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 June 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 June 30, 2001 53,578,961
Part I. Financial Information
Item 1. Financial Statements
Pogo Producing Company and Subsidiaries
Consolidated Statements of Income (Unaudited)
Three Months Ended
June 30,
------------------------------------
2001 2000
---------------- ----------------
(Expressed in thousands, except per share amounts)
Revenues:
Oil and gas $ 164,412 $ 104,553
Pipeline sales and other 4,982 3,476
Gains (losses) on sales - (9)
---------------- ----------------
Total 169,394 108,020
---------------- ----------------
Operating Costs and Expenses:
Lease operating 29,696 23,517
Pipeline operating and natural gas purchases 4,400 3,156
General and administrative 9,650 7,539
Exploration 5,486 2,114
Dry hole and impairment 12,277 2,120
Depreciation, depletion and amortization 53,464 32,839
---------------- ----------------
Total 114,973 71,285
---------------- ----------------
Operating Income 54,421 36,735
---------------- ----------------
Interest:
Charges (14,988) (8,210)
Income 694 186
Capitalized 10,303 4,604
Minority Interest - Dividends and costs associated
with preferred securities of a subsidiary trust (2,501) (2,559)
Foreign Currency Transaction Loss (421) (794)
---------------- ----------------
Income Before Taxes and Cumulative
Effect of Change in Accounting Principle 47,508 29,962
Income Tax Expense (16,529) (13,171)
---------------- ----------------
Income Before Cumulative
Effect of Change in Accounting Principle 30,979 16,791
Cumulative Effect of Change in Accounting Principle - -
---------------- ----------------
Net income $ 30,979 $ 16,791
================ ================
Earnings Per Common Share
Basic
Income before cumulative effect of change in accounting principle $ 0.58 $ 0.42
Cumulative effect of change in accounting principle - -
---------------- ----------------
Net income $ 0.58 $ 0.42
================ ================
Diluted
Income before cumulative effect of change in accounting principle $ 0.53 $ 0.39
Cumulative effect of change in accounting principle - -
---------------- ----------------
Net income $ 0.53 $ 0.39
================ ================
Dividends Per Common Share $ 0.03 $ 0.03
================ ================
Weighted Average Number of Common Shares
and Potential Common Shares Outstanding:
Basic 53,575 40,382
Diluted 63,494 50,052
See accompanying notes to consolidated financial statements.
Six Months Ended
June 30,
------------------------------------
2001 2000
---------------- ----------------
(Expressed in thousands, except per share amounts)
Revenues:
Oil and gas $ 328,325 $ 202,449
Pipeline sales and other 8,259 6,503
Gains (losses) on sales 2,672 (14)
---------------- ----------------
Total 339,256 208,938
---------------- ----------------
Operating Costs and Expenses:
Lease operating 55,523 45,162
Pipeline operating and natural gas purchases 8,420 6,546
General and administrative 17,858 18,056
Exploration 12,434 5,787
Dry hole and impairment 23,044 7,192
Depreciation, depletion and amortization 90,532 64,885
---------------- ----------------
Total 207,811 147,628
---------------- ----------------
Operating Income 131,445 61,310
---------------- ----------------
Interest:
Charges (26,292) (16,956)
Income 1,996 479
Capitalized 14,829 9,614
Minority Interest - Dividends and costs associated
with preferred securities of a subsidiary trust (4,998) (5,117)
Foreign Currency Transaction Loss (1,006) (1,121)
---------------- ----------------
Income Before Taxes and Cumulative
Effect of Change in Accounting Principle 115,974 48,209
Income Tax Expense (45,049) (21,267)
---------------- ----------------
Income Before Cumulative
Effect of Change in Accounting Principle 70,925 26,942
Cumulative Effect of Change in Accounting Principle - (1,768)
---------------- ----------------
Net income $ 70,925 $ 25,174
================ ================
Earnings Per Common Share
Basic
Income before cumulative effect of change in accounting principle $ 1.46 $ 0.67
Cumulative effect of change in accounting principle - (0.04)
---------------- ----------------
Net income $ 1.46 $ 0.63
================ ================
Diluted
Income before cumulative effect of change in accounting principle $ 1.31 $ 0.64
Cumulative effect of change in accounting principle - (0.04)
---------------- ----------------
Net income $ 1.31 $ 0.60
================ ================
Dividends Per Common Share $ 0.06 $ 0.06
================ ================
Weighted Average Number of Common Shares
and Potential Common Shares Outstanding:
Basic 48,425 40,337
Diluted 58,373 47,263
See accompanying notes to consolidated financial statements.
