UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] Quarterly report pursuant to section 13 or 15[d] of the Securities Exchange
Act of 1934
For the quarterly period ended March 31, 2001 or
[__] Transition report pursuant to section 13 or 15[d] of the Securities
Exchange Act of 1934 For the transition period from........to.......
Commission file number 1-7792
Pogo Producing Company
[Exact Name of Registrant as Specified in Its Charter]
Delaware 74-1659398
[State of Other Jurisdiction of [I.R.S. Employer
Incorporation or Organization] Identification No.]
5 Greenway Plaza, Suite 2700
Houston, Texas 77046-0504
[Address or principal executive offices] [Zip Code]
[713] 297-5000
--------------------------------------------------------------------------------
Registrant's Telephone Number, Including Area Code]
Not Applicable
--------------------------------------------------------------------------------
[Former Name, Former Address and Former Fiscal Year, if Changed Since Last
Report]
Indicate by check mark whether the registrant: [1] has filed all reports
required to be filed by Section 13 or 15[d] of the Securities Exchange Act
of 1934 during the preceding 12 months [or for such shorter period that the
registrant was required to file such reports], and [2] has been subject to
such filing requirement for the past 90 days: Yes X No...
Registrant's number of common shares outstanding as of March 31, 2001:
53,568,661
Part I. Financial Information
Pogo Producing Company and Subsidiaries
Consolidated Statements of Income (Unaudited)
Three Months Ended
March 31,
--------------------------------------
2001 2000
----------------- -----------------
(Expressed in thousands,
except per share amounts)
Revenues:
Oil and gas $ 163,913 $ 97,896
Pipeline sales and other 3,277 3,027
Gains (losses) on sales 2,672 (5)
----------------- -----------------
Total 169,862 100,918
----------------- -----------------
Operating Costs and Expenses:
Lease operating 25,827 21,645
Pipeline operating and natural gas purchases 4,020 3,390
General and administrative 8,208 10,517
Exploration 6,948 3,673
Dry hole and impairment 10,767 5,072
Depreciation, depletion and amortization 37,068 32,046
----------------- -----------------
Total 92,838 76,343
----------------- -----------------
Operating Income 77,024 24,575
----------------- -----------------
Interest:
Charges (11,304) (8,746)
Income 1,302 293
Capitalized 4,526 5,010
Minority Interest - Dividends and costs associated
with preferred securities of a subsidiary trust (2,497) (2,558)
Foreign Currency Transaction Loss (585) (327)
----------------- -----------------
Income Before Taxes and Cumulative
Effect of Change in Accounting Principle 68,466 18,247
Income Tax Expense (28,520) (8,096)
----------------- -----------------
Income Before Cumulative
Effect of Change in Accounting Principle 39,946 10,151
Cumulative Effect of Change in Accounting Principle - (1,768)
----------------- -----------------
Net income $ 39,946 $ 8,383
================= =================
Earnings Per Common Share
Basic
Income before cumulative effect of change in accounting principle $ 0.93 $ 0.25
Cumulative effect of change in accounting principle - (0.04)
----------------- -----------------
Net income $ 0.93 $ 0.21
================= =================
Diluted
Income before cumulative effect of change in accounting principle $ 0.80 $ 0.25
Cumulative effect of change in accounting principle - (0.04)
----------------- -----------------
Net income $ 0.80 $ 0.21
================= =================
Dividends Per Common Share $ 0.03 $ 0.03
================= =================
Weighted Average Number of Common Shares
and Potential Common Shares Outstanding:
Basic 43,145 40,291
Diluted 53,122 47,200
See accompanying notes to consolidated financial statements.
1
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
March 31, December 31,
2001 2000
---------------------- ---------------------
(Unaudited)
(Expressed in thousands
except share amounts)
Assets
Current Assets:
Cash and cash equivalents $ 64,396 $ 81,510
Accounts receivable 94,971 84,381
Other receivables 34,162 27,242
Federal income tax receivable 4,301 --
Inventory - Product 3,201 3,054
Inventories - Tubulars 8,237 8,056
Price hedge contracts 5,981 9,153
Other 822 1,276
----------- -----------
Total current assets 216,071 214,672
----------- -----------
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties being amortized 2,697,461 1,698,404
Unevaluated properties and properties
under development, not being amortized 359,404 154,914
Pipelines, at cost 6,524 7,095
Other, at cost 17,148 15,257
----------- -----------
3,080,537 1,875,670
----------- -----------
Accumulated depreciation, depletion and amortization
Oil and gas (1,090,258) (1,053,478)
Pipelines (1,343) (1,780)
Other (9,146) (8,758)
----------- -----------
(1,100,747) (1,064,016)
----------- -----------
Property and equipment, net 1,979,790 811,654
----------- -----------
Other Assets:
Price hedge contracts 12,309 14,869
Debt issue expenses 13,151 10,718
Foreign value added taxes receivable 8,575 7,262
Deferred income tax 5,028 3,695
Other 20,370 20,652
----------- -----------
59,433 57,196
----------- -----------
$ 2,255,294 $ 1,083,522
=========== ===========
See accompanying notes to consolidated financial statements.
2
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
March 31, December 31,
2001 2000
------------- -------------
(Unaudited)
(Expressed in thousands
except share amounts)
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable - operating activities $ 77,757 $ 27,334
Accounts payable - investing activities 61,976 67,703
Accrued interest payable 8,300 7,443
Accrued dividends associated with
preferred securities of a subsidiary trust 813 813
Accrued payroll and related benefits 2,646 2,285
Other 1,035 851
----------- -----------
Total current liabilities 152,527 106,429
----------- -----------
Long-Term Debt 696,000 365,000
Deferred Income Tax 481,733 95,453
Deferred Credits 14,664 13,456
----------- -----------
Total liabilities 1,344,924 580,338
----------- -----------
Minority Interest:
Company-obligated mandatorily redeemable
convertible preferred securities of a subsidiary trust,
net of unamortized issue expenses 144,943 144,913
----------- -----------
Shareholders' Equity:
Preferred stock, $1 par; 2,000,000 shares authorized -- --
Common stock, $1 par; 100,000,000 shares authorized,
53,584,236 and 40,659,591 shares issued, respectively 53,585 40,660
Additional capital 657,042 298,885
Retained earnings 58,835 20,112
Accumulated other comprehensive loss (3,711) (1,062)
Treasury stock (15,575 shares), at cost (324) (324)
----------- -----------
Total shareholders' equity 765,427 358,271
----------- -----------
$ 2,255,294 $ 1,083,522
=========== ===========
See accompanying notes to consolidated financial statements.
