.58	$	70,925	48,425	$	1.46

Effect of dilutive securities:
Options to purchase common shares		—	877				—	906
2006 Notes		1,028	2,726				2,056	2,726
Trust Preferred Securities		1,584	6,316				3,169	6,316

Diluted earnings per share	$	33,591	63,494	$	0.53	$	76,150	58,373	$	1.31

Antidilutive securities—
Options to purchase common shares		—	307	$	33.86		—	307	$	33.86

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. The Company has not yet quantified the financial statement impact from adoption of this new standard.

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, the Company repaid all $78,600,000 principal amount of North Central’s existing

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 fair market value to oil and gas properties acquired and increased interest expense related to 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.

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 “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, 2001, such 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.

Pogo Trust I, a subsidiary of the Company, called its 6½% Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the “Trust Preferred Securities”) for redemption on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities converted their Trust Preferred Securities, representing over $149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares of the Company’s common stock. In connection with the redemption, Pogo Trust I paid a total of $147,000 to former holders of the Trust Preferred Securities. As of June 4, 2002, there were no Trust Preferred Securities outstanding.

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements included in the Company’s annual report on Form 10-K for the year ended December 31, 2001. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas revenues, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company’s financial statements:

The Company accounts for its oil and gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and gas field is typically treated as a development cost and capitalized, but often these seismic programs extend beyond the proved reserve area and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The Company’s estimates of oil and gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and/or the rate of depletion of such oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

The Company reviews its producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows from its oil and gas properties and compares such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows

projected. The Company recognized significant impairment expense due to poor reservoir performance at one of its Gulf of Mexico properties in the first quarter of 2001, and has recognized other less significant impairment expenses to other properties in all four comparative periods. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require the Company to record an impairment of its oil and gas properties and there can be no assurance that such impairments will not be required in the future.

The estimated fair values of the Company’s derivative instruments are recorded on the Company’s consolidated balance sheet. Historically, substantially all of the Company’s derivative instruments represent cash flow hedges of the price of future oil and natural gas production. Therefore, while fair values of such hedging instruments must be estimated at the end of each reporting period, the related changes in such fair values are not included in the Company’s consolidated results of operations. Instead, the changes in fair value of hedging instruments are recorded directly to shareholders’ equity until the hedged oil or natural gas quantities are produced.

The estimation of fair values for the Company’s hedging derivatives requires substantial judgment. The Company estimates the fair values of its derivatives on a monthly basis using an option pricing model. The Company obtains the forecasts of future NYMEX oil and gas prices from independent third parties. The estimated future prices are compared to the prices fixed by the hedge agreements, and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted using the Company’s current borrowing rates under its revolving credit facility. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates. Currently, all of the Company’s derivative instruments are hedges of the price of natural gas production. The Company is not involved in any derivative trading activities.

Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. As of January 1, 2002, the accounting for goodwill has changed. In prior years, goodwill was amortized. As of January 1, 2002, goodwill and other intangibles with an indefinite useful life are no longer amortized, but instead are assessed for impairment at least annually. The Company has never recorded any goodwill in connection with the acquisition of any assets. However, there can be no assurance that the Company may not do so in the future.

There are various assumptions made by the Company in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, the Company prepares estimates of oil, natural gas and natural gas liquid (“NGL”) reserves. These estimates are based on work performed by the Company’s engineers and outside petroleum reservoir consultants. The judgments associated with the estimation of reserves are described earlier in this section. The fair value of the estimated reserves acquired in a business combination is then calculated based on the Company’s estimates of future oil, natural gas and NGL prices. The Company’s estimates of future prices are based on its own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics, such as economic growth forecasts. Such estimates are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity and trends in regional pricing differentials. Future price forecasts from independent third parties are also taken into account in arriving at the Company’s own pricing estimates. The Company’s estimates of future prices are applied to the estimated reserve

quantities acquired to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted to derive a fair value for such reserves. The Company also applies these same general principles in arriving at the fair value of unproved reserves acquired in a business combination. These unproved reserves are generally classified as either probable or possible reserves. Because of their very nature, probable and possible reserve estimates are less precise than those of proved reserves. Generally, in the Company’s business combinations, the determination of the fair values of oil and gas properties requires more judgment than the estimates of fair values for other acquired assets and liabilities.

