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, 2001 or
[ ] Transition report pursuant to section 13 or 15[d] of the Securities
Exchange Act of 1934
For the transition period from ....... to .......
Commission file number 1-7792
POGO PRODUCING COMPANY
[Exact Name of Registrant as Specified in Its Charter]
DELAWARE 74-1659398
[State or Other Jurisdiction of [I.R.S. Employer
Incorporation or Organization] Identification No.]
5 GREENWAY PLAZA, SUITE 2700
HOUSTON, TEXAS 77046-0504
[Address of principal executive offices] [Zip Code]
[713] 297-5000
--------------------------------------------------------------------------------
[Registrant's Telephone Number, Including Area Code]
Not Applicable
--------------------------------------------------------------------------------
[Former Name, Former Address and Former Fiscal Year, if Changed Since Last
Report]
Indicate by check mark whether the registrant: [1] has filed all reports
required to be filed by Section 13 or 15[d] of the Securities Exchange Act
of 1934 during the preceding 12 months [or for such shorter period that the
registrant was required to file such reports], and [2] has been subject to
such filing requirement for the past 90 days: Yes X No
---
Registrant's number of common shares outstanding as of September 30, 2001:
53,634,752
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
POGO PRODUCING COMPANY AND SUBSIDIARIES
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2001 2000 2001 2000
--------- --------- --------- ---------
(Expressed in thousands, except per share amounts)
REVENUES:
Oil and gas $ 139,677 $ 125,720 $ 468,002 $ 328,169
Pipeline sales and other 2,043 3,362 10,302 9,865
Gains (losses) on sales 1,815 -- 4,487 (14)
--------- --------- --------- ---------
Total 143,535 129,082 482,791 338,020
--------- --------- --------- ---------
OPERATING COSTS AND EXPENSES:
Lease operating 31,939 23,883 87,462 69,139
Pipeline operating and natural gas purchases 1,838 3,576 10,258 10,122
General and administrative 11,281 8,605 29,139 26,567
Exploration 5,013 2,694 17,447 8,481
Dry hole and impairment 3,053 6,570 26,097 13,762
Depreciation, depletion and amortization 55,754 31,643 146,286 96,528
--------- --------- --------- ---------
Total 108,878 76,971 316,689 224,599
--------- --------- --------- ---------
OPERATING INCOME 34,657 52,111 166,102 113,421
--------- --------- --------- ---------
INTEREST:
Charges (15,119) (8,504) (41,411) (25,460)
Income 690 774 2,686 1,253
Capitalized 9,324 5,546 24,153 15,160
MINORITY INTEREST -Dividends and costs associated
with preferred securities of a subsidiary trust (2,501) (2,351) (7,499) (7,468)
FOREIGN CURRENCY TRANSACTION GAIN (LOSS) 338 (930) (668) (2,051)
--------- --------- --------- ---------
INCOME BEFORE TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 27,389 46,646 143,363 94,855
INCOME TAX EXPENSE (11,786) (20,464) (56,835) (41,731)
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 15,603 26,182 86,528 53,124
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE -- -- -- (1,768)
--------- --------- --------- ---------
NET INCOME $ 15,603 $ 26,182 $ 86,528 $ 51,356
========= ========= ========= =========
EARNINGS PER COMMON SHARE
Basic
Income before cumulative effect of change in accounting principle $ 0.29 $ 0.65 $ 1.72 $ 1.32
Cumulative effect of change in accounting principle -- -- -- (0.04)
--------- --------- --------- ---------
Net income $ 0.29 $ 0.65 $ 1.72 $ 1.28
========= ========= ========= =========
Diluted
Income before cumulative effect of change in accounting principle $ 0.28 $ 0.58 $ 1.57 $ 1.22
Cumulative effect of change in accounting principle -- -- -- (0.04)
--------- --------- --------- ---------
Net income $ 0.28 $ 0.58 $ 1.57 $ 1.18
========= ========= ========= =========
DIVIDENDS PER COMMON SHARE $ 0.03 $ 0.03 $ 0.09 $ 0.09
========= ========= ========= =========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
AND POTENTIAL COMMON SHARES OUTSTANDING:
Basic 53,613 40,403 50,239 40,359
Diluted 60,480 50,068 60,068 50,016
See accompanying notes to consolidated financial statements.
-1-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
September 30, December 31,
2001 2000
------------ ------------
(Unaudited)
(Expressed in thousands
except share amounts)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 94,410 $ 81,510
Accounts receivable 58,506 84,381
Other receivables 40,542 27,242
Federal income tax receivable 28,346 --
Inventory - Product 5,601 3,054
Inventories - Tubulars 8,882 8,056
Price hedge contracts 39,459 9,153
Other 2,949 1,276
----------- -----------
Total current assets 278,695 214,672
----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting
Proved properties being amortized 2,747,637 1,698,404
Unevaluated properties and properties
under development, not being amortized 411,902 154,914
Pipelines, at cost 6,524 7,095
Other, at cost 18,503 15,257
----------- -----------
3,184,566 1,875,670
----------- -----------
Accumulated depreciation, depletion and amortization
Oil and gas (1,119,169) (1,053,478)
Pipelines (1,471) (1,780)
Other (10,422) (8,758)
----------- -----------
(1,131,062) (1,064,016)
----------- -----------
Property and equipment, net 2,053,504 811,654
----------- -----------
OTHER ASSETS:
Deferred income tax 47,947 3,695
Debt issue expenses 16,124 10,718
Price hedge contracts 8,243 14,869
Foreign value added taxes receivable 6,234 7,262
Other 21,674 20,652
----------- -----------
100,222 57,196
----------- -----------
$ 2,432,421 $ 1,083,522
=========== ===========
See accompanying notes to consolidated financial statements.
-2-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
September 30, December 31,
2001 2000
------------- ------------
(Unaudited)
(Expressed in thousands
except share amounts)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - operating activities $ 39,035 $ 27,334
Accounts payable - investing activities 56,150 67,703
Foreign income taxes payable 5,217 --
Accrued interest payable 15,698 7,443
Accrued dividends associated with
preferred securities of a subsidiary trust 813 813
Accrued payroll and related benefits 2,653 2,285
Other 1,400 851
------------ ------------
Total current liabilities 120,966 106,429
------------ ------------
LONG-TERM DEBT 756,992 365,000
DEFERRED INCOME TAX 560,101 95,453
OTHER LIABILITIES AND DEFERRED CREDITS 15,326 13,456
------------ ------------
Total liabilities 1,453,385 580,338
------------ ------------
MINORITY INTEREST:
Company-obligated mandatorily redeemable
convertible preferred securities of a subsidiary trust,
net of unamortized issue expenses 145,023 144,913
------------ ------------
SHAREHOLDERS' EQUITY:
Preferred stock, $1 par; 4,000,000 and 2,000,000 shares
authorized, respectively -- --
Common stock, $1 par; 200,000,000 and 100,000,000 shares
authorized; 53,650,327 and 40,659,591 shares issued, respectively 53,650 40,660
Additional capital 658,430 298,885
Retained earnings 102,202 20,112
Accumulated other comprehensive income (loss) 20,055 (1,062)
Treasury stock (15,575 shares), at cost (324) (324)
------------ ------------
Total shareholders' equity 834,013 358,271
------------ ------------
$ 2,432,421 $ 1,083,522
============ ============
See accompanying notes to consolidated financial statements.
