-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NmsPv3XD9bSrarWfI/hLWhVCWEqyqwbYs3hcpCPc6aa3/QohndDSfUIYYRVsQGRA kDf/LYNdzLEnblL5tDQ62A== 0000899243-99-002147.txt : 19991101 0000899243-99-002147.hdr.sgml : 19991101 ACCESSION NUMBER: 0000899243-99-002147 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991029 FILER: COMPANY DATA: COMPANY CONFORMED NAME: POGO PRODUCING CO CENTRAL INDEX KEY: 0000230463 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 741659398 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-07792 FILM NUMBER: 99737052 BUSINESS ADDRESS: STREET 1: 5 GREENWAY PLAZA STE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77252-0504 BUSINESS PHONE: 7132975000 MAIL ADDRESS: STREET 1: 5 GREENWAY PLAZA SUITE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77252 FORMER COMPANY: FORMER CONFORMED NAME: PENNZOIL OFFSHORE GAS OPERATORS INC /TX/ DATE OF NAME CHANGE: 19600201 10-Q 1 FORM 10-Q FOR QUARTER ENDED SEPTEMBER 30, 1999 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 September 30, 1999 or [_] Transition report pursuant to section 13 or 15[d] of the Securities Exchange Act or 1934 For the transition period from...........to........... Commission file number 1-7792 Pogo Producing Company [Exact Name of Registrant as Specified in Its Charter] Delaware 74-1659398 [State or Other Jurisdiction of [I.R.S. Employer Incorporation or Organization] 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 September 30, 1999: 40,202,920
Part I. Financial Information Pogo Producing Company and Subsidiaries Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ------------------------ 1999 1998 1999 1998 --------- --------- --------- --------- (Expressed in thousands, except per share amounts) Revenues: Oil and gas $ 67,195 $ 45,287 $ 148,089 $ 158,836 Pipeline sales and other 2,190 1,055 4,420 842 Gains (losses) on sales (247) (163) 37,503 (106) --------- --------- --------- --------- Total 69,138 46,179 190,012 159,572 --------- --------- --------- --------- Operating Costs and Expenses: Lease operating 19,766 17,884 47,925 50,468 Pipeline operating and natural gas purchases 1,307 728 3,505 728 General and administrative 7,003 8,556 20,990 19,843 Exploration 801 1,426 3,940 7,260 Dry hole and impairment 930 5,128 1,960 7,906 Depreciation, depletion and amortization 27,422 24,921 74,667 83,739 --------- --------- --------- --------- Total 57,229 58,643 152,987 169,944 --------- --------- --------- --------- Operating Income (Loss) 11,909 (12,464) 37,025 (10,372) --------- --------- --------- --------- Interest: Charges (8,305) (6,236) (27,414) (17,513) Income 588 284 898 534 Capitalized 4,670 2,476 13,437 6,540 Minority Interest - Dividends and costs associated with preferred securities of a subsidiary trust (2,557) - (3,356) - Foreign Currency Transaction Gain (Loss) (2,014) 760 (1,605) 953 --------- --------- --------- --------- Income (Loss) Before Income Taxes 4,291 (15,180) 18,985 (19,858) Income Tax Benefit (Expense) (1,554) 6,858 (4,941) 9,052 --------- --------- --------- --------- Net Income (Loss) $ 2,737 $ (8,322) $ 14,044 $ (10,806) ========= ========= ========= ========= Earnings (Loss Per Common Share) Basic $ 0.07 $ (0.22) $ 0.35 $ (0.29) ========= ========= ========= ========= Diluted $ 0.07 $ (0.22) $ 0.35 $ (0.29) ========= ========= ========= ========= Dividends Per Common Share $ 0.03 $ 0.03 $ 0.09 $ 0.09 ========= ========= ========= ========= Weighted Average Number of Common Shares and Potential Common Shares Outstanding: Basic 40,185 38,781 40,154 37,171 Diluted 40,510 38,781 40,370 37,171
See accompanying notes to consolidated financial statements. -1- Pogo Producing Company and Subsidiaries Consolidated Balance Sheets
September 30, December 31, 1999 1998 ------------- ------------ (Unaudited) (Expressed in thousands except share amounts) Assets Current Assets: Cash and cash investments $ 28,430 $ 7,959 Accounts receivable 31,856 24,054 Other receivables 20,013 38,977 Inventory - Product 10,732 969 Inventories - Tubulars 11,057 10,594 Other 1,897 2,814 ------------- ------------ Total current assets 103,985 85,367 ------------- ------------ Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized 1,571,293 1,485,125 Unevaluated properties and properties under development, not being amortized 131,191 215,244 Pipelines, at cost 6,967 6,205 Other, at cost 12,924 11,710 ------------- ------------ 1,722,375 1,718,284 ------------- ------------ Accumulated depreciation, depletion and amortization Oil and gas (977,095) (985,897) Pipelines (1,475) (1,213) Other (6,904) (5,649) ------------- ------------ Property and equipment, net (985,474) (992,759) ------------- ------------ 736,901 725,525 ------------- ------------ Other Assets: Foreign taxes receivable 31,242 23,482 Debt issue expenses 12,885 7,727 Other 20,386 20,295 ------------- ------------ 64,513 51,504 ------------- ------------ $ 905,399 $ 862,396 ============= ============
See accompanying notes to consolidated financial statements. -2- Pogo Producing Company and Subsidiaries Consolidated Balance Sheets
September 30, December 31, 1999 1998 ------------- ------------ (Unaudited) (Expressed in thousands except share amounts) Liabilities and Shareholders' Equity Current Liabilities: Accounts payable - operating activities $ 18,223 $ 12,197 Accounts payable - investing activities 33,899 90,102 Accrued interest payable 7,220 3,226 Accrued dividends associated with preferred securities of a subsidiary trust 813 - Accrued payroll and related benefits 2,481 1,952 Other 246 2 ------------- ------------ Total current liabilities 62,882 107,479 Long-Term Debt 365,000 434,947 Deferred Federal Income Tax 56,781 53,869 Deferred Credits 15,105 16,441 ------------- ------------ Total liabilities 499,768 612,736 ------------- ------------ Minority Interest: Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust, net of unamortized issue expenses 144,804 - ------------- ------------ Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized - - Common stock, $1 par; 100,000,000 shares authorized, 40,218,495 and 40,136,254 shares issued, respectively 40,218 40,136 Additional capital 291,183 290,655 Retained earnings (deficit) (69,168) (79,600) Treasury stock (15,575 shares) and other, at cost (1,406) (1,531) ------------- ------------ Total shareholders' equity 260,827 249,660 ------------- ------------ $ 905,399 $ 862,396 ============= ============
