-----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, JDiMXFHvrWX0HKPhhvz0aN6ZAD+z/wqKr1myiNpR41tu+s3wiijXSDc9N7yFn2wg t9YblJ9TLCPhxbH6DRo/MA== 0000899243-01-500506.txt : 20010515 0000899243-01-500506.hdr.sgml : 20010515 ACCESSION NUMBER: 0000899243-01-500506 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010331 FILED AS OF DATE: 20010514 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: 1632297 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 d10q.txt FOR THE QUARTER ENDED MARCH 31, 2001 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] Quarterly report pursuant to section 13 or 15[d] of the Securities Exchange Act of 1934 For the quarterly period ended March 31, 2001 or [__] Transition report pursuant to section 13 or 15[d] of the Securities Exchange Act of 1934 For the transition period from........to....... Commission file number 1-7792 Pogo Producing Company [Exact Name of Registrant as Specified in Its Charter] Delaware 74-1659398 [State of Other Jurisdiction of [I.R.S. Employer Incorporation or Organization] Identification No.] 5 Greenway Plaza, Suite 2700 Houston, Texas 77046-0504 [Address or 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 March 31, 2001: 53,568,661 Part I. Financial Information Pogo Producing Company and Subsidiaries Consolidated Statements of Income (Unaudited)
Three Months Ended March 31, -------------------------------------- 2001 2000 ----------------- ----------------- (Expressed in thousands, except per share amounts) Revenues: Oil and gas $ 163,913 $ 97,896 Pipeline sales and other 3,277 3,027 Gains (losses) on sales 2,672 (5) ----------------- ----------------- Total 169,862 100,918 ----------------- ----------------- Operating Costs and Expenses: Lease operating 25,827 21,645 Pipeline operating and natural gas purchases 4,020 3,390 General and administrative 8,208 10,517 Exploration 6,948 3,673 Dry hole and impairment 10,767 5,072 Depreciation, depletion and amortization 37,068 32,046 ----------------- ----------------- Total 92,838 76,343 ----------------- ----------------- Operating Income 77,024 24,575 ----------------- ----------------- Interest: Charges (11,304) (8,746) Income 1,302 293 Capitalized 4,526 5,010 Minority Interest - Dividends and costs associated with preferred securities of a subsidiary trust (2,497) (2,558) Foreign Currency Transaction Loss (585) (327) ----------------- ----------------- Income Before Taxes and Cumulative Effect of Change in Accounting Principle 68,466 18,247 Income Tax Expense (28,520) (8,096) ----------------- ----------------- Income Before Cumulative Effect of Change in Accounting Principle 39,946 10,151 Cumulative Effect of Change in Accounting Principle - (1,768) ----------------- ----------------- Net income $ 39,946 $ 8,383 ================= ================= Earnings Per Common Share Basic Income before cumulative effect of change in accounting principle $ 0.93 $ 0.25 Cumulative effect of change in accounting principle - (0.04) ----------------- ----------------- Net income $ 0.93 $ 0.21 ================= ================= Diluted Income before cumulative effect of change in accounting principle $ 0.80 $ 0.25 Cumulative effect of change in accounting principle - (0.04) ----------------- ----------------- Net income $ 0.80 $ 0.21 ================= ================= Dividends Per Common Share $ 0.03 $ 0.03 ================= ================= Weighted Average Number of Common Shares and Potential Common Shares Outstanding: Basic 43,145 40,291 Diluted 53,122 47,200
See accompanying notes to consolidated financial statements. 1 Pogo Producing Company and Subsidiaries Consolidated Balance Sheets
March 31, December 31, 2001 2000 ---------------------- --------------------- (Unaudited) (Expressed in thousands except share amounts) Assets Current Assets: Cash and cash equivalents $ 64,396 $ 81,510 Accounts receivable 94,971 84,381 Other receivables 34,162 27,242 Federal income tax receivable 4,301 -- Inventory - Product 3,201 3,054 Inventories - Tubulars 8,237 8,056 Price hedge contracts 5,981 9,153 Other 822 1,276 ----------- ----------- Total current assets 216,071 214,672 ----------- ----------- Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized 2,697,461 1,698,404 Unevaluated properties and properties under development, not being amortized 359,404 154,914 Pipelines, at cost 6,524 7,095 Other, at cost 17,148 15,257 ----------- ----------- 3,080,537 1,875,670 ----------- ----------- Accumulated depreciation, depletion and amortization Oil and gas (1,090,258) (1,053,478) Pipelines (1,343) (1,780) Other (9,146) (8,758) ----------- ----------- (1,100,747) (1,064,016) ----------- ----------- Property and equipment, net 1,979,790 811,654 ----------- ----------- Other Assets: Price hedge contracts 12,309 14,869 Debt issue expenses 13,151 10,718 Foreign value added taxes receivable 8,575 7,262 Deferred income tax 5,028 3,695 Other 20,370 20,652 ----------- ----------- 59,433 57,196 ----------- ----------- $ 2,255,294 $ 1,083,522 =========== ===========
See accompanying notes to consolidated financial statements. 2 Pogo Producing Company and Subsidiaries Consolidated Balance Sheets
March 31, December 31, 2001 2000 ------------- ------------- (Unaudited) (Expressed in thousands except share amounts) Liabilities and Shareholders' Equity Current Liabilities: Accounts payable - operating activities $ 77,757 $ 27,334 Accounts payable - investing activities 61,976 67,703 Accrued interest payable 8,300 7,443 Accrued dividends associated with preferred securities of a subsidiary trust 813 813 Accrued payroll and related benefits 2,646 2,285 Other 1,035 851 ----------- ----------- Total current liabilities 152,527 106,429 ----------- ----------- Long-Term Debt 696,000 365,000 Deferred Income Tax 481,733 95,453 Deferred Credits 14,664 13,456 ----------- ----------- Total liabilities 1,344,924 580,338 ----------- ----------- Minority Interest: Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust, net of unamortized issue expenses 144,943 144,913 ----------- ----------- Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized -- -- Common stock, $1 par; 100,000,000 shares authorized, 53,584,236 and 40,659,591 shares issued, respectively 53,585 40,660 Additional capital 657,042 298,885 Retained earnings 58,835 20,112 Accumulated other comprehensive loss (3,711) (1,062) Treasury stock (15,575 shares), at cost (324) (324) ----------- ----------- Total shareholders' equity 765,427 358,271 ----------- ----------- $ 2,255,294 $ 1,083,522 =========== ===========
