<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, 2000 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 September 30, 2000:
40,521,081
<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,
------------------------- --------------------------
2000 1999 2000 1999
---------- ----------- ----------- -----------
(Expressed in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas $ 126,472 $ 67,195 $ 337,479 $ 148,089
Pipeline sales and other 3,362 2,190 9,865 4,420
Gains (losses) on sales 0 (247) (14) 37,503
----------- ---------- ----------- -----------
Total 129,834 69,138 347,330 190,012
----------- ---------- ----------- -----------
Operating Costs and Expenses:
Lease operating 23,375 19,712 69,381 48,229
Pipeline operating and natural gas purchases 3,576 1,307 10,122 3,505
General and administrative 8,605 7,057 26,567 20,686
Exploration 2,694 801 8,481 3,940
Dry hole and impairment 6,570 930 13,762 1,960
Depreciation, depletion and amortization 31,477 27,422 97,523 74,667
---------- ---------- ----------- -----------
Total 76,297 57,229 225,836 152,987
---------- ---------- ----------- -----------
Operating Income 53,537 11,909 121,494 37,025
---------- ---------- ----------- -----------
Interest:
Charges (8,504) (8,305) (25,460) (27,414)
Income 774 588 1,253 898
Capitalized 5,546 4,670 15,160 13,437
Minority Interest - Dividends and costs associated
with preferred securities of a subsidiary trust (2,351) (2,557) (7,468) (3,356)
Foreign Currency Transaction Loss (930) (2,014) (2,051) (1,605)
---------- ---------- ----------- -----------
Income Before Income Taxes 48,072 4,291 102,928 18,985
Income Tax Expense (21,177) (1,554) (45,768) (4,941)
---------- ---------- ----------- -----------
Net Income $ 26,895 $ 2,737 $ 57,160 $ 14,044
========== ========== =========== ===========
Earnings Per Common Share
Basic $ 0.67 $ 0.07 $ 1.42 $ 0.35
========== ========== =========== ===========
Diluted $ 0.59 $ 0.07 $ 1.30 $ 0.35
========== ========== =========== ===========
Dividends Per Common Share $ 0.03 $ 0.03 $ 0.09 $ 0.09
========== ========== =========== ===========
Weighted Average Number of Common Shares
and Potential Common Shares Outstanding:
Basic 40,403 40,185 40,359 40,154
Diluted 50,068 40,510 50,016 40,370
</TABLE>
See accompanying notes to consolidated financial statements.
-1-
<PAGE>
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------- ------------
(Unaudited)
(Expressed in thousands
except share amounts)
<S> <C> <C>
Assets
Current Assets:
Cash and cash equivalents $ 68,292 $ 6,267
Accounts receivable 63,453 37,321
Other receivables 19,679 35,870
Inventory - Product 16,519 7,209
Inventories - Tubulars 8,877 10,352
Other 1,877 2,370
----------- ------------
Total current assets 178,697 99,389
----------- ------------
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties being amortized 1,626,757 1,638,321
Unevaluated properties and properties
under development, not being amortized 237,954 144,357
Pipelines, at cost 7,095 6,984
Other, at cost 13,640 13,103
----------- ------------
1,885,446 1,802,765
----------- ------------
Accumulated depreciation, depletion and amortization
Oil and gas (1,097,021) (1,006,542)
Pipelines (1,718) (1,534)
Other (8,371) (7,329)
----------- ------------
(1,107,110) (1,015,405)
----------- ------------
Property and equipment, net 778,336 787,360
----------- ------------
Other Assets:
Foreign tax net operating losses 710 16,237
Foreign value added taxes receivable 6,553 12,025
Debt issue expenses 11,231 12,686
Other 21,789 20,496
----------- ------------
40,283 61,444
----------- ------------
$ 997,316 $ 948,193
=========== ============
</TABLE>
See accompanying notes to consolidated financial statements.