See accompanying notes to consolidated financial statements. - 3 - Pogo Producing Company and Subsidiaries Condensed Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended September 30, ----------------------------------- 1999 1998 -------------- ----------- (Expressed in thousands) Cash Flows from Operating Activities: Cash received from customers $ 135,812 $ 177,750 Operating, exploration, and general and administrative expenses paid (73,521) (88,263) Interest paid (21,890) (15,974) Federal income taxes received 6,446 - Federal income taxes paid (13,000) - Value added taxes paid (791) (3,376) Other 94 329 ----------- ----------- Net cash provided by operating activities 33,150 70,466 ----------- ----------- Cash Flows from Investing Activities: Capital expenditures (156,754) (135,964) Purchase of proved reserves - (2,961) Proceeds from the sale of properties 81,989 350 ----------- ----------- Net cash used in investing activities (74,765) (138,575) ----------- ----------- Cash Flows from Financing Activities: Proceeds from issuance of new financing 300,000 - Borrowings under senior debt agreements 250,053 340,854 Payments under senior debt agreements (470,000) (257,500) Payments of production payment - (15,246) Payments of cash dividends on common stock (3,612) (3,327) Payments of preferred dividends of a subsidiary trust (2,484) - Payment of financing issue expenses (11,943) - Proceeds from exercise of stock options and other 555 377 ----------- ----------- Net cash provided by financing activities 62,569 65,158 ----------- ----------- Effect of Exchange Rate Changes on Cash (483) 727 ----------- ----------- Net Increase (Decrease) in Cash and Cash Investments 20,471 (2,224) Cash and Cash Investments at the Beginning of the Year 7,959 19,646 ----------- ----------- Cash and Cash Investments at the End of the Period $ 28,430 $ 17,422 =========== =========== Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: Net income (loss) $ 14,044 $ (10,806) Adjustment to reconcile net income (loss) to net cash provided by operating activities - Minority interest 3,356 - Foreign currency transaction (gains) losses 1,605 (953) Gains from the sales of properties (37,503) 106 Depreciation, depletion and amortization 74,667 83,739 Dry hole and impairment 1,960 7,906 Interest capitalized (13,437) (6,540) Deferred federal income taxes 2,967 (9,389) Change in operating assets and liabilities (14,509) 6,403 ----------- ----------- Net Cash Provided by Operating Activities $ 33,150 $ 70,466 =========== ===========
See accompanying notes to consolidated financial statements. -4- Pogo Producing Company and Subsidiaries Consolidated Statements of Shareholders' Equity (Unaudited)
Nine Months Ended September 30, ---------------------------------------------------------------------------- 1999 1998 -------------------------------- ------------------------------------ Shares Amount Shares Amount ------------- ------------ --------------- ----------- (Expressed in thousands, except share amounts) Common Stock: $1.00 par-100,000,000 shares authorized Balance at beginning of year 40,136,254 $ 40,136 33,552,702 $ 33,553 Conversion of 2004 Notes - - 3,879,726 3,880 Issued for common stock of acquired company - - 1,665,491 1,665 Issued for exchangeable convertible preferred stock of acquired company - - 699,273 699 Issued for convertible debt of acquired company - - 174,818 175 Adjustment for fractional shares and other 13,132 13 - - Stock options exercised 69,109 69 147,240 147 ------------- ------------ --------------- ----------- Issued at end of period 40,218,495 40,218 40,119,250 40,119 ------------- ------------ --------------- ----------- Additional Capital: Balance at beginning of year 290,655 144,848 Conversion of 2004 Notes - 80,712 Issued for common stock of acquired company - 38,818 Issued for exchangeable convertible preferred stock of acquired company - 19,301 Issued for convertible debt of acquired company - 4,825 Cancellation of treasury shares - (206) Adjustment for fractional shares and other (13) - Stock options exercised 541 1,835 ------------ ----------- Balance at end of period 291,183 290,133 ------------ ----------- Retained Earnings (Deficit): Balance at beginning of year (79,600) (31,971) Net income (loss) 14,044 (10,806) Dividends ($0.09 per common share) (3,612) (3,327) ------------ ----------- Balance at end of period (69,168) (46,104) ------------ ----------- Treasury Stock and Other: Balance at beginning of year (15,575) (1,531) (15,575) (324) Acquisition of treasury shares of acquired company - - (9,615) (206) Cancellation of treasury shares of acquired company - - 9,615 206 Activity during the period - 125 - - ------------- ------------ --------------- ----------- Balance at end of period (15,575) (1,406) (15,575) (324) ------------- ------------ --------------- ----------- Common Stock Outstanding, at the End of the Period 40,202,920 40,103,675 ============= =============== Total Shareholders' Equity $ 260,827 $ 283,824 ============ ===========
See accompanying notes to consolidated financial statements. -5- 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 which are not necessarily indicative of results for the entire year. Certain prior year amounts have been reclassified to conform with current year presentation. 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, 1998. (2) Long-Term Debt - Long-term debt and the amount due within one year at September 30, 1999 and December 31, 1998, consist of the following: September 30, December 31, 1999 1998 ------------- ------------ (Expressed in thousands) Senior debt - Bank revolving credit agreement LIBO Rate based loans, borrowings at an average interest rate of 7.4% $ - $ 205,000 Uncommitted credit lines with banks, borrowings at an average interest rate of 6.1% - 4,000 Banker's acceptance loans, borrowings at an average interest rate of 5.9% - 10,947 ------------ ------------ Total senior debt - 219,947 ------------ ------------ Subordinated debt - 8 3/4% Senior subordinated notes due 2007 ("2007 Notes") 100,000 100,000 10 3/8% Senior subordinated notes due 2009 ("2009 Notes") 150,000 - 5 1/2% Convertible subordinated notes due 2006 ("2006 Notes") 115,000 115,000 ------------ ------------ Total subordinated debt 365,000 215,000 ------------ ------------ Long-term debt, none due within one year $ 365,000 $ 434,947 ============ ============ Refer to Note 3 of Notes to Consolidated Financial Statements included in the Company's annual report on Form 10-K for the year ended December 31, 1998, for a further discussion of the Company's uncommitted credit lines, the banker's acceptance loans, the 2007 Notes, the 2006 Notes, and the bank revolving credit agreement. On July 16, 1999, the Company and its lenders entered into an amendment to its amended and restated credit agreement which, in addition to other minor matters, extended the maturity date of the lenders' revolving loan commitments to July 1, 2001, and if applicable, their term loan commitments to July 2, 2003. On January 15, 1999, the Company issued $150,000,000 of 10 3/8% Senior Subordinated Notes, due 2009 (the "2009 Notes"). The proceeds from the issuance of the 2009 Notes were used to repay amounts outstanding under the Company's credit agreement. The 2009 Notes bear interest at a rate of 10 3/8%, and are payable semiannually in arrears on February 15 