-3-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended
September 30,
---------------------------------
2001 2000
------------- -------------
(Expressed in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from customers $ 510,915 $ 310,888
Cash received from price hedge contracts 8,808 --
Operating, exploration, and general
and administrative expenses paid (159,823) (110,892)
Interest paid (29,919) (24,119)
Federal income taxes paid (31,115) (3,000)
Federal income taxes received -- 3,000
Value added taxes received 1,028 5,472
Other 1,527 (318)
------------- -------------
Net cash provided by operating activities 301,421 181,031
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (280,819) (101,311)
Acquisition of NORIC, net of $21,235 cash acquired (323,476) --
Purchase of proved reserves (2,714) --
Proceeds from the sale of properties and subsidiaries 20,001 --
------------- -------------
Net cash used in investing activities (587,008) (101,311)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of new debt 200,000 --
Borrowings under senior debt agreements 1,063,992 67,000
Payments under senior debt agreements (872,000) (77,000)
Payment of North Central senior debt acquired (78,600) --
Payments of cash dividends on common stock (4,438) (3,640)
Payments of preferred dividends of a subsidiary trust (7,312) (7,314)
Payments of financing issue expenses (8,720) (131)
Proceeds from exercise of stock options and other 6,699 4,497
------------- -------------
Net cash provided by (used in) financing activities 299,621 (16,588)
------------- -------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH (1,134) (1,107)
------------- -------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 12,900 62,025
CASH AND CASH EQUIVALENTS AT THE BEGINNING OF THE YEAR 81,510 6,267
------------- -------------
CASH AND CASH EQUIVALENTS AT THE END OF THE PERIOD $ 94,410 $ 68,292
============= =============
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Net income $ 86,528 $ 51,356
Adjustments to reconcile net income to
net cash provided by operating activities -
Cumulative effect of change in accounting principle -- 1,768
Minority interest 7,499 7,468
Foreign currency transaction (gains) losses 668 2,051
(Gains) losses from the sales of properties (4,487) 14
Depreciation, depletion and amortization 146,286 96,528
Dry hole and impairment 26,097 13,762
Interest capitalized (24,153) (15,160)
Price hedge contracts 5,342 --
Deferred federal income taxes 48,588 45,738
Change in operating assets and liabilities 9,053 (22,494)
------------- -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES $ 301,421 $ 181,031
============= =============
See accompanying notes to consolidated financial statements.
-4-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Consolidated Statements of Shareholders' Equity (Unaudited)
For the Nine Months Ended September 30,
------------------------------------------------------------------------------------
2001 2000
------------------------------------------- ---------------------------------------
Shareholders' Shareholders'
Equity Compre- Equity Compre-
----------------------------- hensive -------------------------- hensive
Shares Amount Income Shares Amount Income
------------- -------------- ----------- ------------ ----------- ----------
(Expressed in thousands, except share amounts)
COMMON STOCK:
$1.00 par-200,000,000 and 100,000,000
shares authorized, respectively
Balance at beginning of year 40,659,591 $ 40,660 40,279,661 $ 40,279
Shares issued for acquisition of NORIC 12,615,816 12,615 -- --
Stock options exercised 337,264 337 191,915 192
Shares issued as compensation 37,656 38 65,080 65
------------- -------------- ------------ -----------
Issued at end of period 53,650,327 53,650 40,536,656 40,536
------------- -------------- ------------ -----------
ADDITIONAL CAPITAL:
Balance at beginning of year 298,885 291,909
Shares issued for acquisition of NORIC 351,729 --
Stock options exercised 6,922 3,687
Shares issued as compensation 894 1,222
-------------- -----------
Balance at end of period 658,430 296,818
-------------- -----------
RETAINED EARNINGS (DEFICIT):
Balance at beginning of year 20,112 (62,291)
Net income 86,528 $ 86,528 51,356 $ 51,356
Dividends ($0.09 per common share) (4,438) (3,640)
-------------- -----------
Balance at end of period 102,202 (14,575)
-------------- -----------
ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS):
Balance at beginning of year (1,062) (1,061)
Exchange gains (losses)
on Canadian currency and other 2,253 2,253 (70) (70)
Cumulative effect of
change in accounting principle (2,438) (2,438) -- --
Unrealized gains arising during the
period on price hedge contracts 23,067 23,067 -- --
Reclassification adjustment for
losses included in net income (1,765) (1,765) -- --
--------------
Net unrealized gains (losses)
on price hedge contracts 21,302 --
-------------- -----------
Balance at end of period 20,055 (1,131)
-------------- ----------- ----------- -----------
COMPREHENSIVE INCOME $ 107,645 $ 51,286
=========== ===========
TREASURY STOCK:
Balance at beginning of year (15,575) (324) (15,575) (324)
Activity during the period -- -- -- --
------------- -------------- ------------ -----------
Balance at end of period (15,575) (324) (15,575) (324)
------------- -------------- ------------ -----------
COMMON STOCK OUTSTANDING,
AT THE END OF THE PERIOD 53,634,752 40,521,081
============= ============
TOTAL SHAREHOLDERS' EQUITY $ 834,013 $ 321,324
============== ===========
See accompanying notes to consolidated financial statements.
-5-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Unaudited)
(1) GENERAL INFORMATION -
The consolidated financial statements included herein have been
prepared by Pogo Producing Company (the "Company") without audit and include all
adjustments (of a normal and recurring nature) which are, in the opinion of
management, necessary for the fair presentation of interim results which are not
necessarily indicative of results for the entire year. Certain prior year
amounts have been reclassified to conform with current year presentation. Refer
to the Consolidated Statements of Shareholders' Equity for an analysis of Other
Comprehensive Income which was $23,533,000 and $26,212,000, respectively, for
the three months ended September 30, 2001 and 2000 and $107,645,000 and
$51,286,000, respectively, for the nine months ended September 30, 2001 and
2000. The financial statements should be read in conjunction with the
consolidated financial statements and notes thereto included in the Company's
annual report on Form 10-K for the year ended December 31, 2000.
(2) LONG-TERM DEBT -
Long-term debt and the amount due within one year at September 30, 2001
and December 31, 2000, consist of the following:
September 30, December 31,
2001 2000
------------- -------------
(Expressed in thousands)
Senior debt -
Bank revolving credit agreement
LIBOR based loans, borrowings at average interest rate of 4.76% $ 167,000 $ --
Banker's acceptances, borrowing at an interest rate of 4.01% 24,992 --
------------- -------------
Total senior debt 191,992 --
------------- -------------
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
8 1/4% Senior subordinated notes due 2011 ("2011 Notes") 200,000 --
5 1/2% Convertible subordinated notes due 2006 ("2006 Notes") 115,000 115,000
------------- -------------
Total subordinated debt 565,000 365,000
------------- -------------
Long-term debt, none due within one year $ 756,992 $ 365,000
============= =============
Refer to Note 3 in Notes to Consolidated Financial Statements included
in the Company's annual report on Form 10-K for the year ended December 31,
2000, for further information on the Company's debt agreements.
On March 8, 2001, prior to the merger with NORIC Corporation ("NORIC")
and the acquisition of North Central Oil Corporation ("North Central") on March
14, 2001, the Company entered into a reserve based revolving credit facility
(the "Credit Facility"). The Credit Facility provides for a $515,000,000
revolving credit facility until March 7, 2006. The amount that may be borrowed
may not exceed a borrowing base which is determined semi-annually and is
calculated based upon substantially all of the Company's proved oil and gas
properties. The borrowing base is currently established at $425,000,000. The
Credit Facility is governed by various financial and other covenants,
including requirements to maintain positive working capital (excluding current
maturities of debt) and a fixed charge coverage ratio, creation of liens, a
limitation on commodity hedging above certain specified limits, the prepayment
of subordinated debt, the payment of dividends, mergers and consolidations,
investments and asset dispositions. In addition, the Company has pledged the
stock of North Central and its inter-company receivable with North Central as
security for its obligations under the Credit Facility and is prohibited from
pledging borrowing base properties as security for other debt. The Credit
Facility also permits short-term "swing line" loans and the issuance of up to
$50,000,000 in letters of credit. Borrowings under the Credit facility bear
interest, at the Company's option, at a base (prime) rate plus a variable margin
(currently none) or LIBOR plus a variable margin (currently 1.25%). The margin
varies as a function of the percentage of the borrowing base utilized. A
commitment fee on the unborrowed amount that is currently available under the
Credit Facility is also charged based on the percentage of the borrowing base
that is being utilized.
In connection with its entering into the Credit Facility, the Company's
previously existing uncommitted money market line of credit with a commercial
bank was terminated.
-6-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Unaudited)
(2) LONG-TERM DEBT (CONTINUED) -
The Master Banker's Acceptance Agreement between the Company and one of
its lenders provides that the lender has agreed to accept bank drafts from the
Company up to $25,000,000. The banker's drafts are available on an uncommitted
basis and the bank has no obligation to accept the Company's request for drafts.