-2-
<PAGE>
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------- ------------
(Unaudited)
(Expressed in thousands
except share amounts)
<S> <C> <C>
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable - operating activities $ 25,383 $ 21,724
Accounts payable - investing activities 31,016 62,878
Accrued interest payable 7,261 7,457
Accrued dividends associated with
preferred securities of a subsidiary trust 813 813
Accrued payroll and related benefits 2,098 2,149
Other 546 208
------------ -----------
Total current liabilities 67,117 95,229
------------ -----------
Long-Term Debt 365,000 375,000
Deferred Income Tax 79,955 51,177
Deferred Credits 13,260 13,524
------------ -----------
Total liabilities 525,332 534,930
------------ -----------
Minority Interest:
Company-obligated mandatorily redeemable
convertible preferred securities of a subsidiary trust,
net of unamortized issue expenses 144,856 144,751
------------ -----------
Shareholders' Equity:
Common stock, $1 par; 100,000,000 shares authorized,
40,536,656 and 40,279,661 shares issued, respectively 40,536 40,279
Additional capital 296,818 291,909
Retained earnings (deficit) (8,771) (62,291)
Treasury stock (15,575 shares) and other, at cost (1,455) (1,385)
------------ -----------
Total shareholders' equity 327,128 268,512
------------ -----------
$ 997,316 $ 948,193
============ ===========
</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,
---------------------------------------
2000 1999
---------------- ----------------
(Expressed in thousands)
<S> <C> <C>
Cash Flows from Operating Activities:
Cash received from customers $ 310,888 $ 135,812
Operating, exploration, and general
and administrative expenses paid (110,892) (73,521)
Interest paid (24,119) (21,890)
Federal income taxes received 3,000 6,446
Federal income taxes paid (3,000) (13,000)
Value added taxes received (paid) 5,472 (791)
Other (318) 94
----------------- ----------------
Net cash provided by operating activities 181,031 33,150
----------------- ----------------
Cash Flows from Investing Activities:
Capital expenditures (101,311) (156,754)
Proceeds from the sale of properties - 81,989
----------------- ----------------
Net cash used in investing activities (101,311) (74,765)
----------------- ----------------
Cash Flows from Financing Activities:
Proceeds from issuance of new debt - 150,000
Proceeds from issuance of new financing - 150,000
Borrowings under senior debt agreements 67,000 250,053
Payments under senior debt agreements (77,000) (470,000)
Payments of cash dividends on common stock (3,640) (3,612)
Payments of preferred dividends of a subsidiary trust (7,314) (2,484)
Payment of financing issue expenses (131) (11,943)
Proceeds from exercise of stock options and other 4,497 555
----------------- ----------------
Net cash (used in) provided by financing activities (16,588) 62,569
----------------- ----------------
Effect of Exchange Rate Changes on Cash (1,107) (483)
----------------- ----------------
Net Increase in Cash and Cash Equivalents 62,025 20,471
Cash and Cash Equivalents at the Beginning of the Year 6,267 7,959
----------------- ----------------
Cash and Cash Equivalents at the End of the Period $ 68,292 $ 28,430
================= ================
Reconciliation of Net Income to Net Cash
Provided by Operating Activities:
Net income $ 57,160 $ 14,044
Adjustments to reconcile net income to
net cash provided by operating activities -
Minority interest 7,468 3,356
Foreign currency transaction loss 2,051 1,605
Losses (gains) from the sales of properties 14 (37,503)
Depreciation, depletion and amortization 97,523 74,667
Dry hole and impairment 13,762 1,960
Interest capitalized (15,160) (13,437)
Deferred income tax expense (benefit) 45,738 (3,110)
Change in operating assets and liabilities (27,525) (8,432)
----------------- ----------------
Net Cash Provided by Operating Activities $ 181,031 $ 33,150
================= ================
</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,
---------------------------------------------------------------------
2000 1999
--------------------------------- ------------------------------
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 40,279,661 $ 40,279 40,136,254 $ 40,136
Stock options exercised 191,915 192 69,109 69
Shares issued as compensation 65,080 65
Adjustment for fractional shares and other - - 13,132 13
------------- --------------- --------------- ------------
Issued at end of period 40,536,656 40,536 40,218,495 40,218
------------- --------------- --------------- ------------
Additional Capital:
Balance at beginning of year 291,909 290,655
Stock options exercised 3,687 541
Shares issued as compensation 1,222
Adjustment for fractional shares and other - (13)
--------------- ------------
296,818 291,183
--------------- ------------
Retained Earnings (Deficit):
Balance at beginning of year (62,291) (79,600)
Net income 57,160 14,044
Dividends ($0.09 per common share) (3,640) (3,612)
--------------- ------------
Balance at end of period (8,771) (69,168)
--------------- ------------
Treasury Stock and Other:
Balance at beginning of year (15,575) (1,385) (15,575) (1,531)
Activity during the period - (70) - 125
------------ --------------- -------------- ------------
Balance at end of period (15,575) (1,455) (15,575) (1,406)
------------ --------------- -------------- ------------
Common Stock Outstanding,
at the End of the Period 40,521,081 40,202,920
============ ===============
Total Shareholders' Equity $ 327,128 $ 260,827
=============== ============
</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 and 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, 1999.