and August 15 of each year, commencing August 15, 1999. The 2009 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the credit agreement, its unsecured credit lines, and bankers acceptances, are equal in right of payment to the 2007 Notes, but are senior in right of payment to its subordinated indebtedness, which currently includes the 2006 Notes. The Company, at its option, may redeem the 2009 Notes in whole or in part, at any time on or after February 15, 2004, at a redemption price of 105.188% of their principal value and decreasing percentages thereafter. No sinking fund payments are required on the 2009 Notes. The 2009 Notes are redeemable at the option of any holder, upon the occurrence of a change in control (as defined in the indenture governing the 2009 Notes), at 101% of their principal amount. The indenture governing the 2009 Notes also imposes certain covenants on the Company that are similar to the covenants contained in the indenture governing the 2007 Notes, including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of asset sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and mergers, consolidations and the sale of assets. As of September 30, 1999, $8,900,000 was available to the Company for common stock dividends under the covenant that restricts certain types of payments and distributions by the company. -6- Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (3) Minority Interest - Pogo Trust I, a business trust in which the Company owns all of the issued common securities (the "Trust"), issued $150,000,000 (3,000,000 securities having a liquidation preference of $50 each) of 6 1/2% Cumulative Quarterly Income Convertible Securities, Series A (the "Trust Preferred Securities") on June 2, 1999. The proceeds of the issuance of the Trust Preferred Securities were used to purchase $150,000,000 of the Company's 6 1/2% Junior Subordinated Convertible Debentures, due 2029 (the "Debentures"). The financial terms of the Debentures are generally the same as those of the Trust Preferred Securities. The Trust Preferred Securities accrue and pay distributions quarterly in arrears at a rate of 6 1/2% per annum on the stated liquidation amount of $50 per Trust Preferred Security on March 1, June 1, September 1, and December 1 of each year to security holders of record on the business day immediately preceding the distribution payment date. The Company has guaranteed, on a subordinated basis, distributions and other payments due on the Trust Preferred Securities to the extent that there are funds available in the Trust. The Company may cause the Trust to defer the payment of distributions for successive periods up to 20 consecutive periods unless an event of default on the Debentures has occurred and is continuing. During such periods, accrued distributions on the Trust Preferred Securities will compound quarterly and the Company will generally not be permitted to declare or pay distributions on its common stock or debt securities that rank equal or junior to the Debentures. The Trust Preferred Securities are convertible at the option of the holder at any time into common stock of the Company at the rate of 2.1053 shares of Company common stock per Trust Preferred Security. This conversion rate will be subject to adjustment to prevent dilution and is currently equivalent to a conversion price of $23.75 per share of Company common stock. The Trust Preferred Securities are mandatorily redeemable upon maturity of the Debentures on June 1, 2029, or to the extent of any earlier redemption of any Debenture by the Company and are callable by the Trust at any time after June 1, 2002. In addition, if the tax laws change so that the Trust becomes subject to federal income taxes or if interest payments made by the Company to the Trust or the Debentures are no longer deductible for federal income tax purposes, the Trust may liquidate and distribute Debentures to holders of the Trust Preferred Securities and, in certain circumstances, the Company may shorten the stated maturity of the Debentures to as early as June 2, 2014. The amounts recorded for the third quarter and first nine months of 1999 under Minority Interests - 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. -7- Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (4) Geographic Segment Reporting - The Company's long-lived assets, revenues and operating income (loss) by segment and geographic area are as follows:
Company Oil and Gas Pipelines Other ----------- ----------- --------- ---------- (Expressed in thousands) Long-Lived Assets: As of September 30, 1999: United States $ 397,246 $ 388,077 $ 5,492 $ 3,677 Kingdom of Thailand 334,700 332,512 - 2,188 Canada 4,955 4,800 - 155 ----------- ----------- --------- ---------- Total $ 736,901 $ 725,389 $ 5,492 $ 6,020 =========== =========== ========= ========== As of December 31, 1998: United States $ 502,787 $ 493,633 $ 4,992 $ 4,162 Kingdom of Thailand 209,552 207,756 - 1,796 Canada 13,186 13,083 - 103 ----------- ----------- --------- ---------- Total $ 725,525 $ 714,472 $ 4,992 $ 6,061 =========== =========== ========= ========== Revenues: For the three months ended September 30, 1999 United States $ 51,808 $ 49,897 $ 2,094 $ (183) Kingdom of Thailand 16,441 16,403 - 38 Canada 889 895 - (6) ----------- ----------- --------- ---------- Total $ 69,138 $ 67,195 $ 2,094 $ (151) =========== =========== ========= ========== For the three months ended September 30, 1998 United States $ 36,919 $ 36,113 $ 810 $ (4) Kingdom of Thailand 8,845 8,772 - 73 Canada 415 402 - 13 ----------- ----------- --------- ---------- Total $ 46,179 $ 45,287 $ 810 $ 82 =========== =========== ========= ========== For the nine months ended September 30, 1999 United States $ 160,664 $ 118,686 $ 4,556 $ 37,412 Kingdom of Thailand 26,555 26,590 - (35) Canada 2,793 2,813 - (20) ----------- ----------- --------- ---------- Total $ 190,012 $ 148,089 $ 4,556 $ 37,357 =========== =========== ========= ========== For the nine months ended September 30, 1998 United States $ 130,250 $ 129,621 $ 810 $ (181) Kingdom of Thailand 28,907 28,813 - 94 Canada 415 402 - 13 ----------- ----------- --------- ---------- Total $ 159,572 $ 158,836 $ 810 $ (74) =========== =========== ========= ========== Operating Income (Loss): For the three months ended September 30, 1999 United States $ 12,138 $ 11,633 $ 688 $ (183) Kingdom of Thailand (244) (282) - 38 Canada 15 21 - (6) ----------- ----------- --------- ---------- Total $ 11,909 $ 11,372 $ 688 $ (151) =========== =========== ========= ========== For the three months ended September 30, 1998 United States $ (8,075) $ (8,535) $ 641 $ (181) Kingdom of Thailand (3,928) (4,022) - 94 Canada (461) (474) - 13 ----------- ----------- --------- ---------- Total $ (12,464) $ (13,031) $ 641 $ (74) =========== =========== ========= ========== For the nine months ended September 30, 1999 United States $ 45,263 $ 7,236 $ 615 $ 37,412 Kingdom of Thailand (6,635) (6,600) - (35) Canada (1,603) (1,583) - (20) ----------- ----------- --------- ---------- Total $ 37,025 $ (947) $ 615 $ 37,357 =========== =========== ========= ========== For the nine months ended September 30, 1998 United States $ (3,239) $ (3,699) $ 641 $ (181) Kingdom of Thailand (6,672) (6,766) - 94 Canada (461) (474) - 13 ----------- ----------- --------- ---------- Total $ (10,372) $ (10,939) $ 641 $ (74) =========== =========== ========= ==========