Drafts drawn under this agreement would be reflected as long-term debt on the
Company's balance sheet because the Company currently has the ability and intent
to reborrow such amounts under the Credit Facility. The Company's 2007 Notes,
2009 Notes, and the Company's new notes due 2011 (described below) may restrict
all or a portion of the amounts that may be borrowed under the Master Banker's
Acceptance Agreement as senior debt. The Master Banker's Acceptance Agreement
permits either party to terminate the letter agreement at any time upon five
business days notice.
On April 10, 2001 the Company issued $200,000,000 principal amount of
Senior Subordinated Notes due 2011 (the "2011 Notes"). The 2011 Notes bear
interest at a rate of 8 1/4%, payable semi-annually in arrears on April 15 and
October 15 of each year, commencing October 15, 2001. The 2011 Notes are general
unsecured senior subordinated obligations of the Company, are subordinated in
right of payment to the Company's senior indebtedness, which currently includes
the Company's obligations under the Credit Facility and its banker's
acceptances, are equal in right of payment to the 2007 Notes and the 2009 Notes,
but are senior in right of payment to the Company's subordinated indebtedness,
which currently includes the 2006 Notes. In addition, they are senior in right
of payment to the liquidation preference under the Company's Trust Preferred
Securities. The Company, at its option, may redeem the 2011 Notes in whole or in
part, at any time on or after April 15, 2006, at a redemption price of 104.125%
of their principal value and decreasing percentages thereafter. The indentures
governing the 2011 Notes also imposes certain covenants on the Company that are
substantially identical to the covenants contained in the indentures governing
the 2007 Notes and the 2009 Notes, including covenants limiting: incurrence of
indebtedness including senior indebtedness; restricted payments; the issuance
and sales of restricted subsidiary capital stock; transactions with affiliates;
liens; disposition of proceeds of asset sales; non-guarantor restricted
subsidiaries; dividends and other payment restrictions affecting restricted
subsidiaries; and mergers, consolidations and the sale of assets.
(3) INCOME TAXES -
The Company does not provide for U.S. income taxes on unremitted
earnings of foreign subsidiaries where the Company's present intention is to
reinvest the unremitted earnings in its foreign operations. Unremitted earnings
of foreign subsidiaries for which U.S. income taxes have not been provided are
approximately $48,000,000 at September 30, 2001. It is not practical to
determine the amount of U.S. income taxes that would be payable upon remittance
of the assets that represent those earnings.
During the three months ended September 30, 2001, the Company
reevaluated its estimates regarding the realizability of its Thailand operating
loss carryforwards as well as its ability to indefinitely reinvest all
unremitted foreign earnings in its foreign operations. Based on the Company's
future expectations for its Thailand operations, the Company believes that it
is more-likely-than-not that its remaining Thailand operating loss carryforward
will be realized and, therefore, reversed the remaining valuation allowance
accordingly. In addition, the Company has provided for U.S. income taxes on the
unremitted earnings from a portion of its Thailand operations. However, where
the Company's continued intention is to reinvest the unremitted earnings of a
foreign subsidiary in its foreign operations, the Company will continue not to
provide U.S. income taxes on those earnings.
-7-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Unaudited)
(4) HEDGING ACTIVITIES -
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities ("SFAS 133"). In June 2000, the FASB issued SFAS 138,
Accounting for Derivative Instruments and Hedging Activities, an amendment of
FASB Statement No. 133. SFAS 133, as amended, establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair market value.
The statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge criteria are met. Special accounting
for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting. The Company adopted SFAS 133 effective January 1,
2001. Based on the nature of the Company's derivative instruments currently
outstanding and the historical volatility of oil and gas commodity prices, the
Company expects that SFAS 133 could increase volatility in the Company's
earnings and other comprehensive income for future periods.
SFAS 133, in part, allows special hedge accounting. SFAS 133 provides
that the effective portion of the gain or loss on a derivative instrument
designated and qualifying as a cash flow hedging instrument be reported as a
component of other comprehensive income and be reclassified into earnings in the
same period during which the hedged forecasted transaction affects earnings. The
remaining gain or loss on the derivative instrument, if any, must be recognized
currently in earnings.
SFAS 133 requires that as of the date of initial adoption, the
difference between the market value of derivative instruments and the previous
carrying amount of these derivatives be recorded in net income or other
comprehensive income, as appropriate, as the cumulative effect of a change in
accounting principle. Based on interpretive guidance issued during the first
quarter of 2001, the Company determined that the cumulative effect of adopting
SFAS 133 should be recorded in other comprehensive income. As such, effective
January 1, 2001, the Company recorded an unrealized loss of $2,438,000, net of
deferred taxes of $1,313,000, in other comprehensive income. During the first
nine months of 2001, the Company recognized a $2,716,000 gain included in oil
and gas revenues on these contracts. An immaterial amount of ineffectiveness on
these hedge contracts was also recognized in other income. Unrealized gains on
derivative instruments arising during the nine months ended September 30, 2001
of $23,067,000, net of deferred taxes of $12,421,000, has been reflected as a
component of other comprehensive income. Based on the fair market value of the
hedge contracts as of September 30, 2001, the Company would reclassify
additional pre-tax income of approximately $25,500,000 (approximately
$16,575,000 net of taxes) from other comprehensive income (shareholders' equity)
to net income during the next twelve months.
As of September 30, 2001, the Company held options to sell 70 million
cubic feet of natural gas production per day for the period from October 1, 2001
through December 31, 2002. The Company has designated these contracts as cash
flow hedges designed to give the Company the right, but not the obligation, to
sell natural gas at a sales price of $4.25 per MMBtu for the period from October
2001 through March 2002 and $4.00 per MMBtu for the period from April 2002
through December 2002. These contracts are designed to guarantee the Company a
minimum "floor" price for the contracted volumes of production without limiting
the Company's participation in price increases during the covered period. As of
September 30, 2001, the Company was a party to the following hedging
arrangements:
NYMEX
Volume Contract Fair
in Price per Market
Contract Period MMBtu(a) MMBtu(a) Value(b)
--------------------------- ------------ ------------ ------------
October 2001 - March 2002 12,740 $4.25 $ 22,082,000
April 2002 - December 2002 19,250 $4.00 $ 25,620,000
(a) MMBtu means million British Thermal Units.
(b) Fair Market value is calculated using prices derived from NYMEX
futures contract prices existing at September 30, 2001.
These hedging transactions are settled based upon the average of the
reporting settlement prices on the NYMEX for the last three trading days or
occasionally, the penultimate trading day of a particular contract month. For
any particular floor transaction, the counter-party is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction. The Company is not required to make
any payment in connection with the settlement of a floor transaction.
As of September 30, 2001 the Company was not a party to any commodity
price hedging contracts with respect to any of its current or future crude oil
and condensate production.