3
Pogo Producing Company and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended
March 31,
-------------------------------------------
2001 2000
--------- --------
(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers $ 182,097 $ 93,158
Operating, exploration, and general
and administrative expenses paid (34,531) (32,647)
Interest paid (8,326) (8,665)
Federal income taxes paid (6,500) --
Value added taxes paid (1,313) (131)
Other 3,621 1,106
--------- ---------
Net cash provided by operating activities 135,048 52,821
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures (80,150) (35,596)
Acquisition of NORIC, net of $21,235 cash acquired (323,476) --
Proceeds from the sale of properties 2,748 (5)
--------- ---------
Net cash used in investing activities (400,878) (35,601)
--------- ---------
Cash Flows from Financing Activities:
Borrowings under senior debt agreements 668,000 51,000
Payments under senior debt agreements (337,000) (51,000)
Payment of North Central senior debt acquired (78,600) --
Payments of cash dividends on common stock (1,223) (1,209)
Payments of preferred dividends of a subsidiary trust (2,438) (2,513)
Payment of financing issue expenses (4,583) (12)
Proceeds from exercise of stock options and other 5,330 1,616
--------- ---------
Net cash used by financing activities 249,486 (2,118)
--------- ---------
Effect of Exchange Rate Changes on Cash (770) (15)
--------- ---------
Net Increase in Cash and Cash Equivalents (17,114) 15,087
Cash and Cash Equivalents at the Beginning of the Year 81,510 6,267
--------- ---------
Cash and Cash Equivalents at the End of the Period $ 64,396 $ 21,354
========= =========
Reconciliation of Net Income to Net
Cash Provided by Operating Activities:
Net income $ 39,946 $ 8,383
Adjustments to reconcile net income to
net cash provided by operating activities -
Cumulative effect of change in accounting principle -- 1,768
Minority interest 2,497 2,558
Foreign currency transaction losses 585 327
(Gains) losses from the sales of properties (2,672) 5
Depreciation, depletion and amortization 37,068 32,046
Dry hole and impairment 10,767 5,072
Interest capitalized (4,526) (5,010)
Price hedge contracts 720 --
Deferred federal income taxes 20,622 8,095
Change in operating assets and liabilities 30,041 (423)
--------- ---------
Net Cash Provided by Operating Activities $ 135,048 $ 52,821
========= =========
See accompanying notes to consolidated financial statements.
4
Pogo Producing Company and Subsidiaries
Consolidated Statements of Shareholders' Equity (Unaudited)
For the Three Months Ended March 31,
----------------------------------------------------------------------------
2001 2000
---------------------------------- -----------------------------------
Shareholders' Shareholders'
Equity Compre- Equity Compre-
--------------------- hensive --------------------- hensive
Shares Amount Income Shares Amount Income
------ ------ ------- ------ ------ -------
(Expressed in thousands, except share amounts)
Common Stock:
$1.00 par-100,000,000 shares authorized
Balance at beginning of year 40,659,591 $ 40,660 40,279,661 $ 40,279
Shares issued for acquisition of NORIC 12,615,816 12,616 -- --
Stock options exercised 308,829 309 103,264 103
------------ ------------ ------------ ----------
Issued at end of period 53,584,236 53,585 40,382,925 40,382
------------ ------------ ------------ ----------
Additional Capital:
Balance at beginning of year 298,885 291,909
Shares issued for acquisition of NORIC 351,729 --
Stock options exercised 6,428 1,893
------------ ----------
Balance at end of period 657,042 293,802
------------ ----------
Retained Earnings (Deficit):
Balance at beginning of year 20,112 (62,291)
Net income 39,946 $ 39,946 8,383 $ 8,383
Dividends ($0.03 per common share) (1,223) (1,209)
------------ ----------
Balance at end of period 58,835 (55,117)
------------ ----------
Accumulated Other
Comprehensive Income (Loss):
Balance at beginning of year (1,062) (1,061)
Exchange gains (losses)
on Canadian currency 609 609 (21) (21)
Unrealized loss on price hedge contracts (820) (820) --
Cumulative effect of
change in accounting principle (2,438) (2,438) --
------------ ------------ ---------- -------
Balance at end of period (3,711) (1,082)
------------ ---------
Comprehensive Income $ 37,297 $ 8,362
============ =======
Treasury Stock:
Balance at beginning of year (15,575) (324) (15,575) (324)
Activity during the period -- -- -- --
------------ ------------ ----------- ----------
Balance at end of period (15,575) (324) (15,575) (324)
------------ ------------ ----------- ----------
Common Stock Outstanding,
at the End of the Period 53,568,661 40,367,350
============ ===========
Total Shareholders' Equity $ 765,427 $277,661
============ ========
See accompanying notes to consolidated financial statements.
5
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(1) General Information -
The consolidated financial statements included herein have been prepared
by
Pogo Producing Company (the "Company") without audit and include all
adjustments
(of a normal and recurring nature) which are, in the opinion of
management,
necessary for the fair presentation of interim results which are
not necessarily
indicative of results for the entire year. Certain prior year
amounts have been
reclassified to conform with current year presentation. The
financial statements
should be read in conjunction with the consolidated
financial statements, and
notes thereto included in the Company's annual report
on Form 10-K for the year
ended December 31, 2000.
(2) Long-Term Debt -
Long-term debt and the amount due within one year at March 31, 2001 and
December 31, 2000, consist of the following:
March 31, December 31,
2001 2000
------- ---------
(Expressed in thousands)
Senior debt -
Bank revolving credit agreement
LIBOR rate based loan, borrowing at an interest rate of 6.7% $300,000 $ --
Prime rate based loan, borrowing at an interest rate of 8% 21,000 --
Swing Line loan, borrowing at an interest rate of 6.6% 10,000 --
-------- --------
Total senior debt 331,000 --
-------- --------
Subordinated debt -
8 3/4% Senior subordinated notes due 2007 ("2007 Notes") 100,000 100,000
10 3/8% Senior subordinated notes due 2009 ("2009 Notes") 150,000 150,000
5 1/2% Convertible subordinated notes due 2006 ("2006 Notes") 115,000 115,000
-------- --------
Total subordinated debt 365,000 365,000
-------- --------
Long-term debt, none due within one year $696,000 $365,000
======== ========
Refer to Note 3 of Notes to Consolidated Financial Statements included in
the Company's annual report on Form 10-K for the year ended December 31, 2000,
for a further discussion of the Company's debt agreements.
On March 8, 2001, prior to the merger with NORIC Corporation ("NORIC") and
the acquisition of North Central Oil Corporation ("North Central") on March 14,
2001, the Company entered into a reserve based revolving credit facility (the
"Credit Facility"). The Credit Facility provides for a $515,000,000 revolving
credit facility until March 7, 2006. The amount that may be borrowed may not
exceed a borrowing base which is determined semi-annually and is calculated
based upon substantially all of the Company's proved oil and gas properties. As
of May 1, 2001, the Company had $325,000,000 available under its Credit
Facility. The Credit Facility is governed by various financial and other
covenants, including requirements to maintain positive working capital
(excluding current maturities of debt) and a fixed charge coverage ratio,
creation of liens, a limitation on commodity hedging above certain specified
limits, the prepayment of subordinated debt, the payment of dividends, mergers
and consolidations, investments and asset dispositions. In addition, the Company
has pledged the stock of North Central and its inter-company receivable with
North Central as security for its obligations under the Credit Facility and is
prohibited from pledging borrowing base properties as security for other debt.
The Credit Facility also permits short-term "swing line" loans and the issuance
of up to $50,000,000 in letters of credit. Borrowings under the Credit facility
bear interest, at the Company's option, at a base (prime) rate plus a variable
margin
(currently none) or LIBOR plus a variable margin (currently l.125%). The
margin varies as a function of the percentage of the borrowing base utilized. A
commitment fee on the unborrowed amount that is currently available under the
Credit Facility is also charged based on the percentage of the borrowing base
that is being utilized. As of May 1, 2001, there was $150,000,000 outstanding
under the Credit Facility.