See accompanying notes to consolidated financial statements. 3 Pogo Producing Company and Subsidiaries Condensed Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended March 31, ------------------------------------------- 2001 2000 --------- -------- (Expressed in thousands) Cash Flows from Operating Activities: Cash received from customers $ 182,097 $ 93,158 Operating, exploration, and general and administrative expenses paid (34,531) (32,647) Interest paid (8,326) (8,665) Federal income taxes paid (6,500) -- Value added taxes paid (1,313) (131) Other 3,621 1,106 --------- --------- Net cash provided by operating activities 135,048 52,821 --------- --------- Cash Flows from Investing Activities: Capital expenditures (80,150) (35,596) Acquisition of NORIC, net of $21,235 cash acquired (323,476) -- Proceeds from the sale of properties 2,748 (5) --------- --------- Net cash used in investing activities (400,878) (35,601) --------- --------- Cash Flows from Financing Activities: Borrowings under senior debt agreements 668,000 51,000 Payments under senior debt agreements (337,000) (51,000) Payment of North Central senior debt acquired (78,600) -- Payments of cash dividends on common stock (1,223) (1,209) Payments of preferred dividends of a subsidiary trust (2,438) (2,513) Payment of financing issue expenses (4,583) (12) Proceeds from exercise of stock options and other 5,330 1,616 --------- --------- Net cash used by financing activities 249,486 (2,118) --------- --------- Effect of Exchange Rate Changes on Cash (770) (15) --------- --------- Net Increase in Cash and Cash Equivalents (17,114) 15,087 Cash and Cash Equivalents at the Beginning of the Year 81,510 6,267 --------- --------- Cash and Cash Equivalents at the End of the Period $ 64,396 $ 21,354 ========= ========= Reconciliation of Net Income to Net Cash Provided by Operating Activities: Net income $ 39,946 $ 8,383 Adjustments to reconcile net income to net cash provided by operating activities - Cumulative effect of change in accounting principle -- 1,768 Minority interest 2,497 2,558 Foreign currency transaction losses 585 327 (Gains) losses from the sales of properties (2,672) 5 Depreciation, depletion and amortization 37,068 32,046 Dry hole and impairment 10,767 5,072 Interest capitalized (4,526) (5,010) Price hedge contracts 720 -- Deferred federal income taxes 20,622 8,095 Change in operating assets and liabilities 30,041 (423) --------- --------- Net Cash Provided by Operating Activities $ 135,048 $ 52,821 ========= =========
See accompanying notes to consolidated financial statements. 4 Pogo Producing Company and Subsidiaries Consolidated Statements of Shareholders' Equity (Unaudited)
For the Three Months Ended March 31, ---------------------------------------------------------------------------- 2001 2000 ---------------------------------- ----------------------------------- Shareholders' Shareholders' Equity Compre- Equity Compre- --------------------- hensive --------------------- hensive Shares Amount Income Shares Amount Income ------ ------ ------- ------ ------ ------- (Expressed in thousands, except share amounts) Common Stock: $1.00 par-100,000,000 shares authorized Balance at beginning of year 40,659,591 $ 40,660 40,279,661 $ 40,279 Shares issued for acquisition of NORIC 12,615,816 12,616 -- -- Stock options exercised 308,829 309 103,264 103 ------------ ------------ ------------ ---------- Issued at end of period 53,584,236 53,585 40,382,925 40,382 ------------ ------------ ------------ ---------- Additional Capital: Balance at beginning of year 298,885 291,909 Shares issued for acquisition of NORIC 351,729 -- Stock options exercised 6,428 1,893 ------------ ---------- Balance at end of period 657,042 293,802 ------------ ---------- Retained Earnings (Deficit): Balance at beginning of year 20,112 (62,291) Net income 39,946 $ 39,946 8,383 $ 8,383 Dividends ($0.03 per common share) (1,223) (1,209) ------------ ---------- Balance at end of period 58,835 (55,117) ------------ ---------- Accumulated Other Comprehensive Income (Loss): Balance at beginning of year (1,062) (1,061) Exchange gains (losses) on Canadian currency 609 609 (21) (21) Unrealized loss on price hedge contracts (820) (820) -- Cumulative effect of change in accounting principle (2,438) (2,438) -- ------------ ------------ ---------- ------- Balance at end of period (3,711) (1,082) ------------ --------- Comprehensive Income $ 37,297 $ 8,362 ============ ======= 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 53,568,661 40,367,350 ============ =========== Total Shareholders' Equity $ 765,427 $277,661 ============ ========
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, 2000. (2) Long-Term Debt - Long-term debt and the amount due within one year at March 31, 2001 and December 31, 2000, consist of the following:
March 31, December 31, 2001 2000 ------- --------- (Expressed in thousands) Senior debt - Bank revolving credit agreement LIBOR rate based loan, borrowing at an interest rate of 6.7% $300,000 $ -- Prime rate based loan, borrowing at an interest rate of 8% 21,000 -- Swing Line loan, borrowing at an interest rate of 6.6% 10,000 -- -------- -------- Total senior debt 331,000 -- -------- -------- 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") 150,000 150,000 5 1/2% Convertible subordinated notes due 2006 ("2006 Notes") 115,000 115,000 -------- -------- Total subordinated debt 365,000 365,000 -------- -------- Long-term debt, none due within one year $696,000 $365,000 ======== ========