(2) Long-Term Debt -
Long-term debt and the amount due within one year at September 30, 2000 and
December 31, 1999, consist of the following:
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
-------------- ------------
(Expressed in thousands)
<S> <C> <C>
Senior debt -
Bank revolving credit agreement
LIBO Rate based loans, borrowings at an average interest rate of 7.8% $ - $ 5,000
Uncommitted credit lines with banks, borrowings at an average interest rate of 5.9% - 5,000
-------------- ------------
Total senior debt - 10,000
-------------- ------------
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 $ 365,000 $ 375,000
============== ============
</TABLE>
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, 1999,
for a further discussion of the Company's debt agreements. Effective May 3,
2000, the borrowing base under the Company's bank revolving credit agreement was
increased to $200,000,000 and the restriction against new indebtedness was
increased a corresponding amount to $565,000,000. As of September 30, 2000
$53,000,000 was available to the Company for common stock dividends under the
most restrictive covenants included in the indentures governing the Company's
various debt agreements.
(3) Impact of SFAS 133 -
In June 1998, the FASB issued SFAS 133, Accounting for Derivative
Investments and Hedging Activities. 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. 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.
In June 1999, the FASB issued SFAS 137 which deferred the effective date of
SFAS 133 to fiscal years beginning after June 15, 2000. A company may implement
SFAS 133 as of the beginning of any fiscal quarter after issuance, however, the
statement cannot be applied retroactively. The Company does not plan to early
adopt SFAS 133. The Company will have satisfied all of its existing free
standing derivative contracts by the effective date of SFAS 133. The Company has
also performed a review of its other contractural arrangements to determine if
they contain embedded derivatives. The Company does not currently believe that
the adoption of SFAS 133 will have a material effect on the financial position
or results of operations of the Company.
-6-
<PAGE>
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(4) Business Segment Information -
Financial information by operating segment is presented below:
<TABLE>
<CAPTION>
Company Oil and Gas Pipelines Other
----------------- ---------------- -------------- --------------
(Expressed in thousands)
<S> <C> <C> <C> <C>
Long-Lived Assets:
As of September 30, 2000:
United States $ 433,678 $ 425,336 $ 5,377 $ 2,965
Kingdom of Thailand 333,244 331,175 - 2,069
Canada 11,414 11,179 - 235
----------------- ---------------- -------------- --------------
Total $ 778,336 $ 767,690 $ 5,377 $ 5,269
================= ================ ============== ==============
As of December 31, 1999:
United States $ 440,914 $ 432,034 $ 5,450 $ 3,430
Kingdom of Thailand 340,204 338,084 - 2,120
Canada 6,242 6,018 - 224
----------------- ---------------- -------------- --------------
Total $ 787,360 $ 776,136 $ 5,450 $ 5,774
================= ================ ============== ==============
Revenues:
For the three months ended September 30, 2000
United States $ 74,368 $ 71,547 $ 3,017 $ (196)
Kingdom of Thailand 53,922 53,922 - -
Canada 1,544 1,003 - 541
----------------- ---------------- -------------- --------------
Total $ 129,834 $ 126,472 $ 3,017 $ 345
================= ================ ============== ==============
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 nine months ended September 30, 2000
United States $ 208,768 $ 199,578 $ 9,609 $ (419)
Kingdom of Thailand 135,116 135,030 - 86
Canada 3,446 2,871 - 575
----------------- ---------------- -------------- --------------
Total $ 347,330 $ 337,479 $ 9,609 $ 242
================= ================ ============== ==============
For the nine months ended September 30, 1999
United States $ 160,664 $ 118,686 $ 4,566 $ 37,412
Kingdom of Thailand 26,555 26,590 - (35)
Canada 2,793 2,813 - (20)
----------------- ---------------- -------------- --------------
Total $ 190,012 $ 148,089 $ 4,566 $ 37,357
================= ================ ============== ==============
Operating Income (Loss):
For the three months ended September 30, 2000
United States $ 21,365 $ 22,286 $ (725) $ (196)
Kingdom of Thailand 31,483 31,483 - -
Canada 689 148 - 541
----------------- ---------------- -------------- --------------
Total $ 53,537 $ 53,917 $ (725) $ 345
================= ================ ============== ==============
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 nine months ended September 30, 2000
United States $ 53,354 $ 54,838 $ (1,065) $ (419)
Kingdom of Thailand 68,018 67,932 - 86
Canada 122 (453) - 575
----------------- ---------------- -------------- --------------
Total $ 121,494 $ 122,317 $ (1,065) $ 242
================= ================ ============== ==============
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
================= ================ ============== ==============
</TABLE>
-7-
<PAGE>