In connection with its entering into the Credit Facility, the Company's
previously existing uncommitted money market line of credit with a commercial
bank was terminated.
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(2) Long-Term Debt (continued) -
The Master Banker's Acceptance Agreement between the Company and one of
its lenders was recently modified to increase the amount which the lender has
agreed to accept bank drafts from the Company up to $25,000,000. The banker's
drafts are available on an uncommitted basis and the bank has no obligation to
accept the Company's request for drafts. Drafts drawn under this agreement would
be reflected as long-term debt on the Company's balance sheet because the
Company currently has the ability and intent to reborrow such amounts under the
Credit Facility. The Company's 2007 Notes, 2009 Notes, and the Company's new
notes due 2011 (described below) may restrict all or a portion of the amounts
that may be borrowed under the Master Banker's Acceptance Agreement as senior
debt. The Master Banker's Acceptance Agreement permits either party to terminate
the letter agreement at any time upon five business days notice. As of May 1,
2001 no amounts were outstanding under this agreement.
On April 10, 2001 the Company issued $200,000,000 principal amount of
Senior Subordinated Notes due 2011 (the "2011 Notes"). The 2011 Notes bear
interest at a rate of 8 1/4%, payable semi-annually in arrears on April 15 and
October 15 of each year, commencing October 15, 2001. The 2011 Notes are
general unsecured senior subordinated obligations of the Company, are
subordinated in right of payment to the Company's senior indebtedness, which
currently includes the Company's obligations under the Credit Facility and its
banker's acceptances, are equal in right of payment to the 2007 Notes and the
2009 Notes, but are senior in right of payment to the Company's subordinated
indebtedness, which currently includes the 2006 Notes. In addition, they are
senior in right of payment to the liquidation preference under the Company's
Trust Preferred Securities. The Company, at its option, may redeem the 2011
Notes in whole or in part, at any time on or after April 15, 2006, at a
redemption price of 104.125% of their principal value and decreasing
percentages thereafter. The indentures governing the 2011 Notes also imposes
certain covenants on the Company that are substantially identical to the
covenants contained in the indentures governing the 2007 Notes and the 2009
Notes, including covenants limiting: incurrence of indebtedness including
senior indebtedness; restricted payments; the issuance and sales of restricted
subsidiary capital stock; transactions with affiliates; liens; disposition of
proceeds of asset sales; non-guarantor restricted subsidiaries; dividends and
other payment restrictions affecting restricted subsidiaries; and mergers,
consolidations and the sale of assets.
(3) Income Taxes -
The Company does not provide for U.S. income taxes on unremitted earnings
of foreign subsidiaries as the Company's present intention is to reinvest the
unremitted earnings in its foreign operations. Unremitted earnings of foreign
subsidiaries are approximately $20,000,000 at March 31, 2001. It is not
practicable to determine the amount of U.S. income taxes that would be payable
upon remittance of the assets that represent those earnings.
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(4) Hedging Activities -
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities ("SFAS 133"). In June 2000, the FASB issued SFAS 138,
Accounting for Derivative Instruments and Hedging Activities, an amendment of
FASB Statement No. 133. SFAS 133, as amended, establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair market
value.
The statement requires that changes in the derivative's fair value be
recognized
currently in earnings unless specific hedge criteria are met.
Special accounting
for qualifying hedges allows a derivative's gains and losses
to offset related
results on the hedged item in the income statement, and
requires that a company
must formally document, designate and assess the
effectiveness of transactions
that receive hedge accounting. The Company
adopted SFAS 133 effective January 1,
2001. Based on the nature of the
Company's derivative instruments currently
outstanding and the historical
volatility of oil and gas commodity prices, the
Company expects that SFAS 133
could increase volatility in the Company's
earnings and other comprehensive
income for future periods.
SFAS 133, in part, allows special hedge accounting. SFAS 133 provides that
the effective portion of the gain or loss on a derivative instrument designated
and qualifying as a cash flow hedging instrument be reported as a component of
other comprehensive income and be reclassified into earnings in the same period
during which the hedged forecasted transaction affects earnings. The remaining
gain or loss on the derivative instrument, if any, must be recognized currently
in earnings.
SFAS 133 requires that as of the date of initial adoption, the difference
between the market value of derivative instruments and the previous carrying
amount of theses derivatives be recorded in net income or other comprehensive
income, as appropriate, as the cumulative effect of a change in accounting
principle. Based on interpretive guidance issued during the first quarter of
2001, the Company determined that the cumulative effect of adopting SFAS 133
should be recorded in other comprehensive income. As such, effective January 1,
2001, the Company recorded an unrealized loss of $2,438,000, net of deferred
taxes of $1,313,000, in other comprehensive income. During the first quarter of
2001, the Company recognized a $720,000 loss as an offset to oil and gas
revenues related to hedge ineffectiveness on these contracts. Unrealized losses
on derivative instruments arising during the three months ended March 31, 2001
of $820,000, net of deferred taxes of $441,000, has been reflected as a
component of other comprehensive income. Based on the future market prices, the
Company currently expects additional pre-tax charges of $8,434,000 to be
recorded in net income during 2001.
As of March 31, 2001, the Company held options to sell 70 million cubic
feet of natural gas production per day for the period from April 1, 2001
through
December 31, 2002. The Company has designated these contracts as cash
flow
hedges designed to give the Company the right, but not the obligation, to
sell
natural gas at a sales price of $4.25 per MMBtu for the period from April
2001
through March 2002 and $4.00 per MMBtu for the period from April 2002
through
December 2002. These contracts are designed to guarantee the Company a
minimum
"floor" price for the contracted volumes of production without limiting
the
Company's participation in price increases during the covered period. As
of
March 31, 2001, the Company was a party to the following hedging
arrangements:
NYMEX
Volume Contract Fair
in Price per Market
Contract Period MMBtu(a) MMBtu(a) Value (b)
----------------------------- -------------- --------------- -----------------
April 2001 - March 2002 25,550 $ 4.25 $ 5,981,000
April 2002 - December 2002 19,250 $ 4.00 $12,309,000
(a) MMBtu means million British Thermal Units.
(b) Fair Market value is calculated using prices derived from NYMEX
futures contract prices existing at March 31, 2001.
These hedging transactions are settled based upon the average of the
reporting settlement prices on the NYMEX for the last three trading days or
occasionally, the penultimate trading day of a particular contract month. For
any particular floor transaction, the counter-party is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction. The Company is not required to make
any payment in connection with the settlement of a floor transaction.
As of March 31, 2001 the Company was not a party to any commodity price
hedging contracts with respect to any of its current or future crude oil and
condensate production.