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, 2000, for a further discussion of the Company's debt agreements. On March 8, 2001, prior to the merger with NORIC Corporation ("NORIC") and the acquisition of North Central Oil Corporation ("North Central") on March 14, 2001, the Company entered into a reserve based revolving credit facility (the "Credit Facility"). The Credit Facility provides for a $515,000,000 revolving credit facility until March 7, 2006. The amount that may be borrowed may not exceed a borrowing base which is determined semi-annually and is calculated based upon substantially all of the Company's proved oil and gas properties. As of May 1, 2001, the Company had $325,000,000 available under its Credit Facility. The Credit Facility is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, creation of liens, a limitation on commodity hedging above certain specified limits, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. In addition, the Company has pledged the stock of North Central and its inter-company receivable with North Central as security for its obligations under the Credit Facility and is prohibited from pledging borrowing base properties as security for other debt. The Credit Facility also permits short-term "swing line" loans and the issuance of up to $50,000,000 in letters of credit. Borrowings under the Credit facility bear interest, at the Company's option, at a base (prime) rate plus a variable margin (currently none) or LIBOR plus a variable margin (currently l.125%). The margin varies as a function of the percentage of the borrowing base utilized. A commitment fee on the unborrowed amount that is currently available under the Credit Facility is also charged based on the percentage of the borrowing base that is being utilized. As of May 1, 2001, there was $150,000,000 outstanding under the Credit Facility. In connection with its entering into the Credit Facility, the Company's previously existing uncommitted money market line of credit with a commercial bank was terminated. Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (2) Long-Term Debt (continued) - The Master Banker's Acceptance Agreement between the Company and one of its lenders was recently modified to increase the amount which the lender has agreed to accept bank drafts from the Company up to $25,000,000. The banker's drafts are available on an uncommitted basis and the bank has no obligation to accept the Company's request for drafts. Drafts drawn under this agreement would be reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under the Credit Facility. The Company's 2007 Notes, 2009 Notes, and the Company's new notes due 2011 (described below) may restrict all or a portion of the amounts that may be borrowed under the Master Banker's Acceptance Agreement as senior debt. The Master Banker's Acceptance Agreement permits either party to terminate the letter agreement at any time upon five business days notice. As of May 1, 2001 no amounts were outstanding under this agreement. On April 10, 2001 the Company issued $200,000,000 principal amount of Senior Subordinated Notes due 2011 (the "2011 Notes"). The 2011 Notes bear interest at a rate of 8 1/4%, payable semi-annually in arrears on April 15 and October 15 of each year, commencing October 15, 2001. The 2011 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Facility and its banker's acceptances, are equal in right of payment to the 2007 Notes and the 2009 Notes, but are senior in right of payment to the Company's subordinated indebtedness, which currently includes the 2006 Notes. In addition, they are senior in right of payment to the liquidation preference under the Company's Trust Preferred Securities. The Company, at its option, may redeem the 2011 Notes in whole or in part, at any time on or after April 15, 2006, at a redemption price of 104.125% of their principal value and decreasing percentages thereafter. The indentures governing the 2011 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indentures governing the 2007 Notes and the 2009 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. (3) Income Taxes - The Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries as the Company's present intention is to reinvest the unremitted earnings in its foreign operations. Unremitted earnings of foreign subsidiaries are approximately $20,000,000 at March 31, 2001. It is not practicable to determine the amount of U.S. income taxes that would be payable upon remittance of the assets that represent those earnings. Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (4) Hedging Activities - In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). In June 2000, the FASB issued SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS 133 effective January 1, 2001. Based on the nature of the Company's derivative instruments currently outstanding and the historical volatility of oil and gas commodity prices, the Company expects that SFAS 133 could increase volatility in the Company's earnings and other comprehensive income for future periods. SFAS 133, in part, allows special hedge accounting. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS 133 requires that as of the date of initial adoption, the difference between the market value of derivative instruments and the previous carrying amount of theses 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. During the first quarter of 2001, the Company recognized a $720,000 loss as an offset to oil and gas revenues related to hedge ineffectiveness on these contracts. Unrealized losses on derivative instruments arising during the three months ended March 31, 2001 of $820,000, net of deferred taxes of $441,000, has been reflected as a component of other comprehensive income. Based on the future market prices, the Company currently expects additional pre-tax charges of $8,434,000 to be recorded in net income during 2001. As of March 31, 2001, the Company held options to sell 70 million cubic feet of natural gas production per day for the period from April 1, 2001 through December 31, 2002. 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 $4.25 per MMBtu for the period from April 2001 through March 2002 and $4.00 per MMBtu for the period from April 2002 through December 2002. These contracts are designed to guarantee the Company a minimum "floor" price for the contracted volumes of production without limiting the Company's participation in price increases during the covered period. As of March 31, 2001, the Company was a party to the following hedging arrangements:
NYMEX Volume Contract Fair in Price per Market Contract Period MMBtu(a) MMBtu(a) Value (b) ----------------------------- -------------- --------------- ----------------- April 2001 - March 2002 25,550 $ 4.25 $ 5,981,000 April 2002 - December 2002 19,250 $ 4.00 $12,309,000
(a) MMBtu means million British Thermal Units. (b) Fair Market value is calculated using prices derived from NYMEX futures contract prices existing at March 31, 2001. These hedging transactions are settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days or occasionally, the penultimate trading day of a particular contract month. For any particular floor transaction, the counter-party is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor transaction. As of March 31, 2001 the Company was not a party to any commodity price hedging contracts with respect to any of its current or future crude oil and condensate production. 8 Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (5) Business Segment Information - Financial information by operating segment is presented below:
Company Oil and Gas Pipelines Other ------- ----------- --------- ----- (Expressed in thousands) Long-Lived Assets: As of March 31, 2001: United States $ 1,633,524 $ 1,624,051 $ 5,181 $ 4,292 Kingdom of Thailand 333,916 330,360 -- 3,556 Canada and other 12,350 12,196 -- 154 ----------- ----------- ----------- ----------- Total $ 1,979,790 $ 1,966,607 $ 5,181 $ 8,002 =========== =========== =========== =========== As of December 31, 2000: United States $ 462,530 $ 454,246 $ 5,315 $ 2,969 Kingdom of Thailand 337,317 334,018 -- 3,299 Canada 11,807 11,576 -- 231 ----------- ----------- ----------- ----------- Total $ 811,654 $ 799,840 $ 5,315 $ 6,499 =========== =========== =========== =========== Revenues: For the three months ended March 31, 2001 United States $ 119,472 $ 113,484 $ 4,292 $ 1,696 Kingdom of Thailand 47,994 47,945 -- 49 Canada and other 2,396 2,396 -- -- ----------- ----------- ----------- ----------- Total $ 169,862 $ 163,825 $ 4,292 $ 1,745 =========== =========== =========== =========== For the three months ended March 31, 2000 United States $ 66,423 $ 63,436 $ 3,382 $ (395) Kingdom of Thailand 33,638 33,637 -- 1 Canada 857 823 -- 34 ----------- ----------- ----------- ----------- Total $ 100,918 $ 97,896 $ 3,382 $ (360) =========== =========== =========== =========== Operating Income (Loss): For the three months ended March 31, 2001 United States $ 58,647 $ 56,897 $ 54 $ 1,696 Kingdom of Thailand 23,747 23,698 -- 49 Canada and other (5,370) (5,370) -- -- ----------- ----------- ----------- ----------- Total $ 77,024 $ 75,225 $ 54 $ 1,745 =========== =========== =========== =========== For the three months ended March 31, 2000 United States $ 13,016 $ 13,633 $ (222) $ (395) Kingdom of Thailand 11,752 11,751 -- 1 Canada (193) (227) -- 34 ----------- ----------- ----------- ----------- Total $ 24,575 $ 25,157 $ (222) $ (360) =========== =========== =========== ===========
9 Pogo Producing Company and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) (6) 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 Three Months Ended March 31, 2001 March 31, 2000 -------------------------------------- ----------------------------------------- Income Shares Per Share Income (a) Shares Per Share ------ ------ --------- ---------- ------ --------- Basic earnings per share - $39,946 43,145 $ 0.93 $ 10,151 40,291 $ 0.25 ========= ========= Effect of dilutive securities: Options to purchase common shares - 935 - 593 2006 Notes 1,028 2,726 - - Trust Preferred Securities 1,584 6,316 1,584 6,316 -------- ------------- ---------- ------------- Diluted earnings per share $42,558 53,122 $ 0.80 $ 11,735 47,200 $ 0.25 ======== ============= ========= ========== ============= ========= Antidilutive securities - Options to purchase common shares - 270 $ 27.93 - 278 $ 32.61 2006 Notes - - - 1,028 2,726 $ 0.38
(a) Represents income before cumulative effect of change in accounting principle. (7) Acquisition - On March 14, 2001, the previously announced merger of the Company and NORIC was consummated. As a result of the merger, the Company acquired all of the outstanding capital stock of North Central, which was the principal asset of NORIC. North Central is an independent domestic oil and gas exploration and production company whose operations are being integrated with the Company's existing domestic operations. 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. Such allocations are based upon preliminary information and are subject to change when final valuations are obtained. Commencing March 14, 2001, North Central's operations are consolidated with the operations of the Company. Pursuant to the merger agreement amount the Company and NORIC and certain NORIC shareholders dated as of November 19, 2000, former shareholders received 12,615,816 shares of the Company's common stock and approximately $344,711,000 in cash. In addition, at the closing the Company repaid all $78,600,000 principal amount of North Central's existing bank debt. The sources of funds used in connection with the merger included cash on hand at the Company and NORIC and borrowings under the Company's new credit agreement discussed in Note 2 above, "Long-Term Debt." The following summary presents unaudited pro forma consolidated results of operations as if the acquisition has occurred at the beginning of each period presented. 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 in increased depreciation, depletion and amortization expense resulting from the allocation of fair market value to oil and gas properties acquired and increased interest expense on acquisition debt. The unaudited proforma financial information is not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at those dates, nor are they necessarily indicative of future operating results.