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(5) 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, 2000 September 30, 2000
------------------------------------------ -------------------------------------------
Income Shares Per Share Income Shares Per Share
------------- ----------- ------------- ------------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
Basic earnings per share - $ 26,895 40,403 $ 0.67 $ 57,160 40,359 $ 1.42
============= ============
Effect of dilutive securities:
Options to purchase common shares - 623 - 615
2006 Notes 1,028 2,726 3,083 2,726
Trust Preferred Securities 1,584 6,316 4,753 6,316
------------- ----------- ------------- -----------
Diluted earnings per share $ 29,507 50,068 $ 0.59 $ 64,996 50,016 $ 1.30
============= =========== ============= ============= =========== ============
Antidilutive securities -
Options to purchase common shares - 276 $ 32.75 - 276 $ 32.75
Three Months Ended Nine Months Ended
September 30, 1999 September 30, 1999
------------------------------------------ -------------------------------------------
Income Shares Per Share Income Shares Per Share
------------- ----------- ------------- ------------- ----------- ------------
Basic earnings per share - $ 2,737 40,185 $ 0.07 $ 14,044 40,154 $ 0.35
============= ============
Effect of dilutive securities:
Options to purchase common shares - 325 - 216
------------- ----------- ------------- -----------
Diluted earnings per share $ 2,737 40,510 $ 0.07 $ 14,044 40,370 $ 0.35
============= =========== ============= ============= =========== ============
Antidilutive securities -
Options to purchase common shares - 1,106 $ 23.73 - 2,668 $ 20.99
2006 Notes 1,028 2,726 $ 0.38 3,083 2,726 $ 1.13
Trust Preferred Securities (a) 1,584 6,316 $ 0.25 2,089 2,776 $ 0.75
(a) The Trust Preferred Securities were issued on June 2, 1999.
</TABLE>
(6) Comprehensive Income -
During 1998, the Company adopted the Financial Accounting Standards Board's
(FASB) 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.
-8-
<PAGE>
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(7) Price Hedge Transactions -
During the first nine months of 2000, approximately 27% of the Company's
equivalent production was subject to hedge positions compared to approximately
2% for the first nine months of 1999. Approximately 7% of the Company's
equivalent production was subject to hedge positions in all of 1999.
As of September 30, 2000, the Company had settled all of its commodity
price hedging contracts with respect to its natural gas production and still had
outstanding commodity price hedging contracts with respect to its crude oil and
condensate production as follows:
<TABLE>
<CAPTION>
NYMEX Contract Price per Bbl Fair
--------------------------------------------
Volume in Collars Market
--------------------------
Period Bbls Swaps Floors Ceilings Value (a)
---------------------------------- --------- -------------- ------------ ------------ ----------------
<S> <C> <C> <C> <C> <C>
Price Swap Contract
October 2000 -- December 2000 184,000 $ 21.15 - - $ (1,757,000)
Collar Contract
October 2000 -- December 2000 92,000 - $ 21.00 25.03 $ (521,000)
</TABLE>
(a) Fair market value is calculated using prices derived from NYMEX futures
contract prices existing at September 30, 2000.
-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, 1999.
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, 1999, 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
The Company reported net income for the third quarter of 2000 of
$26,895,000 or $0.67 per share ($29,507,000 or $0.59 per share on a diluted
basis), compared to 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). For the first nine
months of 2000, the Company reported net income of $57,160,000 or $1.42 per
share ($64,996,000 or $1.30 per share on a diluted basis) compared to net income
for the first nine months of 1999 of $14,044,000 or $0.35 per share (on both a
basic and a diluted basis). The increase in net income during the third quarter
and first nine months of 2000, compared to the third quarter and first nine
months of 1999, was primarily related to increased oil and gas revenues
resulting from improved oil and gas production levels and prices. The net
income reported in the first nine months of 1999 was affected by gains
recognized by the Company from the sale of certain properties, most of which
were recognized in the first quarter of 1999.
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 and
first nine months of 2000, compared to the third quarter and first nine months
of 1999, resulted primarily from the issuance of common stock upon the exercise
of stock options pursuant to the Company's incentive plans. The earnings per
share computation on a diluted basis in the periods presented primarily reflect
additional shares of common stock issuable upon the assumed conversion of the
Company's 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities
due 2029 (the "Trust Preferred Securities") and 5 1/2% Convertible Subordinated
Notes due 2006 (the "2006 Notes") and, to a 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.
