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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
COMMISSION FILE NO. 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, P.O. BOX 2504
HOUSTON, TEXAS 77252-2504
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 297-5000
--------------------------
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each exchange on which registered:
COMMON STOCK, $1 PAR VALUE NEW YORK STOCK EXCHANGE
PACIFIC STOCK EXCHANGE
PREFERRED STOCK PURCHASE RIGHTS NEW YORK STOCK EXCHANGE
PACIFIC STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act:
5 1/2% CONVERTIBLE SUBORDINATED NOTES DUE JUNE 15, 2006
--------------------------
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 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
requirements for the past 90 days. Yes /X/ No / /.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /
The aggregate market value of the Common Stock held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$311,300,000 as of February 22, 1999 (based on $10.00 per share, the last sale
price of the Common Stock as reported on the New York Stock Exchange Composite
Tape on such date).
40,135,311 shares of the registrant's Common Stock were outstanding as of
February 22, 1999.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 27, 1999 (to be filed not later than
120 days after December 31, 1998) are incorporated by reference in Part III of
this Form 10-K.
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FORWARD LOOKING STATEMENTS
The statements included or incorporated by reference in this Report on Form
10-K for the year ended December 31, 1998 (this "Annual Report") include
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended. All statements included herein or therein other than statements of
historical fact are forward-looking statements. When used herein or therein, the
words "anticipate," "estimate," "expect," "objective," "projection," "forecast,"
"goal," and similar expressions are intended to identify forward-looking
statements. Such forward-looking statements include, without limitation, the
statements herein and therein regarding the timing of future events regarding
the operations of Pogo Producing Company (the "Company") both domestically and
in Thailand, and the statements set forth herein under the caption "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" regarding the Company's anticipated
future financial position and cash requirements. Although the Company believes
that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to have
been correct. Important factors that could cause actual results to differ
materially from the Company's expectations ("Cautionary Statements") are
disclosed in this Annual Report and in other filings by the Company with the
Securities and Exchange Commission (the "Commission") including, without
limitation, in connection with such forward-looking statements. All subsequent
written and oral forward-looking statements attributable to the Company or
persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements. The Company's actual results could differ materially from
those anticipated in these forward-looking statements as a result of the risk
factors set forth below and other factors set forth in or incorporated by
reference in this Annual Report. These factors include:
- the cyclical nature of the oil and natural gas industries
- uncertainties associated with the United States and worldwide economies
- current and potential governmental regulatory actions in countries where
the Company owns an interest
- substantial competitor production increases resulting in oversupply and
declining prices
- the Company's ability to implement cost reductions
- the Company's ability to raise additional capital or sell assets
- operating interruptions (including leaks, explosions, fires, mechanical
failure, unscheduled downtime, transportation interruptions, and spills
and releases and other environmental risks)
- fluctuations in foreign currency exchange rates in areas of the world
where the Company owns an interest, particularly Southeast Asia
- covenant restrictions in the Company's indebtedness
- the impact of the Year 2000 issue
Many of those factors are beyond the Company's ability to control or
predict. Management cautions against putting undue reliance on forward-looking
statements or projecting any future results based on such statements or present
or prior earnings levels.
All subsequent written and oral forward-looking statements attributable to
the Company and persons acting on the Company's behalf are qualified in their
entirety by the cautionary statements contained in this section and elsewhere in
this Annual Report.
2
CERTAIN DEFINITIONS
As used in this Annual Report, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel, "MBbls"
means thousand barrels and "MMBbls" means million barrels. "BOE" means barrel of
oil equivalent, "Mcfe" means thousand cubic feet of natural gas equivalent,
"MMcfe" means million cubic feet of natural gas equivalent and "Bcfe" means
billion cubic feet of natural gas equivalent. Natural gas equivalents and crude
oil equivalents are determined using the ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids ("NGL"). References to "$"
and "dollars" refer to United States dollars. All estimates of reserves
contained in this Annual Report, unless otherwise noted, are reported on a "net"
basis. Information regarding production, acreage and numbers of wells are set
forth on a gross basis, unless otherwise noted.
3
ITEM 1. BUSINESS
The Company was incorporated in 1970 and is engaged in oil and gas
exploration, development and production activities on its properties located
offshore in the Gulf of Mexico, onshore in selected areas in New Mexico, Texas
and Louisiana, and internationally, primarily in the Gulf of Thailand and in
Canada. As of December 31, 1998, the Company had interests in 105 lease blocks
offshore Louisiana and Texas, approximately 419,000 gross acres onshore in the
United States and Canada, approximately 847,000 gross acres offshore in the
Kingdom of Thailand and approximately 113,000 gross acres in the British North
Sea. On August 17, 1998, a wholly owned subsidiary of the Company merged with
and into Arch Petroleum Inc. ("Arch") in a stock-for-stock tax-free merger
accounted for as a purchase.
As of December 31, 1998, four significant operating areas, including the
Outer Continental Shelf area of the Gulf of Mexico offshore Louisiana and Texas
in water depths less than 600 feet (the "Shelf") and on the continental slope in
water depths ranging from 600 feet to approximately 4,500 feet (the "Continental
Slope"), the Permian Basin area in New Mexico and Block B8/32 Concession in the
Kingdom of Thailand (the "Thailand Concession), accounted for approximately 76%
of the Company's estimated proved natural gas reserves, approximately 97% of the
Company's estimated proved oil, condensate and natural gas liquids reserves,
approximately 78% of the Company's 1998 natural gas production and 94% of the
Company's 1998 oil, condensate and natural gas liquids production. Reserves, as
estimated by Ryder Scott, and production data, as estimated by the Company, for
the four significant operating areas are shown in the following table. The
percentages presented on the table are the percentage of the Company's total net
proved natural gas and liquids reserves, natural gas and liquids production and
total proved reserves, respectively.
SIGNIFICANT OPERATING AREAS
1998 AVERAGE NET
NET PROVED RESERVES(A) DAILY PRODUCTION
------------------------------------------ ------------------------------------------
NATURAL GAS LIQUIDS(B) NATURAL GAS LIQUIDS(B)
-------------------- -------------------- -------------------- --------------------
MMCF % MBBLS % MCF % BBLS %
--------- --------- --------- --------- --------- --------- --------- ---------
DOMESTIC
Gulf of Mexico--Shelf.................... 90,579 20.6 13,711 20.3 76,630 48.2 9,915 54.5
Gulf of Mexico--Continental Slope........ 34,000 7.7 1,691 2.5 -- -- -- --
New Mexico............................... 43,202 9.8 16,226 24.0 10,667 6.7 4,631 25.4
INTERNATIONAL
Kingdom of Thailand...................... 168,389 38.3 33,811 50.1 36,774 23.1 2,561 14.1
--------- --- --------- --- --------- --- --------- ---
TOTAL...................................... 336,170 76.4 65,439 96.9 124,071 78.0 17,107 94.0
--------- --- --------- --- --------- --- --------- ---
--------- --- --------- --- --------- --- --------- ---
TOTAL
PROVED
RESERVES(A)
%
-------------
DOMESTIC
Gulf of Mexico--Shelf.................... 20.4
Gulf of Mexico--Continental Slope........ 5.2
New Mexico............................... 16.6
INTERNATIONAL
Kingdom of Thailand...................... 43.9
---
TOTAL...................................... 86.1
---
---
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(a) Net proved reserves and total net proved reserves are each as of December
31, 1998.
(b) "Liquids," includes oil, condensate and NGL.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 26% of the Company's proved reserves were located as
of December 31, 1998. During 1998, approximately 48% of the Company's natural
gas production and approximately 55% of its oil and condensate production was
from its domestic offshore properties, contributing approximately 53% of the
Company's consolidated oil and gas revenues. Although the Company's operations
were historically focused on the Shelf where it owns interests in 89 lease
blocks, the Company has recently expanded its exploration efforts further
offshore into the Continental Slope where the Company currently has interests in
16 lease blocks with water depths that range from 600 feet to approximately
4,400 feet.
4
LEASE ACQUISITIONS
The Company has participated, either on its own or with other companies, in
bidding on and acquiring interests in federal and state leases offshore in the
Gulf of Mexico since December 1970. As a result of such purchases and subsequent
activities, as of December 31, 1998, the Company owned interests in 97 federal
leases and 8 state leases offshore Louisiana and Texas. Federal leases generally
have primary terms of five, eight or ten years, depending on water depth, and
state leases generally have terms of three or five years, depending on location,
in each case subject to extension by development and production operations.
As part of its strategy, the Company intends to continue an active lease
evaluation program in the Gulf of Mexico in order to identify exploration and
exploitation opportunities. During 1998, the Company was successful in acquiring
interests in four lease blocks through federal Outer Continental Shelf oil and
gas lease sales and one lease block by assignment from a third party. As in the
case of prior sales, the extent to which the Company participates in future
bidding on federal or state offshore lease sales will depend on the availability
of funds and its estimates of hydrocarbon deposits, operating expenses and
future revenues which reasonably may be expected from available lease blocks.
Such estimates typically take into account, among other things, estimates of
future hydrocarbon prices, federal regulations, and taxation policies applicable
to the petroleum industry. It is also the Company's objective to acquire certain
producing leasehold properties in areas where additional low-risk drilling or
improved production methods by the Company can provide attractive rates of
return.
EXPLORATION AND DEVELOPMENT
The scope of exploration and development programs relating to the Company's
offshore interests is affected by prices for oil and gas, and by federal, state
and local legislation, regulations and ordinances applicable to the petroleum
industry. The Company's domestic offshore capital and exploration expenditures
for 1998 were approximately $68,000,000 (excluding approximately $5,000,000 of
net property acquisitions), or 21% lower than the Company's domestic offshore
capital and exploration expenditures of approximately $86,300,000 for 1997
(excluding approximately $900,000 of net property acquisitions) and 26% lower
than the Company's domestic offshore capital and exploration expenditures of
approximately $92,400,000 for 1996. The decrease in the Company's domestic
offshore capital and exploration expenditures for 1998, compared with 1997 and
1996, resulted primarily from the Company's decision to decrease its drilling
activity in light of poor oil and gas prices and a decrease in construction and
installation of offshore platforms, pipelines and other facilities. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Leases acquired by the Company and other participants in its bidding groups
are customarily committed, on a block-by-block basis, to separate operating
agreements under which the appointed operator supervises exploration and
development operations for the account and at the expense of the group. These
agreements usually contain terms and conditions which have become relatively
standardized in the industry. Major decisions regarding development and
operations typically require the consent of at least a majority (in working
interest) of the participants. Because the Company generally has a meaningful
working interest position, the Company believes it can significantly influence
(but not always control) decisions regarding development and operations on most
of the leases in which it has a working interest even though it may not be the
operator of a particular lease. The Company is the operator on all or a portion
of 27 of the 105 offshore leases in which it had an interest on December 31,
1998.
Platforms and related facilities are installed on an offshore lease block
when, in the judgment of the lease interest owners, the necessary capital
expenditures are justified. A decision to install a platform generally is made
after the drilling of one or more exploratory wells with contracted drilling
equipment. Platform costs vary depending on, among other factors, the number of
slots, water depth, currents, and sea floor conditions. Over the four years
ended December 31, 1998, the gross construction and installation cost of
production platforms and related facilities located on the Shelf in which the
Company shared a portion of the construction costs based on its ownership
interest in the development ranged from approximately $3,000,000 to
approximately $16,500,000. Wells, platforms and related facilities are typically
much more
5
expensive on the Continental Slope. The Company is currently participating in
the construction of one platform, one sub-sea development and related facilities
on the Continental Slope at a total capital commitment of $204,045,000 dollars
($30,341,000 net to the Company's working interest), of which approximately 38%
has been incurred through December 31, 1998. The Company believes that future
development projects on the Continental Slope may require similar capital
commitments, each of which must be justified in the then current and anticipated
future product price environment. In order to better manage the risks of large
projects on the Continental Slope, the Company generally seeks to have a smaller
ownership interest in these lease blocks than it averages in shallower waters.