-8- Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (5) Comprehensive Income - During 1998, the Company adopted the Financial Accounting Standards Board's (FASB's) Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income ("SFAS 130"). Currently there are no significant amounts to be included in the computation of comprehensive income of the Company, as defined, that are required to be disclosed under the provisions of SFAS 130. (6) Impact of SFAS 133 - In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities: ("SFAS 133"). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair market value and that changes in the derivative's fair market value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133 is effective for the Company in 2001 but early adoption is allowed. The Company has not yet quantified the impact of adopting SFAS 133 or determined the timing or method of adoption. However, SFAS 133 could increase volatility in earnings and other comprehensive income should the Company enter into transactions covered by the pronouncement. (7) 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 share (diluted earnings per share) consider the effect of dilutive securities as set out below, in thousands, except per share amounts:
Three Months Ended Nine Months Ended September 30, 1999 September 30, 1999 ---------------------------------- ---------------------------------- Income Shares Per Share Income Shares Per Share -------- --------- --------- --------- -------- ---------- Basic earnings per share - $ 2,737 40,185 $ 0.07 $ 14,044 40,154 $ 0.35 ========= ========== Effect of dilutive securities: Options to purchase common shares - 325 - 216 -------- --------- --------- -------- Diluted earnings per share $ 2,737 40,510 $ 0.07 $ 14,044 40,370 $ 0.35 ======== ========= ========= ========= ======== ========== Antidilutive securities - Options to purchase common shares - 1,106 $ 23.73 - 2,668 $ 20.99 2006 Notes 1,028 2,726 $ 0.38 3,083 2,726 $ 1.13 Trust Preferred Securities (a) 1,584 6,316 $ 0.25 2,089 2,776 $ 0.75 Three Months Ended Nine Months Ended September 30, 1998 September 30, 1998 ---------------------------------- ---------------------------------- Income Shares Per Share Income Shares Per Share -------- --------- --------- --------- -------- ---------- Basic earnings per share - $ (8,322) 38,781 $ (0.22) $ (10,806) 37,171 $ (0.29) ========= ========== Effect of dilutive securities: Options to purchase common shares - - - - - - -------- --------- --------- -------- Diluted earnings per share $ (8,322) 38,781 $ (0.22) $ (10,806) 37,171 $ (0.29) ======== ========= ========= ========= ======== ========== Antidilutive securities - Options to purchase common shares - 2,476 $ 24.73 - 2,476 $ 24.73 2004 Notes (b) - - - 560 816 $ 0.69 2006 Notes 1,051 2,726 $ 0.39 3,118 2,726 $ 1.14
(a) The Trust Preferred Securities were issued on June 2, 1999. (b) The 2004 Notes were converted to common stock or called in the first quarter of 1998. -9- Pogo Producing Company and Subsidiaries 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, 1998. 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, 1998, 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. Results of Operations Net income (Loss) The Company reported net income for the third quarter of 1999 of $2,737,000 or $0.07 per share (on both a basic and a diluted basis), compared to a net loss for the third quarter of 1998 of $8,322,000 or $0.22 per share (on both a basic and a diluted basis). For the first nine months of 1999, the Company reported net income of $14,044,000 or $0.35 per share (on both a basic and a diluted basis) compared to a net loss for the first nine months of 1998 of $10,806,000 or $0.29 per share (on both a basic and a diluted basis). The net income reported during the first nine months of 1999, compared to the first nine months of 1998, was primarily related to a net gain recognized by the Company from the sale of certain properties, including the previously announced sale of the Lopeno Field in South Texas, most of which occurred in the first quarter of 1999. These property sales were part of an effort by the Company to sell its non-strategic and/or underperforming properties to generate cash and maximize its focus on properties with greater exploration potential. If the gain of $37,503,000 related to the sale of such properties during 1999 is excluded, the Company would have reported a net loss for the first nine months of $10,333,000 or $0.26 per share (on both a basic and a diluted basis). 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 third quarter of 1999, compared to the third quarter of 1998, resulted primarily from the issuance as of August 17, 1998 of approximately 2,500,000 shares of common stock to former holders of Arch capital stock and convertible debt securities in connection with the Company's acquisition of Arch Petroleum Inc. ("Arch") and, to a lesser extent, the issuance of common stock upon the exercise of stock options pursuant to the Company's incentive plans. The increase in the weighted average number of common shares outstanding for the first nine months of 1999, compared to the first nine months of 1998, is related to the issuance of shares, in the Arch acquisition, the issuance of shares of common stock upon the exercise of stock options and the issuance of approximately 3,900,000 shares of the Company's common stock upon the conversion of the Company's 5 1/2% Convertible Subordinated Notes due 2004 (the "2004 Notes") prior to their being redeemed on March 16, 1998. The earnings per share computation on a diluted basis in the periods presented also reflects 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. Total Revenues The Company's total revenues for the third quarter of 1999 were $69,138,000, an increase of approximately 50% from total revenues of $46,179,000 for the third quarter of 1998. The increase in the Company's total revenues for the third quarter of 1999, compared to the third quarter of 1998, resulted primarily from a substantial increase in oil and gas revenues and, to a much lesser extent, from increased pipeline sales. The Company's total revenues for the first nine months of 1999 were $190,012,000, an increase of approximately 19% compared to total revenues of $159,572,000 for the first nine months of 1998. The increase in the Company's total revenues for the first nine months of 1999, compared to the first nine months of 1998, resulted primarily from the gains related to the previously discussed sale of oil and gas properties and, to a lesser extent, pipeline sales revenues that were only partially offset by a decline in the Company's oil and gas revenues. -10- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations Oil and Gas Revenues The Company's oil and gas revenues for the third quarter of 1999 were $67,195,000, an increase of approximately 48% from oil and gas revenues of $45,287,000 for the third quarter of 1998. The Company's oil and gas revenues for the first nine months of 1999 were $148,089,000, a decrease of approximately 7% from oil and gas revenues of $158,836,000 for the first nine months of 1998. The following table reflects an analysis of variances in the Company's oil and gas revenues (expressed in thousands) between 1999 and 1998:
Increase (decrease) in oil and gas revenues 3/rd/ Qtr 1999 Nine Mo. 1999 resulting from variances in: Compared to Compared to 3/rd/ Qtr 1998 Nine Mo. 1998 -------------- ------------- Natural gas -- Price............................................................ $ 5,066 $ (224) Production....................................................... 1,488 (17,325) ------- -------- 6,554 (17,549) ------- -------- Crude oil and condensate -- Price............................................................ 12,698 14,566 Production....................................................... 1,093 (6,110) ------- -------- 13,791 8,456 ------- -------- Natural Gas Liquids ("NGL")......................................... 1,563 (1,654) ------- -------- Increase (decrease) in oil and gas revenues...................... $21,908 $(10,747) ======= ========
The increase in the Company's oil and gas revenues for the third quarter of 1999, compared to the third quarter of 1998, is primarily related to increases in the prices that the Company received for its oil, condensate and NGL ("liquid hydrocarbons") and natural gas production volumes and, to a lesser extent, increases in natural gas and liquid hydrocarbon production volumes. The decrease in the Company's oil and gas revenues for the first nine months of 1999, compared to the first nine months of 1998, is primarily related to a decline in the Company's natural gas and liquid hydrocarbon production volumes, that was partially offset by increases in the prices that the Company received for its liquid hydrocarbon production volumes.
Comparison of Increases (Decreases) in: 3/rd/ Quarter % 1/st/ Nine Months % ----------------- ----------------- Natural Gas -- 1999 1998 Change 1999 1998 Change ------ ------ ------ ------ ------ ------ Average prices North America (a)...................................... $ 2.64 $ 1.99 33% $ 2.19 $ 2.13 3% Kingdom of Thailand(b)................................. $ 1.66 $ 1.74 (5%) $ 1.55 $ 1.74 (11%) Company-wide average price........................ $ 2.32 $ 1.93 20% $ 2.03 $ 2.04 -- Average daily production volumes (MMcf per day) North America (a)...................................... 99.6 105.2 (5%) 101.0 125.6 (20%) Kingdom of Thailand.................................... 47.9 35.3 36% 32.2 38.9 (17%) ------ ------ ------ ------ Company-wide average daily production............. 147.5 140.5 5% 133.2 164.4 (19%) ====== ====== ====== ======
____________________________ (a) North American average prices and production reflect production from the United States and Canada for the third quarter and first nine months of 1999, but only production from the United States for periods prior to August 17, 1998, the date on which the Company acquired its interests in Canada as part of the Arch acquisition. "MMcf" stands 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 dollars based on the revenue recorded in the Company's financial records. The average price that the Company received for its natural gas production in the Kingdom of Thailand during portions of the third quarter of1998 and the third quarter and first nine months of 1999 reflects the impact of the penalty provisions of the Company's gas sales agreement with the Petroleum Authority of Thailand from October 1, 1998 through early August 1999, when production from a new platform in the Tantawan field and the Benchamas field increased to a level sufficient to meet the Company's contractual commitments under its gas sales agreement. -11- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations Natural Gas Thailand Prices. The price that the Company receives under the Gas Sales Agreement with the Petroleum Authority of Thailand ("PTT") is subject to a penalty provision if the Company does not meet the minimum delivery requirements set forth in the agreement. The average price that the Company received for its natural gas production in the Kingdom of Thailand during the third quarter of 1998 and portions of the third quarter and first nine months of 1999 reflects the impact of the penalty provisions of the Gas Sales Agreement from October 1, 1998 through early August 1999, when production from a new platform in the Tantawan field and the Benchamas field increased to a level sufficient to meet the Company's contractual commitments under the Gas Sales Agreement. Production. The increase in the Company's natural gas production during the third quarter of 1999, compared to the third quarter of 1998, was related to increased production from the Company's operations in Thailand which included the completion of a successful in-fill drilling program in the Tantawan field, and the commencement of production from the Benchamas field and a new platform in the Tantawan field. This increase in production was partially offset by decreased production from the Company's North American operations which was related in large measure to decreased production from the Company's East Cameron Block 334 "E" platform and the sale of the Lopeno field during the first quarter of 1999. The decline in the Company's North American natural gas production during the third quarter and first nine months of 1999, compared to the third quarter and first nine months of 1998, was partially offset by successful development of the Company's Garden Banks Block 367 and Main Pass Block 226 field and its continued successful offshore and onshore drilling and workover program. The Company's Thailand natural gas production during the first nine months of 1999, compared to the first nine months of 1998, declined in part due to disappointing reservoir performance and, in part, due to the need to shut-in production from platforms during the in-fill drilling program that commenced during the first quarter of 1999 and was recently completed, that was not entirely offset by the previously discussed new drilling and development in the Tantawan field that was recently completed and which is currently ongoing in the Benchamas field.
