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

FORM 10-Q

Commission file number 1-7792

POGO PRODUCING COMPANY
(Exact Name of Registrant as Specified in Its Charter)

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

        Registrant's number of common shares outstanding as of April 30, 2003: 61,834,933

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

See accompanying notes to consolidated financial statements.

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POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

See accompanying notes to consolidated financial statements.

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POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

See accompanying notes to consolidated financial statements.

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POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders' Equity (Unaudited)

See accompanying notes to consolidated financial statements.

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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 to current year presentation. Such reclassifications had no effect on the Company's operating income, net income or shareholders' equity. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

(2) EARNINGS PER SHARE—

        Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. Earnings per share and potential common shares (diluted earnings per share) consider the effect of dilutive securities as set out below. Amounts are expressed in thousands, except per share amounts.

(a)

Reflects income before cumulative effect of change in accounting principle.

(b)

The Trust Preferred securities were converted to common stock on June 3, 2002.

(3) HEDGING ACTIVITIES—

        As of March 31, 2003, the Company held various derivative instruments. During 2002 and 2003, the Company entered into natural gas and crude oil option agreements referred to as "collars". Collars are designed to establish floor and ceiling prices on anticipated future natural gas and crude oil production. The Company has designated these contracts as cash flow hedges designed to achieve a more predictable cash flow, as well as to reduce its exposure to price volatility. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Currently, the Company does not expect losses due to creditworthiness of its counterparties.

        During the three months ended March 31, 2003 and 2002, the Company recognized a pre-tax loss of $10,775,000 ($7,004,000 after taxes) and a pre-tax gain of $9,009,000 ($5,856,000 after taxes),

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respectively, from its price hedge contracts which are included in oil and gas revenues. Unrealized losses on derivative instruments of $2,546,000, net of deferred taxes of $1,371,000, have been reflected as a component of other comprehensive income for the three months ended March 31, 2003. Based on the fair market value of the hedge contracts as of March 31, 2003, the Company would reclassify additional pre-tax losses of approximately $13,531,000 (approximately $8,795,000 after taxes) from accumulated other comprehensive income (shareholders' equity) to net income during the next twelve months.

        The gas hedging transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. The oil hedging transactions are generally settled based on the average of the reporting settlement prices for West Texas Intermediate on the NYMEX for each trading day of a particular contract month. For any particular collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction.

        The estimated fair value of these transactions is based upon various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. Further details related to the Company's hedging activities as of March 31, 2003 are as follows:

(a)

MMBtu means million British Thermal Units.

(4) CHANGE IN ACCOUNTING PRINCIPLE—

        The Company has adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," ("SFAS 143") as of January 1, 2003, which requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, a cumulative effect of a change in accounting principle was also required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized

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costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation against its recorded amount and will record any resulting gain or loss.

        The Company recorded a liability representing expected future costs associated with site reclamation, facilities dismantlement, and plugging and abandonment of wells as follows (in thousands):

        For the three months ended March 31, 2003 the Company recognized depreciation expense related to its ARO of $972,000. As a result of the adoption of SFAS 143 on January 1, 2003, the Company recorded a $56,769,000 increase in the net capitalized cost of its oil and gas properties and recognized an after-tax charge of $4,166,000 for the cumulative effect of the change in accounting principle. Had SFAS 143 been applied retroactively in the three months ended March 31, 2002, the Company's net income and earnings per share would have been as follows (expressed in 000's, except per share amounts):

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(5) GEOGRAPHIC INFORMATION—

        Financial information by geographic segment is presented below:

(6) ACCOUNTING FOR STOCK-BASED COMPENSATION—

        The Company's incentive plans authorize awards granted wholly or partly in common stock (including rights or options which may be exercised for or settled in common stock) to key employees and non-employee directors (collectively, "Stock Awards"). Prior to January 1, 2003, the Company accounted for Stock Awards using the intrinsic value recognition provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Under this method, the Company recognized no compensation expense for stock options granted when the exercise price of the options is equal to or greater than the quoted market price of the Company's common stock on the grant date. Effective January 1, 2003, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based Compensation" ("SFAS 123") and the prospective method transition provisions of Statement of Financial Accounting Standards No. 148, "Accounting for Stock Based Compensation—Transition and Disclosure—an amendment of FAS No. 123" ("SFAS 148") for all Stock Awards granted, modified or settled after January 1, 2003. The Company granted no Stock Awards during the three-month period ended March 31, 2003.