Total Revenues
The Company's total revenues for the third quarter of 2000 were
$129,834,000, an increase of approximately 88% from total revenues of
$69,138,000 for the third quarter of 1999. The Company's total revenues for the
first nine months of 2000 were $347,330,000, an increase of approximately 83%
compared to total revenues of $190,012,000 for the first nine months of 1999.
The increase in the Company's total revenues for the third quarter and first
nine months of 2000, compared to the third quarter and first nine months of
1999, resulted primarily from a substantial increase in oil and gas revenues
and, to a much lesser extent, pipeline sales. The increase in total revenues
for the first nine months of 2000, compared to the first nine months of 1999,
was also partially offset by a decrease in gains on sales of Company properties.
Oil and Gas Revenues
The Company's oil and gas revenues for the third quarter of 2000 were
$126,472,000, an increase of approximately 88% from oil and gas revenues of
$67,195,000 for the third quarter of 1999. The Company's oil and gas revenues
for the first nine months of 2000 were $337,479,000, an increase of
approximately 128% from oil and gas revenues of $148,089,000 for the first nine
months of 1999. The following table reflects an analysis of variances in the
Company's oil and gas revenues (expressed in thousands) between 2000 and 1999:
-10-
<PAGE>
<TABLE>
<CAPTION>
Increase (decrease) in oil and gas revenues 3/rd/ Qtr 2000 Nine Mo. 2000
resulting from variances in: Compared to Compared to
3/rd/ Qtr 1999 Nine Mo. 1999
-------------- -------------
<S> <C> <C>
Natural gas --
Price...................................................... $10,772 $ 26,943
Production................................................. 3,337 25,278
------- --------
14,109 52,221
------- --------
Crude oil and condensate --
Price...................................................... 13,855 47,825
Production................................................. 30,669 84,501
------- --------
44,524 132,326
------- --------
Natural Gas Liquids ("NGL")................................... 644 4,843
------- --------
Increase (decrease) in oil and gas revenues................ $59,277 $189,390
======= ========
</TABLE>
The increase in the Company's oil and gas revenues for the third quarter
and first nine months of 2000, compared to the third quarter and first nine
months of 1999, is primarily related to increases in the Company's oil,
condensate and NGL ("liquid hydrocarbons") and natural gas production volumes
and, to a lesser extent, an increase in the price that it received for its
liquid hydrocarbons and natural gas production volumes.
<TABLE>
<CAPTION>
Comparison of Increases (Decreases) in: 3/rd/ Quarter % 1/st/ Nine Months %
-------------------- -------------------
Natural Gas -- 2000 1999 Change 2000 1999 Change
------- -------- --------- ------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
Average prices
North America (a).................................. $ 3.63 $ 2.64 38% $ 3.11 $ 2.19 43%
Kingdom of Thailand(b)............................. $ 2.23 $ 1.66 34% $ 2.13 $ 1.55 37%
Company-wide average price....................... $ 3.11 $ 2.32 34% $ 2.77 $ 2.03 36%
Average daily production volumes (MMcf per day)
North America (c).................................. 100.9 99.6 1% 108.8 101.0 8%
Kingdom of Thailand.............................. 58.2 47.9 22% 57.2 32.2 78%
------- ------- ------- -------
Company-wide average daily production 159.1 147.5 8% 166.0 133.2 25%
======= ======= ======= =======
</TABLE>
____________________________
(a) North American average prices and production reflect production from
the United States and Canada. The average prices received for North
American production reflect the effect of the Company's hedging
transactions during the relevant period. See "Liquidity and Capital
Resources - Other Matters; Current Hedging Activity."
(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.
(c) "MMcf" stands for million cubic feet.
<TABLE>
<CAPTION>
Comparison of Increases (Decreases) in: 3/rd/ Quarter % 1/st/ Nine Months %
------------------ ------------------
Crude Oil and Condensate -- 2000 1999 Change 2000 1999 Change
------- ------- -------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Average prices
North America(a)................................... $ 29.25 $ 20.24 45% $ 27.18 $ 15.89 71%
Kingdom of Thailand................................ $ 32.38 $ 26.21 24% $ 30.31 $ 22.18 37%
Company-wide average price......................... $ 30.88 $ 21.62 43% $ 28.68 $ 16.81 71%
Average daily production volumes (Bbls per day)
North America(b)................................... 12,977 12,509 4% 13,225 12,610 5%
Kingdom of Thailand................................ 14,090 3,763 274% 12,234 2,150 469%
------- ------- ------- -------
Company-wide average daily production 27,067 16,272 66% 25,459 14,760 72%
======= ======= ======= =======
Total Liquid Hydrocarbons --
Company-wide average daily production (Bbls per day) 29,056 18,771 55% 27,615 16,851 64%
======= ======= ======= =======
</TABLE>
__________________________
(a) North American average prices and production reflect production from
the United States and Canada. The average prices received for North
American production reflects the effect of the Company's hedging
transactions during the relevant period. See "Liquidity and Capital
Resources-Other Matters; Current Hedging Activity."