Future development costs include costs incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our offshore production platforms, FPSOs, FSOs, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment.

For financial reporting purposes, the Company generally provides taxes at the rate applicable for the appropriate tax jurisdiction. Where the Company’s present intention is to reinvest the unremitted earnings in its foreign operations, the Company does not provide for U.S. income taxes on unremitted earning of foreign subsidiaries. Management periodically assesses the need to utilize these unremitted earnings to finance the U.S. operations of the Company. This assessment is based on cash flow projections that are the result of estimates of future production, commodity pricing and expenditures by tax jurisdiction for the Company’s operations. Such estimates are inherently imprecise since many assumptions are utilized in the cash flow projections that may be revised in the future.

The Company reported net income for the second quarter of 2002 of $28,618,000 or $0.51 per share ($30,754,000 or $0.48 per share on a diluted basis), compared to net income for the second quarter of 2001 of $30,979,000 or $0.58 per share ($33,591,000 or $0.53 per share on a diluted basis). For the first six months of 2002, the Company reported net income of $37,643,000 or $0.68 per share ($40,336,000 or $0.66 per share on a diluted basis) compared to net income for the first six months of 2001 of $70,925,000 or $1.46 per share ($76,150,000 or $1.31 per share on a diluted basis). The decrease in net income during the second quarter and first six months of 2002, compared to the second quarter and first six months of 2001, 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 that closed on March 14, 2001. The net income reported in the second quarter and first six months of 2002, compared to the second quarter and first six months of 2001, was also negatively impacted by losses from the sale of several marginal offshore properties in the Gulf of Mexico as part of the Company’s ongoing asset rationalization process during the first half of 2002. Conversely, net income reported in the first six months of 2001 was positively impacted by a gain on the sale of certain non-strategic properties, all of

Earnings per common share are based on the weighted average number of common shares outstanding for the respective periods. The increase in the weighted average number of common shares outstanding for the second quarter and first six months of 2002, compared to the second quarter and first six months of 2001, resulted primarily from the issuance of common stock in connection with the conversion of the Company’s Trust Preferred Securities that were called for redemption on June 3, 2002 and, to a lesser extent, the exercise of stock options pursuant to the Company’s incentive plans. Earnings per share computations on a diluted basis for all 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 computation on a diluted basis for all periods presented reflect the weighted average of additional shares of common stock issuable upon the assumed conversion of the Trust Preferred Securities (prior to their conversion). Earnings per share computations for the second quarter of 2002, and the second quarter and first six months of 2001, also reflect the weighted average of additional shares of common stock issuable upon the assumed conversion of the Company’s 5½% Convertible Subordinated Notes due 2006 (the “2006 Notes”).

The Company’s total revenues for the second quarter of 2002 were $184,385,000, an increase of approximately 9% from total revenues of $169,394,000 for the second quarter of 2001. The Company’s total revenues for the first six months of 2002 were $327,295,000, a decrease of approximately 3% compared to total revenues of $339,256,000 for the first six months of 2001. The increase in the Company’s total revenues for the second quarter of 2002, compared to the second quarter of 2001, resulted primarily from an increase in oil and gas revenues, partially offset by a decrease in pipeline sales and a loss on sales of properties, both of which were attributable to the Company’s sale of certain non-strategic properties. The decrease in the Company’s total revenues for the first six months of 2002, compared to the first six months of 2001, resulted primarily from a decrease in pipeline sales and a loss on sales of properties, both of which were attributable to the Company’s sale of certain non-strategic properties and, to a much lesser extent, a slight decrease in oil and gas revenues.