Comparison of Increases (Decreases) in: 3/rd/ Quarter % 1/st/ Nine Months % ------------------- ------------------- Crude Oil and Condensate -- 1999 1998 Change 1999 1998 Change ------- ------- ------ ------- ------- ------ Average prices North America(a)...................................... $ 20.24 $ 12.80 58% $ 15.89 $ 13.45 18% Kingdom of Thailand................................... $ 26.21 $ 13.08 100% $ 22.18 $ 13.71 62% Company-wide average price........................... $ 21.62 $ 12.85 68% $ 16.81 $ 13.49 25% Average daily production volumes (Bbls per day) North America(a)...................................... 12,509 13,124 (5%) 12,610 13,316 (5%) Kingdom of Thailand................................... 3,763 2,598 45% 2,150 2,774 (22%) ------- ------- ------- ------- Company-wide average daily production................ 16,272 15,722 4% 14,760 16,090 (8%) ======= ======= ======= ======= Total Liquid Hydrocarbons -- Company-wide average daily production (Bbls per day) 18,771 17,809 5% 16,851 18,858 (11%) ======= ======= ======= =======
__________________________ (a) North American average prices and production reflect production from the United States and Canada for the third quarter and first nine months of 1999, but only production from the United States for periods prior to August 17, 1998, the date on which the Company acquired its interests in Canada as part of the Arch acquisition. "Bbls" stands for million barrels. Crude Oil and Condensate Thailand Prices. Since the inception of production from the Tantawan Field, crude oil and condensate has been stored on a Floating Production, Storage and Offloading system until an economic quantity was accumulated for offloading and sale. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, which are denominated in dollars. In addition, the Company is generally paid for its crude oil and condensate production from Thailand in U.S. dollars. -12- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations Production. The decrease in the Company's North American crude oil and condensate production during the third quarter and first nine months of 1999, compared to the third quarter and first nine months of 1998, resulted from the anticipated natural decline in oil and condensate production from certain of the Company's offshore properties, that was partially offset by increased production from the Company's Permian basin properties due to an active workover and recompletion program that commenced in late 1998 and additional production from properties acquired in the Arch acquisition. The increase in the Company's Thailand crude oil and condensate production for the third quarter of 1999, compared to the third quarter of 1998, reflects the success of the in-fill drilling program in the Tantawan Field, and the commencement of production from the Benchamas Field and a new platform in the Tantawan Field. The Company's Thailand crude oil and condensate production for the first nine months of 1999, compared to the first nine months of 1998, declined in part due to disappointing reservoir performance and, in part, due to the need to shut-in production from platforms during the in-fill drilling program that commenced during the first quarter of 1999 and was recently completed. This decline was partially offset by increased production in the third quarter of 1999 due to the reasons previously described. 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 third quarter of 1999, compared with the third quarter of 1998, related to an increase in both the Company's NGL production volumes and the average price that the Company received for its NGL production. The decrease in NGL revenues for the first nine months of 1999, compared with the first nine months of 1998, related to a decrease in the Company's NGL production volumes due to decreased production from the Company's East Cameron 334 "E" platform, that was partially offset by an increase in the average price that the Company received for its NGL production. Costs and Expenses
3/rd/ Quarter 1/st/ Nine Months --------------------------- % ---------------------------- % Comparison of Increases (Decreases) in: 1999 1998 Change 1999 1998 Change --------- --------- ---------- ---------- Lease Operating Expenses North America..................... $12,959,000 $11,795,000 10% $ 35,545,000 $ 34,521,000 3% Kingdom of Thailand............... $ 6,807,000 $ 6,089,000 12% $ 12,380,000 $ 15,947,000 (22%) ----------- ----------- ------------ ------------ Total Lease Operating Expenses. $19,766,000 $17,884,000 11% $ 47,925,000 $ 50,468,000 ( 5%) =========== =========== ============ ============ Pipeline Operating and Natural Gas Purchases (a)................. $ 1,307,000 $ 728,000 80% $ 3,505,000 $ 728,000 N/A General and Administrative Expenses.. $ 7,003,000 $ 8,556,000 (18%) $ 20,990,000 $ 19,843,000 6% Exploration Expenses................. $ 801,000 $ 1,426,000 (44%) $ 3,940,000 $ 7,260,000 (46%) Dry Hole and Impairment Expenses..... $ 930,000 $ 5,128,000 (82%) $ 1,960,000 $ 7,906,000 (75%) Depreciation, Depletion and Amortization (DD&A) Expenses..... $27,422,000 $24,921,000 10% $ 74,667,000 $ 83,739,000 (11%) DD&A rate........................ $ 1.13 $ 1.08 5% $ 1.14 $ 1.09 5% Mcfe produced (b)................ 23,929,000 22,772,000 5% 63,962,000 75,781,000 (16%)
_____________________________________________________ (a) The Company acquired its primary pipeline assets as part of the Arch acquisition on August 17, 1998. Consequently, pipeline operating and natural gas purchase expenses only reflect results of operations after that date. (b) "Mcfe" stands for thousands of cubic feet equivalent. - 13- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations
3/rd/ Quarter 1/st/ Nine Months --------------------------- % ---------------------------- % Comparison of Increases (Decreases) in: 1999 1998 Change 1999 1998 Change --------- --------- ---------- ---------- Interest-- Charges.................................. $(8,305,000) $(6,236,000) 33% $(27,414,000) $(17,513,000) 57% Interest Income.......................... $ 588,000 $ 284,000 107% $ 898,000 $ 534,000 68% Capitalized Interest Expense............. $ 4,670,000 $ 2,476,000 89% $ 13,437,000 $ 6,540,000 105% Minority Interest - Dividends and costs Associated with Preferred Securities of a Subsidiary Trust....................... $(2,557,000) -- N/A $ (3,356,000) -- N/A Foreign Currency Transaction Gain (Loss).............................. $(2,014,000) $ 760,000 N/A $ (1,605,000) $ 953,000 N/A Income Tax Benefit (Expense)............... $(1,554,000) $ 6,858,000 N/A $ (4,941,000) $ 9,052,000 N/A
Lease Operating Expenses. The increase in North American lease operating expenses for the third quarter and first nine months of 1999, compared to the third quarter and first nine months of 1998, primarily resulted from increased lease operating expenses related to properties acquired in the Arch acquisition for which no similar expenses were recorded during a material portion of the third quarter and first nine months of 1998, and, to a much lesser extent, increased severance taxes, that was not entirely offset by the results of a company-wide cost reduction program. The increase in Thailand lease operating expenses for the third quarter of 1999, compared the third quarter of 1998, was primarily related to lease operating expenses for the Benchamas field which commenced production during the third quarter of 1999, which was partially offset by the Company's cost- reduction program. Included within the operating expenses for the Benchamas field is an operating lease for the FSO "Benchamas Explorer" under which the Company made payments of $1,064,000 to the lessor during the third quarter of 1999 on account of the lease. The decrease in Thailand lease operating expenses for the first nine months of 1999, compared to the first nine months of 1998, related to recognition of previously deferred billings to third parties and, to a lesser extent, to