-8-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Unaudited)
(5) BUSINESS SEGMENT INFORMATION -
Financial information by operating segment is presented below:
COMPANY OIL AND GAS PIPELINES OTHER
------------ ------------ ------------ ------------
(Expressed in thousands)
LONG-LIVED ASSETS:
As of September 30, 2001:
United States $ 1,715,438 $ 1,705,915 $ 5,053 $ 4,470
Kingdom of Thailand 337,795 334,184 -- 3,611
Other 271 271 -- --
------------ ------------ ------------ ------------
Total $ 2,053,504 $ 2,040,370 $ 5,053 $ 8,081
============ ============ ============ ============
As of December 31, 2000:
United States $ 462,530 $ 454,246 $ 5,315 $ 2,969
Kingdom of Thailand 337,317 334,018 -- 3,299
Canada and other 11,807 11,576 -- 231
------------ ------------ ------------ ------------
Total $ 811,654 $ 799,840 $ 5,315 $ 6,499
============ ============ ============ ============
REVENUES:
For the three months ended September 30, 2001
United States $ 92,135 $ 88,658 $ 1,950 $ 1,527
Kingdom of Thailand 50,568 50,563 -- 5
Canada and other 832 456 -- 376
------------ ------------ ------------ ------------
Total $ 143,535 $ 139,677 $ 1,950 $ 1,908
============ ============ ============ ============
For the three months ended September 30, 2000
United States $ 74,368 $ 71,547 $ 3,017 $ (196)
Kingdom of Thailand 53,170 53,170 -- --
Canada and other 1,544 1,003 -- 541
------------ ------------ ------------ ------------
Total $ 129,082 $ 125,720 $ 3,017 $ 345
============ ============ ============ ============
For the nine months ended September 30, 2001
United States $ 341,225 $ 326,869 $ 10,649 $ 3,707
Kingdom of Thailand 136,639 136,575 -- 64
Canada and other 4,927 4,558 -- 369
------------ ------------ ------------ ------------
Total $ 482,791 $ 468,002 $ 10,649 $ 4,140
============ ============ ============ ============
For the nine months ended September 30, 2000
United States $ 208,768 $ 199,578 $ 9,609 $ (419)
Kingdom of Thailand 125,806 125,720 -- 86
Canada and other 3,446 2,871 -- 575
------------ ------------ ------------ ------------
Total $ 338,020 $ 328,169 $ 9,609 $ 242
============ ============ ============ ============
OPERATING INCOME (LOSS):
For the three months ended September 30, 2001
United States $ 14,741 $ 13,270 $ (56) $ 1,527
Kingdom of Thailand 21,317 21,312 -- 5
Canada and other (1,401) (1,777) -- 376
------------ ------------ ------------ ------------
Total $ 34,657 $ 32,805 $ (56) $ 1,908
============ ============ ============ ============
For the three months ended September 30, 2000
United States $ 21,365 $ 22,286 $ (725) $ (196)
Kingdom of Thailand 30,057 30,057 -- --
Canada and other 689 148 -- 541
------------ ------------ ------------ ------------
Total $ 52,111 $ 52,491 $ (725) $ 345
============ ============ ============ ============
For the nine months ended September 30, 2001
United States $ 114,052 $ 110,531 $ (186) $ 3,707
Kingdom of Thailand 62,091 62,027 -- 64
Canada and other (10,041) (10,410) -- 369
------------ ------------ ------------ ------------
Total $ 166,102 $ 162,148 $ (186) $ 4,140
============ ============ ============ ============
For the nine months ended September 30, 2000
United States $ 53,354 $ 54,838 $ (1,065) $ (419)
Kingdom of Thailand 59,945 59,859 -- 86
Canada and other 122 (453) -- 575
------------ ------------ ------------ ------------
Total $ 113,421 $ 114,244 $ (1,065) $ 242
============ ============ ============ ============
-9-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Unaudited)
(6) EARNINGS PER SHARE -
Earnings per common share (basic earnings per share) are based on the
weighted average number of shares of common stock outstanding during the
periods. Earnings per share and potential common share (diluted earnings per
share) consider the effect of dilutive securities as set out below. Amounts are
expressed in thousands, except per share amounts.
Three Months Ended Nine Months Ended
September 30, 2001 September 30, 2001
---------------------------------------- ----------------------------------------
Income Shares Per Share Income Shares Per Share
---------- ---------- ---------- ---------- ---------- ----------
BASIC EARNINGS PER SHARE - $ 15,603 53,613 $ 0.29 $ 86,528 50,239 $ 1.72
========== ==========
Effect of dilutive securities:
Options to purchase common shares -- 551 -- 787
2006 Notes -- -- 3,083 2,726
Trust Preferred Securities 1,584 6,316 4,753 6,316
---------- ---------- ---------- ----------
DILUTED EARNINGS PER SHARE $ 17,187 60,480 $ 0.28 $ 94,364 60,068 $ 1.57
========== ========== ========== ========== ========== ==========
Antidilutive securities -
Options to purchase common shares -- 1,231 $ 27.08 -- 313 $ 31.00
2006 Notes $ 1,028 2,726 $ 0.38 -- -- --
Three Months Ended Nine Months Ended
September 30, 2000 September 30, 2000
---------------------------------------- ----------------------------------------
Income Shares Per Share Income Shares Per Share
---------- ---------- ---------- ---------- ---------- ----------
BASIC EARNINGS PER SHARE - $ 26,182 40,403 $ 0.65 $ 53,124 40,359 $ 1.32
========== ==========
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 $ 28,794 50,068 $ 0.58 $ 60,960 50,016 $ 1.22
========== ========== ========== ========== ========== ==========
Antidilutive securities -
Options to purchase common shares -- 276 $ 32.75 -- 276 $ 32.75
(a) Represents income before cumulative effect of change in accounting
principle.
(7) RECENT ACCOUNTING PRONOUNCEMENTS -
The Financial Accounting Standards Board has recently issued two new
pronouncements, Statement of Financial Accounting Standards No. 143 ("SFAS
143"), "Accounting for Asset Retirement Obligations" and Statement of Financial
Accounting Standard No. 144, ("SFAS 144"), "Accounting for the Impairment or
Disposal of Long-Lived Assets."
SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the related
asset. If the liability is settled for an amount other than the recorded amount
a gain or loss is recognized. The standard is effective for the Company
beginning in 2003, but earlier adoption is encouraged. Adoption of the standard
will result in recording a cumulative effect of a change in accounting principle
to earnings in the period of adoption. The Company has not yet determined the
impact of this new standard or when the new standard will be adopted.
SFAS 144 addresses the financial accounting and reporting for the
impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121 but
retains its fundamental provisions for the (a) recognition/measurement of
impairment of long-lived assets to be held and used and (b) measurement of
long-lived assets to be disposed of by sale. SFAS 144 also supersedes the
accounting/reporting provisions of APB Opinion No. 30 for segments of a business
to be disposed of but retains the requirement to report discontinued operations
separately from continuing operations and extends that reporting to a component
of an entity that either has been disposed of or is classified as held for sale.
SFAS 144 is effective for the Company beginning in 2002. The Company is
currently evaluating the impact of this new standard.
-10-
POGO PRODUCING COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Unaudited)
(8) ACQUISITION -
On March 14, 2001, the previously announced merger of the Company and
NORIC was consummated. As a result of the merger, the Company acquired all of
the outstanding capital stock of North Central which was the principal asset of
NORIC. North Central was an independent domestic oil and gas exploration and
production company. The merger was accounted for using the purchase method of
accounting. Accordingly, the purchase price was allocated to the net assets
acquired based upon their estimated fair market values at the date of
acquisition. Such allocations are based upon preliminary information and are
subject to change when final valuations are obtained. Commencing March 14, 2001,
North Central's operations are consolidated with the operations of the Company.
Pursuant to the merger agreement among the Company and NORIC and certain NORIC
shareholders dated as of November 19, 2000, former shareholders received
12,615,816 shares of the Company's common stock and approximately $344,711,000
in cash. In addition, at the closing the Company repaid all $78,600,000
principal amount of North Central's existing bank debt. The sources of funds
used in connection with the merger included cash on hand at the Company and
NORIC and borrowings under the Company's new credit agreement.
The following summary presents unaudited pro forma consolidated results
of operations as if the acquisition had occurred at the beginning of each period
presented. The pro forma results are for illustrative purposes only and include
adjustments in addition to the pre-acquisition historical results of North
Central, such as increased depreciation, depletion and amortization expense
resulting from the allocation of fair market value to oil and gas properties
acquired and increased interest expense on acquisition debt. The unaudited pro
forma financial information is not necessarily indicative of the operating
results that would have occurred had the acquisition been consummated at those
dates, nor are they necessarily indicative of future operating results.
Nine Months Ended
September 30,
----------------------------------
2001 2000
------------ ------------
Revenues $ 545,771 $ 436,920
Income before cumulative effect of change in accounting principle $ 102,922 $ 56,594
Net income $ 102,922 $ 54,826
Earnings per share:
Basic -
Income before cumulative effect of change in accounting principle $ 1.92 $ 1.06
Net income $ 1.92 $ 1.03
Diluted -
Income before cumulative effect of change in accounting principle $ 1.75 $ 1.06
Net income $ 1.75 $ 1.02
-11-
POGO PRODUCING COMPANY AND SUBSIDIARIES
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
This discussion should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations
included in the Company's annual report on Form 10-K for the year ended December
31, 2000. Certain statements contained herein are prospective and therefore
should be considered "Forward Looking Statements." As further discussed in the
Company's annual report on Form 10-K for the year ended December 31, 2000, such
forward-looking statements are subject to risks, uncertainties and other factors
that could cause actual results to differ materially from future results
expressed or implied by such forward looking statements.