-1-
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
June 30, December 31,
2001 2000
--------------- ---------------
(Unaudited)
(Expressed in thousands
except share amounts)
Assets
Current Assets:
Cash and cash equivalents $ 79,943 $ 81,510
Accounts receivable 67,410 84,381
Other receivables 39,675 27,242
Federal income tax receivable 4,301 -
Inventory - Product 7,188 3,054
Inventories - Tubulars 9,575 8,056
Price hedge contracts 24,675 9,153
Other 4,675 1,276
------------- -------------
Total current assets 237,442 214,672
------------- -------------
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties being amortized 2,739,460 1,698,404
Unevaluated properties and properties
under development, not being amortized 401,347 154,914
Pipelines, at cost 6,524 7,095
Other, at cost 17,766 15,257
------------- -------------
3,165,097 1,875,670
------------- -------------
Accumulated depreciation, depletion and amortization
Oil and gas (1,146,426) (1,053,478)
Pipelines (1,406) (1,780)
Other (9,887) (8,758)
------------- -------------
(1,157,719) (1,064,016)
------------- -------------
Property and equipment, net 2,007,378 811,654
------------- -------------
Other Assets:
Debt issue expenses 16,590 10,718
Price hedge contracts 13,102 14,869
Foreign value added taxes receivable 9,391 7,262
Deferred income tax 9,007 3,695
Other 21,312 20,652
------------- -------------
69,402 57,196
------------- -------------
$ 2,314,222 $ 1,083,522
============= =============
See accompanying notes to consolidated financial statements.
-2-
Pogo Producing Company and Subsidiaries
Consolidated Balance Sheets
June 30, December 31,
2001 2000
---------------- -----------------
(Unaudited)
(Expressed in thousands
except share amounts)
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable - operating activities $ 58,694 $ 27,334
Accounts payable - investing activities 50,474 67,703
Federal income taxes payable 11,000 -
Accrued interest payable 11,804 7,443
Accrued dividends associated with
preferred securities of a subsidiary trust 813 813
Accrued payroll and related benefits 2,829 2,285
Other 3,268 851
--------------- -----------------
Total current liabilities 138,882 106,429
--------------- -----------------
Long-Term Debt 714,997 365,000
Deferred Income Tax 491,373 95,453
Deferred Credits 15,431 13,456
--------------- -----------------
Total liabilities 1,360,683 580,338
--------------- -----------------
Minority Interest:
Company-obligated mandatorily redeemable
convertible preferred securities of a subsidiary trust,
net of unamortized issue expenses 144,959 144,913
--------------- -----------------
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; 53,594,536 and 40,659,591 shares issued,
respectively 53,594 40,660
Additional capital 657,231 298,885
Retained earnings 88,207 20,112
Accumulated other comprehensive income (loss) 9,872 (1,062)
Treasury stock (15,575 shares), at cost (324) (324)
--------------- -----------------
Total shareholders' equity 808,580 358,271
--------------- -----------------
$ 2,314,222 $ 1,083,522
=============== =================
See accompanying notes to consolidated financial statements.
-3-
Pogo Producing Company and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended
June 30,
--------------------------------------------------------
2001 2000
--------------------- --------------------------
(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers $ 365,015 $ 200,589
Operating, exploration, and general
and administrative expenses paid (91,077) (76,807)
Interest paid (19,255) (16,061)
Federal income taxes paid (14,807) (3,000)
Federal income taxes received - 3,000
Value added taxes (paid) received (2,129) 1,362
Other 2,051 301
-------------------- -----------------------
Net cash provided by operating activities 239,798 109,384
-------------------- -----------------------
Cash Flows from Investing Activities:
Capital expenditures (179,114) (57,665)
Acquisition of NORIC, net of $21,235 cash acquired (323,476) -
Purchase of proved reserves (2,714) -
Proceeds from the sale of properties 4,348 -
-------------------- -----------------------
Net cash used in investing activities (500,956) (57,665)
-------------------- -----------------------
Cash Flows from Financing Activities:
Proceeds from issuance of new debt 200,000 -
Borrowings under senior debt agreements 833,997 67,000
Payments under senior debt agreements (684,000) (77,000)
Payment of North Central senior debt acquired (78,600) -
Payments of cash dividends on common stock (2,830) (2,425)
Payments of preferred dividends of a subsidiary trust (4,875) (4,875)
Payments of financing issue expenses (8,625) (22)
Proceeds from exercise of stock options and other 5,472 1,876
-------------------- -----------------------
Net cash provided by (used in) financing activities 260,539 (15,446)
-------------------- -----------------------
Effect of Exchange Rate Changes on Cash (948) (395)
-------------------- -----------------------
Net Change in Cash and Cash Equivalents (1,567) 35,878
Cash and Cash Equivalents at the Beginning of the Year 81,510 6,267
-------------------- -----------------------
Cash and Cash Equivalents at the End of the Period $ 79,943 $ 42,145
==================== =======================
Reconciliation of Net Income to Net
Cash Provided by Operating Activities:
Net income $ 70,925 $ 25,174
Adjustments to reconcile net income to
net cash provided by operating activities -
Cumulative effect of change in accounting principle - 1,768
Minority interest 4,998 5,117
Foreign currency transaction losses 1,006 1,121
(Gains) losses from the sales of properties (2,672) 14
Depreciation, depletion and amortization 90,532 64,885
Dry hole and impairment 23,044 7,192
Interest capitalized (14,829) (9,614)
Price hedge contracts 2,469 -
Deferred federal income taxes 21,784 21,267
Change in operating assets and liabilities 42,541 (7,540)
-------------------- -----------------------
Net Cash Provided by Operating Activities $ 239,798 $ 109,384
==================== =======================
See accompanying notes to consolidated financial statements.