SIGNIFICANT DOMESTIC OFFSHORE OPERATING AREAS DURING 1998
OUTER CONTINENTAL SHELF. The Outer Continental Shelf has been an important
part of the Company's operations since the first lease in that area was
purchased in 1970 and production began in 1973. As of December 31, 1998, the
Company held interests in 89 blocks on the Shelf. The Company currently has 215
oil and gas wells producing from multiple reservoirs and horizons on the Shelf.
During 1998, the Company participated in the drilling of five wells on the
Shelf, the setting of one production platform and related facilities and the
upgrading of three platforms.
CONTINENTAL SLOPE. Since 1996 when the Company acquired its first interest
in a lease block in the Continental Slope, the Company has been increasingly
active in this area. As of December 31, 1998, the Company owns interests in 16
blocks in the Continental Slope and has interests in five wells that it has
drilled there, including three that were drilled in 1998. The Company is
currently participating in the construction of one platform and related
facilities at Viosca Knoll Blocks 780 and 823, and one subsea facility on Garden
Banks 367, on the Continental Slope.
ONSHORE OPERATIONS
The Company has onshore division staffs in Houston and Midland, Texas and
Calgary, Canada. Its onshore activities are concentrated in known oil and gas
provinces, principally the Permian Basin area of southeastern New Mexico, West
Texas and Northwest Texas, in the onshore Gulf Coast areas of South Texas, East
Texas and South Louisiana and in Alberta and British Columbia in Canada. The
Company conducts its onshore operations in the United States directly and
through its wholly owned subsidiary Arch. The Company conducts its operations in
Canada through its wholly-owned subsidiary, Pogo Canada Ltd. See "--Significant
Onshore Operating Areas During 1998."
LEASE ACQUISITIONS
Commencing in 1995 and continuing into 1998, the Company increased its
activities in the onshore Gulf Coast areas of East Texas and South Louisiana
through its participation in several large proprietary 3-D seismic surveys, in
connection with which the Company typically purchases an option to acquire an
interest in the acreage covered by the 3-D seismic survey. As it has in recent
years, in 1998 the Company also successfully participated in various onshore
federal, state and provincial lease sales and acquired interests in prospective
acreage from private individuals. As of December 31, 1998, the Company held
interests in approximately 303,000 gross (151,000 net) acres onshore in the
United States and 117,000 gross (51,000 net) acres in Canada, an increase of
approximately 76% from year end 1997. The increase in acreage is primarily
related to the Company's acquisition of Arch and, to a lesser extent, the
Company's successful participation in the lease sales and private property
acquisitions described above, that was partially offset by the sale of certain
properties that it no longer considered strategic and the expiration of leases
in the ordinary course of business.
EXPLORATION AND DEVELOPMENT
The Company's primary drilling objective in the Permian Basin is the Brushy
Canyon (Delaware) formation which generally produces oil from depths of 6,000 to
9,000 feet. Since the Company began exploring in the Brushy Canyon (Delaware)
formation in October 1989, it has participated in drilling 389
6
wells in the Permian Basin, West and Northwest Texas areas through December 31,
1998, including 32 wells in 1998. See "--Significant Domestic Onshore Operating
Areas During 1998."
In Southwest Louisiana, the Company participated in drilling 20 wells since
1996, including seven wells in 1998, to test various prospects, primarily in the
Hackberry and Yegua formations, almost all of which were identified on
proprietary 3-D seismic surveys that the Company and its industry partners have
acquired since 1995.
Onshore reserves as of December 31, 1998, accounted for approximately 31% of
the Company's total proved reserves. During 1998, approximately 29% of the
Company's natural gas production and 31% of its oil and condensate production
was from its onshore properties, contributing approximately 30% of the Company's
consolidated oil and gas revenues.
The Company generally conducts its onshore activities through joint ventures
and other interest-sharing arrangements with major and independent oil
companies. The Company operates many of its own onshore properties using
independent contractors.
The Company's onshore capital and exploration expenditures were
approximately $48,800,000 (excluding approximately $133,100,000 of net property
acquisitions, including approximately $131,500,000 related to the acquisition of
Arch) for 1998, or 19% lower than the Company's onshore capital and exploration
expenditures of approximately $60,000,000 (excluding approximately $1,700,000 of
net property acquisitions) for 1997 and 4% higher than the Company's onshore
capital and exploration expenditures of approximately $47,000,000 (excluding
approximately $3,800,000 of net property acquisitions) for 1996. The decrease in
the Company's onshore capital and exploration expenditures for 1998, compared to
1997, resulted primarily from the Company's decision to curtail non-essential
drilling in light of poor oil and gas prices, that was not entirely offset by
capital and exploration expenditures in Canada where the Company acquired its
interest in Pogo Canada Ltd. in August 1998. The increase in capital and
exploration expenditures for 1998, compared to 1996, primarily related to
capital and exploration expenditures in Canada where the Company acquired an
interest during 1998 as part of the Arch acquisition.
SIGNIFICANT ONSHORE OPERATING AREAS DURING 1998
NEW MEXICO. The Company believes that during the past six years it has been
one of the most active companies drilling for oil and natural gas in the
southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin
where the Company has interests in over 105,000 gross acres. The Company's
primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in
the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of
the Permian Basin are generally characterized by production from relatively
shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and
relatively high initial rates of production (frequently equaling the top field
allowables which typically range from 142 Bbls to 230 Bbls per day, depending on
the depth of production from the field). The Company has achieved rapid cost
recovery with respect to its New Mexico wells drilled to date because of
relatively low capital costs and high initial rates of production.
LOPENO FIELD. The Company acquired its initial interest in the Lopeno Field
in 1983. The Lopeno Field is located within 40 miles of the border with Mexico,
in 1983. As of December 31, 1998, the Company had interests in 29 producing
wells in the Lopeno Field. The Lopeno Field produces from over 20 upper Wilcox
sandstone reservoirs ranging in depth up to 12,500 feet. In late 1998, the
Company decided to sell its interest in the Lopeno Field as part of its asset
rationalization efforts. The Company currently expects to sell its interest by
March 15, 1999, effective back to January 1, 1999. Proceeds from the sale will
be used to reduce the Company's total debt and for general corporate purposes.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas throughout the world. Currently, the
Company maintains an office in Bangkok, Thailand from which it directs field
operations on the Thailand Concession through its wholly owned subsidiary
7
Thaipo Limited ("Thaipo"). Thaipo currently owns, directly or indirectly, a
46.34% working interest in the entire Thailand Concession. The remainder of the
working interest is owned, directly or indirectly by Thai Romo Ltd. (46.34%), a
subsidiary of Rutherford-Moran Oil Corporation ("RMOC"), and Palang Sophon
Limited ("Palang") (7.32%). RMOC has entered into an agreement to merge with,
and become, a wholly owned subsidiary of Chevron Corporation ("Chevron"). It is
the Company's understanding that Chevron will also acquire a majority of the
stock of Palang. Based on publicly available information and communications with
Chevron, RMOC and Palang, it is the Company's current understanding that
Chevron's merger with RMOC, and its acquisition of a majority interest in
Palang, will be consummated on or shortly after March 17, 1999. Following these
transactions, Chevron will own or control, directly or indirectly, 53.66% of the
working interests in the Thailand Concession. Thaipo is currently the operator
of the Thailand Concession, pursuant to the joint operating agreement governing
the Thailand Concession and as designated by the government of Thailand. Subject
to approval by the government of Thailand and the agreement of the parties to
the joint operating agreement, Thaipo has agreed to transfer operatorship to a
subsidiary of Chevron on or about September 30, 1999. In addition, Chevron has
agreed to lend funds to RMOC to cover its cash call obligations under the joint
operating agreement until Chevron's merger with RMOC is consummated. As of
December 31, 1998, the Company's proved reserves located in the Kingdom of
Thailand accounted for approximately 44% of the Company's total proved reserves.
During 1998, approximately 29% of the Company's natural gas production and 31%
of its oil and condensate production came from its operations on the Thailand
Concession, contributing approximately 17% of the Company's consolidated oil and
gas revenues.
EXPLORATION AND DEVELOPMENT
The Company's international capital and exploration expenditures were
approximately $107,400,000 for 1998, or 22% higher than the Company's
international capital and exploration expenditures of approximately $88,300,000
for 1997 (excluding approximately $28,600,000 of net property acquisitions) and
67% higher than the Company's international capital and exploration expenditures
of approximately $64,400,000 (excluding approximately $4,200,000 of net property
acquisitions) for 1996. The increase in the Company's international capital and
exploration expenditures for 1998, compared to 1997 and 1996, resulted primarily
from increased platform and facilities construction costs related to development
of the Benchamas Field and increased drilling activity in the Tantawan and
Benchamas Fields. Substantially all of the Company's international capital and
exploration expenditures for 1998 were related to the Company's license in the
Kingdom of Thailand. On December 1, 1998, the Company together with two joint
partners, were successful in obtaining a license from the United Kingdom
governing approximately 113,000 acres in the British sector of the North Sea.
Terms of the license provided for a minimum work commitment that will involve
the acquisition, processing and interpretation of 3-D seismic data over the
block. The initial exploratory term of this license expires on December 1, 2004,
unless otherwise extended or a production license is granted. In addition, the
Company continues to evaluate other international opportunities that are
consistent with the Company's international exploration strategy and expertise.
Platforms are installed on the Thailand Concession in fields where, in the
judgment of Thaipo and its joint venture partners, the necessary capital
expenditures are justified. A decision to install a platform generally is made
after the drilling of one or more exploratory wells with contracted drilling
equipment and the area where the platform would be located has been designated a
production area by the government of the Kingdom of Thailand. See "--Contractual
Terms Governing the Thailand Concession and Related Production." Platforms are
used to accommodate both development drilling and additional exploratory
drilling. Over the four years ended December 31, 1998, the gross cost of the
first five production platforms and related facilities in the Tantawan Field has
averaged approximately $20,000,000. The Company is currently participating in
the construction of platforms and related facilities for the Benchamas Field at
a total capital commitment of $267,470,000 dollars ($123,946,000 net to the
Company's working interest), of which approximately 67% has been incurred
through December 31, 1998. The Company and its joint venture partners have been
working to employ advanced platform facility design and advanced drilling and
completion techniques, including slimhole, batch and horizontal drilling, to
reduce the cost of developing the Thailand Concession. The Company believes that
future satellite platforms and related facilities may
8
be installed for as little as approximately $13,000,000 per platform in the
future. Platform costs vary and more (or less) expensive platforms could be
required in the future depending on, among other factors, the number of slots,
water depth, currents, and sea floor conditions. See "--Significant
International Operating Areas During 1998; Tantawan Field."
SIGNIFICANT INTERNATIONAL OPERATING AREAS DURING 1998
TANTAWAN FIELD. In August 1995, at the request of Thaipo and its joint
venture partners, the government of Thailand designated a portion of the
Thailand Concession comprising approximately 68,000 acres as the Tantawan
production area or the "Tantawan Field." Initial production from the Tantawan
Field commenced on February 1, 1997. Currently, there are 28 wells producing
from four platforms. The Company is currently planning to install a fifth
platform in the Tantawan Field from which production is expected to commence in
the first half of 1999.
Oil and gas production from the Tantawan Field is gathered through pipelines
from the platforms into a Floating Production Storage and Offloading system (an
"FPSO") named the "Tantawan Explorer." The FPSO is a converted oil tanker with a
capacity of slightly less than 1,000,000 Bbls, that is moored in the Tantawan
Field, on which hydrocarbon processing, separation, dehydration, compression,
metering and other production related equipment is installed. Following
processing on board the FPSO, natural gas produced from the field is delivered
to The Petroleum Authority of Thailand ("PTT") through an export pipeline. Oil
and condensate produced from the field is stored on board the FPSO and
transferred to shore by oil tanker. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources."