On March 14, 2001, the previously announced merger of Pogo Producing
Company (the "Company") and NORIC Corporation ("NORIC") was consummated. As a
result of the merger, the Company acquired all of the outstanding capital stock
of North Central Oil Corporation ("North Central"), an independent domestic oil
and gas exploration and production company, which was the principal asset of
NORIC. The merger was accounted for using the purchase method of accounting.
Commencing March 14, 2001, the results of North Central's operations are
consolidated with the Company's. Pursuant to the merger agreement among the
Company, NORIC and certain NORIC shareholders dated as of November 19, 2000,
former shareholders of NORIC received 12,615,816 shares of the Company's common
stock and approximately $344,711,000 in cash. In addition, at the closing the
Company repaid all $78,600,000 principal amount of North Central's existing bank
debt. The sources of funds used in connection with the merger included cash on
hand at the Company and NORIC and borrowings under the Company's credit
agreement.
RESULTS OF OPERATIONS
Net income
The Company reported net income for the third quarter of 2001 of
$15,603,000 or $0.29 per share ($17,187,000 or $0.28 per share on a diluted
basis), compared to net income for the third quarter of 2000 of $26,182,000 or
$0.65 per share ($28,794,000 or $0.58 per share on a diluted basis). The
difference in net income during the third quarter of 2001, compared to the third
quarter of 2000, was primarily related to increased oil and gas revenues
resulting from improved oil and gas production levels that was more than offset
by decreased average prices received by the Company for its natural gas, crude
oil and condensate production and increased depreciation, depletion and
amortization expenses related, in part, to the improved oil and gas production
levels. For the first nine months of 2001, the Company reported net income of
$86,528,000 or $1.72 per share ($94,364,000 or $1.57 per share on a diluted
basis) compared to net income before cumulative effect of change in accounting
principle for the first nine months of 2000 of $53,124,000 or $1.32 per share
($60,960,000 or $1.22 per share on a diluted basis). The increase in net income
during the first nine months of 2001, compared to the first nine months of 2000,
was primarily related to increased oil and gas revenues resulting from improved
oil and gas production levels and increased average prices that the Company
received for its natural gas production, which was partially offset by decreased
average prices the Company received for its oil and condensate production. These
factors were also partially offset in both comparative periods by a decrease in
revenues from the sale of natural gas liquids ("NGL"). The net income reported
in the third quarter and first nine months of 2001 was also positively impacted
by a gain on the sale of certain non-strategic minor properties, including the
sale of its Canadian operations and assets.
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 2001, compared to the third quarter and first nine months
of 2000, resulted primarily from the
-12-
issuance of common stock in connection with the merger with NORIC on March 14,
2001 and, to a lesser extent, the exercise of stock options pursuant to the
Company's incentive plans. Earnings per share computations on a diluted basis
for all periods reflect additional shares of common stock issuable upon the
assumed conversion of Pogo Trust I's 6 1/2% Cumulative Quarterly Income
Convertible Preferred Securities due 2029 (the "Trust Preferred Securities")
and, to a much lesser extent, additional shares of common stock issuable upon
the assumed exercise of options to purchase common shares under the Company's
incentive plans, less treasury shares that are assumed to have been purchased by
the Company from the option proceeds. Earnings per share computations for the
first nine months of 2001, and the third quarter and first nine months of 2000,
also reflect additional shares of common stock issuable upon the assumed
conversion of the Company's 5 1/2% Convertible Subordinated Notes due 2006 (the
"2006 Notes").
Total Revenues
The Company's total revenues for the third quarter of 2001 were
$143,535,000, an increase of approximately 11% from total revenues of
$129,082,000 for the third quarter of 2000. The Company's total revenues for the
first nine months of 2001 were $482,791,000, an increase of approximately 43%
compared to total revenues of $338,020,000 for the first nine months of 2000.
The increase in the Company's total revenues for the third quarter and first
nine months of 2001, compared to the third quarter and first nine months of
2000, resulted primarily from a substantial increase in oil and gas revenues
and, to a much lesser extent, a gain on sales of certain non-strategic minor
properties.
Oil and Gas Revenues
The Company's oil and gas revenues for the third quarter of 2001 were
$139,677,000, an increase of approximately 11% from oil and gas revenues of
$125,720,000 for the third quarter of 2000. The Company's oil and gas revenues
for the first nine months of 2001 were $468,002,000, an increase of
approximately 43% from oil and gas revenues of $328,169,000 for the first nine
months of 2000. The following table reflects an analysis of variances in the
Company's oil and gas revenues (expressed in thousands) between 2001 and 2000:
Increase (decrease) in oil and gas revenues 3RD QTR 2001 NINE MO. 2001
resulting from variances in: COMPARED TO COMPARED TO
3RD QTR 2000 NINE MO. 2000
------------ -------------
NATURAL GAS --
Price ................................................. $ (4,479) $ 55,945
Production ............................................ 22,581 73,250
------------ ------------
18,102 129,195
------------ ------------
CRUDE OIL AND CONDENSATE --
Price ................................................. (13,477) (14,533)
Production ............................................ 9,846 27,750
------------ ------------
(3,631) 13,217
------------ ------------
NATURAL GAS LIQUIDS ...................................... (514) (2,579)
------------ ------------
Increase (decrease) in oil and gas revenues ........... $ 13,957 $ 139,833
============ ============
The increase in the Company's oil and gas revenues for the third
quarter of 2001, compared to the third quarter of 2000, is primarily related to
increases in the Company's natural gas and oil and condensate production
volumes, that was only partially offset by a decrease in the average price that
it received for its oil and condensate and natural gas production volumes and
decreased revenues from its NGL production. The increase in the Company's oil
and gas revenues for the first nine months of 2001, compared to the first nine
months of 2000, is primarily related to increases in the Company's natural gas
and oil and condensate production volumes and an increase in the average price
that the Company received for its natural gas production volumes, that was only
partially offset by a decrease in the average price that it received for its oil
and condensate production volumes and decreased revenues from its NGL
production. Due to the relatively high price (relative to crude oil and
condensate) that the Company received for its natural gas production volumes
during the third quarter and first nine months of 2001, the Company elected in
many instances to leave the NGL in the natural gas. The Company has increased
the incidence of processing its natural gas production volumes to extract NGL
for resale due to the decline in natural gas prices, relative to oil and
condensate prices.
-13-
Comparison of Increases (Decreases) in: 3RD QUARTER 1ST NINE MONTHS
NATURAL GAS -- ------------------- % ------------------- %
2001 2000 CHANGE 2001 2000 CHANGE
-------- -------- -------- -------- -------- --------
Average prices
North America(a) ................................ $ 2.99 $ 3.62 (17)% $ 4.61 $ 3.11 48%
Kingdom of Thailand(b) .......................... $ 2.28 $ 2.23 2% $ 2.31 $ 2.13 8%
Company-wide average price ................. $ 2.81 $ 3.11 (10)% $ 4.00 $ 2.77 44%
Average daily production volumes (MMcf per day)
North America(a) ................................ 183.3 100.9 82% 171.4 108.8 58%
Kingdom of Thailand ............................. 63.2 58.2 9% 62.3 57.2 9%
-------- -------- -------- --------
Company-wide average daily production ...... 246.5 159.1 55% 233.7 166.0 41%
======== ======== ======== ========
----------
(a) North American average prices and production reflect
production from the United States and Canada, prior to the
sale of the Company's Canadian operations in the third quarter
of 2001. "MMcf" and "Bbls" stand for million cubic feet and
barrels, respectively.
(b) The Company is paid for its natural gas production in the
Kingdom of Thailand in Thai Baht. The average prices are
presented in U.S. dollars based on the revenue recorded in the
Company's financial records.