        The following table illustrates the effect on the Company's net income and earnings per share if the fair value recognition provisions of SFAS 123 for employee stock-based compensation had been

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applied to all Stock Awards outstanding during the three-month periods ending March 31, 2003 and 2002 (in thousands of dollars, except per share amounts):

(7) CONVERSION OF TRUST PREFERRED SECURITIES—

        Pogo Trust I, a subsidiary of the Company, called its 6¹/2% 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. Subsequent to June 3, 2002, there were no Trust Preferred Securities outstanding. The amounts recorded under Minority Interest—Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust during the first quarter of 2002 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.

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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, 2002. Some of the statements in the discussion are "Forward Looking Statements" and are thus prospective. As further discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, 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.

Results of Operations

Net Income

        The Company reported net income for the first quarter of 2003 of $88,477,000 or $1.45 per share ($93,671,000 or $1.37 per share on a diluted basis), compared to 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). The increase in net income was primarily related to increases in the average prices that the Company received for its natural gas, crude oil and condensate production volumes, in addition to increased production from the Company's onshore, Gulf of Mexico and Thailand properties.

        Earnings per common share are based on the weighted average number of common shares outstanding for the first quarter of 2003 of 61,157,000 (65,128,000 on a diluted basis), compared to 53,750,000 (54,487,000 on a diluted basis) for the first quarter of 2002. The increase in the weighted average number of common shares outstanding for the first quarter of 2003, compared to the first quarter of 2002, resulted primarily from the conversion of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities into 6,309,972 shares of the Company's common stock on June 3, 2002 and to a much lesser extent, the issuance of shares upon the exercise of stock options pursuant to the Company's stock option plans and stock issued as compensation. The earnings per share computation on a diluted basis for the first quarter of 2003 reflects additional shares of common stock issuable upon the assumed conversion of the Company's 5¹/2% Convertible Subordinated Notes due 2006 (the "2006 Notes") and the elimination of related interest requirements, as adjusted for applicable federal income taxes. In addition, for both periods, the number of common shares outstanding in the diluted computations are adjusted to include dilutive shares that are assumed to have been issued by the Company in connection with outstanding options under its Incentive Plans, less treasury shares that are assumed to have been purchased by the Company from the option proceeds.

Total Revenues

        The Company's total revenues for the first quarter of 2003 were $310,754,000, an increase of approximately 117% compared to total revenues of $142,910,000 for the first quarter of 2002. The increase in the Company's total revenues for the first quarter of 2003, compared to the first quarter of 2002, resulted primarily from increased oil and gas revenues, which is attributable to higher product prices and higher natural gas, crude oil and condensate production.

Oil and Gas Revenues

        The Company's oil and gas revenues for the first quarter of 2003 were $309,867,000, an increase of approximately 118% from oil and gas revenues of $142,297,000 for the first quarter of 2002. The

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following table reflects an analysis of variances in the Company's oil and gas revenues (expressed in thousands) between 2003 and 2002.

        The increase in the Company's oil and gas revenues in the first quarter of 2003, compared to the first quarter of 2002, is related to increases in the average price that the Company received for its natural gas, crude oil and condensate production and to a lesser extent an increase in the Company's natural gas, crude oil and condensate production volumes.

(a)

North American average prices reflect the impact of the Company's price hedging activity. Price hedging activity reduced the average price of the Company's North American natural gas production during the first quarter of 2003 by $0.39 per Mcf and increased the average price by $0.52 per Mcf for the first quarter of 2002. "MMcf" is an abbreviation for million cubic feet.

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(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.