BENCHAMAS FIELD AND THE MALIWAN PRODUCTION AREA. In July 1997, the
government of Thailand designated another portion of the Thailand Concession
comprising approximately 102,000 acres as the Benchamas and Pakakrong production
area or the "Benchamas Field." In September 1997, the government of Thailand
designated an additional 91,000 acres of the Thailand Concession as the Maliwan
production area. Current development plans call for the staged development of
these fields, with the Benchamas Field to be brought on production first. The
Benchamas Field development plan contemplates the initial installation of three
production platforms, with natural gas and oil from these platforms delivered by
undersea pipeline to a central processing and compression platform where the
oil, condensate and natural gas will be processed and separated. The natural gas
will then be sold to PTT and delivered into export pipelines for transportation
to shore, while the oil and condensate produced from the field will be stored on
board a Floating Storage and Offloading system ("FSO"), known as the "Benchamas
Explorer," for sale and ultimate transfer to shore by oil tanker. The FSO will
be moored in the Benchamas Field. Its capacity will be approximately 1,400,000
Bbls of crude and condensate. The Benchamas Field's current development plan
calls for initial production to commence in the third quarter of 1999 with
production from the Maliwan production area to begin in late 2001.
OTHER AREAS. In addition to the above mentioned fields, Thaipo and its
joint venture partners have identified other potentially promising areas on the
Thailand Concession. Since acquiring their interest in the Thailand Concession,
Thaipo and its joint venture partners have acquired 3-D seismic surveys covering
approximately 673,650 acres of the Thailand Concession, including 221,650 acres
during the fourth quarter of 1997 over what is known as the Jarmjuree area.
Through February 1, 1999, Thaipo and its joint venture partners have drilled
eight wells on areas of the Thailand Concession that are not currently
designated as production areas. Interpretation of the data provided by these
wells and 3-D seismic data covering these areas is ongoing. Thaipo and its joint
venture partners also currently plan to drill additional exploration wells in
these areas during 1999.
CONTRACTUAL TERMS GOVERNING THE THAILAND CONCESSION AND RELATED PRODUCTION
The Thailand Concession was granted in August 1991. The exploratory term for
those portions of the Thailand Concession that have not yet been designated a
production area (comprising approximately 474,000 acres) expires July 31, 2000.
For those portions of the Thailand Concession that have been designated as
production areas, the initial production period term is 20 years, which is also
subject to
9
extension, generally for a term of ten years. See also "--Miscellaneous; Sales."
Currently, the Tantawan, Maliwan, and Benchamas and Pakakrong areas have been
designated as production areas. Subject to governmental approval, other portions
of the Thailand Concession may be designated production areas in the future.
Production resulting from the Thailand Concession is subject to a royalty
ranging from 5% to 15% of oil and gas sales, plus certain fixed U.S. dollar
amounts payable at specified cumulative production levels. Revenue from
production in Thailand is also subject to income taxes and other similar
governmental charges including a Special Remuneratory Benefit tax ("SRB").
Thaipo and its joint venture partners have entered into a thirty-year Gas
Sales Agreement with PTT (the "Gas Sales Agreement"), governing gas production
from the Tantawan Field and anticipated gas production from the Benchamas Field.
The terms of the Gas Sales Agreement currently include a minimum daily contract
quantity ("DC") of 85 MMcf per day, which the Company currently anticipates will
continue until the Benchamas Field commences production, at which time the DC
will, subject to certain exceptions, be based on a percentage of the remaining
proved reserves, but in any event, will not be less than 125 MMcf per day. The
DC is the minimum daily volume that PTT has agreed to take, or pay for if not
taken, under the agreement. Likewise, Thaipo and its joint venture partners are
subject to certain penalties if they are unable to meet the DC, principal among
which is a decrease in sales price of up to 25% of the then current sales price.
As a result of declining production from existing wells in the Tantawan Field,
the need to shut-in existing wells while drilling additional wells from the same
platform, and the decision to emphasize oil and condensate production from the
Tantawan Field, commencing on October 1, 1998, the Company and its joint venture
partners are currently delivering less natural gas than is being nominated by
PTT under the Gas Sales Agreement. This could result in the Company receiving
only 75% of the current contract price on a portion of its future natural gas
sales to PTT. The Company is taking actions that it currently believes will
minimize the penalty that it will incur on future gas sales to PTT by increasing
production from the Tantawan Field. The contract sales price is subject to
automatic semi-annual adjustments based upon a formula which takes into account
changes in: Singapore fuel oil prices; the U.S. Bureau of Labor Statistics
Oilfield Machinery and Tool Index; the Thai wholesale producer price index; and
the U.S./Thai currency exchange rate. However, the Gas Sales Agreement provides
for adjustment on a more frequent basis in the event that certain indices and
factors on which the price is based fluctuate outside a given range. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations; Foreign Currency Transaction Gain (Loss)" and
"--Liquidity and Capital Resources; Other Matters; Southeast Asia Economic
Issues."
MISCELLANEOUS
OTHER ASSETS
The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in
eight pipelines (excluding field gathering pipelines) through which offshore
hydrocarbon production is transported. Through a wholly-owned subsidiary,
Saginaw Pipeline Company, L.C. ("Saginaw"), which the Company acquired in its
merger with Arch, the Company owns and operates the Saginaw pipeline, a six
inches in diameter pipeline that runs from just outside of Fort Worth, Texas to
Wichita Falls, Texas. Industrial Natural Gas, L.C., a subsidiary of Saginaw,
markets the sale and transmission of natural gas through the Saginaw pipeline.
In addition, the Company owns an approximately 19% interest in a cryogenic
gas processing plant near Erath, Louisiana, which entitles it to process up to
186 MMcf of natural gas and 5,478 Bbls of natural gas liquids per day. The plant
is not currently operating at full capacity.
SALES
The marketing of offshore oil and gas production is subject to the
availability of pipelines and other transportation, processing and refining
facilities, as well as the existence of adequate markets. As a result, even if
hydrocarbons are discovered in commercial quantities, a substantial period of
time may elapse before commercial production commences. If pipeline facilities
in an area are insufficient, the Company
10
may have to await the construction or expansion of pipeline capacity before
production from that area can be marketed. The Company's domestic offshore
properties are generally located in areas where a pipeline infrastructure is
well developed and there is adequate availability in such pipelines to transport
the Company's current and projected future production.
The Company's Thailand Concession is traversed by two major (34 inches and
36 inches in diameter, respectively) natural gas pipelines that are owned and
operated by PTT and which come within approximately 25 miles of the Tantawan
Field (and are slightly closer to the Benchamas Field). Thaipo and its joint
venture partners in the Tantawan Field signed a long-term gas sales contract
with PTT in November 1995 which has since been amended to include production
from the Benchamas Field. All oil and condensate production from the Tantawan
Field is initially stored aboard the FPSO and is then sold to various third
parties, including PTT, on a tanker load by tanker load basis at prices based on
then current world oil prices, typically with reference to the Malaysian Tapis
crude oil benchmark price. The buyer is responsible for sending a tanker to off
load the oil and condensate it has purchased. It is currently anticipated that
when the Benchamas Field commences production, crude oil and condensate
production from the Benchamas Field will be initially stored aboard the FSO and
a portion of such production will be sold under a long-term contract with a
single buyer and a portion will continue to be sold on a tanker load by tanker
load basis, similar to the way Tantawan Field crude is currently marketed. See
"--International Operations; Contractual Terms Governing the Thailand Concession
and Related Production."
The marketing of onshore oil and gas production is also subject to the
availability of pipelines, crude oil hauling and other transportation,
processing and refining facilities as well as the existence of adequate markets.
Generally, the Company's onshore oil and gas production is located in areas
where commercial production of economic discoveries can be rapidly effectuated.
Most of the Company's North American natural gas sales are currently made in
the "spot market" for no more than one month at a time at then currently
available prices. Prices on the spot market fluctuate with demand. Crude oil and
condensate production is also generally sold one month at a time at the price
that is then currently available. Other than any futures contracts which may
exist from time to time, and which are referred to in "--Miscellaneous;
Competition and Market Conditions," and the Gas Sales Agreement with PTT for
production from the Tantawan and Benchamas Fields (see "--International
Operations; Contractual Terms Governing the Thailand Concession and Related
Production"), the Company has no existing contracts that require the delivery of
fixed quantities of oil or natural gas other than on a best efforts basis. Enron
Corp. and its affiliates and PTT, who purchased $29,539,000 (15% of the
Company's consolidated gross revenues) and $23,137,000 (12% of the Company's
consolidated gross revenues) of the Company's oil and gas production during
1998, respectively, were the Company's only customers to which sales exceeded
10% of its 1998 revenues. The oil and gas sold to Enron Corp. and its affiliates
was sold under a number of short term, generally month to month, contracts.
COMPETITION AND MARKET CONDITIONS
The Company experiences competition from other oil and gas companies in all
phases of its operations, as well as competition from other energy related
industries. The Company's profitability and cash flow are highly dependent upon
the prices of oil and natural gas, which historically have been seasonal,
cyclical and volatile. In general, prices of oil and gas are dependent upon
numerous factors beyond the control of the Company, including various weather,
economic, political and regulatory conditions. In the past, when natural gas
prices in the United States were low, the Company at times elected to curtail
certain quantities of its production. In the future, the Company may again elect
to curtail certain quantities of its natural gas production. Current low oil
prices continue to have a material adverse effect on the Company's cash flows
and, if sustained for a significant length, could have a material adverse effect
on the Company's operations and financial condition and may result in a further
reduction in funds available under the Company's credit agreement.
Because it is impossible to predict future oil and gas price movements with
any certainty, the Company from time to time enters into contracts on a portion
of its production to hedge against the volatility in oil and gas prices. Such
hedging transactions, historically, have never exceeded 50% of the Company's
total oil and gas production on an energy equivalent basis for any given period.
While intended
11
to limit the negative effect of price declines, such transactions could
effectively limit the Company's participation in price increases for the covered
period, which increases could be significant. As of December 31, 1998, the
Company was not a party to any natural gas futures contracts, crude oil swap
agreements or other commodity hedging arrangements. When the Company does engage
in such hedging activities, it may satisfy its obligations with its own
production or by the purchase (or sale) of third party production. The Company
may also cancel all delivery obligations by offsetting such obligations with
equivalent agreements, thereby effecting a purely cash transaction.
OPERATING AND UNINSURED RISKS
The Company's operations are subject to risks inherent in the exploration
for and production of oil and natural gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
pollution and other environmental risks. Offshore oil and gas operations are
subject to the additional hazards of marine and helicopter operations, such as
capsizing, collision and adverse weather and sea conditions. These hazards could
result in substantial losses to the Company due to injury or loss of life,
severe damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations. The Company carries insurance
which it believes is in accordance with customary industry practices, but is not
fully insured against all risks incident to its business.
Drilling activities are subject to numerous risks, including the risk that
no commercially productive hydrocarbon reserves will be encountered. The cost of
drilling, completing and operating wells and of installing production facilities
and pipelines is often uncertain. The Company's drilling operations may be
curtailed, delayed or canceled as a result of numerous factors, including title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery or availability of material, equipment and
fabrication yards. The availability of a ready market for the Company's natural
gas production depends on a number of factors, including the demand for and
supply of natural gas, the proximity of natural gas reserves to pipelines, the
capacity of such pipelines and government regulations.
Due to the recent decline in oil and gas prices, many of the Company's
partners, particularly the smaller ones, are experiencing liquidity and cash
flow problems. These problems may lead to their attempting to delay or slow down
the pace of drilling or project development in order to conserve cash, to a
point that the Company believes is detrimental to the project. In most cases,
the Company has the ability to influence the pace of development through joint
operating agreements. Some partners may be unwilling or unable to pay their
share of the costs of projects as they become due. At worst, a partner may
declare bankruptcy and refuse or be unable to pay its share of the costs of a
project. The Company would then be required to pay this partner's share of the
project costs. In most instances, the Company believes that it is contractually
protected from such an event through its ability to take over the non-paying
partner's share of the project and by applicable oil and gas lien laws and
bankruptcy laws. The Company believes that it would ultimately recover any sums
that it is owed by non-paying partners that do not meet their share of the costs
of a project in a timely fashion.