Comparison of Increases (Decreases) in: 3RD QUARTER 1ST NINE MONTHS
CRUDE OIL AND CONDENSATE -- ------------------- % ------------------- %
2001 2000 CHANGE 2001 2000 CHANGE
-------- -------- -------- -------- -------- --------
Average prices(a)
North America ................................... $ 25.51 $ 29.90 (15)% $ 26.40 $ 28.96 (9)%
Kingdom of Thailand ............................. $ 24.85 $ 31.81 (22)% $ 25.76 $ 27.53 (6)%
Company-wide average price ..................... $ 25.17 $ 30.90 (19)% $ 26.09 $ 28.25 (8)%
Average daily production volumes (Bbls per day)
North America ................................... 15,009 12,698 18% 14,815 12,413 19%
Kingdom of Thailand(b) .......................... 15,283 14,087 8% 14,220 12,234 16%
-------- -------- -------- --------
Company-wide average daily production .......... 30,292 26,785 13% 29,035 24,647 18%
======== ======== ======== ========
TOTAL LIQUID HYDROCARBONS --
Company-wide average daily
production (Bbls per day)(b) .................. 32,824 29,056 13% 30,812 27,615 12%
======== ======== ======== ========
----------
(a) Average prices are computed on production that is actually
sold during the period. For North American average prices,
this equates to actual production. However, in the Gulf of
Thailand, crude oil and condensate sold may be more or less
than actual production. See footnote (b).
(b) Oil and condensate production in the Gulf of Thailand is
produced and stored on the FPSO and FSO pending sale and is
sold in tanker loads that typically average between 300,000
and 750,000 barrels per sale. Therefore, oil and condensate
sales volumes for a given period in the Gulf of Thailand may
not equate to actual production. In accordance with generally
accepted accounting principles, as currently interpreted,
reported revenues are based on sales volumes. However, the
Company believes that actual production volumes are a more
meaningful measure of the Company's operating results and
therefore reports production volumes as part of its operating
results. The Company produced 94,000 barrels of oil and
condensate less than it sold in the third quarter of 2001;
110,000 barrels more than it sold in the first nine months of
2001; and 26,000 and 223,000 barrels more than it sold in the
third quarter and first nine months of 2000, respectively.
Natural Gas
Thailand Prices. The price that the Company receives under the gas
sales agreement with the PTT Public Company Limited ("PTT") is based upon a
formula that takes into account a number of factors including, among other
items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore.
The increase in the average price that the Company received for its natural gas
production in the Kingdom of Thailand for the third quarter and first nine
months of 2001, compared to the third quarter and first nine months of 2000,
reflects positive adjustments under the gas sales agreement.
Production. The increase in the Company's natural gas production during
the third quarter and first nine months of 2001, compared to the third quarter
and first nine months of 2000, was primarily related to production from
properties
-14-
acquired in the North Central acquisition and, to a lesser extent, successful
development programs on the Company's Thailand and New Mexico properties that
were partially offset by natural production decline. The Company and its joint
venture partners in Thailand recently reached a preliminary agreement with PTT
to sell PTT up to an additional approximately 58 billion cubic feet of gas over
the next two and a half years at production rates which vary, depending upon the
time period, from 26 up to 85 Mcf per day (12Mcf to 40Mcf net to the Company).
The additional gas volumes under this new agreement will be sold at prices that
are 12% less than the prices the Company receives under its existing gas sales
agreement.
Crude Oil and Condensate
Thailand Prices. Since the inception of production from the Company's
properties located in the Gulf of Thailand, crude oil and condensate have been
stored on storage vessels (an FPSO in the Tantawan field and an FSO in the
Benchamas field) until an economic quantity is accumulated for offloading and
sale. A typical sale ranges from 300,000 to 750,000 barrels. Prices that the
Company receives for its crude oil and condensate production from Thailand are
based on world benchmark prices, typically as a differential to Malaysian TAPIS
crude and are denominated in U.S. dollars. In addition, the Company is generally
paid for its crude oil and condensate production from Thailand in U.S. dollars.
Thailand 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 2001, compared to the third quarter and first nine months
of 2000, largely resulted from increased production from the Benchamas Field.
Due to a change in interpretation of an accounting principle, for purposes of
the financial statements, the Company now records its oil production in Thailand
at the time of sale rather than when produced, as it had previously done. In
accordance with generally accepted accounting principles as currently
interpreted, at the end of each quarter, the crude oil and condensate stored on
board the FSO and FPSO pending sale is accounted for as inventory at cost and
included on the Company's balance sheet as "Inventory - product." Reported
revenues are based on sales volumes. When a tanker load of oil is sold in
Thailand, the entire amount will be accounted for as production sold, regardless
of when it was produced. The Company believes that actual production volumes are
a more meaningful measure of the Company's operating results than sales volumes
and therefore reports production volumes as part of its operating results. The
Company produced 94,000 barrels of oil and condensate less than it sold in the
third quarter of 2001, 110,000 barrels more than it sold in the first nine
months of 2001, and 26,000 and 223,000 barrels more than it sold in the third
quarter and first nine months of 2000, respectively. As of September 30, 2001,
the Company had approximately 460,000 net cumulative barrels stored on board the
FPSO and FSO.
North American Production. The increase in the Company's North American
crude oil and condensate production during the third quarter and first nine
months of 2001, compared to the third quarter and first nine months of 2000,
primarily related to production from properties acquired in the North Central
acquisition and, to a lesser extent, successful development programs on the
Company's other properties that was partially offset by natural production
decline.
NGL Production. The Company's oil and gas revenues, and its total
liquid hydrocarbon production, reflect the production and sale by the Company of
NGL, which are liquid products extracted from natural gas production. The
decrease in NGL revenues for the third quarter of 2001, compared with the third
quarter of 2000, related to a decline in the average price that the Company
received for its NGL production volumes, which was only partially offset by an
increase in the volume of NGL produced by the Company. The decrease in NGL
revenues for the first nine months of 2001, compared with the first nine months
of 2000, primarily related to the decision by the Company not to extract NGL
from its natural gas production due to the more favorable economics of leaving
it in the natural gas stream and, to a lesser extent, a decline in the average
price that the Company received for its NGL production volumes. The Company has
resumed processing a higher percentage of its natural gas production volumes,
where possible or practicable, to extract NGL for resale due to the recent
decline in natural gas prices, relative to oil and condensate prices.