(a)

Average prices are computed on production that is actually sold during the period and include the impact of the Company's price hedging activity. Price hedging activity reduced the average price of the Company's North American crude oil and condensate production by $0.91 per barrel during the first quarter of 2003. For North American average prices, sales volumes equate to actual production. However, in the Gulf of Thailand, crude oil and condensate sold may be more or less than actual production. See footnote (b) below. "Bbls" is an abbreviation for barrels.

(b)

Oil and condensate production in the Gulf of Thailand is produced and stored on the FPSO and FSO pending sale and is sold in tanker loads that typically average between 300,000 and 750,000 barrels per sale. Therefore, oil and condensate sales volumes for a given period in the Gulf of Thailand may not equate to actual production. In accordance with generally accepted accounting principles, reported revenues are based on sales volumes. However, the Company believes that actual production volumes also provide a meaningful measure of the Company's operating results. The Company produced 268,000 barrels and 167,000 barrels more than it sold in the first quarters of 2003 and 2002, respectively.

Natural Gas

        Thailand Prices.    The price that the Company receives under the gas sales agreement with the Petroleum Authority of Thailand ("PTT") is based upon a formula that takes into account a number of factors including, among other items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore. The contract price is also subject to adjustments for quality. An amendment to the Gas Sales Agreement provided that for certain volumes which the Company produces in excess of the base contractual amount (currently 145 MMcf per day) the price that the Company receives from PTT will be equal to 88% of the then-current price calculated under its Gas Sales Agreement.

        Production.    The increase in the Company's natural gas production during the first quarter of 2003, compared to the first quarter of 2002, was primarily related to successful development programs on the Company's Madden Unit and Gulf of Mexico properties, including its Mississippi Canyon Blocks

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661/705 and Main Pass 61/62 Fields, and increased Thailand production from the Benchamas Field, partially offset by natural production declines at other properties.

Crude Oil and Condensate

        Thailand Prices.    Since the inception of production from the Tantawan Field, crude oil and condensate have been stored on the FPSO until an economic quantity is accumulated for offloading and sale. The first such sale of crude oil and condensate from the Tantawan Field occurred in July 1997. Commencing in July 1999 when production began from the Benchamas Field, crude oil and condensate from that field has been stored on the FSO and sold as economic quantities were accumulated. A typical sale ranges from 300,000 to 750,000 barrels. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, typically as a differential to Malaysian TAPIS crude, and are denominated in U.S. dollars. As discussed further under "Costs and Expenses, Lease Operating Expenses," the Company records all crude oil held in the FPSO and the FSO at the end of an accounting period as inventory held at cost. When such crude oil is sold, usually during the following month, the difference between the cost of the crude oil and the sales revenue is recognized in the income statement.

        Production.    The increase in the Company's crude oil and condensate production during the first quarter of 2003, compared to the first quarter of 2002, resulted primarily from the continuing success of the Company's development program in the Main Pass Blocks 61/62 Field, its Ewing Bank Block 871 Field and its Mississippi Canyon 661/705 Field and, to a lesser extent, increased crude oil and condensate production at its Benchamas Field in the Kingdom of Thailand. These increases were partially offset by natural production declines at other properties.

        In accordance with generally accepted accounting principles, the Company records its oil production in the Kingdom of Thailand at the time of sale, rather than when produced. At the end of each quarter, the crude oil and condensate stored on board the FSO and FPSO pending sale is accounted for as inventory at cost. Reported revenues are based on sales volumes. When a tanker load of oil is sold in Thailand, the entire amount will be accounted for as production sold, regardless of when it was produced. As of March 31, 2003, the Company had approximately 470,000 net barrels stored on board the FPSO and FSO.

        NGL Production.    The Company's oil and gas revenues, and its total liquid hydrocarbon production, also reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for the first quarter of 2003, compared with the first quarter of 2002, primarily related to an increase in NGL prices received from $11.55 per barrel in the first quarter of 2002 to $22.31 per barrel in the first quarter of 2003, and, to a lesser extent, an increase in volumes extracted (primarily from the Company's Mississippi Canyon Blocks 661/705 Field gas production.)

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Costs and Expenses