	2nd Qtr 2002 Compared to 2nd Qtr 2001			1st Half 2002 Compared to 1st Half 2001
Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas—
Price	$	(27,882	)	$	(76,890	)
Production		3,771			24,234

		(24,111	)		(52,656	)

Crude oil and condensate—
Price		(6,482	)		(22,359	)
Production		47,960			68,685

		41,478			46,326

Natural Gas Liquids (NGL)—		3,462			5,543

Increase (decrease) in oil and gas revenues	$	20,829		$	(787	)

The increase in the Company’s oil and gas revenues for the second quarter of 2002, compared to the second quarter of 2001, is primarily related to increases in the Company’s oil and condensate, natural gas and NGL production volumes, that were partially offset by the decrease in the prices received for natural gas, crude oil and condensate production. The slight decrease in the Company’s oil and gas revenues for the first half of 2002, compared to the first half of 2001, is primarily related to lower prices received for the Company’s natural gas production and, to a lesser extent, crude oil and condensate production, which more than offset the higher production volumes for the Company’s crude oil, condensate, natural gas and NGL production.

	2nd Quarter				% Change		1st Six Months				% Change
	2002		2001		% Change		2002		2001		% Change
Comparison of Increases (Decreases) in:
Natural Gas—
Average prices
North America(a)	$	3.21	$	4.62	(31	)%	$	3.01	$	5.53	(46	)%
Kingdom of Thailand(b)	$	2.12	$	2.24	(5	)%	$	2.22	$	2.34	(5	)%
Company-wide average price	$	2.91	$	4.04	(28	)%	$	2.79	$	4.66	(40	)%
Average daily production volumes (MMcf per day)
North America(a)		206.1		205.0	1	%		198.6		165.4	20	%
Kingdom of Thailand		79.5		66.1	20	%		76.3		61.8	23	%

Company-wide average daily production		285.6		271.1	5	%		274.9		227.2	21	%

	2nd Quarter				% Change		1st Six Months				% Change
	2002		2001		% Change		2002		2001		% Change
Comparison of Increases (Decreases) in:
Crude Oil and Condensate—
Average prices(c)
North America	$	24.28	$	25.84	(6	)%	$	22.39	$	26.86	(17	)%
Kingdom of Thailand	$	24.32	$	28.21	(14	)%	$	22.09	$	26.37	(16	)%
Company-wide average price	$	24.29	$	26.75	(9	)%	$	22.29	$	26.64	(16	)%
Average daily production volumes (Bbls per day)
North America(c)		30,659		15,514	98	%		28,862		14,719	96	%
Kingdom of Thailand(d)		15,715		13,442	17	%		16,114		13,679	18	%

Company-wide average daily production		46,374		28,956	60	%		44,976		28,398	58	%

Total Liquid Hydrocarbons—
Company-wide average daily production (Bbls per day)(d)		51,400		31,028	66	%		49,299		29,790	65	%

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 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 generally equal to 88% of the then-current price under its 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 second quarter and first six months of 2002, compared to the second quarter and first six months of 2001, reflects positive adjustments related to base production sold under the gas sales agreement that were more than offset by the excess production sold at lower prices under the memorandum of understanding.

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

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 is 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 U.S. dollars. In addition, the Company is generally paid for its crude oil and condensate production from Thailand in U.S. dollars.