-15-
Costs and Expenses
3RD QUARTER
Comparison of Increases (Decreases) in: ------------------------------ %
2001 2000 CHANGE
------------- -------------
LEASE OPERATING EXPENSES
North America ................................. $ 21,163,000 $ 15,092,000 40%
Kingdom of Thailand ........................... $ 10,776,000 $ 8,791,000 23%
Total Lease Operating Expenses .......... $ 31,939,000 $ 23,883,000 34%
PIPELINE OPERATING AND NATURAL
GAS PURCHASES .................................. $ 1,838,000 $ 3,576,000 (49)%
GENERAL AND ADMINISTRATIVE EXPENSES .............. $ 11,281,000 $ 8,605,000 31%
EXPLORATION EXPENSES ............................. $ 5,013,000 $ 2,694,000 86%
DRY HOLE AND IMPAIRMENT EXPENSES ................. $ 3,053,000 $ 6,570,000 (54)%
DEPRECIATION, DEPLETION AND
AMORTIZATION (DD&A) EXPENSES .................. $ 55,754,000 $ 31,643,000 76%
DD&A rate ..................................... $ 1.33 $ 1.02 30%
Mcfe sold(a) .................................. 41,363,000 30,521,000 35%
INTEREST--
Charges ....................................... $ (15,119,000) $ (8,504,000) 78%
Interest Income ............................... $ 690,000 $ 774,000 (11)%
Capitalized Interest Expense .................. $ 9,324,000 $ 5,546,000 68%
MINORITY INTEREST - DIVIDENDS AND COSTS .......... $ (2,501,000) $ (2,351,000) 6%
FOREIGN CURRENCY TRANSACTION GAIN(LOSS) .......... $ 338,000 $ (930,000) N/A
INCOME TAX EXPENSE ............................... $ (11,786,000) $ (20,464,000) (42)%
1ST NINE MONTHS
Comparison of Increases (Decreases) in: ------------------------------ %
2001 2000 CHANGE
------------- -------------
LEASE OPERATING EXPENSES
North America ................................. $ 60,934,000 $ 44,335,000 37%
Kingdom of Thailand ........................... $ 26,528,000 $ 24,804,000 7%
Total Lease Operating Expenses .......... $ 87,462,000 $ 69,139,000 27%
PIPELINE OPERATING AND NATURAL
GAS PURCHASES .................................. $ 10,258,000 $ 10,122,000 1%
GENERAL AND ADMINISTRATIVE EXPENSES .............. $ 29,139,000 $ 26,567,000 10%
EXPLORATION EXPENSES ............................. $ 17,447,000 $ 8,481,000 106%
DRY HOLE AND IMPAIRMENT EXPENSES ................. $ 26,097,000 $ 13,762,000 90%
DEPRECIATION, DEPLETION AND
AMORTIZATION (DD&A) EXPENSES .................. $ 146,286,000 $ 96,528,000 52%
DD&A rate ..................................... $ 1.27 $ 1.06 20%
Mcfe sold(a) .................................. 113,604,000 89,547,000 27%
INTEREST--
Charges ....................................... $ (41,411,000) $ (25,460,000) 63%
Interest Income ............................... $ 2,686,000 $ 1,253,000 114%
Capitalized Interest Expense .................. $ 24,153,000 $ 15,160,000 59%
MINORITY INTEREST - DIVIDENDS AND COSTS .......... $ (7,499,000) $ (7,468,000) 0%
FOREIGN CURRENCY TRANSACTION GAIN(LOSS) .......... $ (668,000) $ (2,051,000) (67)%
INCOME TAX EXPENSE ............................... $ (56,835,000) $ (41,731,000) 36%
----------
(a) "Mcfe" stands for thousands of cubic feet equivalent.
Lease Operating Expenses.
The increase in North American lease operating expenses for the third
quarter and first nine months of 2001, compared to the third quarter and first
nine months of 2000, primarily related to increased severance taxes resulting
from increased production from the Company's non-U.S. government owned
properties (accounting for approximately $1,762,000 and $10,272,000 of the
increase for the quarter and nine-month periods, respectively), lease operating
expenses attributable to properties acquired in the North Central acquisition
and generally increasing costs resulting from an industry-wide increase in
demand for oil field services and equipment, that was only partially offset by
decreased lease maintenance expenses. The increase in lease operating expenses
in the Kingdom of Thailand for the third quarter and first nine months of 2001,
compared to the third quarter and first nine months of 2000, primarily related
to increased expenses related to well workovers and increased insurance expenses
related to construction of platforms for the Benchamas field, as well as
generally increasing costs resulting from an industry-wide increase in demand
for oil field services and equipment. A substantial portion of the Company's
lease operating expenses in the Kingdom of Thailand relates to the lease
payments made in connection with the bareboat charter of the FPSO for the
Tantawan field and the FSO for the Benchamas field. Collectively, these lease
payments accounted for $3,666,000, $10,873,000, $3,798,000 and $11,311,000 (net
to the Company's interest) of the Company's Thailand lease operating expenses
for the third quarter and first nine months of 2001 and the third quarter and
first nine months of 2000, respectively.
Pipeline Operating and Natural Gas Purchases
Revenue from the sale of natural gas purchased for resale is reported
under "Pipeline sales and other." The decrease in pipeline operating expenses
and natural gas purchase costs for the third quarter of 2001, compared to the
third quarter of 2000, primarily related to the decreased cost of natural gas
purchased for resale by the Company. The increase in pipeline operating expenses
and natural gas purchase costs for the first nine months of 2001, compared to
the first nine months of 2000, primarily related to increased cost of natural
gas purchased for resale by the Company.
-16-
General and Administrative Expenses
The increase in general and administrative expenses for the third
quarter and first nine months of 2001, compared with the third quarter and first
nine months of 2000, related to increased expenses associated with the Company's
acquisition of North Central and its employees, as well as an increase in the
size of the Company's work force and normal salary and concomitant benefit
expense adjustments.
Exploration Expenses
Exploration expenses consist primarily of rental payments required
under oil and gas leases to hold non- producing properties ("delay rentals") and
exploratory geological and geophysical costs that are expensed as incurred. The
increase in exploration expense for the third quarter of 2001, compared to the
third quarter of 2000, resulted primarily from the cost of acquisition of 3-D
data in the Company's Offshore and Western divisions, a payment to transfer
seismic licenses used by North Central and the payment of a reservation fee in
Thailand, which was partially offset by generally decreased geophysical
acquisition costs in the Company's Hungary exploration play. The increase in
exploration expense for the first nine months of 2001, compared to the first
nine months of 2000, resulted primarily from the cost of conducting two major
3-D projects in Hungary and a payment to transfer seismic licenses used by North
Central.
Dry Hole and Impairment
The decrease in the Company's dry hole and impairment expense for the
third quarter of 2001, compared to the third quarter of 2000, resulted primarily
from the success of the Company's drilling program. The increase in the
Company's dry hole and impairment expense for the first nine months of 2001,
compared to the first nine months of 2000, resulted primarily from a
non-operated property located in the offshore Gulf of Mexico that incurred
unexpectedly high drilling and completion expenses. Accounting rules also
require that if the expected future cash flow of the Company's reserves on a
property fall below the cost that is recorded on the Company's books, these
reserves must be impaired and written down to the property's fair value. No such
impairments are currently required on the Company's properties. Depending on
market conditions, including the prices for oil and natural gas, and the results
of operations, a similar test may be conducted at any time to determine whether
impairments are appropriate. Depending on the results of this test, an
impairment could be required on some of the Company's properties and this
impairment could have a material negative non-cash impact on the Company's
earnings and balance sheet.
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 2001, compared
to the third quarter and first nine months of 2000, 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 increase in the composite DD&A rate for all of the Company's
producing fields for the third quarter and first nine months of 2001, compared
to the third quarter and first nine months of 2000, resulted primarily from
production from fields acquired in the North Central acquisition that, because
they were valued at fair market value in connection with the acquisition,
contribute a DD&A rate higher than the Company's recent historic average. The
increase was partially offset by 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 and first nine months of 2001, compared to the third quarter
and first nine months of 2000, resulted primarily from an increase in the
average
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amount of the Company's outstanding debt related to the acquisition of North
Central, partially offset by a decline in the average interest rate on the
outstanding debt. The increase in the Company's interest charges for the first
nine months of 2001, compared to the first nine months of 2000, was also
affected by a charge for amortization of debt issuance expense during the first
quarter of 2001 related to the termination of the Company's previous credit
facility in connection with the North Central acquisition.
Interest Income. The decrease in the Company's interest income for the
third quarter of 2001, compared to the third quarter of 2000, resulted primarily
from a decrease in the amount of cash and cash equivalents temporarily invested.
The increase in the Company's interest income for the first nine months of 2001,
compared to the first nine months of 2000, resulted primarily from an increase
in the amount of cash and cash equivalents temporarily invested.
Capitalized Interest. The increase in capitalized interest for the
third quarter and first nine months of 2001, compared to the third quarter and
first nine months of 2000, resulted primarily from an increase in the amount of
capital expenditures subject to interest capitalization during the relevant
periods ($406,624,000 and $345,967,000 in 2001, compared to $236,895,000 and
$239,844,000 in 2000), partially offset by a decrease in the interest rate used
to determine the amount of capitalized interest. A substantial percentage of the
Company's capitalized interest expense related to unevaluated properties
acquired in the North Central acquisition and capital expenditures for the
development of the Benchamas field in the Gulf of Thailand and 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. The amounts recorded for the third quarter and first nine months
of 2000 and 2001, respectively, under Minority Interest -- Dividends and Costs
Associated with Preferred Securities of a Subsidiary Trust principally reflect
cumulative unpaid 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 reported in the third quarter of
2001, and the losses reported for the third quarter of 2000 and first nine
months of 2000 and 2001 resulted primarily from the fluctuation against the U.S.
dollar of cash and other monetary assets and liabilities denominated in Thai
Baht that were on the Company's subsidiary financial statements during the
respective periods. The Company cannot predict what the Thai Baht to U.S. dollar
exchange rate will be in the future. As of September 30, 2001, the Company was
not a party to any financial instrument that was intended to constitute a
foreign currency hedging arrangement.
