<PAGE>
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 ...
<TABLE>
<S> <C>
Registrant's number of common shares outstanding as of September 30, 1999: 40,202,920
</TABLE>
<PAGE>
Part I. Financial Information
Pogo Producing Company and Subsidiaries
Consolidated Statements of Income (Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ------------------------
1999 1998 1999 1998
--------- --------- --------- ---------
(Expressed in thousands, except per share amounts)
<S> <C> <C> <C> <C>
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
</TABLE>
See accompanying notes to consolidated financial statements.
-1-
<PAGE>
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------- ------------
(Unaudited)
(Expressed in thousands
except share amounts)
<S> <C> <C>
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
============= ============
</TABLE>
See accompanying notes to consolidated financial statements.
-2-
<PAGE>
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------- ------------
(Unaudited)
(Expressed in thousands
except share amounts)
<S> <C> <C>
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
============= ============
</TABLE>
See accompanying notes to consolidated financial statements.
- 3 -
<PAGE>
Pogo Producing Company and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------------------------
1999 1998
-------------- -----------
(Expressed in thousands)
<S> <C> <C>
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
=========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
-4-
<PAGE>
Pogo Producing Company and Subsidiaries
Consolidated Statements of Shareholders' Equity (Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
----------------------------------------------------------------------------
1999 1998
-------------------------------- ------------------------------------
Shares Amount Shares Amount
------------- ------------ --------------- -----------
(Expressed in thousands, except share amounts)
<S> <C> <C> <C> <C>
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
============ ===========
</TABLE>
See accompanying notes to consolidated financial statements.
-5-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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:
<TABLE>
<CAPTION>
Company Oil and Gas Pipelines Other
----------- ----------- --------- ----------
(Expressed in thousands)
<S> <C> <C> <C> <C>
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)
=========== =========== ========= ==========
</TABLE>
-8-
<PAGE>
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:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, 1999 September 30, 1999
---------------------------------- ----------------------------------
Income Shares Per Share Income Shares Per Share
-------- --------- --------- --------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
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
<CAPTION>
Three Months Ended Nine Months Ended
September 30, 1998 September 30, 1998
---------------------------------- ----------------------------------
Income Shares Per Share Income Shares Per Share
-------- --------- --------- --------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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-
<PAGE>
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-
<PAGE>
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:
<TABLE>
<CAPTION>
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
-------------- -------------
<S> <C> <C>
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)
======= ========
</TABLE>
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.
<TABLE>
<CAPTION>
Comparison of Increases (Decreases) in: 3/rd/ Quarter % 1/st/ Nine Months %
----------------- -----------------
Natural Gas -- 1999 1998 Change 1999 1998 Change
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
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%)
====== ====== ====== ======
</TABLE>
____________________________
(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-
<PAGE>
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.
<TABLE>
<CAPTION>
Comparison of Increases (Decreases) in: 3/rd/ Quarter % 1/st/ Nine Months %
------------------- -------------------
Crude Oil and Condensate -- 1999 1998 Change 1999 1998 Change
------- ------- ------ ------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
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%)
======= ======= ======= =======
</TABLE>
__________________________
(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-
<PAGE>
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
<TABLE>
<CAPTION>
3/rd/ Quarter 1/st/ Nine Months
--------------------------- % ---------------------------- %
Comparison of Increases (Decreases) in: 1999 1998 Change 1999 1998 Change
--------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
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%)
</TABLE>
_____________________________________________________
(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-
<PAGE>
Pogo Producing Company and Subsidiaries
Management's Discussion and Analysis of
Financial Condition and Results of Operations
<TABLE>
<CAPTION>
3/rd/ Quarter 1/st/ Nine Months
--------------------------- % ---------------------------- %
Comparison of Increases (Decreases) in: 1999 1998 Change 1999 1998 Change
--------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
Pogo Producing Company and Subsidiaries
Management's Discussion and Analysis of
Financial Condition and Results of Operations
<TABLE>
<CAPTION>
Swaps
------------------------------
Weighted Average
NYMEX
Contract Price Volume in Volume in
Period per MMBtu(a) MMBtus MBtu/day(b)
- -------------------------- -------------- --------- -----------
<S> <C> <C> <C>
01-Oct-1999 -- 31-Mar-2000 $3.11 1,820 10,000
01-Oct-1999 -- 31-Aug-2000 $2.87 5,025 15,000
</TABLE>
(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:
<TABLE>
<CAPTION>
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
- -------------------------- -------- ---------- --------------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
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 --- --- ---
</TABLE>
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-
<PAGE>
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-
<PAGE>
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-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
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.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1999
<CASH> 28,430
<SECURITIES> 0
<RECEIVABLES> 51,869
<ALLOWANCES> 0<F1>
<INVENTORY> 21,789
<CURRENT-ASSETS> 103,985
<PP&E> 1,722,375
<DEPRECIATION> 985,474
<TOTAL-ASSETS> 905,399
<CURRENT-LIABILITIES> 62,882
<BONDS> 365,000
0
0
<COMMON> 40,218
<OTHER-SE> 220,609
<TOTAL-LIABILITY-AND-EQUITY> 905,399
<SALES> 152,509<F2>
<TOTAL-REVENUES> 190,012
<CGS> 51,430<F3>
<TOTAL-COSTS> 51,430<F3>
<OTHER-EXPENSES> 101,557<F4>
<LOSS-PROVISION> 0<F5>
<INTEREST-EXPENSE> 27,414
<INCOME-PRETAX> 18,985
<INCOME-TAX> 4,941
<INCOME-CONTINUING> 14,044
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 14,044
<EPS-BASIC> 0.35
<EPS-DILUTED> 0.35
<FN>
<F1>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.
<F2>Does not include Gains or Losses on Property Sales.
<F3>Include Lease Operating Expense, but excludes General and Administrative,
Exploration, Dry Hole and Impairment and Depreciation, Depletion and
Amortization Expenses.
<F4>Includes General and Administrative, Exploration, Dry Hole and Impairment and
Depreciation, Depletion and Amortization Expenses.
<F5>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.
</FN>
</TABLE>