-4-
Pogo Producing Company and Subsidiaries
Consolidated Statements of Shareholders' Equity (Unaudited)
For the Six Months Ended June 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 319,129 319 120,462 121
----------- ---------- -------------- ----------
Issued at end of period 53,594,536 53,594 40,400,123 40,400
----------- ---------- -------------- ----------
Additional Capital:
Balance at beginning of year 298,885 291,909
Shares issued for acquisition of NORIC 351,729 -
Stock options exercised 6,617 2,198
---------- ----------
Balance at end of period 657,231 294,107
---------- ----------
Retained Earnings (Deficit):
Balance at beginning of year 20,112 (62,291)
Net income 70,925 $ 70,925 25,174 $ 25,174
Dividends ($0.06 per common share) (2,830) (2,425)
---------- ----------
Balance at end of period 88,207 (39,542)
---------- ----------
Accumulated Other
Comprehensive Income (Loss):
Balance at beginning of year (1,062) (1,061)
Exchange gains (losses)
on Canadian currency 389 389 (100) (100)
Cumulative effect of
change in accounting principle (2,438) (2,438) - -
Unrealized gains arising during the
period on price hedge contracts 14,504 14,504 -
Reclassification adjustment for losses
included in net income (1,521) (1,521) -
---------- ---------- ---------- --------
Balance at end of period 9,872 (1,161)
---------- ----------
Comprehensive Income $ 81,859 $ 25,074
========== ========
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 53,578,961 40,384,548
=========== ==============
Total Shareholders' Equity $ 808,580 $ 293,480
========== ==========
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 forthe 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 $44,562,000 and $16,712,000, respectively, for
the three months ended June 30, 2001 and 2000 and $81,859,000 and $25,074,000,
respectively, for the six months ended June 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 June 30, 2001 and
December 31, 2000, consist of the following:
June 30, December 31,
2001 2000
-------------- -------------
(Expressed in thousands)
Senior debt -
Bank revolving credit agreement
LIBOR based loans, borrowings at average interest rate of 5.13% $ 120,000 $ -
Swing Line loan, borrowing at an interest rate of 6.75% 10,000
Banker's acceptances, borrowing at an interest rate of 4.61% 19,997 -
----------- -----------
Total senior debt 149,997 -
----------- -----------
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 $ 714,997 $ 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. As
of July 25, 2001, the borrowing base was 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 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 July 25, 2001, there was $132,000,000 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.
-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 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 draftsare
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 July 25, 2001
there was $24,912,000 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 $28,000,000 at June 30, 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.
-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 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 six months
of 2001, the Company recognized a $2,340,000 loss as an offset to 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 six months ended June 30, 2001 of
$12,983,000, net of deferred taxes of $6,991,000, has been reflected as a
component of other comprehensive income. Based on the fair market value of the
hedge contracts as of June 30, 2001, the Company would reclassify additional
pre-tax income of approximately $11,600,000 (approximately $7,500,000 net of
taxes) from other comprehensive income (shareholders' equity) to net income
during the next twelve months.
As of June 30, 2001, the Company held options to sell 70 million cubic feet
of natural gas production per day for the period from July 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 July 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 June
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)
---------------------------- ---------- ----------- -----------
July 2001 - March 2002 19,180 $4.25 $ 18,266,000
April 2002 - December 2002 19,250 $4.00 $ 19,511,000
(a) MMBtu means million British Thermal Units.