an ongoing cost reduction program, that was partially offset by the previously discussed costs attributable to the Benchamas field. Pipeline Operating and Natural Gas Purchases The Company acquired primarily all of its pipeline interests as part of its acquisition of Arch on August 17, 1998. The Company purchases natural gas for transportation through the Pogo Onshore Pipeline, which runs from Wichita Falls, Texas to just outside of Fort Worth, Texas. This gas is then resold under firm contracts to its customers. The expense of purchasing the natural gas is reported on the Company's income statement under pipeline operating and natural gas purchases. Revenue from the sale of the natural gas is reported as revenue under pipeline sales and other. Prior to the acquisition of the Pogo Onshore Pipeline interests, the Company did not separately report its pipeline operating expenses or revenues, nor did it purchase any natural gas for resale to customers of its pipelines. The increase in pipeline operating expenses and natural gas purchase costs for the third quarter of 1999, compared to the third quarter of 1998, was primarily related to the fact that expenses for the pipeline were recorded for the entire third quarter of 1999, whereas expenses for the third quarter of 1998 did not commence until the pipeline was acquired as part of the Arch acquisition on August 17, 1998. General and Administrative Expenses The decrease in general and administrative expenses for the third quarter of 1999, compared with the third quarter of 1998, was primarily related to costs incurred during the third quarter of 1998 related to the Arch acquisition, for which no comparable expenses were incurred in the third quarter of 1999. The increase in general and administrative expenses for the first nine months of 1999, compared with the first nine months of 1998, was - 14- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations primarily related to an increase in the size of the Company's work force due to the Arch acquisition, that was partially offset by expenses in the third quarter of 1998 related to the Arch acquisition. 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 decrease in exploration expense for the third quarter of 1999, compared to the third quarter of 1998, resulted primarily from decreased geophysical data acquisition costs in the Gulf of Mexico, which was partially offset by increased expenses stemming from increased geophysical activity in the Company's onshore North American operating areas. The decrease in exploration expense for the first nine months of 1999, compared to the first nine months of 1998, resulted primarily from generally decreased geophysical activity by the Company during the first half of the year, except in Canada, where the Company participated in a significant 3-D survey during the first quarter of 1999. Depreciation, Depletion and Amortization Expenses The increase in the Company's depreciation, depletion and amortization ("DD&A") expense for the third quarter of 1999, compared to the third quarter of 1998, resulted primarily from an increase in the Company's natural gas and liquid hydrocarbon production and, to a lesser extent, an increase in the Company's composite DD&A rate. The decrease in the Company's depreciation, depletion and amortization ("DD&A") expense for the first nine months of 1999, compared to the first nine months of 1998, resulted primarily from a decrease in the Company's natural gas and liquid hydrocarbon production, that was only partially offset by 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 third quarter and first nine months of 1999, compared to the third quarter and first nine months of 1998, resulted primarily from an increased percentage of the Company's production coming from certain of the Company's fields that have DD&A rates that are higher than the Company's recent historical composite rate and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates that are lower than the Company's recent historical composite DD&A rate. Management currently anticipates that this trend will continue for the foreseeable future, resulting in generally increasing DD&A rates. Interest Interest Charges. The increase in the Company's interest charges for the third quarter of 1999, compared to the third quarter of 1998, resulted primarily from an increase in average interest rates on the debt outstanding (resulting primarily from the issuance of the 10 3/8% Senior Subordinated Notes due 2009 (the "2009 Notes") on January 15, 1999) and, to a lesser extent, an increase in the total amount of debt outstanding. The increase in the Company's interest charges for the first nine months of 1999, compared to the first nine months of 1998, resulted in almost equal measure primarily from an increase in average interest rates on the debt outstanding (resulting primarily from the issuance of the 10 3/8% Senior Subordinated Notes due 2009 (the "2009 Notes") on January 15, 1999) and an increase in the total amount of debt outstanding. Capitalized Interest. The increase in capitalized interest for the third quarter and first nine months of 1999, compared to the third quarter and first nine months of 1998, resulted primarily from an increase in the amount of capital expenditures subject to interest capitalization during the third quarter and first nine months of 1999 ($221,600,000 and $221,080,000 , respectively), compared to the third quarter and first nine months of 1998 ($141,259,000 and $122,414,000, respectively), and from an increase in the computed rate that the Company uses to apply to such capital expenditures to arrive at the total amount of capitalized interest. A substantial percentage of the Company's capitalized interest expense resulted from capitalization of interest related to capital expenditures for the - 15- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations development of the Benchamas Field in the Gulf of Thailand and, to a lesser extent, several development projects in the Gulf of Mexico. With the completion of the Benchamas Field and the Garden Banks Block 367 project in the Gulf of Mexico in third quarter of 1999, the amount of capital expenditures subject to capitalization should generally be lower during the next several quarters than it has been during the last year. Consequently, management currently expects that capitalized interest expense should decrease significantly in the next several quarters. Minority Interest -- Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust Pogo Trust I, a business trust in which the Company owns all of the issued common securities, issued $150,000,000 of 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities, Series A (the "Trust Preferred Securities") on June 2, 1999. The amounts recorded for the third quarter and first nine months of 1999 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 and loss 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 subsidiary's financial statements during the respective periods. In early July 1997, the government of the Kingdom of Thailand announced that the value of the Baht would be set against the dollar and other currencies under a "managed float" program arrangement. During the third quarter of 1999, the value of the Thai Baht generally declined against the U.S. dollar resulting in the losses recorded for the third quarter and first nine months of 1999. The Company cannot predict what the Thai Baht to U. S. dollar exchange rate may be in the future. Moreover, it is anticipated that this exchange rate will remain volatile. As of October 15, 1999, the Company was not a party to any financial instrument that was intended to constitute a foreign currency hedging arrangement. Income Tax Benefit (Expense) The Company's income tax expense for the third quarter of 1999 resulted primarily from pre-tax income from the Company's North American operations, that was only partially offset by tax benefit of accrued foreign