Three Months Ended March 31, -------------------------------- 2001 2000 -------------------------------- Revenues $ 232,842 $ 128,929 Income before cumulative effect of change in accounting principle $ 56,864 $ 4,999 Net income $ 56,864 $ 3,231 Earnings per share: Basic - Income before cumulative effect of change in accounting principle $ 1.07 $ 0.09 Net income $ 1.07 $ 0.06 Diluted - Income before cumulative effect of change in accounting principle $ 0.94 $ 0.09 Net income $ 0.94 $ 0.06
10 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, 2000. 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, 2000, 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"), which was the principal asset of NORIC Corporation. North Central is an independent domestic oil and gas exploration and production company whose operations are being integrated with Pogo's existing domestic operations. 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 new credit agreement discussed under "Liquidity and Capital Resources." RESULTS OF OPERATIONS Net Income The Company reported net income for the first quarter of 2001 of $39,946,000 or $0.93 per share ($42,558,000 or $0.80 per share on a diluted basis), compared to net income (before the cumulative effect of a change in accounting principle) for the first quarter of 2000 of $10,151,000 or $0.25 per share (on both a basic and a diluted basis). The increase in net income during the first quarter of 2001, compared to the first quarter of 2000, was primarily related to increased oil and gas revenues resulting from improved natural gas prices and increased crude oil production volumes. Net income in the first quarter of 2000 was also decreased by $1,768,000 resulting from a change in accounting principle related to the Company's method of accounting for crude oil inventory stored on its FPSO and FSO in the Gulf of Thailand. Earnings per common share are based on the weighted average number of common shares outstanding for the first quarter of 2001 of 43,145,000 (53,122,000 on a diluted basis), compared to 40,291,000 (47,200,000 on a diluted basis) for the first quarter of 2000. The increase in the weighted average number of common shares outstanding for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from the issuance of common stock in connection with the merger with NORIC on March 14, 2001 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 both periods reflect additional shares of common stock issuable upon the assumed conversion of Pogo Trust I's 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the "Trust Preferred Securities") and, to a much lesser extent, additional shares of common stock issuable upon the assumed exercise of options to purchase common shares under the Company's incentive plans, less treasury shares that are assumed to have been purchased by the Company from the option proceeds. Earnings per share computations for the first quarter of 2001 also reflect additional shares of common stock issuable upon the assumed conversion of the Company's 5 1/2% Convertible Subordinated Notes due 2006 (the "2006 Notes"). 11 Total Revenues The Company's total revenues for the first quarter of 2001 were $169,862,000, an increase of approximately 68% from total revenues of $100,918,000 for the first quarter of 2000. The increase in the Company's total revenues for 2001, compared to 2000, resulted primarily from increased oil and gas revenues and, to a much lesser extent, a gain recorded on the sale of certain non-strategic assets and an increase in pipeline sales revenue. Oil and Gas Revenues The Company's oil and gas revenues for the first quarter of 2001 were $163,913,000, an increase of approximately 67% from oil and gas revenues of $97,896,000 for the first quarter of 2000. The following table reflects an analysis of variances in the Company's oil and gas revenues (expressed in thousands) between 2001 and 2000:
Increase (decrease) in oil and gas revenues 1ST QTR resulting from variances in: 2001 COMPARED TO 1ST QTR 2000 ----------- NATURAL GAS -- Price.............................................. $49,492 Production......................................... 2,359 ------- 51,851 ------- CRUDE OIL AND CONDENSATE -- Price.............................................. 901 Production......................................... 15,034 ------- 15,935 ------- NATURAL GAS LIQUIDS ("NGL")........................... (1,769) ------- Increase (decrease) in oil and gas revenues........ $66,017 =======
The increase in the Company's oil and gas revenues in the first quarter of 2001, compared to the first quarter of 2000, was related to an increase in the average price that the Company received for its natural gas production, an increase in its crude oil and condensate production and, to a lesser extent, an increase in its natural gas production and in the average price that it received for its oil and condensate production. These increases were partially offset by a decline in revenues related to decreased production of NGL. NGL is extracted from natural gas. Due to the relatively high price (relative to crude oil and condensate) that the Company is currently receiving for its natural gas production volumes, the Company has elected in many instances to leave the NGL in the natural gas at this time, rather than to extract it for resale as NGL. Generally, this leads to increased average prices for the Company's natural gas production volumes.
Comparison of Increases (Decreases) in: 1ST QTR 1ST QTR % CHANGE NATURAL GAS -- 2001 2000 2001 to 2000 ------- ------- ----------------- Average prices North America (a)........................................... $ 7.02 $ 2.76 154% Kingdom of Thailand(b)...................................... $ 2.45 $ 1.97 24% Company-wide average price............................. $ 5.59 $ 2.50 124% Average daily production volumes (MMcf per day) North America (a)........................................... 125.3 117.6 7% Kingdom of Thailand......................................... 57.4 58.5 (2)% ------- ------- Company-wide average daily production.................. 182.7 176.1 4% ======= =======
12 Crude Oil and Condensate -- Average prices North America(a)............................................ $ 28.02 $ 25.72 9% Kingdom of Thailand......................................... $ 25.22 $ 26.85 (6)% Company-wide average price............................. $ 26.54 $ 26.24 1% Average daily production volumes (Bbls per day) North America(a)............................................ 13,916 13,352 4% Kingdom of Thailand (c)..................................... 13,918 11,359 23% ------- ------- Company-wide average daily production (c).............. 27,834 24,711 13% ======= ======= TOTAL LIQUID HYDROCARBONS -- Company-wide average daily production (Bbls per day)(c)....... 28,538 26,641 7% ======= =======