RISKS OF FOREIGN OPERATIONS
Ownership of property interests and production operations in Thailand and
Canada, and in any other areas outside the United States in which the Company
may choose to do business, are subject to the various risks inherent in foreign
operations. These risks may include, among other things, currency restrictions
and exchange rate fluctuations, loss of revenue, property and equipment as a
result of hazards such as expropriation, nationalization, war, insurrection and
other political risks, risks of increases in taxes and governmental royalties,
renegotiation of contracts with governmental entities, changes in laws and
policies governing operations of foreign-based companies and other uncertainties
arising out of foreign government sovereignty over the Company's international
operations. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Results of Operations; Foreign Currency Transaction Gain
(Loss)," and "--Liquidity and Capital Resources; Other Matters; Southeast Asia
Economic Issues." The Company's international operations may also be adversely
affected by laws and policies of the United States affecting foreign trade,
taxation and investment. In addition, in the event of a dispute arising from
foreign operations, the Company may be subject to the exclusive jurisdiction of
12
foreign courts or may not be successful in subjecting foreign persons to the
jurisdiction of the courts of the United States. The Company seeks to manage
these risks by concentrating its international exploration efforts in areas
where the Company believes that the existing government is stable and favorably
disposed towards United States exploration and production companies.
EXPLORATION AND PRODUCTION DATA
In the following data "gross" refers to the total acres or wells in which
the Company has an interest and "net" refers to gross acres or wells multiplied
by the percentage working interest owned by the Company.
ACREAGE
The Company owns interests in developed and undeveloped oil and gas acreage
in various parts of the world. These ownership interests generally take the form
of "working interests" in oil and gas leases which have varying terms. In
addition, the Company holds certain other types of mineral interests, including
fee interests (which never expire) and royalty interests (which generally
terminate when the underlying mineral lease expires). The Company owns varying
fee and royalty interests in 10,800 gross acres in Texas and a royalty interest
in 5,000 gross acres (1,250 net acres) offshore Louisiana. The following table
shows the Company's interest in developed and undeveloped oil and gas acreage
under lease as of December 31, 1998:
DEVELOPED UNDEVELOPED
ACREAGE(A) ACREAGE(B)
-------------------- ---------------------
GROSS NET GROSS NET
--------- --------- ---------- ---------
Onshore
Louisiana..................................... 2,745 559 20,146 6,338
New Mexico.................................... 31,102 20,336 74,297 55,302
Texas......................................... 37,257 14,133 133,198 54,114
Canada........................................ 22,921 2,817 93,814 48,413
Other......................................... 3,400 334 478 56
--------- --------- ---------- ---------
Total Onshore............................... 97,425 38,179 321,933 164,223
--------- --------- ---------- ---------
Domestic Offshore
Louisiana (State)............................. 5,463 2,642 1,169 584
Louisiana (Federal)........................... 166,570 54,267 167,056 56,389
Texas (Federal)............................... 40,320 11,678 74,185 20,850
--------- --------- ---------- ---------
Total Domestic Offshore..................... 212,353 68,587 242,410 77,823
--------- --------- ---------- ---------
Total North America......................... 309,778 106,766 564,343 242,046
--------- --------- ---------- ---------
International
North Sea..................................... -- -- 112,729 45,091
Gulf of Thailand.............................. 260,407 120,682 473,733 219,530
--------- --------- ---------- ---------
Total International......................... 260,407 120,682 586,462 264,621
--------- --------- ---------- ---------
Total Company............................... 570,185 227,448 1,150,805 506,667
--------- --------- ---------- ---------
--------- --------- ---------- ---------
- ------------------------
(a) ("Developed acreage" consists of lease acres spaced or assignable to
production (including acreage held by aproduction) on which wells have been
drilled or completed to a point that would permit production of commercial)
quantities of oil or natural gas. "Developed acreage" in Thailand includes
all acreage designated as a production area by the Thai government, which
currently includes the Tantawan, Maliwan, Benchamas and Pakakrong production
areas.
13
(b) ("Undeveloped acreage" includes acreage under lease or subject to lease or
purchase options that the Company bcurrently expects to exercise.
Approximately 9% of the Company's total domestic offshore net undeveloped
acreage is )under leases that have terms expiring in 1999 (unless otherwise
extended) and another approximately 12% of total domestic offshore net
undeveloped acreage will expire in 2000 (unless otherwise extended).
Approximately 11% of the Company's total onshore net undeveloped acreage is
under leases that have terms expiring in 1999 (unless otherwise extended)
and another approximately 14% of total onshore net undeveloped acreage will
expire in 2000 (unless otherwise extended). All of the Company's undeveloped
acreage in the Kingdom of Thailand must be relinquished to the Thai
government on July 31, 2000, unless designated as a production area or
unless the exploration term is extended. See "--International Operations;
Contractual Terms Governing the Thailand Concession and Related Production."
PRODUCTIVE WELLS AND DRILLING ACTIVITY
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1998. For purposes of this table
"productive wells" are defined as wells producing hydrocarbons and wells
"capable of production" (e.g., natural gas wells waiting for pipeline
connections or necessary governmental certification to commence deliveries and
oil wells waiting to be connected to currently installed production facilities).
This table does not include exploratory or developmental wells which have
located commercial quantities of oil or natural gas but which are not capable of
commercial production without the installation of material production facilities
or which, for a variety of reasons, the Company does not currently believe will
be placed on production.
NATURAL GAS
OIL WELLS(A) WELLS(A)
-------------------- ----------------------
GROSS NET GROSS NET
--------- --------- ----------- ---------
Offshore United States........................... 125 34.2 90 27.1
Onshore (U.S. and Canada)........................ 901 454.4 189 75.7
Kingdom of Thailand.............................. -- -- 28 13.1
--------- --------- --- ---------
Total........................................ 1,026 488.6 307 115.9
--------- --------- --- ---------
--------- --------- --- ---------
- ------------------------
(a) One or more completions in the same bore hole are counted as one well. The
data in the above table includes five gross (.6 net) oil wells and 45 gross
(20.4 net) natural gas wells with multiple completions.
The following table shows the number of successful gross and net exploratory
and development wells in which the Company has participated and the number of
gross and net wells abandoned as dry holes during the periods indicated. An
onshore well is considered successful upon the installation of permanent
equipment for the production of hydrocarbons or when electric logs run to
evaluate such wells indicate the presence of commercial hydrocarbons and the
Company currently intends to complete such wells. Successful offshore wells
consist of exploratory or development wells that have been completed or are
"suspended" pending completion (which has been determined to be feasible and
economic) and exploratory test wells that were not intended to be completed and
that encountered commercially producible
14
hydrocarbons. A well is considered a dry hole upon reporting of permanent
abandonment to the appropriate agency.
1998 1997 1996
---------------------- ---------------------- ----------------------
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
----------- --------- ----------- --------- ----------- ---------
Gross Wells:
Offshore United States
Exploratory.................................... 5.0 1.0 4.0 1.0 4.0 2.0
Development.................................... 2.0 -- 12.0 3.0 17.0 3.0
Onshore United States and Canada
Exploratory.................................... 9.0 4.0 18.0 12.0 12.0 4.0
Development.................................... 32.0 1.0 50.0 3.0 39.0 1.0
Offshore Kingdom of Thailand
Exploratory.................................... 12.0 -- 18.0 1.0 7.0 --
Development.................................... 12.0 -- 16.0 -- 16.0 --
----- --- ----- --------- --- ---
Total........................................ 72.0 6.0 118.0 20.0 95.0 10.0
----- --- ----- --------- --- ---
----- --- ----- --------- --- ---
Net Wells:
Offshore United States
Exploratory.................................... 1.07 .25 1.21 .25 1.7 1.5
Development.................................... .80 -- 4.15 1.05 4.9 1.5
Onshore United States and Canada
Exploratory.................................... 5.08 2.19 11.27 7.40 6.5 0.9
Development.................................... 22.61 .34 30.18 1.41 24.4 0.7
Onshore Kingdom of Thailand
Exploratory.................................... 5.56 -- 8.34 .46 2.4 --
Development.................................... 5.56 -- 5.11 -- 7.4 --
----- --- ----- --------- --- ---
Total........................................ 40.68 2.78 60.26 10.57 47.3 4.6
----- --- ----- --------- --- ---
----- --- ----- --------- --- ---
PRODUCTION AND SALES
The following table summarizes the Company's average daily production, net
of all royalties, overriding royalties and other outstanding interests, for the
periods indicated. Natural gas production refers only to marketable production
of natural gas on an "as sold" basis.
1998 1997 1996
--------- --------- ---------
Located in the United States and Canada
Natural Gas (Mcf per day)...................................... 122,246 147,200 107,700
--------- --------- ---------
--------- --------- ---------
Liquid Hydrocarbons (Bbls per day)
Crude Oil and Condensate..................................... 13,214 13,712 11,968
Natural Gas Liquids(a)....................................... 2,421 2,923 2,173
--------- --------- ---------
Total North American Liquid Hydrocarbons................... 15,635 16,635 14,141
--------- --------- ---------
--------- --------- ---------
Located in the Kingdom of Thailand
Natural Gas (Mcf per day)...................................... 36,774 34,500 --
--------- --------- ---------
--------- --------- ---------
Liquid Hydrocarbons (Bbls per day)
Crude Oil and Condensate..................................... 2,561 2,216 --
--------- --------- ---------
--------- --------- ---------
- ------------------------
(a) NGL production sales includes sales attributable to both the Company's
leasehold and plant ownership.
15
The following table shows the average sales prices received by the Company
for its production and the average production (lifting) costs per unit of
production during the periods indicated. See "--Miscellaneous; Sales" and
"--Miscellaneous; Competition and Market Conditions."
1998 1997 1996
--------- --------- ---------
Sales Prices:
Located in the United States and Canada
Natural Gas (per Mcf)........................................... $ 2.00 $ 2.50 $ 2.40
Crude Oil and Condensate (per Bbl).............................. $ 12.97 $ 19.49 $ 22.12
Natural Gas Liquids (per Bbl)................................... $ 10.52 $ 12.89 $ 14.92
Located in the Kingdom of Thailand
Natural Gas (per Mcf)........................................... $ 1.72 $ 1.93 --
Crude Oil and Condensate (per Bbl).............................. $ 13.17 $ 18.60 --
Production (lifting) Costs(a):
Located in the United States and Canada
Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per
Mcfe)......................................................... $ .61 $ .49 $ .53
Located in the Kingdom of Thailand
Natural Gas, Crude Oil and Condensate (per Mcfe)(b)............. $ 1.10 $ 1.12 --
- ------------------------
(a) Production costs were converted to common units of measure on the basis of
relative energy content. Such production acosts exclude all depletion and
amortization associated with property and equipment.
(b) The major contributing factor to lifting costs are lease operating expenses.
A substantial portion of the Company's blease operating expenses in the
Kingdom of Thailand relate to lease payments made by a subsidiary of the
Company in connection with its bareboat charter of the FPSO, which amounted
to $11,122,000 net to the Company during 1998. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources; Future Capital Requirements; Other Material Long-Term
Commitments."
RESERVES
The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1998, 1997, and 1996, and the
present value as of such dates (based on an annual discount rate of 10%) of the
estimated future net revenues from the production and sale of those reserves, as
estimated by Ryder Scott Petroleum Engineers ("Ryder Scott"), the Company's
independent
16
petroleum engineers, in accordance with criteria prescribed by the Securities
and Exchange Commission ("SEC").