(b) "Bbls" stands for barrels.
-11-
<PAGE>
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. During portions of the first nine months of 1999,
the Company and its joint venture partners did not met the contractual minimum
delivery requirements under the Gas Sales Agreement. This permitted PTT to
reduce the price it paid on a portion of the natural gas which the Company sold
to PTT during that period by 25% from the then current contract price. Since
production commenced from new facilities installed in the Tantawan and Benchamas
Fields, the Company has generally been able to meet its contractual delivery
obligations to PTT and is currently receiving the current contract price.
Production. The increase in the Company's natural gas production during the
third quarter and first nine months of 2000, compared to the third quarter and
first nine months of 1999, was related in large measure to production from the
Benchamas Field which commenced during the third quarter of 1999 and, to a
lesser extent, increased production from certain of the Company's domestic
properties, including its East Cameron Block 270 Field and certain of its
Permian basin fields, that was partially offset by anticipated decline from
other Company properties.
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 are 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 U.S. dollars. The Company is generally paid for its crude oil and
condensate production from Thailand in U.S. dollars.
Production. The increase in the Company's crude oil and condensate
production from the Gulf of Thailand during the third quarter and first nine
months of 2000, compared to the third quarter and first nine months of 1999,
resulted from production from the Benchamas Field during the third quarter of
1999 and, to a lesser extent, increased production from the Tantawan Field. The
increase in the Company's domestic crude oil and condensate production for the
third quarter of 2000, compared to the third quarter of 1999, was primarily
related to increased production from the Company's offshore Gulf of Mexico
properties. The increase in the Company's domestic crude oil and condensate
production for the first nine months of 2000, compared to the first nine months
of 1999, was primarily related to increased production from the Company's
Permian Basin properties and, to a much lesser extent, increased production from
its offshore Gulf of Mexico properties.
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 2000, compared with the third quarter of
1999, related to an increase in the average price that the Company received for
its NGL production, that was only partially offset by decreased NGL production.
The increase in NGL revenues for the first nine months of 2000, compared with
the first nine months of 1999, related to an increase in the average price that
the Company received for its NGL production volumes and, to a lesser extent, an
increase in NGL production volumes.
Costs and Expenses
<TABLE>
<CAPTION>
3/rd/ Quarter % 1/st/ Nine Months %
Comparison of Increases (Decreases) in: ------------------------ ------------------------
2000 1999 Change 2000 1999 Change
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Lease Operating Expenses
North America..................... $15,092,000 $12,905,000 17% $44,335,000 $35,849,000 24%
Kingdom of Thailand............... 8,283,000 6,807,000 22% 25,046,000 12,380,000 102%
----------- ----------- ----------- -----------
Total Lease Operating
Expenses................... $23,375,000 $19,712,000 19% $69,381,000 $48,229,000 44%
=========== =========== =========== ===========
Pipeline Operating and Natural
Gas Purchases...................... $ 3,576,000 $ 1,307,000 174% $10,122,000 $ 3,505,000 189%
General and Administrative Expenses.. $ 8,605,000 $ 7,057,000 22% $26,567,000 $20,686,000 28%
Exploration Expenses................. $ 2,694,000 $ 801,000 236% $ 8,481,000 $ 3,940,000 115%
Dry Hole and Impairment Expenses..... $ 6,570,000 $ 930,000 606% $13,762,000 $ 1,960,000 602%
Depreciation, Depletion and
Amortization (DD&A) Expenses...... $31,477,000 $27,422,000 15% $97,523,000 $74,667,000 31%
DD&A rate (in Mcfe (a))........... $ 1.01 $ 1.13 (11)% $ 1.06 $ 1.14 ( 7)%
Mcfe produced..................... 30,677,000 23,929,000 28% 90,822,000 63,962,000 42%
</TABLE>
_________________________________________
(a) "Mcfe" stands for thousands of
cubic feet equivalent.