losses from the Company's operations in the Kingdom of Thailand. The Company's income tax expense for the first nine months of 1999 resulted primarily from a pre-tax gain on the sale of the Lopeno Field and, to a lesser extent, pre-tax from the Company's U.S. operations, that was only partially offset by the tax benefit of accrued foreign losses from the Company's international operations. Liquidity and Capital Resources Cash Flows The Company's Condensed Consolidated Statement of Cash Flows for the first nine months of 1999 reflects net cash provided by operating activities of $33,150,000. In addition to net cash provided by operating activities, the Company received $81,989,000 from the sale of certain non-strategic and/or underperforming properties, proceeds of $300,000,000 from the sale of Trust Preferred Securities and 2009 Notes and net proceeds of $555,000 from the exercise of stock options and other miscellaneous income sources. During the first nine months of 1999, the Company invested $156,754,000 of such cash flow in capital projects, repaid a net $219,947,000 under its senior debt arrangements, paid $11,943,000 in financing issuance expenses, paid $3,612,000 (three quarterly dividend payments of $0.03 per share) in cash dividends to holders of the Company's common stock and paid $2,484,000 in cash distributions to holders of its Trust Preferred Securities. As of - 16- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations September 30, 1999, the Company's cash and cash investments were $28,430,000, its long-term debt stood at $365,000,000 and its net obligations on mandatorily redeemable convertible preferred securities of its subsidiary Pogo Trust I, were $150,000,000, which is reflected on the Company's September 30, 1999 balance sheet net of $5,196,000 of unamortized issue expense. Future Capital Requirements The Company's capital and exploration budget for 1999, 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 is $195,000,000. The Company currently anticipates that its available cash and cash investments, cash provided by operating activities, funds available under its credit agreement, uncommitted credit lines and banker's acceptance facilities 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 1999, and future dividend and distribution payments at current levels (including a dividend payment of $0.03 per share to be paid on November 19, 1999 to shareholders of record on November 5, 1999). 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 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. Other Matters Year 2000 Readiness Disclosure. Information regarding the Company's Year 2000 readiness is contained in the Company's annual report on Form 10-K for the year ended December 31, 1998 and reference is made to the information contained there. There has been no material change in the Company's Year 2000 readiness since that information was disclosed. Hedging From time to time, the Company has utilized and expects to continue to utilize 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. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. All of the Company's recent historical hedging transactions have been carried out in the over-the-counter market with investment grade institutions. The Company accounts for these transactions as hedging activities and, accordingly, gains or losses are included in oil and gas revenues when the hedged production is delivered. Neither the hedging contract nor the unrealized gains and losses on these contracts are recognized in the financial statements. Natural Gas. As of October 22, 1999, the Company had entered into commodity price hedging contracts with respect to its future 1999 and 2000 natural gas production as follows: -17- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations
Swaps ------------------------------ Weighted Average NYMEX Contract Price Volume in Volume in Period per MMBtu(a) MMBtus MBtu/day(b) - -------------------------- -------------- --------- ----------- 01-Oct-1999 -- 31-Mar-2000 $3.11 1,820 10,000 01-Oct-1999 -- 31-Aug-2000 $2.87 5,025 15,000
(a) "MMBtu" means million British Thermal Units. (b) "MBtu" means thousand British Thermal Units. 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. With respect to any particular swap transaction, the counterparty is required to make a payment to the Company in the event that the settlement price for any settlement period is less than the swap price for such transaction, and the Company is required to make payment to the counterparty in the event that the settlement price for any settlement period is greater than the swap price for such transaction. 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 payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such transaction. 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. The Company believes that it has no material basis risk with respect to gas swaps because it only enters into them with respect to its North American natural gas production, substantially all of which is sold under spot contracts that have historically correlated with the swap price. Crude Oil. As of October 22, 1999, the Company had entered into commodity price hedging contracts with respect to its future oil production for 1999 and 2000 as follows:
Swaps Collars ---------------------------- ---------------------------------- Weighted NYMEX Average Contract Price NYMEX per Bbl Volume in Contract Price Volume in --------------------- Period Bbls/day Bbls per Bbl Bbls Floors Ceilings - -------------------------- -------- ---------- --------------- ---------- -------- ---------- 01-Oct-1999 -- 31-Dec-1999 2,000 182,000 $21.51 --- --- --- 01-Oct-1999 -- 31-Mar-2000 1,500 273,000 $21.12 --- --- --- 01-Oct-1999 -- 31-Mar-2000 1,000 --- --- 182,000 $21.15 $23.00 01-Jan-2000 -- 31-Dec-2000 2,000 730,000 $21.15 --- --- ---
Because substantially all of the Company's oil production is sold under spot contracts that correlate either to the NYMEX West Texas Intermediate price or the Indonesian TAPIS benchmark crude (with respect to production from the Company's Thailand operations), the Company believes that it has no material basis risk with respect to these transactions, meaning that fluctuations in the prices which the Company receives for its domestic oil production will correlate with the NYMEX West Texas Intermediate price. -18- Pogo Producing Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations Part II. Other Information Item 6. Exhibits and Reports on Form 8-K (A) Exhibits 27 -- Financial Data Schedule (B) Reports on Form 8-K None -19- 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 Vice President and Chief Financial Officer Date: October 29, 1999 -20- EX-27 2 FINANCIAL DATA SCHEDULE
5 This Financial Data Schedule contains summary financial information extracted from the Consolidated Financial Statements (Unaudited) of Pogo Producing Company, including the Consolidated Balance Sheets as of September 30, 1999 and the Consolidated Statements of Income for the nine months ended September 30, 1999, and is qualified in its entirety by reference to such Consolidated Financial Statements. 1,000 9-MOS DEC-31-1998 SEP-30-1999 28,430 0 51,869 0 21,789 103,985 1,722,375 985,474 905,399 62,882 365,000 0 0 40,218 220,609 905,399 152,509 190,012 51,430 51,430 101,557 0 27,414 18,985 4,941 14,044 0 0 0 14,044 0.35 0.35 This amount is not disclosed on the face of the Consolidated Financial Statements due to lack of materiality, but is included as a contra-asset in Accounts Receivable. Does not include Gains or Losses on Property Sales. Include Lease Operating Expense, but excludes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. Includes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. This amount is not disclosed on the face of the Consolidated Financial Statements due to lack of materiality, but is included in Oil and Gas Revenues.
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