8
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(5) Business Segment Information -
Financial information by operating segment is presented below:
Company Oil and Gas Pipelines Other
------- ----------- --------- -----
(Expressed in thousands)
Long-Lived Assets:
As of March 31, 2001:
United States $ 1,633,524 $ 1,624,051 $ 5,181 $ 4,292
Kingdom of Thailand 333,916 330,360 -- 3,556
Canada and other 12,350 12,196 -- 154
----------- ----------- ----------- -----------
Total $ 1,979,790 $ 1,966,607 $ 5,181 $ 8,002
=========== =========== =========== ===========
As of December 31, 2000:
United States $ 462,530 $ 454,246 $ 5,315 $ 2,969
Kingdom of Thailand 337,317 334,018 -- 3,299
Canada 11,807 11,576 -- 231
----------- ----------- ----------- -----------
Total $ 811,654 $ 799,840 $ 5,315 $ 6,499
=========== =========== =========== ===========
Revenues:
For the three months ended March 31, 2001
United States $ 119,472 $ 113,484 $ 4,292 $ 1,696
Kingdom of Thailand 47,994 47,945 -- 49
Canada and other 2,396 2,396 -- --
----------- ----------- ----------- -----------
Total $ 169,862 $ 163,825 $ 4,292 $ 1,745
=========== =========== =========== ===========
For the three months ended March 31, 2000
United States $ 66,423 $ 63,436 $ 3,382 $ (395)
Kingdom of Thailand 33,638 33,637 -- 1
Canada 857 823 -- 34
----------- ----------- ----------- -----------
Total $ 100,918 $ 97,896 $ 3,382 $ (360)
=========== =========== =========== ===========
Operating Income (Loss):
For the three months ended March 31, 2001
United States $ 58,647 $ 56,897 $ 54 $ 1,696
Kingdom of Thailand 23,747 23,698 -- 49
Canada and other (5,370) (5,370) -- --
----------- ----------- ----------- -----------
Total $ 77,024 $ 75,225 $ 54 $ 1,745
=========== =========== =========== ===========
For the three months ended March 31, 2000
United States $ 13,016 $ 13,633 $ (222) $ (395)
Kingdom of Thailand 11,752 11,751 -- 1
Canada (193) (227) -- 34
----------- ----------- ----------- -----------
Total $ 24,575 $ 25,157 $ (222) $ (360)
=========== =========== =========== ===========
9
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(6) Earnings per Share -
Earnings per common share (basic earnings per share) are based on the
weighted average number of shares of common stock outstanding during the
periods. Earnings per share and potential common share (diluted earnings per
share) consider the effect of dilutive securities as set out below, in
thousands, except per share amounts:
Three Months Ended Three Months Ended
March 31, 2001 March 31, 2000
-------------------------------------- -----------------------------------------
Income Shares Per Share Income (a) Shares Per Share
------ ------ --------- ---------- ------ ---------
Basic earnings per share - $39,946 43,145 $ 0.93 $ 10,151 40,291 $ 0.25
========= =========
Effect of dilutive securities:
Options to purchase common shares - 935 - 593
2006 Notes 1,028 2,726 - -
Trust Preferred Securities 1,584 6,316 1,584 6,316
-------- ------------- ---------- -------------
Diluted earnings per share $42,558 53,122 $ 0.80 $ 11,735 47,200 $ 0.25
======== ============= ========= ========== ============= =========
Antidilutive securities -
Options to purchase common shares - 270 $ 27.93 - 278 $ 32.61
2006 Notes - - - 1,028 2,726 $ 0.38
(a) Represents income before cumulative effect of change in
accounting principle.
(7) Acquisition -
On March 14, 2001, the previously announced merger of the Company and
NORIC
was consummated. As a result of the merger, the Company acquired all of
the
outstanding capital stock of North Central, which was the principal asset
of
NORIC. North Central is an independent domestic oil and gas exploration and
production company whose operations are being integrated with the Company's
existing domestic operations. The merger was accounted for using the purchase
method of accounting. Accordingly, the purchase price was allocated to the net
assets acquired based upon their estimated fair market values at the date of
acquisition. Such allocations are based upon preliminary information and are
subject to change when final valuations are obtained. Commencing March 14,
2001,
North Central's operations are consolidated with the operations of the
Company.
Pursuant to the merger agreement amount the Company and NORIC and
certain NORIC
shareholders dated as of November 19, 2000, former shareholders
received
12,615,816 shares of the Company's common stock and approximately
$344,711,000
in cash. In addition, at the closing the Company repaid all
$78,600,000
principal amount of North Central's existing bank debt. The sources
of funds
used in connection with the merger included cash on hand at the
Company and
NORIC and borrowings under the Company's new credit agreement
discussed in Note
2 above, "Long-Term Debt."
The following summary presents unaudited pro forma consolidated results of
operations as if the acquisition has occurred at the beginning of each period
presented. The pro forma results are for illustrative purposes only and include
adjustments in addition to the pre-acquisition historical results of North
Central, such as in increased depreciation, depletion and amortization expense
resulting from the allocation of fair market value to oil and gas properties
acquired and increased interest expense on acquisition debt. The unaudited
proforma financial information is not necessarily indicative of the operating
results that would have occurred had the
acquisition been consummated at those
dates, nor are they necessarily indicative
of future operating results.
Three Months Ended
March 31,
--------------------------------
2001 2000
--------------------------------
Revenues $ 232,842 $ 128,929
Income before cumulative effect of change in accounting principle $ 56,864 $ 4,999
Net income $ 56,864 $ 3,231
Earnings per share:
Basic -
Income before cumulative effect of change in accounting principle $ 1.07 $ 0.09
Net income $ 1.07 $ 0.06
Diluted -
Income before cumulative effect of change in accounting principle $ 0.94 $ 0.09
Net income $ 0.94 $ 0.06
10
POGO PRODUCING COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
This discussion should be read in conjunction with Management's Discussion and
Analysis of Financial Condition and Results of Operations included in the
Company's annual report on Form 10-K for the year ended December 31, 2000.
Certain statements contained herein are "forward-looking statements" and are
thus prospective. As further discussed in the Company's annual report on
Form 10-K for the year ended December 31, 2000, such forward-looking statements
are subject to risks, uncertainties and other factors that could cause actual
results to differ materially from future results expressed or implied by such
forward-looking statements.
On March 14, 2001, the previously announced merger of Pogo Producing Company
(the "Company") and NORIC Corporation ("NORIC") was consummated. As a result of
the merger, the Company acquired all of the outstanding capital stock of North
Central Oil Corporation ("North Central"), which was the principal asset of
NORIC Corporation. North Central is an independent domestic oil and gas
exploration and production company whose operations are being integrated with
Pogo's existing domestic operations. The merger was accounted for using the
purchase method of accounting. Commencing March 14, 2001, the results of North
Central's operations are consolidated with the Company's. Pursuant to the
merger agreement among the Company, NORIC and certain NORIC shareholders dated
as of November 19, 2000, former shareholders of NORIC received 12,615,816 shares
of the Company's common stock and approximately $344,711,000 in cash. In
addition, at the closing the Company repaid all $78,600,000 principal amount of
North Central's existing bank debt. The sources of funds used in connection
with the merger included cash on hand at the Company and NORIC and borrowings
under the Company's new credit agreement discussed under "Liquidity and Capital
Resources."
RESULTS OF OPERATIONS
Net Income
The Company reported net income for the first quarter of 2001 of $39,946,000
or $0.93 per share ($42,558,000 or $0.80 per share on a diluted basis), compared
to net income (before the cumulative effect of a change in accounting
principle) for the first quarter of 2000 of $10,151,000 or $0.25 per share (on
both a basic and a diluted basis). The increase in net income during the first
quarter of 2001, compared to the first quarter of 2000, was primarily related to
increased oil and gas revenues resulting from improved natural gas prices and
increased crude oil production volumes. Net income in the first quarter of 2000
was also decreased by $1,768,000 resulting from a change in accounting principle
related to the Company's method of accounting for crude oil inventory stored on
its FPSO and FSO in the Gulf of Thailand.