Thailand Production. The increase in the Company’s crude oil and condensate production from the Gulf of Thailand during the second quarter and first six months of 2002, compared to the second quarter and first six months 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. The Company currently anticipates that production facilities upgrades at Benchamas Field, scheduled for the third quarter 2002, could require 20-25 days to accomplish

and will likely reduce the Company’s net third quarter oil production by about 5,000 barrels per day. In accordance with generally accepted accounting principles, the Company records its oil production in 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. 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 2,000 barrels less than it sold in the second quarter of 2002 and 165,000 barrels more than it sold in the first six months of 2002. It produced 351,000 and 205,000 barrels more than it sold in the second quarter and first six months of 2001, respectively. As of June 30, 2002, the Company had approximately 424,000 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 second quarter and first six months of 2002, compared with the second quarter and first six months of 2001, primarily related to NGL removed from the Company’s Mississippi Canyon Blocks 661/705 Field gas production and, to a lesser extent, the decision by the Company to extract NGL from a higher percentage of its other natural gas production due to favorable economics. These increases were partially offset by a decline in the average prices that the Company received for its NGL production during the comparative periods.

	2nd Quarter						% Change		1st Six Months						% Change
	2002			2001			% Change		2002			2001			% Change
Comparison of Increases (Decreases) in:
Lease Operating Expenses
North America	$	24,505,000		$	22,721,000		8	%	$	47,271,000		$	39,771,000		19	%
Kingdom of Thailand	$	10,080,000		$	6,975,000		45	%	$	18,597,000		$	15,752,000		18	%
Total Lease Operating Expenses	$	34,585,000		$	29,696,000		16	%	$	65,868,000		$	55,523,000		19	%
Pipeline Operating and Natural Gas Purchases	$	—		$	4,400,000		N/M		$	181,000		$	8,420,000		(98	)%
General and Administrative Expenses	$	10,828,000		$	9,650,000		12	%	$	22,370,000		$	17,858,000		25	%
Exploration Expenses	$	1,352,000		$	5,486,000		(75	)%	$	1,176,000		$	12,434,000		(91	)%
Dry Hole and Impairment Expenses	$	3,500,000		$	12,277,000		(72	)%	$	8,495,000		$	23,044,000		(63	)%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	73,942,000		$	53,464,000		38	%	$	139,748,000		$	90,532,000		54	%
DD&A rate	$	1.37		$	1.33		3	%	$	1.37		$	1.24		10	%
Mcfe sold(a)		54,065,000			39,509,000		37	%		102,299,000			72,241,000		42	%
Interest—
Charges	$	(14,500,000	)	$	(14,988,000	)	(3	)%	$	(29,088,000	)	$	(26,292,000	)	11	%
Interest Income	$	534,000		$	694,000		(23	)%	$	912,000		$	1,996,000		(54	)%
Capitalized Interest Expense	$	6,859,000		$	10,303,000		(33	)%	$	13,512,000		$	14,829,000		(9	)%
Minority Interest—Dividends and Costs	$	(1,638,000	)	$	(2,501,000	)	(35	)%	$	(4,140,000	)	$	(4,998,000	)	(17	)%
Foreign Currency Transaction Gain (Loss)	$	659,000		$	(421,000	)	N/M		$	1,331,000		$	(1,006,000	)	N/M
Income Tax Expense	$	(23,474,000	)	$	(16,529,000	)	42	%	$	(34,341,000	)	$	(45,049,000	)	(24	)%

The increase in North American lease operating expenses for the second quarter and first six months of 2002, compared to the second quarter and first six months 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, partially offset by decreased severance taxes and lease maintenance costs in the Gulf of Mexico and the Company’s Western Division properties.

The increase in lease operating expenses in the Kingdom of Thailand for the second quarter and first six months of 2002, compared to the second quarter and first six months of 2001, primarily related to increased rental expenses for compressors and other equipment, increased insurance costs and a decrease in the amount of lifting costs carried as product inventory. In accordance with generally accepted accounting practices, the portion of lifting costs that is attributable to crude oil and condensate stored on the FPSO and FSO is treated as an inventoried cost until that crude oil and condensate is sold. At the time the crude oil and condensate is sold, those inventoried lifting costs are recognized as lease operating expenses. Variances in production, sales and costs will result in variances in the amount of lease operating expense that is currently recognized as expense and the amount recorded as product inventory to be recognized in subsequent periods. 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 $3,625,000 and $7,211,000 (net to the Company’s interest) of the Company’s Thailand lease operating expenses for the second quarter and first six months of 2001 and 2002, respectively.