-12-
<PAGE>
<TABLE>
<CAPTION>
3/rd/ Quarter % 1/st/ Nine months %
Comparison of Increases (Decreases) in: --------------------------- ---------------------------
2000 1999 Change 2000 1999 Change
------------ ----------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Interest--
Charges.......................... $ (8,504,000) $(8,305,000) 2% $(25,460,000) $(27,414,000) (7)%
Interest Income.................. $ 774,000 $ 588,000 32% $ 1,253,000 $ 898,000 40%
Capitalized Interest Expense..... $ 5,546,000 $ 4,670,000 19% $ 15,160,000 $ 13,437,000 13%
Minority Interest - Dividends and
costs Associated with Preferred
Securities of a Subsidiary Trust... $ (2,351,000) $(2,557,000) (8)% $ (7,468,000) $ (3,356,000) 123%
Foreign Currency Transaction
Loss............................. $ 930,000 $ 2,014,000 (54)% $ 2,051,000 $ 1,605,000 28%
Income Tax Expense.................. $ 21,177,000 $ 1,554,000 1263% $ 45,768,000 $ 4,941,000 826%
</TABLE>
Lease Operating Expenses.
The increase in North American lease operating expenses for the third
quarter and first nine months of 2000, compared to the third quarter and first
nine months of 1999, related in large measure to increased severance taxes
resulting from increased production from the Company's non-U.S. government owned
properties (accounting for $1,551,000 and $4,056,000 of the increase for the
quarterly and nine month periods, respectively) and, to a lesser extent,
unanticipated equipment repairs in the Gulf of Mexico and the Company's Western
Division properties. The increase in lease operating expenses in the Kingdom of
Thailand for the third quarter and first nine months of 2000, compared to the
third quarter and first nine months of 1999, primarily related to the fact that,
prior to the commencement of production, no lease operating expenses were
incurred by the Company in the Benchamas field. 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 $3,798,000 (net to the Company's interest) of the
Company's Thailand lease operating expenses for the third quarter in both 2000
and 1999. For the first nine months of 2000, these lease payments were
$11,311,000, compared to $9,821,000 for the first nine months of 1999. The
increase in lease payments for the first nine months of 2000, compared to the
first nine months of 1999, resulted from the fact that lease payments on the FSO
located in the Benchamas Field did not begin until mid-way through the month of
May, 1999.
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." 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 and first nine months of 2000,
compared to the third quarter and first nine months of 1999, primarily related
to the increased cost of natural gas purchased for resale by the Company.
General and Administrative Expenses
The increase in general and administrative expenses for the third quarter
and first nine months of 2000, compared with the third quarter and first nine
months of 1999, related to, among other items, normal salary and concomitant
benefit expense adjustments and increased fees paid to professional consultants,
including legal, accounting and other experts. In addition, with respect to the
nine month comparative periods, increased expenses associated with the Company's
Thailand operations related to the commencement of production from the Benchamas
field.
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 third quarter of 2000, compared to the
third quarter of 1999, resulted primarily from generally increased geophysical
activity by the Company in: the offshore Gulf of Mexico, where the Company
acquired significant amounts of non-proprietary 3-D data; Hungary, where
approximately 890 kilometers of proprietary 2-D data was acquired; and in
Thailand, where additional and existing 3-D data was processed. The increase in
exploration expense for the first nine months of 2000, compared to the first
nine months of 1999, resulted primarily from increased geophysical activity by
the Company in the previously mentioned areas as well as expenses related to 3-D
seismic surveys acquired on the Company's exploration leases in the United
Kingdom sector of the North Sea and in Canada.
-13-
<PAGE>
Dryhole and Impairment Expenses
The increase in the Company's dryhole and impairment expenses for the third
quarter and first nine months of 2000, compared to the third quarter and first
nine months of 1999, resulted primarily from the expensing of costs related to
wells that were drilled where no hydrocarbons were found or where it was
determined that hydrocarbons were not present in sufficient quantities to
justify development and, to a lesser extent, the determination that there were
less hydrocarbon reserves present than originally anticipated at the time of
initial development.
Depreciation, Depletion and Amortization Expenses
The increase in the Company's depreciation, depletion and amortization
("DD&A") expense for the third quarter and first nine months of 2000, compared
to the third quarter and first nine months of 1999, resulted from an increase in
the Company's liquid hydrocarbon and natural gas production, that was only
partially offset by a decrease in the Company's composite DD&A rate.
The decrease in the composite DD&A rate for all of the Company's producing
fields for the third quarter and first nine months of 2000, compared to the
third quarter and first nine months of 1999, 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 lower than the Company's recent
historical composite rate (principally the Benchamas Field and certain Permian
basin properties) and a corresponding decrease in the percentage of the
Company's production coming from fields that have DD&A rates that are higher
than the Company's recent historical composite DD&A rate.