Earnings per common share are based on the weighted average number of common
shares outstanding for the first quarter of 2001 of 43,145,000 (53,122,000 on a
diluted basis), compared to 40,291,000 (47,200,000 on a diluted basis) for the
first quarter of 2000. The increase in the weighted average number of common
shares outstanding for the first quarter of 2001, compared to the first quarter
of 2000, resulted primarily from the issuance of common stock in connection with
the merger with NORIC on March 14, 2001 and, to a lesser extent the exercise of
stock options pursuant to the Company's incentive plans. Earnings per share
computations on a diluted basis for both periods reflect additional shares of
common stock issuable upon the assumed conversion of Pogo Trust I's 6 1/2%
Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the
"Trust Preferred Securities") and, to a much lesser extent, additional shares of
common stock issuable upon the assumed exercise of options to purchase common
shares under the Company's incentive plans, less treasury shares that are
assumed to have been purchased by the Company from the option proceeds.
Earnings per share computations for the first quarter of 2001 also reflect
additional shares of common stock issuable upon the assumed conversion of the
Company's 5 1/2% Convertible Subordinated Notes due 2006 (the "2006 Notes").
11
Total Revenues
The Company's total revenues for the first quarter of 2001 were $169,862,000,
an increase of approximately 68% from total revenues of $100,918,000 for the
first quarter of 2000. The increase in the Company's total revenues for 2001,
compared to 2000, resulted primarily from increased oil and gas revenues and, to
a much lesser extent, a gain recorded on the sale of certain non-strategic
assets and an increase in pipeline sales revenue.
Oil and Gas Revenues
The Company's oil and gas revenues for the first quarter of 2001 were
$163,913,000, an increase of approximately 67% from oil and gas revenues of
$97,896,000 for the first quarter of 2000. The following table reflects an
analysis of variances in the Company's oil and gas revenues (expressed in
thousands) between 2001 and 2000:
Increase (decrease) in oil and gas revenues 1ST QTR
resulting from variances in: 2001
COMPARED TO
1ST QTR
2000
-----------
NATURAL GAS --
Price.............................................. $49,492
Production......................................... 2,359
-------
51,851
-------
CRUDE OIL AND CONDENSATE --
Price.............................................. 901
Production......................................... 15,034
-------
15,935
-------
NATURAL GAS LIQUIDS ("NGL")........................... (1,769)
-------
Increase (decrease) in oil and gas revenues........ $66,017
=======
The increase in the Company's oil and gas revenues in the first quarter of
2001, compared to the first quarter of 2000, was related to an increase in the
average price that the Company received for its natural gas production, an
increase in its crude oil and condensate production and, to a lesser extent, an
increase in its natural gas production and in the average price that it received
for its oil and condensate production. These increases were partially offset by
a decline in revenues related to decreased production of NGL. NGL is extracted
from natural gas. Due to the relatively high price (relative to crude oil and
condensate) that the Company is currently receiving for its natural gas
production volumes, the Company has elected in many instances to leave the NGL
in the natural gas at this time, rather than to extract it for resale as NGL.
Generally, this leads to increased average prices for the Company's natural gas
production volumes.
Comparison of Increases (Decreases) in: 1ST QTR 1ST QTR % CHANGE
NATURAL GAS -- 2001 2000 2001 to 2000
------- ------- -----------------
Average prices
North America (a)........................................... $ 7.02 $ 2.76 154%
Kingdom of Thailand(b)...................................... $ 2.45 $ 1.97 24%
Company-wide average price............................. $ 5.59 $ 2.50 124%
Average daily production volumes (MMcf per day)
North America (a)........................................... 125.3 117.6 7%
Kingdom of Thailand......................................... 57.4 58.5 (2)%
------- -------
Company-wide average daily production.................. 182.7 176.1 4%
======= =======
12
Crude Oil and Condensate --
Average prices
North America(a)............................................ $ 28.02 $ 25.72 9%
Kingdom of Thailand......................................... $ 25.22 $ 26.85 (6)%
Company-wide average price............................. $ 26.54 $ 26.24 1%
Average daily production volumes (Bbls per day)
North America(a)............................................ 13,916 13,352 4%
Kingdom of Thailand (c)..................................... 13,918 11,359 23%
------- -------
Company-wide average daily production (c).............. 27,834 24,711 13%
======= =======
TOTAL LIQUID HYDROCARBONS --
Company-wide average daily production (Bbls per day)(c)....... 28,538 26,641 7%
======= =======
____________________________
(a) North American average prices and production reflect production from
the United States and Canada. "MMcf" and "Bbls" stand for million
cubic feet and barrels, respectively.
(b) The Company is paid for its natural gas production in the Kingdom of
Thailand in Thai Baht. The average prices are presented in U.S.
dollars based on the revenue recorded in the Company's financial
records.
(c) Oil and condensate production in the Gulf of Thailand is produced and
stored on the FPSO and FSO pending sale and is sold in tanker loads
that typically average between 300,000 and 750,000 barrels per sale.
Therefore, oil and condensate sales volumes for a given period in the
Gulf of Thailand may not equate to actual production. In accordance
with generally accepted accounting principles, as currently
interpreted, reported revenues are based on sales volumes. However,
the Company believes that actual production volumes are a more
meaningful measure of the Company's operating results and therefore
reports production volumes as part of its operating results. The
Company produced 146,000 barrels less than it sold in the first
quarter of 2001 and produced 164,000 barrels more than it sold in the
first quarter of 2000.
Natural Gas
Thailand Prices. The price that the Company receives under the gas sales
agreement with the Petroleum Authority of Thailand ("PTT") is based upon a
formula which takes into account a number of factors including, among other
items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore.
The increase in the average price that the Company received for its natural gas
production in the Kingdom of Thailand for the first quarter of 2001, compared to
the first quarter of 2000, reflects positive adjustments under the gas sales
agreement.
Production. The increase in the Company's natural gas production during the
first quarter of 2001, compared to the first quarter of 2000, was primarily
related to production from properties acquired in the North Central acquisition
and, to a lesser extent, successful development programs on the Company's New
Mexico properties that was partially offset by natural decline at certain of the
Company's other properties.
Crude Oil and Condensate
Thailand Prices. Since the inception of production from the Company's
properties located in the Gulf of Thailand, crude oil and condensate have been
stored on storage vessels (an FPSO in the Tantawan field and an FSO in the
Benchamas field) until an economic quantity was accumulated for offloading and
sale. A typical sale ranges from 300,000 to 750,000 barrels. Prices that the
Company receives for its crude oil and condensate production from Thailand are
based on world benchmark prices, typically as a differential to Malaysian TAPIS
crude and are denominated in dollars. In addition, the Company is generally paid
for its crude oil and condensate production from Thailand in dollars.