Revenue from the sale of natural gas purchased for resale is reported under “Pipeline sales.” 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 quarterly and six month periods for 2001 and 2002.

The increase in general and administrative expenses for the second quarter of 2002, compared with the second quarter of 2001, related to 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. The increase in general and administrative expenses for the first six months of 2002, compared with the first six months of 2001, related to 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 decreased from an average of $0.24 per Mcfe for the second quarter and $0.25 per Mcfe for the first six months of 2001, to $0.20 per Mcfe for the second quarter and $0.22 per Mcfe for the first six months of 2002.

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 decrease in exploration expense for the second quarter and first six months of 2002, compared to the second quarter and first six months of 2001, resulted primarily from a decrease in 3-D seismic acquisition activities during the 2002 periods and, to a lesser extent, 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. Exploration expenses for the second quarter and first six months of 2001 included the cost of conducting two major 3-D projects in Hungary and seismic operations in Canada and the Gulf of Mexico, for which no comparable expenses were experienced during the same periods in 2002.

The slight increase in the composite DD&A rate for all of the Company’s producing fields for the second quarter of 2002, compared to the second quarter of 2001, was primarily attributable to increased production from fields with a DD&A rate higher than the Company’s recent historic average. The increase in the composite DD&A rate for all of the Company’s producing fields for the first six months of 2002, compared to the first six months of 2001, was primarily attributable to production from fields acquired in the North Central acquisition which, because they were valued at fair market value in connection with the acquisition, contribute a DD&A rate higher than the Company’s recent historic average. Such rate increases were partially offset by increased production from certain of the Company’s fields having DD&A rates lower than the Company’s recent historical composite rate (principally the new Main Pass Blocks 61/62 Field and its Benchamas Field).

Interest Charges. The decrease in the Company’s interest charges for the second quarter of 2002, compared to the second quarter of 2001, resulted primarily from a decline in the average interest rate on the Company’s outstanding debt, partially offset by an increase in the average debt outstanding during the periods. The increase in the Company’s interest charges for the first six months of 2002, compared to the first six months of 2001, was primarily related to additional debt incurred to finance the North Central acquisition, which was partially offset by a decline in the average interest rate on the outstanding debt and by a charge for amortization of debt issuance costs incurred in the first half of 2001 for which no comparable charges were taken during 2002. These charges related to the termination of the Company’s previous credit facility in connection with the North Central acquisition.

Capitalized Interest. The decrease in capitalized interest for the second quarter of 2002, compared to the second quarter of 2001, resulted primarily from a decrease in the average amount of capital expenditures subject to interest capitalization (approximately $381,000,000 in the second quarter of 2002, compared to approximately $528,000,000 in the second quarter of 2001) and, to a lesser extent, by a decrease in the interest rate used to determine the amount of capitalized interest. The decrease in capitalized interest for the first six months of 2002, compared to the first six months of 2001, resulted primarily from a decrease in the interest rate used to determine the amount of capitalized interest, partially offset by an increase in the amount of capital expenditures subject to interest capitalization (approximately $379,000,000 in the first six months of 2002, compared to approximately $366,000,000 in the first six months of 2001). A substantial percentage of the Company’s capitalized interest relates 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 other development projects in the Gulf of Mexico. The Company currently expects the amount of capital expenditures subject to interest capitalization to decrease during the remainder of 2002 due to the recent completion and installation of platforms and facilities construction in the Gulf of Thailand and the Gulf of Mexico.

Pogo Trust I, a business trust in which the Company owns all of the issued common securities, issued $150,000,000 of Trust Preferred Securities on June 2, 1999. Pogo Trust I called the Trust Preferred Securities for redemption on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities converted their Trust Preferred Securities, representing over $149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares of the Company’s common stock. In connection with the redemption, Pogo Trust I paid a total of $147,000 to former holders of the Trust Preferred Securities. As of June 4, 2002, there were no Trust Preferred Securities outstanding. The amounts recorded for the second quarter and first six months of 2001 and 2002, 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.