AS OF DECEMBER 31,
----------------------------------
1998 1997 1996
---------- ---------- ----------
Total Proved Reserves:
Oil, condensate, and natural gas liquids (MBbls)
Located in the United States and Canada.................................. 33,699 29,382 28,270
Located in the Kingdom of Thailand....................................... 33,811 28,783 21,332
---------- ---------- ----------
Total Company.......................................................... 67,510 58,165 49,602
---------- ---------- ----------
---------- ---------- ----------
Natural Gas (MMcf)
Located in the United States and Canada.................................. 271,780 216,720 215,946
Located in the Kingdom of Thailand....................................... 168,389 184,768 144,998
---------- ---------- ----------
Total Company.......................................................... 440,169 401,488 360,944
---------- ---------- ----------
---------- ---------- ----------
Present value of estimated future net revenues, before income taxes (in
thousands)(a)
Located in the United States and Canada.................................. $ 294,629 $ 406,161 $ 773,127
Located in the Kingdom of Thailand....................................... 200,597 56,620 181,418
---------- ---------- ----------
Total Company.......................................................... $ 495,226 $ 462,781 $ 954,545
---------- ---------- ----------
---------- ---------- ----------
Total Developed Reserves:
Oil, condensate, and natural gas liquids (MBbls)
Located in the United States and Canada.................................. 29,070 26,168 25,898
Located in the Kingdom of Thailand....................................... 4,298 6,982 5,192
---------- ---------- ----------
Total Company.......................................................... 33,368 33,150 31,090
---------- ---------- ----------
---------- ---------- ----------
Natural Gas (MMcf)
Located in the United States and Canada.................................. 184,630 179,972 192,034
Located in the Kingdom of Thailand....................................... 40,424 59,760 45,998
---------- ---------- ----------
Total Company.......................................................... 225,054 239,732 238,032
---------- ---------- ----------
---------- ---------- ----------
Present value of estimated future net revenues, before income taxes (in
thousands)(a)
Located in the United States and Canada.................................. $ 242,574 $ 377,530 $ 710,871
Located in the Kingdom of Thailand....................................... 28,244 36,692 69,062
---------- ---------- ----------
Total Company.......................................................... $ 270,818 $ 414,222 $ 779,933
---------- ---------- ----------
---------- ---------- ----------
- ------------------------
(a) The Company believes, for the reasons set forth in succeeding paragraphs,
that the present value of estimated future anet revenues set forth in the
Annual Report and calculated in accordance with SEC guidelines are not
necessarily indicative of the true present value of the Company's reserves
and, due to the fact that essentially all of the Company's domestic natural
gas production is currently sold on the spot market, whereas all of the
Company's Thai natural gas production is sold pursuant to a long-term gas
sales contract, such estimates of future net revenues from the Company's
domestic and Thai reserves are, accordingly, not useful for comparative
purposes. See the discussion on the following pages for the prices used in
making these calculations.
Natural gas liquids comprised approximately 6% of the Company's total proved
liquids reserves and approximately 11% of the Company's proved developed liquids
reserves as of December 31, 1998. All hydrocarbon liquid reserves are expressed
in standard 42 gallon Bbls. All gas volumes and gas sales are expressed in MMcf
at the pressure and temperature bases of the area where the gas reserves are
located.
17
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing conditions. Reservoirs are considered proved if
economic producibility is supported by actual production or formation tests. In
certain instances, proved reserves are assigned on the basis of a combination of
core analysis and electrical and other type logs which indicate the reservoirs
are analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a reservoir
considered proved includes (i) that portion delineated by drilling and defined
by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that
can be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as hydrocarbons are
produced and additional data becomes available. Proved natural gas reserves are
comprised of non-associated, associated and dissolved gas. An appropriate
reduction in gas reserves has been made for the expected removal of liquids, for
lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in
significant quantities and are removed prior to sale. Reserves that can be
produced economically through the application of established improved recovery
techniques are included in the proved classification when these qualifications
are met: (i) successful testing by a pilot project or the operation of an
installed program in the reservoir provides support for the engineering analysis
on which the project or program was based, and (ii) it is reasonably certain the
project will proceed. Improved recovery includes all methods for supplementing
natural reservoir forces and energy, or otherwise increasing ultimate recovery
from a reservoir, including, (i) pressure maintenance, (ii) cycling, and (iii)
secondary recovery in its original sense. Improved recovery also includes the
enhanced recovery methods of thermal, chemical flooding, and the use of miscible
and immiscible displacement fluids. Estimates of proved reserves do not include
crude oil, condensate, natural gas, or natural gas liquids being held in
underground storage. Depending on the status of development, these proved
reserves are further subdivided into:
(i) "developed reserves" which are those proved reserves reasonably
expected to be recovered through existing wells with existing equipment and
operating methods, including (a) "developed producing reserves" which are
those proved developed reserves reasonably expected to be produced from
existing completion intervals now open for production in existing wells, and
(b) "developed non-producing reserves" which are those proved developed
reserves which exist behind casing of existing wells which are reasonably
expected to be produced through these wells in the predictable future where
the cost of making such hydrocarbons available for production should be
relatively small compared to the cost of new wells; and
(ii) "undeveloped reserves" which are those proved reserves reasonably
expected to be recovered from new wells on undrilled acreage, from existing
wells where a relatively large expenditure is required and from acreage for
which an application of fluid injection or other improved recovery technique
is contemplated where the technique has been proved effective by actual
tests in the area in the same reservoir. Reserves from undrilled acreage are
limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are included only where it can be demonstrated with
reasonable certainty that there is continuity of production from the
existing productive formation.
In computing future revenues from gas reserves attributable to the Company's
domestic interests, prices in effect at December 31, 1998 were used, including
current market prices, contract prices and fixed and determinable price
escalations where applicable. In accordance with SEC guidelines, the gas prices
that were used make no allowances for seasonal variations in gas prices which
are likely to cause future yearly average gas prices to be somewhat lower than
December gas prices. For domestic gas sold under contract, the contract gas
price including fixed and determinable escalations, exclusive of inflation
adjustments, was used until the contract expires and then was adjusted to the
current market price for the area and held at this adjusted price to depletion
of the reserves. In computing future revenues from liquids attributable to the
Company's domestic interests, prices in effect at December 31, 1998 were used
and
18
these prices were held constant to depletion of the properties. The future
revenues are adjusted to reflect the Company's net revenue interest in these
reserves as well as any ad valorem and other severance taxes but do not include,
unless otherwise noted, any provisions for corporate income taxes.
In computing future revenues from the Company's gas reserves attributable to
the Company's interests in the Kingdom of Thailand, the current contract price
under the Gas Sales Agreement was used, without giving effect to any of the
adjustments provided for in the Gas Sales Agreement, due to their indeterminate
nature as of December 31, 1998, in accordance with SEC guidelines. In computing
future revenues from liquids attributable to the Company's interests in the
Kingdom of Thailand, a price was used which the Company believes approximates
the price that the Company would have received for its production from the
Thailand Concession based upon the world market price for Tapis benchmark crude
on December 31, 1998, and this price was held constant until depletion of the
Company's reserves in the Kingdom of Thailand. The future revenues are adjusted
to reflect the Company's net revenue interest in these reserves and the
Company's obligations under the Thailand Concession, including the payment of
SRB and applicable production bonuses, but does not include any provisions for
U.S. or Thai corporate income or other taxes.
In accordance with SEC guidelines, the prices used by the Company to
calculate the present value of estimated future revenues are determined on a
well or field by field basis, as applicable, as described above and were held
constant over the productive life of the reserves. The initial weighted average
prices used by Ryder Scott were as follows:
AS OF DECEMBER 31,
-------------------------------
1998 1997 1996
--------- --------- ---------
Initial Weighted Average Price (in U.S. dollars):
Oil, condensate, and natural gas liquids (per Bbl)
Located in the United States and Canada...................... $ 10.45 $ 16.60 $ 24.06
Located in the Kingdom of Thailand........................... $ 12.68 $ 16.00 $ 24.56
Natural Gas (per Mcf)
Located in the United States and Canada...................... $ 2.01 $ 2.30 $ 3.93
Located in the Kingdom of Thailand........................... $ 1.81 $ 1.83 $ 2.09
The estimates of future net revenue from the Company's domestic and Thailand
properties are based on existing law where the properties are located and are
calculated in accordance with SEC guidelines. Operating costs for the leases and
wells include only those costs directly applicable to the leases or wells. When
applicable, the operating costs include a portion of general and administrative
costs allocated directly to the leases and wells under terms of operating
agreements. Development costs are based on authorization for expenditure for the
proposed work or actual costs for similar projects. The current operating and
development costs were held constant throughout the life of the properties. For
properties located onshore, the estimates of future net revenues and the present
value thereof do not consider the salvage value of the lease equipment or the
abandonment cost of the lease since both are relatively insignificant and tend
to offset each other. The estimated net cost of abandonment after salvage was
considered for offshore properties where such costs net of salvage are
significant.
No deduction was made for indirect costs such as general and administrative
and overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments. Accumulated gas production imbalances, if any, have
been taken into account.
Production data used to arrive at the estimates set forth above includes
estimated production for the last few months of 1998. The future production
rates from reservoirs now on production may be more or less than estimated
because of, among other reasons, mechanical breakdowns and changes in market
demand or allowables set by regulatory bodies. Properties which are not
currently producing may start producing earlier or later than anticipated in the
estimates of future production rates.
19
The future prices received by the Company for the sales of its production
may be higher or lower than the prices used in calculating the estimates of
future net revenues and the present value thereof as set forth herein, and the
operating costs and other costs relating to such production may also increase or
decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by the SEC, omitted from
consideration in arriving at such estimates.
There are numerous uncertainties in estimating the quantity of proved
reserves and in projecting the future rates of production and timing of
development expenditures. Oil and gas reserve engineering must be recognized as
a subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and estimates of other engineers might
differ materially from those of Ryder Scott, the Company's reserve engineers.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing and production subsequent to the date of the estimate may
justify revision of such estimate, which revisions may be material. Accordingly,
reserve estimates are often different from the quantities of oil and gas that
are ultimately recovered.
The Company is periodically required to file estimates of its oil and gas
reserve data with various U.S. governmental regulatory authorities and agencies,
including the Federal Energy Regulatory Commission ("FERC") and the Federal
Trade Commission; with respect to reserves located in Canada, with the Alberta
Energy Utilities Board and, with respect to reserves located in Thailand, the
Kingdom of Thailand's Department of Mineral Resources and PTT, which the Company
considers a quasi-governmental authority. In addition, estimates are from time
to time furnished to governmental agencies in connection with specific matters
pending before such agencies. The basis for reporting reserves to these
agencies, in some cases, is not comparable to that furnished by Ryder Scott in
accordance with SEC guidelines because of the nature of the various reports
required. The major differences generally include differences in the time as of
which such estimates are made, differences in the definition of reserves,
requirements to report in some instances on a gross, net or total operator basis
and requirements to report in terms of smaller geographical units. During 1998,
no estimates by the Company of its total proved net oil and gas reserves were
filed with or included in reports to any governmental authority or agency other
than the SEC; the Alberta Energy Utilities Board for Canadian Reserves; and,
with respect to reserves relating to the Company's properties located in
Thailand, the Kingdom of Thailand's Department of Mineral Resources and PTT.
GOVERNMENT REGULATION
The Company's operations are affected from time to time in varying degrees
by political developments and governmental laws and regulations. Rates of
production of oil and gas have for many years been subject to governmental
conservation laws and regulations, and the petroleum industry has been subject
to federal and state tax laws dealing specifically with it.
FEDERAL INCOME TAX
The Company's operations are significantly affected by certain provisions of
the federal income tax laws applicable to the petroleum industry. The principal
provisions affecting the Company are those that permit the Company, subject to
certain limitations, to deduct as incurred, rather than to capitalize and
amortize, its domestic "intangible drilling and development costs" and to claim
depletion on a portion of its domestic oil and gas properties based on 15% of
its oil and gas gross income from such properties (up to an aggregate of 1,000
Bbls per day of domestic crude oil and/or equivalent units of domestic natural
gas) even though the Company has little or no basis in such properties. Under
certain circumstances, however, a portion of such intangible drilling and
development costs and the percentage depletion allowed in excess of basis will
be tax preference items that will be taken into account in computing the
Company's alternative minimum tax.
20
ENVIRONMENTAL MATTERS
Domestic oil and gas operations are subject to extensive federal regulation
and, with respect to federal leases, to interruption or termination by
governmental authorities on account of environmental and other considerations
including the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") also known as the "Superfund Law." The recent trend towards
stricter standards in environmental legislation and regulation may continue, and
this could increase costs to the Company and others in the industry. Oil and gas
lessees are subject to liability for the costs of clean-up of pollution
resulting from a lessee's operations, and may also be subject to liability for
pollution damages. The Company maintains insurance against costs of clean-up
operations, but is not fully insured against all such risks. A serious incident
of pollution may, as it has in the past, also result in the Department of the
Interior requiring lessees under federal leases to suspend or cease operation in
the affected area.
The operators of the Company's properties have numerous applications pending
before the Environmental Protection Agency (the "EPA") for National Pollution
Discharge Elimination System water discharge permits with respect to offshore
drilling and production operations. The issue generally involved is whether
effluent discharges from each facility or installation comply with the
applicable federal regulations.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulations. If the
party fails to report a spill or cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by the
OPA.