(b) Fair Market value is calculated using prices derived from NYMEX futures
contract prices existing at June 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 June 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 June 30, 2001:
United States $ 1,662,453 $ 1,653,202 $ 5,118 $ 4,133
Kingdom of Thailand 331,621 328,013 - 3,608
Canada and other 13,304 13,166 - 138
------------------- ----------------- ---------------- ----------------
Total $ 2,007,378 $ 1,994,381 $ 5,118 $ 7,879
=================== ================= ================ ================
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 June 30, 2001
United States $ 129,618 $ 124,661 $ 4,473 $ 484
Kingdom of Thailand 38,077 38,067 - 10
Canada and other 1,699 1,684 - 15
------------------- ----------------- ---------------- ----------------
Total $ 169,394 $ 164,412 $ 4,473 $ 509
=================== ================= ================ ================
For the three months ended June 30, 2000
United States $ 67,977 $ 64,595 $ 3,210 $ 172
Kingdom of Thailand 38,998 38,913 - 85
Canada 1,045 1,045 - -
------------------- ----------------- ---------------- ----------------
Total $ 108,020 $ 104,553 $ 3,210 $ 257
=================== ================= ================ ================
For the six months ended June 30, 2001
United States $ 249,090 $ 238,211 $ 8,699 $ 2,180
Kingdom of Thailand 86,071 86,012 - 59
Canada and other 4,095 4,102 - (7)
------------------- ----------------- ---------------- ----------------
Total $ 339,256 $ 328,325 $ 8,699 $ 2,232
=================== ================= ================ ================
For the six months ended June 30, 2000
United States $ 134,400 $ 128,031 $ 6,592 $ (223)
Kingdom of Thailand 72,636 72,550 - 86
Canada 1,902 1,868 - 34
------------------- ----------------- ---------------- ----------------
Total $ 208,938 $ 202,449 $ 6,592 $ (103)
=================== ================= ================ ================
Operating Income (Loss):
For the three months ended June 30, 2001
United States $ 40,730 $ 40,298 $ (52) $ 484
Kingdom of Thailand 17,027 17,017 - 10
Canada and other (3,270) (3,285) - 15
------------------- ----------------- ---------------- ----------------
Total $ 54,487 $ 54,030 $ (52) $ 509
=================== ================= ================ ================
For the three months ended June 30, 2000
United States $ 18,973 $ 18,919 $ (118) $ 172
Kingdom of Thailand 18,136 18,051 - 85
Canada (374) (374) - -
------------------- ----------------- ---------------- ----------------
Total $ 36,735 $ 36,596 $ (118) $ 257
=================== ================= ================ ================
For the six months ended June 30, 2001
United States $ 99,311 $ 97,261 $ (130) $ 2,180
Kingdom of Thailand 40,774 40,715 - 59
Canada and other (8,640) (8,633) - (7)
------------------- ----------------- ---------------- ----------------
Total $ 131,445 $ 129,343 $ (130) $ 2,232
=================== ================= ================ ================
For the six months ended June 30, 2000
United States $ 31,989 $ 32,552 $ (340) $ (223)
Kingdom of Thailand 29,888 29,802 - 86
Canada (567) (601) - 34
------------------- ----------------- ---------------- ----------------
Total $ 61,310 $ 61,753 $ (340) $ (103)
=================== ================= ================ ================
-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
June 30, 2001
--------------------------------------------------
Income Shares Per Share
-------------- ------------- --------------
Basic earnings per share - $ 30,979 53,575 $ 0.58
==============
Effect of dilutive securities:
Options to purchase common shares - 877
2006 Notes 1,028 2,726
Trust Preferred Securities 1,584 6,316
-------------- -------------
Diluted earnings per share $ 33,591 63,494 $ 0.53
============== ============= ==============
Antidilutive securities -
Options to purchase common shares - 307 $ 33.86
Three Months Ended
June 30, 2000
--------------------------------------------------
Income Shares Per Share
-------------- ------------- --------------
Basic earnings per share - $ 16,791 40,382 $ 0.42
==============
Effect of dilutive securities:
Options to purchase common shares - 628
2006 Notes 1,028 2,726
Trust Preferred Securities 1,584 6,316
-------------- -------------
Diluted earnings per share $ 19,403 50,052 $ 0.39
============== ============= ==============
Antidilutive securities -
Options to purchase common shares - 224 $ 34.82
2006 Notes - - -
(a) Represents income before cumulative effect of change in accounting principle.
Six Months Ended
June 30, 2001
---------------------------------------------------
Income Shares Per Share
-------------- -------------- ----------------
Basic earnings per share - $ 70,925 48,425 $ 1.46
================
Effect of dilutive securities:
Options to purchase common shares - 906
2006 Notes 2,056 2,726
Trust Preferred Securities 3,169 6,316
-------------- --------------
Diluted earnings per share $ 76,150 58,373 $ 1.31
============== ============== ================
Antidilutive securities -
Options to purchase common shares - 307 $ 33.86
Six Months Ended
June 30, 2000
---------------------------------------------------
Income (a) Shares Per Share
-------------- -------------- ----------------
Basic earnings per share - $ 26,942 40,337 $ 0.67
================
Effect of dilutive securities:
Options to purchase common shares - 610
2006 Notes - -
Trust Preferred Securities 3,169 6,316
-------------- --------------
Diluted earnings per share $ 30,111 47,263 $ 0.64
============== ============== ================
Antidilutive securities -
Options to purchase common shares - 226 $ 34.72
2006 Notes 2,056 2,726 $ 0.75
(a) Represents income before cumulative effect of change in accounting
principle.
-10-
Pogo Producing Company and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
(7) Acquisition -
On March 14, 2001, the previously announced merger of 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. 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 form 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.