The foreign currency transaction gains reported for the second quarter and first six months of 2002, and the losses reported for the second quarter and first six months of 2001, resulted primarily from the fluctuation against the U.S. dollar of cash and other monetary assets and liabilities denominated in Thai Baht that were included in the Company’s Thai subsidiaries’ financial statements during the respective periods. The Company cannot predict with any degree of certainty the Thai Baht to U.S. dollar exchange rate in future periods. As of July 22, 2002, the Company was not a party to any financial instrument intended to constitute a foreign currency hedging arrangement.

The increase in the Company’s tax expense for the second quarter of 2002, compared to the second quarter of 2001, resulted primarily from increased pre-tax income and, to a lesser extent, an increase in the Company’s effective tax rate resulting from higher pre-tax income derived from the Company’s Thailand operations during the quarterly comparative periods, relative to its pre-tax income from North American operations. The decrease in the Company’s tax expense for the first six months of 2002, compared to the corresponding six months of 2001, resulted primarily from decreased pre-tax income, partially offset by an increase in the Company’s effective tax rate due to higher pre-tax income derived from the Company’s Thailand operations, relative to its pre-tax income from

During the first six months of 2002, the Company invested $175,673,000 in capital projects, repaid a net $25,003,000 under its senior debt arrangements, paid a total of $4,997,000 in cash distributions to holders of its Trust Preferred Securities (including $147,000 in connection with the redemption of the Trust Preferred Securities on June 3, 2002), paid $3,240,000 ($0.06 per share) in cash dividends to holders of the Company’s common stock and paid $130,000 in financing issue costs. As of July 22, 2002, the Company’s cash and cash equivalents were $99,173,000 and its long-term debt stood at $766,942,000. In addition, the Company had $198,000,000 of availability under its revolving credit facility.

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 recently increased by the Company’s Board of Directors to $390,000,000. The Company currently anticipates that its available cash and cash equivalents, cash provided by operating activities and funds available under its revolving 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 payments at current levels (including a dividend payment of $0.03 per share on its common stock to be paid on August 16, 2002 to shareholders of record on August 2, 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.

The Company’s material contractual cash obligations include long-term debt, operating leases, and other contracts. Material contractual cash obligations for which the ultimate settlement amounts are not fixed and determinable include derivative contracts that are sensitive to future changes in commodity prices and other factors. See “Item 3. Quantitative and Qualitative Disclosure about Market Risk.” A summary of the Company’s known contractual obligations as of June 30, 2002 is set forth on the following table:

	Payments Due By Year (in millions)
	Rest of 2002		2003		2004		2005		2006		After 2006		Total
Long Term Debt	$	0.0	$	0.0	$	0.0	$	0.0	$	320.0	$	450.0	$	770.0
Operating Leases(a)	$	11.7	$	21.8	$	21.8	$	21.6	$	21.4	$	64.0	$	162.3
Drilling obligations(b)	$	0.3	$	0.1	$	0.0	$	0.0	$	0.0	$	0.0	$	0.4
Firm transportation agreements(c)	$	0.6	$	1.2	$	1.2	$	1.2	$	1.2	$	5.1	$	10.5

Total	$	12.6	$	23.1	$	23.0	$	22.8	$	342.6	$	519.1	$	943.2

Commitments under Joint Operating Agreements. The oil and gas industry operates in many instances through joint ventures under joint operating agreements and the Company’s operations are no exception. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. The contractual obligations set forth above represent the Company’s working interest share of the contractual commitments that it has entered into as operator and, to the extent that it is aware, the contractual commitments entered into by the operator of projects the Company does not operate.