The OPA also imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10,000,000 depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. For offshore facilities that have a
worst case oil spill potential of more than 1,000 Bbls (which includes many of
the Company's offshore producing facilities), certain amendments to the OPA that
were enacted in 1996 provide that the amount of financial responsibility that
must be demonstrated for most facilities ranges from $10,000,000 to $35,000,000,
depending upon location, with higher amounts, up to $150,000,000 in certain
limited circumstances. The Company believes that it currently has established
adequate proof of financial responsibility for its offshore facilities at no
significant increase in expense over recent prior years. However, the Company
cannot predict whether these financial responsibility requirements under the OPA
amendments will result in the imposition of substantial additional annual costs
to the Company in the future or otherwise materially adversely affect the
Company. The impact, however, should not be any more adverse to the Company than
it will be to other similarly situated or less capitalized owners or operators
in the Gulf of Mexico.
The Company's onshore operations are subject to numerous United States and
Canadian federal, state, provincial and local laws and regulations controlling
the discharge of materials into the environment or otherwise relating to the
protection of the environment including CERCLA. Such laws and regulations, among
other things, impose absolute liability on the lessee under a lease for the cost
of clean-up of pollution resulting from a lessee's operations, subject the
lessee to liability for pollution damages, may require suspension or cessation
of operations in affected areas, and impose restrictions on the injection of
liquids into subsurface aquifers that may contaminate groundwater. Such laws
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. Federal, state,
21
provincial and local initiatives to further regulate the disposal of oil and gas
wastes are also pending in certain states and Canadian provinces, and these
initiatives could have a similar impact on the Company.
The Company is asked to comment on the costs it incurred during the prior
year on capital expenditures for environmental control facilities and the amount
it anticipates incurring during the coming year. The Company believes that, in
the course of conducting its oil and gas operations, many of the costs
attributable to environmental control facilities would have been incurred absent
environmental regulations as prudent, safe oilfield practice. During 1998, the
Company incurred capital expenditures of approximately $4,600,000 for
environmental control facilities, primarily relating to the installation of
certain environmental control facilities on four platforms installed in the Gulf
of Thailand and one platform in the Gulf of Mexico, and the drilling of three
salt water disposal wells. The Company budgeted approximately $171,000 for
expenditures involving environmental control facilities during 1999, including,
among other things, environmental control equipment for two platforms in the
Gulf of Thailand.
OTHER LAWS AND REGULATIONS
Various laws and regulations often require permits for drilling wells and
also cover spacing of wells, the prevention of waste of oil and gas including
maintenance of certain gas/oil ratios, rates of production and other matters.
The effect of these laws and regulations, as well as other regulations that
could be promulgated by the jurisdictions in which the Company has production,
could be to limit the number of wells that could be drilled on the Company's
properties and to limit the allowable production from the successful wells
completed on the Company's properties, thereby limiting the Company's revenues.
The Minerals Management Service of the Department of the Interior (the
"MMS") administers the oil and gas leases held by the Company on federal onshore
lands and offshore tracts in the Outer Continental Shelf. The MMS holds a
royalty interest in these federal leases on behalf of the federal government.
While the royalty interest percentage is fixed at the time that the lease is
entered into, from time to time the MMS changes or reinterprets the applicable
regulations governing its royalty interests, and such action can indirectly
affect the actual royalty obligation that the Company is required to pay. In a
letter dated May 3, 1993, the MMS announced a reinterpretation of its right to
collect royalty payments from producers on certain settlements in which such
producers and pipeline companies were involved a number of years ago. The MMS
reinterpretation has been challenged in court by various producers and trade
groups representing them. On August 27, 1996, in INDEPENDENT PETROLEUM
ASSOCIATION OF AMERICA, ET AL. V. BABBIT ET AL., Nos. 95-5210 ETC., the United
States Court of Appeals for the District of Columbia Circuit held that the May
3, 1993, reinterpretation was invalid and unenforceable. Unless and until this
or other similar cases are resolved in favor of the MMS' reinterpretation of its
regulations, it is unlikely that the Company or other producers will be legally
required to pay royalties on such settlement agreements. The Company was
involved in several settlement agreements with pipelines that could be subject
to the MMS' new reinterpretation. The MMS has reviewed the Company's and other
producers' settlement agreements, to determine whether it believes any
additional royalty payments may be due and has asserted that additional
royalties may be due in connection with two of the Company's settlement
agreements. Based upon existing case law, the Company has asserted through the
administrative appeals process, and continues to believe, that it does not owe
any additional royalties beyond what it has previously paid. However, in the
event that the MMS is able to successfully assert that additional royalty is due
from the Company in connection with settlement agreements to which the Company
is a party, the Company does not currently believe that such additional
assessment will have a material adverse impact on the financial position or
results of operations of the Company.
Recently the MMS and various state and municipal authorities have attempted
to collect alleged underpayment of royalties from various integrated oil
companies in connection with sale transactions between exploration and
production affiliates and pipeline affiliates of the same company. The Company
has not been named in any of these collection efforts, a fact that the Company
believes is primarily due to its never having sold any oil or gas production
from one of its affiliates to another. The Company does not believe that it has
any material liability for underpayment of royalty in connection with affiliate
transactions, including those described above.
22
The FERC has recently embarked on wide-ranging regulatory initiatives
relating to gas transportation rates and services, including the availability of
market-based and other alternative rate mechanisms to pipelines for transmission
and storage services. In addition, the FERC has announced and implemented a
policy allowing pipelines and transportation customers to negotiate rates above
the otherwise applicable maximum lawful cost-based rates on the condition that
the pipelines alternatively offer so-called recourse rates equal to the maximum
lawful cost-based rates. With respect to gathering services, the FERC has issued
orders declaring that certain facilities owned by interstate pipelines primarily
perform a gathering function, and may be transferred to affiliated and
non-affiliated entities that are not subject to the FERC's rate jurisdiction.
These orders have been generally upheld on appeal to the courts. The Company
cannot predict the ultimate outcome of these developments, nor the effect of
these developments on transportation rates. Inasmuch as the rates for these
pipeline services can affect the gas prices received by the Company for the sale
of its production, the FERC's actions may have an impact on the Company.
However, the impact should not be substantially different on the Company than it
will on other similarly situated gas producers and sellers.
EMPLOYEES
As of December 31, 1998, the Company and its subsidiaries had 185 full-time
employees, including 24 in its Bangkok, Thailand office and seven in its
Calgary, Canada office. None of the Company's employees are presently
represented by a union for collective bargaining purposes. The Company considers
its relations with its employees to be excellent.
ITEM 2. PROPERTIES.
The information appearing in Item 1 of this Annual Report is incorporated
herein by reference.
ITEM 3. LEGAL PROCEEDINGS.
The Company is a party to various other legal proceedings consisting of
routine litigation incidental to its businesses, but believes that any potential
liabilities resulting from these proceedings are adequately covered by insurance
or are otherwise immaterial at this time. See "Business--Government Regulation;
Other Laws and Regulations."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
Not Applicable.
23
ITEM S-K 401(B). EXECUTIVE OFFICERS OF REGISTRANT.
Executive officers of the Company are appointed annually to serve for the
ensuing year or until their successors have been elected or appointed. The
executive officers of the Company, their age as of February 15, 1999 and the
year each was elected to his present position are as follows:
YEAR
EXECUTIVE OFFICER EXECUTIVE OFFICE AGE ELECTED
- ------------------------------------------------ ------------------------------------------------ --- -----------
Paul G. Van Wagenen............................. Chairman of the Board, President and Chief 53 1991
Executive Officer
Stuart P. Burbach............................... Executive Vice President--Exploration 46 1998
Kenneth R. Good................................. Executive Vice President 61 1998
Jerry A. Cooper................................. Senior Vice President and Western Division 50 1998
Manager
R. Phillip Laney................................ Senior Vice President and Manager of Worldwide 58 1998
New Ventures
John O. McCoy, Jr............................... Senior Vice President and Chief Administrative 47 1998
Officer
J. D. McGregor.................................. Senior Vice President--Sales 54 1998
Bruce E. Archinal............................... Vice President and Onshore Division Manager 46 1997
David R. Beathard............................... Vice President--Engineering 40 1997
Stephen R. Brunner.............................. Vice President--Operations 40 1997
Frank Davis III................................. Vice President--Land 52 1997
John W. Elsenhans............................... Vice President and Chief Financial Officer 46 1998
Thomas E. Hart.................................. Vice President and Controller 56 1988
Ronald B. Manning............................... Vice President and General Counsel 45 1995
Gerald A. Morton................................ Vice President--Law and Corporate Secretary 40 1997
Prior to assuming their present positions with the Company, the business
experience of each executive officer for more than the last five years was as
follows: Mr. Van Wagenen, who joined the Company in 1979, served as President
and Chief Operating Officer of the Company since 1990; Mr. Burbach served as
Vice President and Offshore Division Manager since rejoining the Company in
1991; Mr. Good, who joined the Company in 1977, served as Corporate Senior Vice
President of the Company since 1996 and prior thereto served as the Company's
Senior Vice President--Land and Budgets since 1991; Mr. Cooper, who joined the
Company in 1979, served as Vice President and Western Division Manager for the
Company since 1991; Mr. Laney, who joined the Company in 1977, served as Vice
President and International Exploration Manager for the Company since 1991; Mr.
McCoy, who joined the Company in 1978, served as Vice President and Chief
Administrative Officer of the Company since 1989; Mr. McGregor, who joined the
Company in 1981, served as Vice President--Sales since 1988; Mr. Archinal, who
joined the Company in 1982, served as the Company's Onshore Division Manager
since 1994 and prior thereto served as Offshore Division Exploration Manager for
the Company since 1991; Mr. Beathard, who joined the Company in 1982, served as
Manager of Petroleum Engineering for the Company since 1991; Mr. Brunner served
as Resident Manager of the Company's Thailand operations since 1995, prior to
which he was an Operations Manager for the Company since joining in 1994 and
prior thereto held various positions in the energy industry, the most recent of
which was as Operations Manager for Zilkha Energy since 1991; Mr. Davis, who
joined the Company in 1978, served as Land Manager for the Company since 1991;
Mr. Elsenhans, who joined the Company in 1991, served as Vice President--
Finance and Treasurer for the Company since 1995, and prior thereto was
Director, Corporate Finance for the Company since 1991; Mr. Hart was Controller
for the Company since joining the Company in 1977; Mr. Manning, who joined the
Company in 1987, was Corporate Secretary and an Associate General Counsel for
the Company since 1990; and Mr. Morton was an Associate General Counsel for the
Company since 1993.
24
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY MATTERS.
The following table shows the range of low and high sales prices of the
Company's Common Stock (the "Common Stock") on the New York Stock Exchange
composite tape where the Common Stock trades under the symbol PPP. The Common
Stock is also listed on the Pacific Stock Exchange.
LOW HIGH
--------- ---------
1997
1st Quarter.............................................. 33 3/8 49 7/8
2nd Quarter.............................................. 33 1/2 41 3/8
3rd Quarter.............................................. 37 7/8 45 3/8
4th Quarter.............................................. 27 44 9/16
1998
1st Quarter.............................................. 26 1/2 34
2nd Quarter.............................................. 21 1/2 34 11/16
3rd Quarter.............................................. 11 5/8 25 7/8
4th Quarter.............................................. 9 13/16 17 1/8
As of February 22, 1999, there were 3,287 holders of record of the Company's
Common Stock.
In each of 1997 and 1998, the Company paid four quarterly dividends of $0.03
per share on its Common Stock. However, the declaration and payment of future
dividends will depend upon, among other things, the Company's future earnings
and financial condition, liquidity and capital requirements, the general
economic and regulatory climate and other factors deemed relevant by the
Company's Board of Directors.