Production. The increase in the Company's Thailand production is related to
production from the Benchamas field that commenced producing in the third
quarter of 2000. Due a change in interpretation of an accounting principle, the
Company now records its oil production in Thailand at the time of sale, rather
than when produced, as it had previously. In accordance with generally accepted
accounting principles, as currently interpreted, at the end of each
13
quarter, the crude oil and condensate stored on board the FSO and FPSO pending
sale is accounted for as inventory at cost. Reported revenues are based on sales
volumes. When a tanker load of oil is sold in Thailand, the entire amount will
be accounted for as production sold, regardless of when it was produced. The
Company believes that actual production volumes are a more meaningful measure of
the Company's operating results than sales volumes and therefore reports
production volumes as part of its operating results. The Company produced
146,000 barrels less than it sold in the first quarter of 2001 and produced
164,000 barrels more than it sold in the first quarter of 2000. As of March 31,
2001, the Company had approximately 204,000 net barrels stored on board the FPSO
and FSO.
NGL Production. The Company's oil and gas revenues, and its total liquid
hydrocarbon production, reflect the production and sale by the Company of NGL,
which are liquid products extracted from natural gas production. The decrease in
NGL revenues for the first quarter of 2001, compared with the first quarter of
2000, primarily related to the decision by the Company not to extract NGL from
its natural gas production due to the more favorable economics of leaving it in
the natural gas stream.
Costs and Expenses
1ST QTR 1ST QTR % CHANGE
Comparison of Increases (Decreases) in: 2001 2000 2001 to 2000
------------ ----------- ---------------
LEASE OPERATING EXPENSES
North America.......................................... $ 17,050,000 $14,290,000 19%
Kingdom of Thailand.................................... $ 8,777,000 $ 7,355,000 19%
Total Lease Operating Expenses................... $ 25,827,000 $21,645,000 19%
Pipeline Operating and Natural Gas Purchases.............. $ 4,020,000 $ 3,390,000 19%
General and Administrative Expenses....................... $ 8,208,000 $10,517,000 (22)%
Exploration Expenses...................................... $ 6,948,000 $ 3,673,000 89%
Dry Hole and Impairment Expenses.......................... $ 10,767,000 $ 5,072,000 112%
Depreciation, Depletion and Amortization (DD&A)
Expenses.............................................. $ 37,068,000 $32,046,000 16%
DD&A Rate.............................................. $1.12 $1.07 5%
Mcfe Produced (a)...................................... 31,854,000 30,568,000 4%
Interest-
Charges............................................... $(11,304,000) $(8,746,000) 29%
Income................................................ 1,302,000 293,000 344%
Capitalized Interest Expense.......................... $ 4,526,000 $ 5,010,000 (10)%
Minority Interest - Dividends and Costs................... $ 2,497,000 $ 2,558,000 (2)%
Foreign Currency Transaction Loss......................... $ (585,000) $ (327,000) 79%
Income Tax Expense........................................ $(28,520,000) $(8,096,000) 252%
_____________________
(a) "Mcfe" stands for thousand of cubic feet equivalent.
Lease Operating Expenses
The increase in North American lease operating expenses for the first quarter
of 2001, compared to the first quarter of 2000, related in large measure to
increased severance taxes resulting from increased production from the Company's
non-U.S. government owned properties (accounting for $3,041,000 of the increase)
and, to a lesser extent, increased expenses related to operation of the
properties acquired in the North Central merger and generally increasing costs
resulting from an industry-wide increase in demand for oil field services and
equipment, that was only partially offset by decreased maintenance costs in the
Gulf of Mexico and the Company's Western Division properties. The increase
14
in lease operating expenses in the Kingdom of Thailand for the first quarter of
2001, compared to the first quarter of 2000, related to increased maintenance
and workover activity in the Benchamas Field and to generally increasing costs
resulting from an industry-wide increase in demand for oil field services and
equipment. A substantial portion of the Company's lease operating expenses in
the Kingdom of Thailand relates to the lease payments made in connection with
the bareboat charter of the FPSO for the Tantawan field and the FSO for the
Benchamas field. Collectively, these lease payments accounted for $3,716,000 and
$3,757,000 of the Company's Thailand lease operating expenses for the first
quarter of 2001 and the first quarter of 2000, respectively.
Pipeline Operating and Natural Gas Purchases
Revenue from the sale of natural gas purchased for resale is reported as
revenue under "Pipeline sales and other." The cost of purchasing natural gas for
resale, together with the costs of operating the pipeline carrying the natural
gas is recorded as an expense under "Pipeline operating and natural gas
purchases." The increase in pipeline operating expenses and natural gas purchase
costs for the first quarter of 2001, compared to the first quarter of 2000,
primarily related to increased cost of natural gas purchased for resale by the
Company.
General and Administrative Expenses
The decrease in general and administrative expenses for the first quarter of
2001, compared with the first quarter of 2000, primarily related to a $1,889,000
retroactive adjustment for the over accrual of certain payroll costs, that was
partially offset by increased expenses associated with the Company's acquisition
of North Central and its employees, as well as an increase in the size of the
Company's work force and normal salary and concomitant benefit expense
adjustments.
Exploration Expenses
Exploration expenses consist primarily of rental payments required under oil
and gas leases to hold non-producing properties ("delay rentals") and
exploratory geological and geophysical costs which are expensed as incurred. The
increase in exploration expense for the first quarter of 2001, compared to the
first quarter of 2000, resulted primarily from the cost of conducting two major
3-D projects in Hungary, that was partially offset by decreased geophysical
acquisition costs in the Company's other operational areas.
Dry Hole and Impairment
The increase in the Company's dry hole and impairment expense for the first
quarter of 2001, compared to the first quarter of 2000, resulted primarily from
impairment expense charged to a non-operated property located in the offshore
Gulf of Mexico due to unexpectedly high drilling and completion expenses and, to
a lesser extent, increased dry hole costs.
Depreciation, Depletion and Amortization Expenses
The increase in the Company's Depreciation, Depletion and Amortization
("DD&A") expense for the first quarter of 2001, compared to the first quarter of
2000, resulted primarily from an increase in the Company's liquid hydrocarbon
and natural gas production and, to a lesser extent, an increase in the Company's
composite DD&A rate.
The increase in the composite DD&A rate for all of the Company's producing
fields for the first quarter of 2001, compared to the first quarter of 2000,
resulted primarily from an increased percentage of the Company's production
coming from certain of the Company's fields that have DD&A rates that are higher
than the Company's recent historical composite rate, including the properties
acquired in the North Central acquisition, and a corresponding decrease in the
percentage of the Company's production coming from fields that have DD&A rates
that are lower than the Company's recent historical composite DD&A rate.
15
Interest
Interest Charges. The increase in the Company's interest charges for the
first quarter of 2001, compared to the first quarter of 2000, resulted primarily
from an increase in amortization of debt issuance expense (principally related
to the termination of the Company's previous credit facility) and, to a lesser
extent, an increase in the average amount of the Company's outstanding debt due
to the acquisition of North Central, that was not entirely offset by decreased
average interest rates on the debt outstanding (resulting primarily from the
increase in bank debt which has a lower interest rate than a substantial portion
of the Company's long-term debt).
Interest Income. The increase in the Company's interest income for the first
quarter of 2001, compared to the first quarter of 2000, resulted primarily from
an increase in the amount of the cash and cash equivalents temporarily invested.
Except for working capital needs, a significant portion of the Company's cash
and cash and cash equivalents were used to fund the North Central acquisition.