Surety Bonds. In the ordinary course of the Company’s business and operations, it is required to post surety bonds from time to time with third parties, including governmental agencies, primarily to cover self insurance, site restoration, equipment dismantlement, plugging and abandonment obligations. As of June 30, 2002, the Company had obtained surety bonds from a number of insurance and bonding institutions covering certain operations in the United States in the aggregate amount of approximately $7,000,000 that are not included in the prior table. In connection with their administration of offshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee’s plugging and abandonment liabilities. The MMS reviews this information and applies certain financial tests including, but not limited to, current asset and net worth tests. The MMS determines whether each lessee is financially capable of paying the estimated costs of such plugging and abandonment liabilities. The Company must annually provide the MMS with financial information. If the Company does not satisfy the MMS requirements, it could be required to post supplemental bonds. In the past, the Company has not been required to post supplemental bonds; however, there can be no assurance that the Company will satisfy the financial tests and remain on the list of MMS lessees exempt from the supplemental bonding requirements. The Company cannot predict or quantify the amount of any such supplemental bonds or the annual premiums related thereto and therefore has not included them in the prior table, but the amount could be substantial.

Guarantee and Letters of Credit. The Company has also issued performance guarantees related to the operations of its subsidiaries in Thailand, Hungary, the U.K and Denmark. If its subsidiaries do not fulfill their contractual obligations or legal obligations under the relevant local laws, the Company could be obligated to make payments to satisfy the subsidiaries’ obligations. Most of these obligations relate to plugging, abandoment, site restoration and compliance with environmental laws. The Company also has guaranteed performance of its subsidiaries’ obligations under the FSO and FPSO leases. To the extent quantifiable, such subsidiaries’ contractual commitments have been included in the prior table. However, the Company’s guarantee of these obligations has not been so included. Currently, there are no letters of credit that have been issued on the Company’s behalf.

From time to time, the Company has entered into various financial instruments, such as interest rate swaps, to manage the impact of changes in interest rates. As of July 22, 2002, the Company had no open interest rate swap or interest rate lock agreements. Therefore, the Company’s exposure to changes in interest rates primarily results from its short-term and long-term debt with both fixed and floating interest rates. The following table presents principal or notional amounts (stated in thousands) and related average interest rates by year of maturity for the Company’s debt obligations and their indicated fair market value at June 30, 2002:

As of June 30, 2002, the Company held options to sell 70 million cubic feet of natural gas production per day for the period from July 1, 2002 through December 31, 2002 at a sales price of $4.00 per million British thermal units (“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 at a sales price of $4.00 per MMBtu through December 2002. 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. Further details related to the Company’s hedging activities are as follows:

Delaware (State or Other Jurisdiction of Incorporation or Organization)		74-1659398 (I.R.S. Employee Identification No.)
5 Greenway Plaza, Suite 2700 Houston, Texas (Address of principal executive offices)		77046-0504 (Zip Code)

Contract Period	Volume in MMBtu(a)	NYMEX Contract Price per MMBtu(a)		Fair Market Value(b)
Floor Contract:

July 2002—December 2002	12,880	$	4.00	$	8,665,000

Contract Period	Volume in MMBtu	NYMEX Contract Price per MMBtu		Fair Market Value(a)
Floor Contract:
July 2002—December 2002	12,880	$	4.00	$	8,665,000

Nominee	For	Withheld
Jerry M. Armstrong	48,482,849	242,430
Robert H. Campbell	48,488,052	237,727
Stephen A. Wells	48,182,397	542,882

POGO PRODUCING COMPANY (Registrant)

By:		/s/ THOMAS E. HART
		Thomas E. Hart Vice President and Chief Accounting Officer



By:		/s/ JAMES P. ULM, II
		James P. Ulm, II Senior Vice President and Chief Financial Officer

		Six Months Ended June 30, 2001
Revenues		$ 402,236
Net income		$ 87,319
Earnings per share
Basic—		$ 1.63
Diluted—		$ 1.46