Six Months Ended
June 30,
-------------------------------------
2001 2000
-------------------------------------
Revenues $ 402,236 $ 270,038
Income before cumulative effect of change in accounting principle $ 87,319 $ 17,835
Net income $ 87,319 $ 16,067
Earnings per share:
Basic -
Income before cumulative effect of change in accounting principle $ 1.63 $ 0.34
Net income $ 1.63 $ 0.30
Diluted -
Income before cumulative effect of change in accounting principle $ 1.46 $ 0.34
Net income $ 1.46 $ 0.30
-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 "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"), an independent domestic oil
and gas exploration and production company, which was the principal asset of
NORIC. Corporation. 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 second quarter of 2001 of
$33,979,000 or $0.58 per share ($33,591,000 or $0.53 per share on a diluted
basis), compared to net income for the second quarter of 2000 of $16,791,000 or
$0.42 per share ($19,403,000 or $0.39 per share on a diluted basis). For the
first six months of 2001, the Company reported net income of $70,925,000 or
$1.46 per share ($76,150,000 or $1.31 per share on a diluted basis) compared to
net income for the first six months of 2000 of $26,942,000 or $0.67 per share
($28,343,000 or $0.60 per share on a diluted basis). The increase in net income
during the second quarter and first six months of 2001, compared to the second
quarter and first six months of 2000, was primarily related to increased oil and
gas revenues resulting from improved oil and gas production levels and increased
natural gas prices. these factors were partially offset by a decrease in
revenues from the sale of natural gas liquids ("NGL") and a decrease in the
average prices that the Company received for its crude oil and condensate
production. The net income reported in the second quarter and first six months
of 2001, compared to the second quarter and first six months of 2000 was also
related to increases in pipeline sales. The net income reported in the first six
months of 2001 was also positively impacted by a gain on the sale of certain
non-strategic properties, all of which were recognized in the first quarter of
2001.
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 second quarter and
first six months of 2001, compared to the second quarter and first six months 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 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 second quarter and first six months of 2001, and
the second quarter 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").
-12-
Total Revenues
The Company's total revenues for the second quarter of 2001 were
$169,394,000, an increase of approximately 57% from total revenues of
$108,020,000 for the second quarter of 2000. The Company's total revenues for
the first six months of 2001 were $339,256,000, an increase of approximately 62%
compared to total revenues of $208,938,000 for the first six months of 2000. The
increase in the Company's total revenues for the second quarter and first six
months of 2001, compared to the second quarter and first six months of 2000,
resulted primarily from a substantial increase in oil and gas revenues and, to a
much lesser extent, increased pipeline sales and, with respect to the six month
periods, an increase in gain on sales of certain non-strategic Company
properties.
Oil and Gas Revenues
The Company's oil and gas revenues for the second quarter of 2001 were
$164,412,000, an increase of approximately 57% from oil and gas revenues of
$104,553,000 for the second quarter of 2000. The Company's oil and gas revenues
for the first six months of 2001 were $328,325,000, an increase of approximately
62% from oil and gas revenues of $202,449,000 for the first six 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 2/nd/ Qtr 2001 1/st/ Half 2001
resulting from variances in: Compared to Compared to
2/nd/ Qtr 2000 1/st/ Half 2000
-------------- ---------------
Natural gas--
Price........................................ $ 19,433 $63,232
Production................................... 39,809 47,861
------- --------
59,242 111,093
------- --------
Crude oil and condensate--
Price........................................ (1,221) (365)
Production................................... 2,134 17,213
------- --------
913 16,848
------- --------
Natural Gas Liquids............................. (296) (2,065)
------- --------
Increase (decrease) in oil and gas revenues.. $59,859 $125,876
======= ========
The increase in the Company's oil and gas revenues for the second
quarter and first six months of 2001, compared to the second quarter and first
six months of 2000, is primarily related to increases in the Company's natural
gas and oil and condensate production volumes and, to a lesser extent, an
increase in the price that it received for its natural gas production volumes.
These factors were partially offset by a decrease in the average price the
Company received for its oil and condensate production volumes and decreased
production of NGL. NGL is extracted from natural gas. NGL is extracted from
natural gas. Due to the relatively high price (relative to crude oil and
condensate) that the Company received for its natural gas production volumes
during the second quarter and first six months of 2001, the Company elected in
many instances to leave the NGL in the natural gas. The Company recently resumed
processing its natural gas production volumes to extract NGL for resale due to
the recent decline in natural gas prices, relative to oil and condensate prices.