Capitalized Interest. The decrease in capitalized interest for the first
quarter of 2001, compared to the first quarter of 2000, resulted primarily from
a decrease in the amount of capital expenditures subject to interest
capitalization during the first quarter of 2001 ($226,409,000), compared to the
first quarter of 2000 ($234,575,000), and from a decrease in the computed
interest rate that the Company uses to apply on such capital expenditures to
arrive at the total amount of capitalized interest. A substantial percentage of
the Company's capitalized interest expense resulted from capitalization of
interest related to capital expenditures for the developments in the Gulf of
Thailand and, to a lesser extent, several development projects in the Gulf of
Mexico.
Minority Interest - Dividends and Costs Associated with Preferred Securities
of a Subsidiary Trust
Pogo Trust I, a subsidiary trust, issued $150,000,000 of Trust Preferred
Securities on June 2, 1999. The amounts recorded for the first quarter of 2001
and the first quarter of 2000, respectively, under "Minority Interest -
Dividends and costs associated with preferred securities of a subsidiary trust"
principally reflect cumulative dividends and, to a lesser extent, the
amortization of issuance expenses related to the offering and sale of the Trust
Preferred Securities.
Foreign Currency Transaction Losses
The foreign currency transaction losses reported for the first quarter of 2001
and the first quarter of 2000 resulted primarily from the fluctuation against
the U.S. dollar of cash and other monetary assets and liabilities denominated in
Thai Baht that were on the Company's subsidiary financial statements during the
respective periods. The weakening of the Thai Baht against the U.S. dollar has
been attributed to, among other things, the negative impact on the Thai economy
of high crude oil prices, continued weakness in the banking sector, and
political uncertainty surrounding recently completed national elections. The
Company cannot predict what the Thai Baht to U.S. dollar exchange rate will be
in the future. As of March 31, 2001, the Company was not a party to any
financial instrument that was intended to constitute a foreign currency hedging
arrangement.
Income Tax Expense
The increase in the Company's income tax expense for the first quarter of
2001, compared to the first quarter of 2000, resulted primarily from increased
pre-tax income from North American operations and from pre-tax income from the
Company's operations in the Kingdom of Thailand that was only partially offset
by tax benefits in the United States for taxes paid, principally in the Kingdom
of Thailand. Management currently expects that its foreign taxes will
constitute a substantial portion of its overall tax burden for the foreseeable
future.
16
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The Company's Condensed Consolidated Statement of Cash Flows for the first
quarter of 2001 reflects net cash provided by operating activities of
$135,048,000. In addition to net cash provided by operating activities, the
Company received $5,330,000, primarily from the exercise of stock options, and
$2,748,000 from the sale of certain non-strategic properties. The Company also
borrowed a net $331,000,000 under its revolving credit facility.
During the first quarter of 2001, the Company acquired the shares of NORIC for
$344,711,000, repaid all $78,600,000 of North Central's senior indebtedness,
invested $80,150,000 in capital projects, paid $4,583,000 in debt issuance
expenses, paid $2,438,000 in cash distributions to holders of its Trust
Preferred Securities and paid $1,223,000 ($0.03 per share) in cash dividends to
holders of the Company's common stock. As of March 31, 2001, the Company's cash
and cash equivalents were $64,396,000 and its long-term debt stood at
$696,000,000.
On April 10, 2001, the Company issued $200,000,000 of 8 1/4% Senior
Subordinated Notes due 2011 (the "2011 Notes"), using the net proceeds to reduce
the Company's outstanding senior indebtedness. As of May 1, 2001, the Company
had $325,000,000 of availability under its revolving credit facility.
Future Capital Requirements
The Company's capital and exploration budget for 2001, which does not include
any amounts that may be expended for the purchase of proved reserves or any
interest which may be capitalized resulting from projects in progress, was
recently increased by the Company's Board of Directors to $350,000,000,
principally on account of the projects to be undertaken on properties acquired
in the North Central acquisition. The Company currently anticipates that its
available cash and cash equivalents, cash provided by operating activities and
funds available under its credit agreement and banker's acceptance facility will
be sufficient to fund the Company's ongoing operating, interest and general and
administrative expenses, any currently anticipated costs associated with the
Company's projects during 2001, and future dividend and distribution payments at
current levels (including a dividend payment of $0.03 per share to be paid on
May 25, 2001 to shareholders of record on May 11, 2001). The declaration of
future dividends on the Company's equity securities will depend upon, among
other things, the Company's future earnings and financial condition, liquidity
and capital requirements, its ability to pay dividends and distributions under
certain covenants contained in its debt instruments, the general economic and
regulatory climate and other factors deemed relevant by the Company's Board of
Directors.
Capital Structure
On March 8, 2001, prior to the merger with NORIC and the acquisition of North
Central on March 14, 2001, the Company entered into a reserve-based revolving
credit facility (the "Credit Facility"). The Credit Facility provides for a
$515,000,000 revolving credit facility until March 7, 2006. The amount that may
be borrowed may not exceed a borrowing base which is determined semi-annually
and is calculated based upon substantially all of the Company's proved oil and
gas properties. As of May 1, 2001, the Company had $325,000,000 of availability
under its Credit Facility. The Credit Facility is governed by various financial
and other covenants, including requirements to maintain positive working capital
(excluding current maturities of debt) and a fixed charge coverage ratio,
creation of liens, a limitation on commodity hedging above certain specified
limits, the prepayment of subordinated debt, the payment of dividends, mergers
and consolidations, investments and asset dispositions. In addition, the Company
has pledged the stock of North Central and its inter-company receivables with
North Central as security for its obligations under the Credit Facility and is
prohibited from pledging borrowing base properties as security for other debt.
The Credit Facility also permits short-term "swing line" loans and the issuance
of up to $50,000,000 in letters of credit. Borrowings under the Credit Facility
bear interest, at the Company's option, at a base (prime) rate plus a variable
margin (currently none) or LIBOR plus a variable margin (currently 1.125%). The
margin varies as a function of the percentage of the borrowing base being
utilized. A commitment fee on the unborrowed amount that is currently available
under the
17
Credit Facility is also charged based upon the percentage of the borrowing base
that is being utilized. As of May 1, 2001, there was $150,000,000 outstanding
under the Credit Facility.
In connection with its entering into the Credit Facility, the Company's
previously existing uncommitted money market line of credit with a commercial
bank was terminated.
Banker's Acceptances. The Master Banker's Acceptance Agreement between the
Company and one of its lenders was recently modified to increase the amount
which the lender has agreed to accept bank drafts from the Company up to
$25,000,000. The banker's drafts are available on an uncommitted basis and the
bank has no obligation to accept the Company's request for drafts. Drafts drawn
under this agreement would be reflected as long-term debt on the Company's
balance sheet because the Company currently has the ability and intent to
reborrow such amounts under the Credit Facility. The Company's 2011 Notes
(described below), its 10 3/8% Senior Subordinated Notes due 2009 and its 8 3/4%
Senior Subordinated Notes due 2007 may restrict all or a portion of the amounts
that may be borrowed under the Master Banker's Acceptance Agreement as senior
debt. The Master Banker's Acceptance Agreement permits either party to
terminate the letter agreement at any time upon five business days notice. As of
May 1, 2001, no amounts were outstanding under this agreement.