Pursuant to the Company's revolving credit agreement with its banks under
which the Company has borrowed funds, and the Indentures relating to the
Company's 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes") and
10 3/8% Senior Subordinated Notes due 2009 (the "2009 Notes"), the Company may
not, subject to certain exceptions, pay any dividends on its capital stock or
make any other distributions on shares of its capital stock (other than
dividends or distributions payable solely in shares of such capital stock) or
apply any funds, property or assets to the purchase, redemption, sinking fund or
other retirement of its capital stock, if the aggregate amount of all such
dividends, purchases, and redemptions would exceed an amount determined based on
the consolidated income of the Company and its consolidated subsidiaries plus
the proceeds of the issuance of capital stock from and after a specified date
set forth in each respective agreement or, in the case of the revolving credit
agreement, if the net worth of the Company is negative. As of February 1, 1999,
$15,000,000 was available for dividends under this limitation in the Indenture
relating to the 2009 Notes, the agreement currently having the most restrictive
covenants.
25
ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AND PRODUCTION
DATA)
FINANCIAL DATA
Revenues:
Crude oil and condensate........................... $ 74,703 $ 112,603 $ 96,908 $ 76,557 $ 65,141
Natural gas........................................ 116,148 158,500 94,589 72,032 99,093
Natural gas liquids................................ 9,303 13,748 11,867 8,097 9,189
---------- ---------- ---------- ---------- ----------
Oil and gas revenues............................... 200,154 284,851 203,364 156,686 173,423
Pipeline sales and other........................... 2,649 1,449 613 873 185
---------- ---------- ---------- ---------- ----------
Total............................................ $ 202,803 $ 286,300 $ 203,977 $ 157,559 $ 173,608
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Income (loss) before extraordinary item.............. $ (43,098) $ 37,116 $ 33,581 $ 9,230 $ 27,374
Extraordinary losses................................. -- -- (821) -- (307)
---------- ---------- ---------- ---------- ----------
Net income (loss).................................... $ (43,098) $ 37,116 $ 32,760 $ 9,230 $ 27,067
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Per share data:
Income (loss) before extraordinary item--
Basic............................................ $ (1.14) $ 1.11 $ 1.01 $ 0.28 $ 0.84
Diluted.......................................... $ (1.14) $ 1.06 $ 0.97 $ 0.28 $ 0.82
Cash dividends..................................... $ 0.12 $ 0.12 $ 0.12 $ 0.12 $ 0.06
Price range of common stock:
High............................................. $ 34.69 $ 49.88 $ 48.38 $ 29.00 $ 24.25
Low.............................................. $ 9.81 $ 27.00 $ 24.38 $ 16.00 $ 15.63
Weighted average number of common shares
outstanding........................................ 37,902 33,421 33,203 32,893 32,663
Longterm debt at year end............................ $ 434,947 $ 348,179 $ 246,230 $ 163,249 $ 149,249
Shareholders' equity at year end..................... $ 249,660 $ 146,106 $ 107,282 $ 71,708 $ 64,037
Total assets at year end............................. $ 862,396 $ 676,617 $ 479,242 $ 338,177 $ 298,826
PRODUCTION (SALES) DATA
Net daily average and weighted average price:
Natural gas (Mcf per day).......................... 159,000 181,700 107,700 121,000 144,800
Price (per Mcf).................................. $ 2.00 $ 2.39 $ 2.40 $ 1.63 $ 1.88
Crude oil-condensate (Bbl per day)................. 15,775 15,927 11,968 11,786 11,100
Price (per Bbl).................................. $ 12.97 $ 19.37 $ 22.12 $ 17.80 $ 16.08
Natural gas liquids (Bbl per day).................. 2,422 2,923 2,173 1,998 2,222
Price (per Bbl).................................. $ 10.52 $ 12.89 $ 14.92 $ 11.10 $ 11.33
CAPITAL EXPENDITURES
Oil and gas:
Domestic Offshore--
Exploration...................................... $ 20,200 $ 18,700 $ 16,800 $ 13,300 $ 2,800
Development...................................... 42,500 59,800 73,900 17,800 44,100
Purchase of reserves............................. 5,000 900 -- -- 32,600
Onshore North America--
Exploration...................................... 16,500 18,100 10,400 8,800 6,800
Development...................................... 28,100 38,400 27,800 22,400 23,700
Purchase of reserves............................. 133,100 1,700 -- 7,900 --
Kingdom of Thailand--
Exploration...................................... 11,600 21,700 8,500 5,500 5,100
Development...................................... 95,500 62,500 54,700 24,400 --
Purchase of reserves............................. -- 29,300 -- 4,200 --
---------- ---------- ---------- ---------- ----------
Total oil and gas.................................. 352,500 251,100 192,100 104,300 115,100
Other................................................ 6,300 4,000 1,600 500 1,200
---------- ---------- ---------- ---------- ----------
Total.............................................. $ 358,800 $ 255,100 $ 193,700 $ 104,800 $ 116,300
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
On August 17, 1998, a wholly owned subsidiary of the Company merged with and
into Arch Petroleum Inc. ("Arch") in a stock-for-stock tax-free merger accounted
for as a purchase. In connection with the merger, the Company paid off
$51,749,000 of Arch's existing bank debt and production payment obligations. The
Company also exchanged $5,000,000 of Arch's existing convertible subordinated
notes, 727,273 shares of Arch preferred stock (having a liquidation preference
of $20,000,000) and 17,321,804 shares of Arch common stock for approximately
2,500,000 shares of Common Stock.
RESULTS OF OPERATIONS
NET INCOME (LOSS)
The Company reported a net loss for 1998 of $43,098,000 or $1.14 per share,
compared to net income for 1997 of $37,116,000 or $1.11 per share ($40,198,000
or $1.06 per share on a diluted basis) and net income for 1996 of $32,760,000 or
$0.99 per share ($35,843,000 or $0.95 per share on a diluted basis). Among other
items affecting the net loss for 1998 were non-recurring expenses totaling
approximately $2,285,000 ($1,485,000 or $0.04 per share on an after-tax basis)
related to the Company's acquisition of Arch and impairments to its oil and gas
properties of $30,813,000, primarily resulting from poor reservoir performance
and persistent low oil and gas prices. The Company recorded an extraordinary
loss of $821,000 during the second quarter of 1996 related to the early
retirement of the Company's 8% Convertible Subordinated Debentures, due 2005
with the proceeds from the Company's issuance on June 18, 1996, of its 5 1/2%
Convertible Subordinated Notes, due 2006 (the "2006 Notes").
Earnings per common share are based on the weighted average number of common
shares outstanding for 1998 of 37,902,000, compared to 33,421,000 (38,064,000 on
a diluted basis) for 1997 and 33,203,000 (37,920,000 on a diluted basis) for
1996. The increase in the weighted average number of common shares outstanding
for 1998, compared to 1997, resulted primarily from the issuance of 3,882,023
shares of its common stock upon the conversion of the Company's 5 1/2%
Convertible Subordinated Notes due 2004 (the "2004 Notes") prior to their being
redeemed on March 16, 1998, the issuance as of August 17, 1998 of approximately
2,500,000 shares of common stock to former holders of Arch capital stock and
convertible debt securities in connection with the Company's acquisition of Arch
and, to a lesser extent, the issuance of common stock upon the exercise of stock
options pursuant to the Company's stock option plans. The increase in weighted
average number of common shares outstanding for 1997, compared to 1996, resulted
primarily from the issuance of common stock upon the exercise of stock options
pursuant to the Company's stock option plans. The earnings per share computation
on a diluted basis in 1998 is identical to the basic earnings per share
computation because there were no securities of the Company that were dilutive
during the period. The earnings per share computation on a diluted basis in 1997
and 1996 primarily reflect additional shares of common stock issuable upon the
assumed conversion of the 2004 Notes and the elimination of related interest
requirements, as adjusted for applicable federal income taxes and, to a lesser
extent, the assumed exercise of options to purchase common shares. In addition,
the number of common shares outstanding in the diluted computation is adjusted,
in accordance with the Financial Accounting Standards Board's Statement of
Financial Accounting Standards ("SFAS") No. 128, to include dilutive shares that
are assumed to have been issued by the Company in connection with options
exercised during the year, less treasury shares that are assumed to have been
purchased by the Company from the option proceeds. SFAS No. 128 was adopted by
the Company in 1997, resulting in a restatement of the earnings per share
calculations for 1997 and 1996, and all preceding years.
TOTAL REVENUES
The Company's total revenues for 1998 were $202,803,000, a decrease of
approximately 29% from total revenues of $286,300,000 for 1997, and a decrease
of approximately 1% from total revenues of $203,977,000 for 1996. The decrease
in the Company's total revenues for 1998, compared to 1997, resulted primarily
from the substantial decrease in oil and gas revenues, that was partially offset
by an increase in pipeline sales related to the Saginaw pipeline, which was
acquired as part of the Arch acquisition, in the
27
third quarter of 1998. The decrease in the Company's total revenues for 1998,
compared to 1996, resulted primarily from the decrease in oil and gas revenues
that were nearly offset by the revenues generated by the Saginaw pipeline.
OIL AND GAS REVENUES
The Company's oil and gas revenues for 1998 were $200,154,000, a decrease of
approximately 30% from oil and gas revenues of $284,851,000 for 1997, and a
decrease of approximately 2% from oil and gas revenues of $203,364,000 for 1996.
The following table reflects an analysis of variances in the Company's oil and
gas revenues (expressed in thousands) between 1998 and the previous two years:
1998 COMPARED TO
----------------------
1997 1996
---------- ----------
Increase (decrease) in oil and gas revenues resulting from variances
in:
Natural gas--
Price............................................................. $ (25,802) $ (15,728)
Production........................................................ (16,550) 37,287
---------- ----------
(42,352) 21,559
Crude oil and condensate--
Price............................................................. (37,178) (40,077)
Production........................................................ (722) 17,872
---------- ----------
(37,900) (22,205)
---------- ----------
Natural Gas Liquids................................................. (4,445) (2,564)
---------- ----------
Increase (decrease) in oil and gas revenues....................... $ (84,697) $ (3,210)
---------- ----------
---------- ----------
28
The decrease in the Company's oil and gas revenues in 1998, compared to
1997, is related to declines in the average price that the Company received for
its natural gas and oil, condensate and NGL ("liquid hydrocarbons") production
volumes and, to a lesser extent, declines in such production volumes. The
decrease in the Company's oil and gas revenues in 1998, compared to 1996, is
related to declines in the average price that the Company received for its
natural gas and liquid hydrocarbon production volumes, that more than offset
substantial increases in natural gas and liquid hydrocarbon production volumes.
% CHANGE % CHANGE
1998 1998
TO TO
1998 1997 1997 1996 1996
--------- --------- ----------- --------- -----------
Comparison of Increases (Decreases) in:
NATURAL GAS--
Average prices
North America............................................ $ 2.09 $ 2.50 (16%) $ 2.40 (13%)
Kingdom of Thailand (Thai baht)(a)....................... 70 60 17% N/A N/A
Company-wide average price............................. $ 2.00 $ 2.39 (16%) $ 2.40 (17%)
Average daily production volumes (MMcf per day)
North America............................................ 122.2 147.2 (17%) 107.7 13%
Kingdom of Thailand (a).................................. 36.8 34.5 7% N/A N/A
--------- --------- ---------
Company-wide average daily production.................. 159.0 181.7 (12%) 107.7 48%
--------- --------- ---------
--------- --------- ---------
CRUDE OIL AND CONDENSATE--
Average prices
North America............................................ $ 12.94 $ 19.49 (34%) $ 22.12 (42%)
Kingdom of Thailand(a)................................... $ 13.17 $ 18.60 (29%) N/A N/A
Company-wide average price............................. $ 12.97 $ 19.37 (33%) $ 22.12 (41%)
Average daily production volumes (Bbls per day)
North America............................................ 13,214 13,711 (4%) 11,968 10%
Kingdom of Thailand (a).................................. 2,561 2,216 16% N/A N/A
--------- --------- ---------
Company-wide average daily production.................. 15,775 15,927 (1%) 11,968 32%
--------- --------- ---------
--------- --------- ---------
TOTAL LIQUID HYDROCARBONS--
Company-wide average daily production
(Bbls per day)........................................... 18,197 18,851 (3%) 14,141 29%
--------- --------- ---------
--------- --------- ---------
- ------------------------
(a) Production from the Tantawan Field commenced in February 1997, with a
start-up phase which extended through March 15, 1997. Consequently, no
production figures are presented for 1996 and all Thailand production
figures for 1997 reflect only nine and a half months of full production.