Comparison of Increases (Decreases) in: 2/nd/ Quarter 1/st/ Six Months
------------------ % %
Natural Gas -- 2001 2000 Change 2001 2000 Change
-------- -------- ------- -------- ------ ------
Average prices
North America (a)..................................... $ 4.62 $ 3.00 54% $ 5.53 $ 2.88 92%
Kingdom of Thailand(b)................................ $ 2.24 $ 2.20 2% $ 2.34 $ 2.08 13%
Company-wide average price....................... $ 4.04 $ 2.73 48% $ 4.66 $ 2.61 79%
Average daily production volumes (MMcf per day)
North America (a)..................................... 205.0 107.8 90% 165.4 112.7 47%
Kingdom of Thailand................................... 66.1 55.1 20% 61.8 56.8 9%
-------- -------- -------- --------
Company-wide average daily production............ 271.1 162.9 66% 227.2 169.5 34%
======== ======== ======== ========
-----------------
(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.
-13-
Comparison of Increases (Decreases) in: 2/nd/ Quarter 1/st/ Six Months
------------------ % ----------------- %
Crude Oil and Condensate -- 2001 2000 Change 2001 2000 Change
-------- -------- ------ -------- ------ ------
Average prices(a)
North America......................................... $25.84 $26.59 (3)% $26.86 $26.15 3%
Kingdom of Thailand................................... $28.21 $31.16 (9)% $26.37 $29.00 (9)%
Company-wide average price........................... $26.75 $28.68 (7)% $26.64 $27.45 (3)%
Average daily production volumes (Bbls per day)
North America......................................... 15,514 13,352 16% 14,719 13,350 10%
Kingdom of Thailand(b)................................ 13,442 11,593 16% 13,679 12,379 11%
------ ------ ------ ------
Company-wide average daily production................ 28,956 24,945 16% 28,398 25,729 10%
====== ====== ====== ======
Total Liquid Hydrocarbons --
Company-wide average daily
production (Bbls per day)(b)........................ 31,028 27,131 14% 29,790 26,887 11%
====== ====== ====== ======
--------------------------
(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 351,000 and 205,000 barrels more than it sold in the second
quarter and first six months of 2001, respectively, and produced 33,000
and 197,000 barrels more than it sold in the second quarter and first
six months of 2000, respectively.
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 second quarter and first six
months of 2001, compared to the second quarter and first six months of 2000,
reflects positive adjustments under the gas sales agreement.
Production. The increase in the Company's natural gas production during
the second quarter and first six months of 2001, compared to the second quarter
and first six months 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 Thailand and New Mexico
properties that were 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 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 dollars. In addition, the Company is generally paid
for its crude oil and condensate production from Thailand in dollars.
Thailand Production. The increase in the Company's crude oil and
condensate production from the Gulf of Thailand during the second quarter and
first six months of 2001, compared to the second quarter and first six months of
2000, resulted from increased production from the Benchamas Field. However, with
respect to the quarterly comparative periods, total sales declined because of
unfavorable tanker lifting schedules, resulting in an increase of 351,000
barrels in inventory stored on board the FPSO and FSO at the end of the period.
Due 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. 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. 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
-14-
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 351,000 and 205,000 barrels more than it sold in the second
quarter and first six months of 2001, respectively, and produced 33,000 and
197,000 barrels more than it sold in the second quarter and first six months of
2000, respectively. As of June 30, 2001, the Company had approximately 555,000
net 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 second quarter and first six
months of 2001, compared to the second quarter and first six 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 decline at
certain of the Company's properties.
NGL Production. The Company's oil and gas revenues, and its total liquid
hydrocarbon production, reflect the production and sale by the Company of NGL,
which are liquid products extracted from natural gas production. The decrease in
NGL revenues for the second quarter and first six months of 2001, compared with
the second quarter and first six 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. The
Company recently resumed processing its natural gas production volumes to
extract NGL for resale due to the recent decline in natural gas prices, relative
to oil and condensate prices.
Costs and Expenses
2nd Quarter 1/st/ Six Months
--------------------------- % -------------------------- %
Comparison of Increases (Decreases) in: 2001 2000 Change 2001 2000 Change
----------- -------- -------- -------
Lease Operating Expenses
North America........................ $ 22,721,000 $ 14,859,000 53% $ 39,771,000 $ 29,149,000 36%
Kingdom of Thailand.................. $ 6,975,000 $ 8,658,000 (19)% $ 15,752,000 $ 16,013,000 (2)%
Total Lease Operating
Expenses.................... $ 29,696,000 $ 23,517,000 26% $ 55,523,000 $ 45,162,000 23%
Pipeline Operating and Natural
Gas Purchases......................... $ 4,400,000 $ 3,156,000 39% $ 8,420,000 $ 6,546,000 29%
General and Administrative Expenses..... $ 9,650,000 $ 7,539,000 28% $ 17,858,000 $ 18,056,000 (1)%
Exploration Expenses.................... $ 5,486,000 $ 2,114,000 160% $ 12,434,000 $ 5,787,000 115%
Dry Hole and Impairment Expenses........ $ 12,277,000 $ 2,120,000 479% $ 23,044,000 $ 7,192,000 220%
Depreciation, Depletion and
Amortization (DD&A) Expenses......... $ 53,464,000 $ 32,839,000 63% $ 90,532,000 $ 64,885,000 40%
DD&A rate............................ $ 1.33 $ 1.10 21% $ 1.24 $ 1.06 17%
Mcfe sold (a)........................ 39,509,000 29,637,000 33% 72,241,000 60,207,000 20%
Interest--
Charges.............................. $ (14,988,000) $ (8,210,000) 83% $ (26,292,000) $(16,956,000) 55%
Interest Income...................... $ 694,000 $ 186,000 273% $ 1,996,000 $ 479,000 317%
Capitalized Interest Expense......... $ 10,303,000 $ 4,604,000 124% $ 14,829,000 $ 9,614,000 54%
Minority Interest - Dividends and
Costs....................... $ (2,501,000) $ (2,559,000) (2)% $ (4,998,000) $ (5,117,000) (2)%
Foreign Currency Transaction Loss....... $ (421,000) $ (794,000) 47% $ (1,006,000) $ (1,121,000) (10)%
Income Tax Expense...................... $ (16,529,000) $ (13,171,000) 25% $ (45,049,000) $(21,267,000) 112%
----------
(a) "Mcfe" stands for thousands of
cubic feet equivalent.