Income Tax Expense
Changes in the Company's income tax expense are a function of the
Company's consolidated effective tax rate and its pre-tax income. The decrease
in the Company's tax expense for the third quarter of 2001, compared to the
third quarter of 2000, resulted primarily from a decrease in pre-tax income. The
increase in the Company's tax expense for the first nine months of 2001,
compared to the first nine months of 2000, resulted primarily from an increase
in pre-tax income. The Company's consolidated effective tax rate for the third
quarter and first nine months of 2001 was 43% and 39.6%, respectively, compared
to 43.9% and 44% for the third quarter and first nine months of 2000,
respectively. The Company conducts its operations in taxing jurisdictions with
varying tax rates. The relative proportion of the Company's income earned in
each taxing jurisdiction affects the Company's consolidated effective tax rate.
Additionally, during the third quarter of 2001, the Company reevaluated certain
estimates regarding its global tax and cash position and, as a result,
recognized certain additional tax benefits attributable to previously
unrecognized operating loss carryforwards and provided for U.S. income taxes on
certain unremitted foreign earnings.
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LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The Company's Condensed Consolidated Statement of Cash Flows for the
first nine months of 2001 reflects net cash provided by operating activities of
$301,421,000. In addition to net cash provided by operating activities, the
Company received $12,631,000 from the sale of its Canadian operations and
assets, $7,370,000 from the sale of certain non-strategic assets and $6,699,000
primarily from the exercise of stock options. The Company also borrowed a net
$191,992,000 under its senior debt arrangements and issued $200,000,000 of its
8 1/4% Senior Subordinated Notes due 2011 (the "2011 Notes").
During the first nine months of 2001, the Company expended $344,711,000
in partial consideration for the NORIC shares, repaid all $78,600,000 of North
Central's senior indebtedness, invested $280,819,000 in capital projects, paid
$8,720,000 in debt issuance expenses, paid $7,312,000 in cash distributions to
holders of its Trust Preferred Securities, paid $2,714,000 to purchase proved
reserves and paid $4,438,000 ($0.09 per share) in cash dividends to holders of
the Company's common stock. As of October 22, 2001, the Company's cash and cash
equivalents were $100,722,000 and its long-term debt stood at $782,000,000 and
it had $208,000,000 of availability under its revolving credit facility.
Future Capital Requirements
The Company's capital and exploration budget for 2001, which does not
include any amounts that may be expended for the purchase of proved reserves or
any interest that may be capitalized resulting from projects in progress, was
recently increased by the Company's Board of Directors to $385,000,000. The
Company currently anticipates that its available cash and cash equivalents, cash
provided by operating activities and funds available under its credit agreement
and banker's acceptance facility will be sufficient to fund the Company's
ongoing operating, interest and general and administrative expenses, any
currently anticipated costs associated with the Company's projects during 2001,
and future dividend and distribution payments at current levels (including a
dividend payment of $0.03 per share on its common stock to be paid on November
16, 2001 to shareholders of record on November 2, 2001). The declaration of
future dividends on the Company's equity securities will depend upon, among
other things, the Company's future earnings and financial condition, liquidity
and capital requirements, its ability to pay dividends and distributions under
certain covenants contained in its debt instruments, the general economic and
regulatory climate and other factors deemed relevant by the Company's Board of
Directors.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
The Company is exposed to market risk, including adverse changes in
commodity prices, interest rates and foreign currency exchange rates. The
information contained in the Company's annual report on Form 10-K for the year
ended December 31, 2000, is incorporated by reference herein and should be read
in conjunction with the following.
INTEREST RATE RISK
From time to time, the Company has entered into various financial
instruments, such as interest rate swaps, to manage the impact of changes in
interest rates. As of October 1, 2001, the Company has no open interest rate
swap or interest rate lock agreements. Therefore, the Company's exposure to
changes in interest rates primarily results from its short-term and long-term
debt with both fixed and floating interest rates. The following table presents
principal or notional amounts (stated in thousands) and related average interest
rates by year of maturity for the Company's debt obligations and their indicated
fair market value at September 30, 2001:
FAIR
2001 2002 2003 2004 2005 THEREAFTER TOTAL VALUE
-------- -------- -------- -------- -------- ------------ ------------ --------
Liabilities Long-Term Debt:
Variable Rate ............. $ 0 $ 0 $ 0 $ 0 $ 0 $ 191,992 $ 191,992 $191,992
Average Interest Rate ..... -- -- -- -- -- 4.66% 4.66% --
Fixed Rate ................ $ 0 $ 0 $ 0 $ 0 $ 0 $ 565,000 $ 565,000 $556,704
Average Interest Rate ..... -- -- -- -- -- 8.35% 8.35% --
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FOREIGN CURRENCY EXCHANGE RATE RISK
In addition to U.S. dollars, the Company conducts business in Thai Baht
and Hungarian Forints, and is therefore subject to foreign currency exchange
rate risk on cash flows related to sales, expenses, financing and investing
transactions. As of October 1, 2001, the Company is not a party to any foreign
currency exchange agreement.
CURRENT HEDGING ACTIVITY
From time to time, the Company has used and expects to continue to use
hedging transactions with respect to a portion of its oil and gas production to
achieve a more predictable cash flow, as well as to reduce its exposure to price
fluctuations. While the use of these hedging arrangements limits the downside
risk of adverse price movements, they may also limit future revenues from
favorable price movements. The use of hedging transactions also involves the
risk that the counter-parties will be unable to meet the financial terms of such
transactions. All of the Company's recent historical hedging transactions have
been carried out in the over-the-counter market with investment grade
institutions. In January 2001, the Company began to account for its hedging
activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities ("SFAS 133"). SFAS 133, as amended, establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair market value.
The statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows the effective portion of the gain or
loss on a derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period during which the hedged forecasted
transaction affects earnings. The remaining gain or loss on the derivative
instruments, if any, must be recognized currently in earnings.
Natural Gas
As of September 30, 2001, the Company held options to sell 70 million
cubic feet of natural gas production per day for the period from October 1, 2001
through December 31, 2002. The Company has designated these contracts as cash
flow hedges designed to give the Company the right, but not the obligation, to
sell natural gas at a sales price of $4.25 per MMBtu for the period from October
2001 through March 2002 and $4.00 per MMBtu for the period from April 2002
through December 2002. These contracts are designed to guarantee a minimum
"floor" price for the contracted volumes of production without limiting the
Company's participation in price increases during the covered period. As of
September 30, 2001, the Company was a party to the following hedging
arrangements:
NYMEX
CONTRACT
VOLUME PRICE PER FAIR MARKET
CONTRACT PERIOD IN MMBtu(a) MMBtu(a) VALUE(b)
----------------------------- ------------ ------------ ------------
Floor Contracts:
October 2001 -- March 2002 12,740 $ 4.25 $ 22,082,000
April 2002 - December 2002 19,250 $ 4.00 $ 25,620,000
----------
(a) MMBtu means million British Thermal Units.
(b) Fair Market Value is calculated using prices derived from
NYMEX futures contract prices existing at September 30, 2001.
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or,
occasionally, the penultimate trading day of a particular contract month. For
any particular floor transaction, the counter-party is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction. The Company is not required to make
any payment in connection with the settlement of a floor transaction.
Crude Oil
As of September 30, 2001, the Company was not a party to any commodity
price hedging contracts with respect to any of its current or future crude oil
and condensate production.
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PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(A) Exhibits
None.
(B) Reports on Form 8-K
Report filed on August 10, 2001, providing the Company's
Unaudited Condensed Consolidated Statement of Income for the Six
Months ended June 30, 2001 and related notes, giving effect to the
merger of NORIC Corporation, the parent company of North Central Oil
Corporation, with and into the Company on Item 5., and attaching an
exhibit under Item 7.
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 24, 2001
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