____________________________ (a) North American average prices and production reflect production from the United States and Canada. "MMcf" and "Bbls" stand for million cubic feet and barrels, respectively. (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. (c) Oil and condensate production in the Gulf of Thailand is produced and stored on the FPSO and FSO pending sale and is sold in tanker loads that typically average between 300,000 and 750,000 barrels per sale. Therefore, oil and condensate sales volumes for a given period in the Gulf of Thailand may not equate to actual production. In accordance with generally accepted accounting principles, as currently interpreted, reported revenues are based on sales volumes. However, the Company believes that actual production volumes are a more meaningful measure of the Company's operating results and therefore reports production volumes as part of its operating results. The Company produced 146,000 barrels less than it sold in the first quarter of 2001 and produced 164,000 barrels more than it sold in the first quarter of 2000. 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 which takes into account a number of factors including, among other items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore. The increase in the average price that the Company received for its natural gas production in the Kingdom of Thailand for the first quarter of 2001, compared to the first quarter of 2000, reflects positive adjustments under the gas sales agreement. Production. The increase in the Company's natural gas production during the first quarter of 2001, compared to the first quarter of 2000, 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 New Mexico properties that was partially offset by natural decline at certain of the Company's other properties. Crude Oil and Condensate Thailand Prices. Since the inception of production from the Company's properties located in the Gulf of Thailand, crude oil and condensate have been stored on storage vessels (an FPSO in the Tantawan field and an FSO in the Benchamas field) until an economic quantity was accumulated for offloading and sale. A typical sale ranges from 300,000 to 750,000 barrels. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, typically as a differential to Malaysian TAPIS crude and are denominated in dollars. In addition, the Company is generally paid for its crude oil and condensate production from Thailand in dollars. Production. The increase in the Company's Thailand production is related to production from the Benchamas field that commenced producing in the third quarter of 2000. Due a change in interpretation of an accounting principle, the Company now records its oil production in Thailand at the time of sale, rather than when produced, as it had previously. In accordance with generally accepted accounting principles, as currently interpreted, at the end of each 13 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 146,000 barrels less than it sold in the first quarter of 2001 and produced 164,000 barrels more than it sold in the first quarter of 2000. As of March 31, 2001, the Company had approximately 204,000 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 decrease in NGL revenues for the first quarter of 2001, compared with the first quarter of 2000, primarily related to the decision by the Company not to extract NGL from its natural gas production due to the more favorable economics of leaving it in the natural gas stream. Costs and Expenses
1ST QTR 1ST QTR % CHANGE Comparison of Increases (Decreases) in: 2001 2000 2001 to 2000 ------------ ----------- --------------- LEASE OPERATING EXPENSES North America.......................................... $ 17,050,000 $14,290,000 19% Kingdom of Thailand.................................... $ 8,777,000 $ 7,355,000 19% Total Lease Operating Expenses................... $ 25,827,000 $21,645,000 19% Pipeline Operating and Natural Gas Purchases.............. $ 4,020,000 $ 3,390,000 19% General and Administrative Expenses....................... $ 8,208,000 $10,517,000 (22)% Exploration Expenses...................................... $ 6,948,000 $ 3,673,000 89% Dry Hole and Impairment Expenses.......................... $ 10,767,000 $ 5,072,000 112% Depreciation, Depletion and Amortization (DD&A) Expenses.............................................. $ 37,068,000 $32,046,000 16% DD&A Rate.............................................. $1.12 $1.07 5% Mcfe Produced (a)...................................... 31,854,000 30,568,000 4% Interest- Charges............................................... $(11,304,000) $(8,746,000) 29% Income................................................ 1,302,000 293,000 344% Capitalized Interest Expense.......................... $ 4,526,000 $ 5,010,000 (10)% Minority Interest - Dividends and Costs................... $ 2,497,000 $ 2,558,000 (2)% Foreign Currency Transaction Loss......................... $ (585,000) $ (327,000) 79% Income Tax Expense........................................ $(28,520,000) $(8,096,000) 252%
_____________________ (a) "Mcfe" stands for thousand of cubic feet equivalent. Lease Operating Expenses The increase in North American lease operating expenses for the first quarter of 2001, compared to the first quarter of 2000, related in large measure to increased severance taxes resulting from increased production from the Company's non-U.S. government owned properties (accounting for $3,041,000 of the increase) and, to a lesser extent, increased expenses related to operation of the properties acquired in the North Central merger and generally increasing costs resulting from an industry-wide increase in demand for oil field services and equipment, that was only partially offset by decreased maintenance costs in the Gulf of Mexico and the Company's Western Division properties. The increase 14 in lease operating expenses in the Kingdom of Thailand for the first quarter of 2001, compared to the first quarter of 2000, related to increased maintenance and workover activity in the Benchamas Field and to generally increasing costs resulting from an industry-wide increase in demand for oil field services and equipment. 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 $3,716,000 and $3,757,000 of the Company's Thailand lease operating expenses for the first quarter of 2001 and the first quarter of 2000, respectively. Pipeline Operating and Natural Gas Purchases Revenue from the sale of natural gas purchased for resale is reported as revenue under "Pipeline sales and other." The cost of purchasing natural gas for resale, together with the costs of operating the pipeline carrying the natural gas is recorded as an expense under "Pipeline operating and natural gas purchases." The increase in pipeline operating expenses and natural gas purchase costs for the first quarter of 2001, compared to the first quarter of 2000, primarily related to increased cost of natural gas purchased for resale by the Company. General and Administrative Expenses The decrease in general and administrative expenses for the first quarter of 2001, compared with the first quarter of 2000, primarily related to a $1,889,000 retroactive adjustment for the over accrual of certain payroll costs, that was partially offset by increased expenses associated with the Company's acquisition of North Central and its employees, as well as an increase in the size of the Company's work force and normal salary and concomitant benefit expense adjustments. 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 increase in exploration expense for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from the cost of conducting two major 3-D projects in Hungary, that was partially offset by decreased geophysical acquisition costs in the Company's other operational areas. Dry Hole and Impairment The increase in the Company's dry hole and impairment expense for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from impairment expense charged to a non-operated property located in the offshore Gulf of Mexico due to unexpectedly high drilling and completion expenses and, to a lesser extent, increased dry hole costs. Depreciation, Depletion and Amortization Expenses The increase in the Company's Depreciation, Depletion and Amortization ("DD&A") expense for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from an increase in the Company's liquid hydrocarbon and natural gas production and, to a lesser extent, an increase in the Company's composite DD&A rate. The increase in the composite DD&A rate for all of the Company's producing fields for the first quarter of 2001, compared to the first quarter of 2000, 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, including the properties acquired in the North Central acquisition, 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. 