Lease Operating Expenses.
The increase in North American lease operating expenses for the second
quarter and first six months of 2001, compared to the second quarter and first
six 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 $5,469,000 and $8,510,000 of the
increase for the quarter and six 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 decrease in lease operating expenses
in the Kingdom of Thailand for the second quarter and first six months of 2001,
compared to the second quarter and first six months of 2000, primarily related
to an accounting adjustment that reduced lease operating expenses attributable
to crude oil and condensate held as inventory on board the FPSO and FSO. These
lease operating expenses will be recognized for accounting purposes when this
crude oil and condensate is sold. In addition, lease operating expenses for both
2001 periods, compared to
-15-
the 2000 periods, were positively affected by a decrease in maintenance and
workover activity in the Benchamas Field. These factors were partially offset by
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 $3,757,000, $7,472,000, $3,757,000 and $7,513,000 (net to
the Company's interest) of the Company's Thailand lease operating expenses for
the second quarter and first six months of 2001 and the second quarter and first
six 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." Prior to the acquisition of the Pogo Onshore
Pipeline interests, the Company did not separately report its pipeline operating
expenses or revenues, nor did it purchase any natural gas for resale to
customers of its pipelines. The increase in pipeline operating expenses and
natural gas purchase costs for the second quarter and first six months of 2001,
compared to the second quarter and first six months of 2000, primarily related
to increased cost of natural gas purchased for resale by the Company.
General and Administrative Expenses
The increase in general and administrative expenses for the second
quarter of 2001, compared with the second quarter 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. The decrease in
general and administrative expenses for the first six months of 2001, compared
with the first six months 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 second quarter and first six months of
2001, compared to the second quarter and first six months of 2000, resulted
primarily from the cost of conducting two major 3-D projects in Hungary, a
payment to transfer seismic licenses used by North Central and the acquisition
of 3-D data in the Company's Offshore and Western Divisions, partially offset by
generally 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
second quarter and first six months of 2001, compared to the second quarter and
first six months of 2000, resulted primarily from increased dry hole costs and,
with respect to the six month comparative periods, impairment expense charged to
a non-operated property located in the offshore Gulf of Mexico due to
unexpectedly high drilling and completion expenses.
Depreciation, Depletion and Amortization Expenses
The increase in the Company's depreciation, depletion and amortization
("DD&A") expense for the second quarter and first six months of 2001, compared
to the second quarter and first six 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 second quarter and first six months of 2001, compared
to the second quarter and first six 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.
-16-
Interest
Interest Charges. The increase in the Company's interest charges for
the second quarter and first six months of 2001, compared to the second quarter
and first six months of 2000, resulted primarily from an increase in the average
amount of the Company's outstanding 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 six months of
2001, compared to the first six 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
second quarter and first six months of 2001, compared to the second quarter and
first six months of 2000, resulted primarily from a decrease in the amount of
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 increase in capitalized interest for the
second quarter and first six months of 2001, compared to the second quarter and
first six months of 2000, resulted primarily from an increase in the amount of
capital expenditures subject to interest capitalization during the relevant
periods ($359,404,000 and $401,347,000, in 2001, compared to $206,735,000 and
$220,726,000 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 resulted from capitalization of interest
related to capital expenditures for the development of the Benchamas field in
the Gulf of Thailand and, to a lesser extent, several development projects in
the Gulf of Mexico.