2011 Notes. As previously discussed, on April 10, 2001, the Company issued
$200,000,000 principal amount of 2011 Notes. The 2011 Notes bear interest at a
rate of 8 1/4%, payable semi-annually in arrears on April 15 and October 15 of
each year, commencing October 15, 2001. The 2011 Notes are general unsecured
senior subordinated obligations of the Company, are subordinated in right of
payment to the Company's senior indebtedness, which currently includes the
Company's obligations under the Credit Facility and its banker's acceptances,
are equal in right of payment to the 2009 Notes and the 2007 Notes, but are
senior in right of payment to the Company's subordinated indebtedness, which
currently includes the 2006 Notes. In addition, they are senior in right of
payment to the liquidation preference under the Company's Trust Preferred
Securities. The Company, at its option, may redeem the 2011 Notes in whole or
in part, at any time on or after April 15, 2006, at a redemption price of
104.125% of their principal value and decreasing percentages thereafter. The
indenture governing the 2011 Notes also imposes certain covenants on the Company
that are substantially identical to the covenants contained in the indentures
governing the 2009 Notes and the 2007 Notes, including covenants limiting:
incurrence of indebtedness including senior indebtedness; restricted payments;
the issuance and sales of restricted subsidiary capital stock; transactions with
affiliates; liens; disposition of proceeds of asset sales; non-guarantor
restricted subsidiaries; dividends and other payment restrictions affecting
restricted subsidiaries; and mergers, consolidations and the sale of assets.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
The Company is exposed to market risk, including adverse changes in commodity
prices, interest rates and foreign currency exchange rates. In addition to the
information contained in this "Item 3. Quantitative and Qualitative Disclosure
About Market Risk", the information contained in the Company's Annual Report on
Form 10-K for the year ended December 31, 2000, and should be read in
conjunction with the following.
INTEREST RATE RISK
From time to time, the Company has entered into various financial instruments,
such as interest rate swaps, to manage the impact of changes in interest rates.
As of May 1, 2001, the Company has no open interest rate swap or interest rate
lock agreements. Therefore, the Company's exposure to changes in interest rates
primarily results from its short-term and long-term debt with both fixed and
floating interest rates. The following table presents principal or notional
amounts (stated in thousands) and related average interest rates by year of
maturity for the Company's debt obligations and their indicated fair market
value at March 31, 2001:
18
Fair
--------
2000 2001 2002 2003 2004 Thereafter Total VALUE
----- ----- ----- ----- ----- -------- -------- --------
Liabilities Long-Term Debt:
Variable Rate.............. $ 0 $ 0 $ 0 $ 0 $ 0 $331,000 $331,000 $331,000
Average Interest Rate...... - - - - - 6.8% 6.8% -
Fixed Rate................. $ 0 $ 0 $ 0 $ 0 $ 0 $365,000 $365,000 $370,398
Average Interest Rate...... - - - - - 8.4% 8.4% --
FOREIGN CURRENCY EXCHANGE RATE RISK
The Company conducts business in Thai Baht, Hungarian Forint and the Canadian
dollar and is therefore subject to foreign currency exchange rate risk on cash
flows related to sales, expenses, financing and investing transactions. As of
May 1, 2001, the Company is not a party to any foreign currency exchange
agreement.
CURRENT HEDGING ACTIVITY
From time to time, the Company has used and expects to continue to use
hedging transactions with respect to a portion of its oil and gas production to
achieve a more predictable cash flow, as well as to reduce its exposure to price
fluctuations. While the use of these hedging arrangements limits the downside
risk of adverse price movements, they may also limit future revenues from
favorable price movements. The use of hedging transactions also involves the
risk that the counter-parties will be unable to meet the financial terms of such
transactions. All of the Company's recent historical hedging transactions have
been carried out in the over-the-counter market with investment grade
institutions. In January 2001, the Company began to account for its hedging
activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities ("SFAS 133"). SFAS 133 establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair market value. The
statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting hedge accounting criteria
are met. Special accounting for qualifying hedges allows the effective portion
of the gain or loss on a derivative instrument designated and qualifying as a
cash flow hedging instrument be reported as a component of other comprehensive
income and be reclassified into earnings in the same period during which the
hedged forecasted transaction affects earnings. The remaining gain or loss on
the derivative instruments, if any, must be recognized currently in earnings.
Natural Gas
As of March 31, 2001, the Company held options to sell 70 million cubic feet
of natural gas production per day for the period from April 1, 2001 through
December 31, 2002. The Company has designated these contracts as cash flow
hedges designed to give the Company the right, but not the obligation, to sell
natural gas at a sales price of $4.25 per MMBtu for the period from April 2001
through March 2002 and $4.00 per MMBtu for the period from April 2002 through
December 2002. These contracts are designed to guarantee a minimum "floor"
price for the contracted volumes of production without limiting the Company's
participation in price increases during the covered period. As of March 31,
2001, the Company was a party to the following hedging arrangements:
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NYMEX
CONTRACT
VOLUME PRICE PER FAIR MARKET
CONTRACT PERIOD IN MMBTU (a) MMBTU(a) VALUE(b)
----------------------------- ----------------- ------------ ------------------
Floor Contracts:
April 2001 -- March 2002 25,550 $4.25 $ 5,981,000
April 2002 - December 2002 19,250 $4.00 $12,309,000
(a) MMBtu means million British Thermal Units.
(b) Fair Market Value is calculated using prices derived from NYMEX futures
contract prices existing at March 31, 2001.
These hedging transactions are settled based upon the average of the reported
settlement prices on the NYMEX for the last three trading days or, occasionally,
the penultimate trading day of a particular contract month. For any particular
floor transaction, the counter-party is required to make a payment to the
Company if the settlement price for any settlement period is below the floor
price for such transaction. The Company is not required to make any payment in
connection with the settlement of a floor transaction.
Crude Oil
As of March 31, 2001, the Company was not a party to any commodity price
hedging contracts with respect to any of its current or future crude oil and
condensate production.
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(A) Exhibits
None
(B) Reports on Form 8-K
Report filed on January 24, 2001, announcing the date of the Company's
Annual Shareholder's Meeting in 2001, attaching a copy of the Company's press
release containing its fourth quarter and year-end 2000 results and two tables
containing supplemental financial and operating data.
Report filed on March 26, 2001, announcing the merger of the Company and
NORIC under Item 2 and setting forth certain pro forma financial information
required under Item 7, the consolidated balance sheets of North Central and its
consolidated subsidiaries as of December 31, 2000 and 1999, and the related
consolidated statements of operations, cash flows and shareholders' equity for
each of the three years in the period ended December 31, 2000; and unaudited
pro forma condensed consolidated financial statements giving effect to the
merger of NORIC with and into the Company as if it had occurred on January 1,
2000 (for purposes of the pro forma unaudited condensed consolidated statement
of income) and December 31, 2000 (for purposes of the pro forma unaudited
condensed consolidated balance sheet).
20
POGO PRODUCING COMPANY AND SUBSIDIARIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
POGO PRODUCING COMPANY
(Registrant)
/s/ THOMAS E. HART
----------------------------------------------
Thomas E. Hart
Vice President and Chief Accounting Officer
/s/ JAMES P. ULM, II
----------------------------------------------
James P. Ulm, II
Vice President and Chief Financial Officer
Date: May 14, 2001
21