15 Interest Interest Charges. The increase in the Company's interest charges for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from an increase in amortization of debt issuance expense (principally related to the termination of the Company's previous credit facility) and, to a lesser extent, an increase in the average amount of the Company's outstanding debt due to the acquisition of North Central, that was not entirely offset by decreased average interest rates on the debt outstanding (resulting primarily from the increase in bank debt which has a lower interest rate than a substantial portion of the Company's long-term debt). Interest Income. The increase in the Company's interest income for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from an increase in the amount of the cash and cash equivalents temporarily invested. Except for working capital needs, a significant portion of the Company's cash and cash and cash equivalents were used to fund the North Central acquisition. Capitalized Interest. The decrease in capitalized interest for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from a decrease in the amount of capital expenditures subject to interest capitalization during the first quarter of 2001 ($226,409,000), compared to the first quarter of 2000 ($234,575,000), and from a decrease in the computed interest rate that the Company uses to apply on 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 developments in the Gulf of Thailand and, to a lesser extent, several development projects in the Gulf of Mexico. Minority Interest - Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust Pogo Trust I, a subsidiary trust, issued $150,000,000 of Trust Preferred Securities on June 2, 1999. The amounts recorded for the first quarter of 2001 and the first quarter of 2000, respectively, under "Minority Interest - Dividends and costs associated with preferred securities of a subsidiary trust" principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities. Foreign Currency Transaction Losses The foreign currency transaction losses reported for the first quarter of 2001 and the first quarter of 2000 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 financial statements during the respective periods. The weakening of the Thai Baht against the U.S. dollar has been attributed to, among other things, the negative impact on the Thai economy of high crude oil prices, continued weakness in the banking sector, and political uncertainty surrounding recently completed national elections. The Company cannot predict what the Thai Baht to U.S. dollar exchange rate will be in the future. As of March 31, 2001, the Company was not a party to any financial instrument that was intended to constitute a foreign currency hedging arrangement. Income Tax Expense The increase in the Company's income tax expense for the first quarter of 2001, compared to the first quarter of 2000, resulted primarily from increased pre-tax income from North American operations and from pre-tax income from the Company's operations in the Kingdom of Thailand that was only partially offset by tax benefits in the United States for taxes paid, principally in the Kingdom of Thailand. Management currently expects that its foreign taxes will constitute a substantial portion of its overall tax burden for the foreseeable future. 16 LIQUIDITY AND CAPITAL RESOURCES Cash Flows The Company's Condensed Consolidated Statement of Cash Flows for the first quarter of 2001 reflects net cash provided by operating activities of $135,048,000. In addition to net cash provided by operating activities, the Company received $5,330,000, primarily from the exercise of stock options, and $2,748,000 from the sale of certain non-strategic properties. The Company also borrowed a net $331,000,000 under its revolving credit facility. During the first quarter of 2001, the Company acquired the shares of NORIC for $344,711,000, repaid all $78,600,000 of North Central's senior indebtedness, invested $80,150,000 in capital projects, paid $4,583,000 in debt issuance expenses, paid $2,438,000 in cash distributions to holders of its Trust Preferred Securities and paid $1,223,000 ($0.03 per share) in cash dividends to holders of the Company's common stock. As of March 31, 2001, the Company's cash and cash equivalents were $64,396,000 and its long-term debt stood at $696,000,000. On April 10, 2001, the Company issued $200,000,000 of 8 1/4% Senior Subordinated Notes due 2011 (the "2011 Notes"), using the net proceeds to reduce the Company's outstanding senior indebtedness. As of May 1, 2001, the Company had $325,000,000 of availability under its revolving credit facility. Future Capital Requirements The Company's capital and exploration budget for 2001, 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 $350,000,000, principally on account of the projects to be undertaken on properties acquired in the North Central acquisition. The Company currently anticipates that its available cash and cash equivalents, cash provided by operating activities and funds available under its credit agreement and banker's acceptance facility will be sufficient to fund the Company's ongoing operating, interest and general and administrative expenses, any currently anticipated costs associated with the Company's projects during 2001, and future dividend and distribution payments at current levels (including a dividend payment of $0.03 per share to be paid on May 25, 2001 to shareholders of record on May 11, 2001). 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. Capital Structure On March 8, 2001, prior to the merger with NORIC and the acquisition of North Central on March 14, 2001, the Company entered into a reserve-based revolving credit facility (the "Credit Facility"). The Credit Facility provides for a $515,000,000 revolving credit facility until March 7, 2006. The amount that may be borrowed may not exceed a borrowing base which is determined semi-annually and is calculated based upon substantially all of the Company's proved oil and gas properties. As of May 1, 2001, the Company had $325,000,000 of availability under its Credit Facility. The Credit Facility is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, creation of liens, a limitation on commodity hedging above certain specified limits, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. In addition, the Company has pledged the stock of North Central and its inter-company receivables with North Central as security for its obligations under the Credit Facility and is prohibited from pledging borrowing base properties as security for other debt. The Credit Facility also permits short-term "swing line" loans and the issuance of up to $50,000,000 in letters of credit. Borrowings under the Credit Facility bear interest, at the Company's option, at a base (prime) rate plus a variable margin (currently none) or LIBOR plus a variable margin (currently 1.125%). The margin varies as a function of the percentage of the borrowing base being utilized. A commitment fee on the unborrowed amount that is currently available under the 17 