Minority Interest -- Dividends and Costs Associated
with Preferred Securities of a Subsidiary Trust
Pogo Trust I, a business trust in which the Company owns all of the
issued common securities, issued $150,000,000 of Trust Preferred Securities on
June 2, 1999. The amounts recorded for the second quarter and first six 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 Losses
The foreign currency transaction losses reported for the second quarter
and first six 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 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 and continued weakness in the
banking sector. The Company cannot predict what the Thai Baht to U.S. dollar
exchange rate will be in the future. As of June 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
The increase in the Company's tax expense for the second quarter
and the first six months of 2001, compared to the second quarter and the first
six months of 2000, resulted primarily from an increase in pre-tax income from
the Company's North American and Kingdom of Thailand operations. The Company's
effective tax rate for the second quarter and first six months of 2001 was 34.8%
and 38.8%, respectively, compared to 44% and 44.1% for the second quarter and
first months of 2000, respectively. The decrease in the effective tax rate in
2001 is attributable to certain tax benefits in the Kingdom of Thailand.
Liquidity and Capital Resources
Cash Flows
The Company's Condensed Consolidated Statement of Cash Flows for the
first six months of 2001 reflects net cash provided by operating activities of
$239,798,000. In addition to net cash provided by operating activities, the
Company received $5,472,000, primarily from the exercise of stock options, and
$4,348,000 from the sale of certain non-strategic properties. The Company also
borrowed a net $149,997,000 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 six 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 $179,114,000 in capital projects, paid
$8,625,000 in debt issuance expenses, paid $4,875,000 in cash distributions to
holders of its Trust
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Preferred Securities, paid $2,714,000 to purchase proved reserves and paid
$2,830,000 ($0.03 per share) in cash dividends to holders of the Company's
common stock. As of July 25, 2001, the Company's cash and cash equivalents were
$84,846,000 and its long-term debt stood at $721,912,000 and it had $268,000,000
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 on its common
stock to be paid on August 17, 2001 to shareholders of record on August 3,
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, 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 July 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 June 30, 2001:
Fair
----
2000 2001 2002 2003 2004 Thereafter Total Value
---- ---- ---- ---- ---- ---------- ----- -----
Liabilities Long-Term Debt:
Variable Rate................. $ 0 $ 0 $ 0 $ 0 $ 0 $ 149,997 $149,997 $149,997
Average Interest Rate......... - - - - - 5.17% 5.17% -
Fixed Rate.................... $ 0 $ 0 $ 0 $ 0 $ 0 $ 565,000 $565,000 $562,204
Average Interest Rate......... - - - - - 8.35% 8.35% -
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 July 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
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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 June 30, 2001, the Company held options to sell 70 million cubic
feet of natural gas production per day for the period from July 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 July 1, 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:
July 2001 -- March 2002 19,180 $4.25 $18,266,000
April 2002 - December 2002 19,250 $4.00 $19,511,000
-----------------
(a) MMBtu means million British Thermal Units.
(b) Fair Market Value is calculated using prices derived from NYMEX futures
contract prices existing at June 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 June 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.
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security-Holders
The registrant held its annual meeting of stockholders in Houston, Texas on
April 24, 2001. The following sets forth the items that were put to a vote of
the stockholders and the results thereof concerning:
(A) election of two directors, each for a term of three years. The vote
tabulation for each nominee was as follows:
Nominee For Withheld
------- --- --------
William L. Fisher 48,218,901 123,341
Paul G. Van Wagenen 48,214,410 127,832
(B) a proposal to amend the Company's Restated Certificate of
Incorporation, to increase the number of shares of the Company's
authorized common stock from 100,000,000 to 200,000,000, with
42,786,475 shares of stock cast for approval, 5,514,314 shares against
approval and 41,453 shares abstained.
(C) a proposal to amend the Company's Restated Certificate of
Incorporation, to increase the number of shares of the Company's
authorized preferred stock from 2,000,000 to 4,000,000, with 28,662,715
shares of stock cast for approval, 14,782,506 shares against approval
and 51,370 shares abstained. In addition, 4,845,651 shares were broker
non-votes.
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(D) ratification of the appointment of Arthur Andersen LLP, independent
public accountants, to audit the financial statements of the registrant
for the year 2001, with 48,045,572 shares of stock cast for the
appointment, 279,301 against the appointment, and 17,369 shares
abstained.
Item 6. Exhibits and Reports on Form 8-K
(A) Exhibits
*4.1 Indenture dated as of April 10, 2001 between Pogo
Producing Company and Wells Fargo Bank Minnesota, National
Association, as Trustee (Exhibit 4.2, Registration
Statement on Form S-4, filed April 24, 2001, File No. 333-
59426).
*Incorporated herein by reference as indicated
(B) Reports on Form 8-K
Report filed on April 6, 2001, announcing the placement of the 2011
Notes on April 4, 2001 under Item 5 and attaching one exhibit under Item 7.
Report filed on April 24, 2001, announcing the Company's quarterly and
financial results and certain unaudited supplemental operating and financial
information related to the Company's first quarter 2001 operating and
financial results under Item 5 and attaching two exhibits 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: August 2, 2001
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