Interest
Interest Charges. The increase in the Company's interest charges for the
third quarter of 2000, compared to the third quarter of 1999, resulted primarily
from an increase in average interest rate on the debt outstanding and, to a
lesser extent an increase in commitment fees paid to the Company's senior
lenders. The decrease in the Company's interest charges for the first nine
months of 2000, compared to the first nine months of 1999, resulted primarily
from a decrease in the average amount of the Company's outstanding debt due to
the issuance of the Trust Preferred Securities in the second quarter of 1999,
that was not entirely offset by increased average interest rates on the debt
outstanding and increased commitment fees paid to the Company's senior lenders.
As of September 30, 2000, the Company was not a party to any interest rate swap
agreements.
Capitalized Interest. The increase in capitalized interest for the third
quarter of 2000, compared to the third quarter of 1999, resulted primarily from
an increase in the amount of capital expenditures subject to interest
capitalization during the third quarter of 2000 ($258,591,000), compared to the
third quarter of 1999 ($221,600,000), and, to a lesser extent, an increase in
the interest rate discussed in the preceding paragraph that the Company uses to
apply on such capital expenditures to arrive at the total amount of capitalized
interest. The increase in capitalized interest for the first nine months of
2000, compared to the first nine months of 1999, resulted primarily from an
increase in the amount of capital expenditures subject to interest
capitalization during the first nine months of 2000 ($239,844,000), compared to
the first nine months of 1999 ($221,080,000) and, to a lesser extent, from an
increase in the interest rate discussed in the preceding paragraph 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 development of the Benchamas field 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 business trust in which the Company owns all of the issued
common securities, issued $150,000,000 of Trust Preferred Securities on June 2,
1999. Therefore the amounts recorded for the first nine months of 1999 under
Minority Interest -- Dividends and Costs Associated with Preferred Securities of
a Subsidiary Trust principally reflected cumulative unpaid dividends and, to a
lesser extent, the amortization of issuance expenses related to the offering and
sale of the Trust Preferred Securities for only a portion of such periods.
Foreign Currency Transaction Losses
The foreign currency transaction losses reported for the third quarter and
first nine months of 1999 and 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. 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 each period presented, the value of the Thai Baht weakened
against the U.S. dollar, resulting in a foreign currency transaction loss. The
-14-
<PAGE>
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 September 30, 2000, 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 third quarter and
first nine months of 2000, compared to the third quarter and first nine months
of 1999, resulted primarily from increased pre-tax income and the increased
contribution to pre-tax income from the Company's Kingdom of Thailand operations
which are subjected to a tax rate in excess of the U.S. statutory tax rate.
Management currently expects that its foreign taxes will constitute a
substantial portion of its overall tax burden for the foreseeable future.
Liquidity and Capital Resources
Cash Flows
The Company's Condensed Consolidated Statement of Cash Flows for the first
nine months of 2000 reflects net cash provided by operating activities of
$181,031,000. In addition to net cash provided by operating activities, the
Company received $4,497,000, primarily from the exercise of stock options.
During the first nine months of 2000, the Company invested $101,297,000 of
such cash flow in capital projects, repaid a net $10,000,000 under its senior
debt agreements and paid $3,640,000 (three quarterly dividend payments of $0.03
per share) in cash dividends to holders of the Company's common stock and paid
$7,314,000 in cash distributions to holders of its Trust Preferred Securities.
As of September 30, 2000, the Company's cash and cash equivalents were
$68,292,000 and its long-term debt stood at $365,000,000. As of September 30,
2000, the Company had $200,000,000 of availability under its revolving credit
facility and its unsecured credit line.
Future Capital Requirements
The Company's capital and exploration budget for 2000, 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
established by the Company's Board of Directors at $200,000,000. The Company
currently anticipates that its available cash and cash equivalents, cash
provided by operating activities and funds available under its credit agreement,
uncommitted credit line 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 2000, and future dividend and distribution payments at current levels
(including a dividend payment of $0.03 per share to be paid on November 17, 2000
to shareholders of record on November 3, 2000). 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.
Other Matters
Current Hedging Activity. From time to time, the Company has used and may
continue to use hedging transactions with respect to a portion of its liquid
hydrocarbon and natural 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, it 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. During the first nine
months of 2000, approximately 27% of the Company's equivalent oil and natural
gas production was subject to hedge positions, compared to 2% of the Company's
equivalent oil and natural gas production during the first nine months of 1999.
-15-
<PAGE>
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security-Holders
None.
Item 6. Exhibits and Reports on Form 8-K
(A) Exhibits
27 -- Financial Data Schedule
(B) Reports on Form 8-K
None.
-16-
<PAGE>
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: November 8, 2000
-17-