Credit Facility is also charged based upon the percentage of the borrowing base that is being utilized. As of May 1, 2001, there was $150,000,000 outstanding under the Credit Facility. In connection with its entering into the Credit Facility, the Company's previously existing uncommitted money market line of credit with a commercial bank was terminated. Banker's Acceptances. The Master Banker's Acceptance Agreement between the Company and one of its lenders was recently modified to increase the amount which the lender has agreed to accept bank drafts from the Company up to $25,000,000. The banker's drafts are available on an uncommitted basis and the bank has no obligation to accept the Company's request for drafts. Drafts drawn under this agreement would be reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under the Credit Facility. The Company's 2011 Notes (described below), its 10 3/8% Senior Subordinated Notes due 2009 and its 8 3/4% Senior Subordinated Notes due 2007 may restrict all or a portion of the amounts that may be borrowed under the Master Banker's Acceptance Agreement as senior debt. The Master Banker's Acceptance Agreement permits either party to terminate the letter agreement at any time upon five business days notice. As of May 1, 2001, no amounts were outstanding under this agreement. 2011 Notes. As previously discussed, on April 10, 2001, the Company issued $200,000,000 principal amount of 2011 Notes. The 2011 Notes bear interest at a rate of 8 1/4%, payable semi-annually in arrears on April 15 and October 15 of each year, commencing October 15, 2001. The 2011 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Facility and its banker's acceptances, are equal in right of payment to the 2009 Notes and the 2007 Notes, but are senior in right of payment to the Company's subordinated indebtedness, which currently includes the 2006 Notes. In addition, they are senior in right of payment to the liquidation preference under the Company's Trust Preferred Securities. The Company, at its option, may redeem the 2011 Notes in whole or in part, at any time on or after April 15, 2006, at a redemption price of 104.125% of their principal value and decreasing percentages thereafter. The indenture governing the 2011 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indentures governing the 2009 Notes and 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. The Company is exposed to market risk, including adverse changes in commodity prices, interest rates and foreign currency exchange rates. In addition to the information contained in this "Item 3. Quantitative and Qualitative Disclosure About Market Risk", the information contained in the Company's Annual Report on Form 10-K for the year ended December 31, 2000, and should be read in conjunction with the following. INTEREST RATE RISK From time to time, the Company has entered into various financial instruments, such as interest rate swaps, to manage the impact of changes in interest rates. As of May 1, 2001, the Company has no open interest rate swap or interest rate lock agreements. Therefore, the Company's exposure to changes in interest rates primarily results from its short-term and long-term debt with both fixed and floating interest rates. The following table presents principal or notional amounts (stated in thousands) and related average interest rates by year of maturity for the Company's debt obligations and their indicated fair market value at March 31, 2001: 18
Fair -------- 2000 2001 2002 2003 2004 Thereafter Total VALUE ----- ----- ----- ----- ----- -------- -------- -------- Liabilities Long-Term Debt: Variable Rate.............. $ 0 $ 0 $ 0 $ 0 $ 0 $331,000 $331,000 $331,000 Average Interest Rate...... - - - - - 6.8% 6.8% - Fixed Rate................. $ 0 $ 0 $ 0 $ 0 $ 0 $365,000 $365,000 $370,398 Average Interest Rate...... - - - - - 8.4% 8.4% --
FOREIGN CURRENCY EXCHANGE RATE RISK The Company conducts business in Thai Baht, Hungarian Forint and the Canadian dollar and is therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. As of May 1, 2001, the Company is not a party to any foreign currency exchange agreement. CURRENT HEDGING ACTIVITY From time to time, the Company has used and expects to continue to use hedging transactions with respect to a portion of its oil and gas production to achieve a more predictable cash flow, as well as to reduce its exposure to price fluctuations. 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 counter-parties 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. In January 2001, the Company began to account for its hedging activities under SFAS 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 in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting hedge accounting criteria are met. Special accounting for qualifying hedges allows the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instruments, if any, must be recognized currently in earnings. Natural Gas As of March 31, 2001, the Company held options to sell 70 million cubic feet of natural gas production per day for the period from April 1, 2001 through December 31, 2002. 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 $4.25 per MMBtu for the period from April 2001 through March 2002 and $4.00 per MMBtu for the period from April 2002 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. As of March 31, 2001, the Company was a party to the following hedging arrangements: 19
NYMEX CONTRACT VOLUME PRICE PER FAIR MARKET CONTRACT PERIOD IN MMBTU (a) MMBTU(a) VALUE(b) - ----------------------------- ----------------- ------------ ------------------ Floor Contracts: April 2001 -- March 2002 25,550 $4.25 $ 5,981,000 April 2002 - December 2002 19,250 $4.00 $12,309,000
(a) MMBtu means million British Thermal Units. (b) Fair Market Value is calculated using prices derived from NYMEX futures contract prices existing at March 31, 2001. These hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days or, occasionally, the penultimate trading day of a particular contract month. For any particular floor transaction, the counter-party is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor transaction. Crude Oil As of March 31, 2001, the Company was not a party to any commodity price hedging contracts with respect to any of its current or future crude oil and condensate production. PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (A) Exhibits None (B) Reports on Form 8-K Report filed on January 24, 2001, announcing the date of the Company's Annual Shareholder's Meeting in 2001, attaching a copy of the Company's press release containing its fourth quarter and year-end 2000 results and two tables containing supplemental financial and operating data. Report filed on March 26, 2001, announcing the merger of the Company and NORIC under Item 2 and setting forth certain pro forma financial information required under Item 7, the consolidated balance sheets of North Central and its consolidated subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, cash flows and shareholders' equity for each of the three years in the period ended December 31, 2000; and unaudited pro forma condensed consolidated financial statements giving effect to the merger of NORIC with and into the Company as if it had occurred on January 1, 2000 (for purposes of the pro forma unaudited condensed consolidated statement of income) and December 31, 2000 (for purposes of the pro forma unaudited condensed consolidated balance sheet). 20 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: May 14, 2001 21 -----END PRIVACY-ENHANCED MESSAGE-----