NATURAL GAS
THAILAND PRICES. The price that the Company receives under the Gas Sales
Agreement for its natural gas production from the Thailand Concession normally
adjusts on a semi-annual basis. However, the Gas Sales Agreement provides for
adjustment on a more frequent basis in the event that certain indices and
factors on which the price is based fluctuate outside a given range. See
"Business--International Operations; Contractual Terms Governing the Thailand
Concession and Related Production." Due to the volatility of the Thai baht and
the current economic difficulties in the Kingdom of Thailand and throughout
Southeast Asia, the price that the Company receives under the Gas Sales
Agreement adjusted several times during 1998, and almost monthly in the latter
half of 1997. The Company cannot predict what the baht to dollar exchange rate
may be in the future. Moreover, it is anticipated that this exchange rate will
remain volatile. See ";Foreign Currency Transaction Gain (Loss)," "--Liquidity
and Capital Resources; Other Matters; Southeast Asia Economic Issues" and
"Business--International Operations; Contractual Terms Governing the Thailand
Concession."
29
PRODUCTION. The decrease in the Company's natural gas production during
1998, compared to 1997, was related in large measure to decreased production
from the Company's East Cameron Block 334 "E" platform, and to a lesser extent,
four periods in the second half of 1998 during which most of the Company's
offshore production was shut-in as a precautionary measure due to hurricanes in
the Gulf of Mexico and natural production declines, that was partially offset by
increased production from the Company's onshore properties located in South
Texas and South Louisiana. The increase in the Company's average natural gas
production for 1998, compared to 1996, was related in large measure to the
commencement of production from the Tantawan Field in the first quarter of 1997,
and, to a lesser extent, production from the Company's East Cameron Block 334
"E" platform, which commenced production in April 1997, and production from
properties that the Company acquired in its acquisition of Arch, that was only
partially offset by the anticipated natural decline in deliverability from
certain of the Company's properties. Commencing on October 1, 1998, the Company
and its joint venture partners in the Thailand Concession have been delivering
less natural gas than is being nominated by PTT under the Gas Sales Agreement.
This could result in the Company receiving only 75% of the current contract
price on a portion of its future natural gas sales to PTT. The Company is taking
actions that it currently believes will minimize the penalty that it will incur
on future gas sales to PTT by, among other things, increasing production from
the Tantawan Field. As of December 31, 1998, the Company was not a party to any
future natural gas sales contracts.
CRUDE OIL AND CONDENSATE
THAILAND PRICES. Since the inception of production from the Tantawan Field,
crude oil and condensate has been stored on the FPSO until an economic quantity
was accumulated for offloading and sale. The first such sale of crude oil and
condensate from the Tantawan Field occurred in July 1997. Prices that the
Company receives for its crude oil and condensate production from Thailand are
based on world benchmark prices, which are denominated in dollars. In addition,
the Company is generally paid for its crude oil and condensate production from
Thailand in U.S. dollars.
PRODUCTION. The decrease in the Company's crude oil and condensate
production during 1998, compared to 1997, resulted primarily from a decrease in
condensate production from the Company's East Cameron Block 334 "E" platform,
which was in part due to damage sustained in a marine accident at the crude oil
and condensate pipeline from the platform, that was only partially offset by
increased production from a full year's worth of production from the Tantawan
Field and the Company's ongoing development drilling and workover programs in
the offshore and onshore Gulf of Mexico regions. The increase in the Company's
average crude oil and condensate production for 1998, compared to 1996, was
related in large measure to the commencement of production from the Tantawan
Field in the first quarter of 1997 and, to a lesser extent, condensate
production from the Company's East Cameron Block 334 "E" platform, which
commenced production in April 1997 and production from properties that the
Company acquired in its acquisition of Arch, that was only partially offset by
the anticipated natural decline in deliverability from certain of the Company's
properties. As of December 31, 1998, the Company was not a party to any crude
oil swaps or futures contracts.
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 that are extracted from natural gas production. The
decrease in NGL revenues for 1998, compared with 1997, primarily related to a
decrease in the average price that the Company received for its NGL and, to a
lesser extent, a decrease in the Company's NGL production volumes. The decrease
in NGL revenues in 1998, compared with 1996, primarily related to a decrease in
price that the Company received for its NGL production, that was only partially
offset by an increase in the Company's NGL production.
30
COSTS AND EXPENSES
% CHANGE % CHANGE
1998 1997 1998 TO 1997 1996 1998 TO 1996
-------------- -------------- ------------- -------------- -------------
Comparison of Increases (Decreases) in:
LEASE OPERATING EXPENSES
North America........................... $ 50,300,000 $ 43,934,000 14% $ 37,628,000 34%
Kingdom of Thailand(a).................. $ 20,913,000 $ 19,567,000 7% N/A N/A
-------------- -------------- --------------
Total Lease Operating Expenses........ $ 71,213,000 $ 63,501,000 12% $ 37,628,000 89%
-------------- -------------- --------------
-------------- -------------- --------------
GENERAL AND ADMINISTRATIVE EXPENSES....... $ 26,356,000 $ 21,412,000 23% $ 18,028,000 46%
EXPLORATION EXPENSES...................... $ 9,802,000 $ 10,530,000 (7%) $ 16,777,000 (42%)
DRY HOLE AND IMPAIRMENT EXPENSES.......... $ 41,736,000 $ 9,631,000 333% $ 8,579,000 386%
DEPRECIATION, DEPLETION AND AMORTIZATION
(DD&A) EXPENSES......................... $ 110,916,000 $ 103,157,000 8% $ 61,857,000 79%
DD&A rate............................... $ 1.12 $ 0.95 18% $ 0.87 29%
Mcfe produced........................... 97,894,000 107,605,000 (9%) 70,472,000 39%
INTEREST--
Charges................................. $ 24,682,000 $ 21,886,000 13% $ 13,203,000 87%
Capitalized Interest Expense............ $ 9,381,000 $ 6,175,000 52% $ 4,244,000 121%
FOREIGN CURRENCY TRANSACTION GAIN
(LOSS).................................. $ 953,000 $ (7,604,000) N/A -- N/A
INCOME TAX BENEFIT (EXPENSE).............. $ 27,751,000 $ (18,091,000) N/A $ (18,800,000) N/A
- ------------------------
(a) Production from the Tantawan Field commenced in February 1997, with a
start-up phase which extended through March 15, 1997. No lease operating
expenses were incurred in Thailand prior to commencement of production.
LEASE OPERATING EXPENSES.
The increase in North American lease operating expenses for 1998, compared
to 1997, were affected by $2,142,000 in expenses related to purchasing natural
gas for transportation and subsequent resale on the Saginaw pipeline system
acquired in the merger with Arch, a non-recurring maintenance project on the
Company's East Cameron 334 "E" platform during the first quarter of 1998 and by
operating expenses related to the Saginaw pipeline system and other Arch
properties for which no corresponding expenses were recorded during 1997. In
addition, lease operating expenses for 1997 were reduced by a $1,793,000 in
refunds in connection with the Company's audit of a joint venture partner and
settlement of a dispute with a vendor. The increase in lease operating expenses
in the Kingdom of Thailand for 1998, compared to 1997, was primarily related to
the fact that prior to the commencement of production in the Tantawan Field on
February 1, 1997, no lease operating expenses were incurred by the Company in
Thailand. A substantial portion of the Company's lease operating expenses in the
Kingdom of Thailand relate to lease payments made by Tantawan Services, L.L.C.,
in connection with its bareboat charter of the FPSO, which amounted to
$11,122,000 and $10,200,000 (net to the Company's interest) for 1998 and 1997,
respectively. See "--Liquidity and Capital Resources; Capital Requirements;
Other Material Long-Term Commitments." In addition to the reasons discussed
above, North American lease operating expenses for 1998, compared to 1996, also
increased due to a shortage of qualified offshore service contractors, which
permitted such contractors to increase the costs of their services significantly
during 1997, increased expenses related to the leasing of certain equipment in
the Gulf of Mexico, a year to year increase in the level of the Company's
operating activities, including increased operating costs related to additional
properties brought on production and an increased ownership interest in certain
properties as a result of the acquisition of such interests also contributed to
the increase.
31
GENERAL AND ADMINISTRATIVE EXPENSES
The increase in general and administrative expenses for 1998, compared with
1997 and 1996, was related to a number of non-recurring expenses arising in
connection with the Company's acquisition of Arch totaling approximately
$2,285,000, that included severance payments to former officers and employees of
Arch, 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 geological
and geophysical costs which are expensed as incurred. The decreases in
exploration expenses for 1998, compared to 1997 and 1996, resulted primarily
from decreased geophysical activity by the Company in most of its operational
areas except Canada, where the Company participated in a significant 3-D survey
during 1998, and a decrease in delay rental payments.
DRY HOLE AND IMPAIRMENT EXPENSES
Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled, along with impairments resulting from the application of SFAS No. 121
due to decreases in expected reserves from producing wells. The increase in dry
hole and impairment expenses for 1998, compared with 1997 and 1996, was
principally related to the dry hole cost of the Company's Mustang Island Block
A-51 well, and impairment expenses related a decline in reserves at the
Company's East Cameron Block 334/335 Field and its Keystone Field located in
Winkler County, Texas (which the Company sold at year-end 1998) and
disappointing reservoir performance at the Company's South Pass Block 78 Field.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES
The Company accounts for its oil and gas activities using the successful
efforts method of accounting. Under the successful efforts method, lease
acquisition costs and all development costs are capitalized. Proved properties
are reviewed whenever events or changes in circumstances indicate that the value
of such property on the Company's books may not be recoverable. Unproved
properties are reviewed quarterly to determine if there has been impairment of
the carrying value, with any such impairment charged to expense in the period.
Proved oil and gas properties are reviewed when circumstances suggest the need
for such a review and, if required, he proved properties are written down to
their estimated fair value. Estimated fair value includes the estimated present
value of all reasonably expected future production, prices, and costs. As a
result of poor reservoir performance and persistent low oil and gas prices, the
Company performed such a review in 1998 and expensed $30,813,000 related to its
domestic oil and gas properties which is included in the Consolidated Statements
of Income as dry hole and impairment expense. Exploratory drilling costs are
capitalized until the results are determined. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Other exploratory costs
are expensed as incurred.
The provision for DD&A expense is based on the capitalized costs, as
determined in the preceding paragraph, plus future costs to abandon offshore
wells and platforms, and is determined on a cost center by cost center basis
using the units of production method. The Company generally creates cost centers
on a field by field basis for oil and gas activities in the Gulf of Mexico and
Gulf of Thailand. Generally, the Company establishes cost centers on the basis
of an oil or gas trend or play for its oil and gas activities onshore in the
United States and Canada. The increase in the Company's DD&A expenses for 1998,
compared to 1997, resulted primarily from an increase in the Company's composite
rate, that was not entirely offset by a decline in the Company's natural gas and
liquid hydrocarbon production. The increase in the Company's DD&A expenses for
1998, compared to 1996, 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.
32
The increase in the composite DD&A rate for all of the Company's producing
fields for 1998, compared to 1997 and 1996, resulted primarily from an increased
percentage of the Company's production coming from certain of the Company's
fields that have DD&A rates that are higher than the Company's recent historical
composite rate and a corresponding decrease in the percentage of the Company's
production coming from fields that have DD&A rates that are lower than the
Company's recent historical composite DD&A rate. Management currently
anticipates that this trend will continue for the foreseeable future, resulting
in generally increasing DD&A rates.
INTEREST
INTEREST CHARGES. The increase in the Company's interest charges for 1998,
compared to 1997 and 1996, resulted primarily from an increase in the average
amount of the Company's outstanding debt and, to a lesser extent, increased
average interest rates on the debt outstanding (resulting primarily from the
issuance of the 2007 Notes on May 22, 1997, which bear interest at an 8 3/4%
annual interest rate). As of December 31, 1998, the Company was not a party to
any interest rate swap agreements. Management currently expects the average
interest rate on its outstanding debt to continue to increase due to the
issuance of the 2009 Notes on January 15, 1999, which bear interest at a 10 3/8%
interest rate.
CAPITALIZED INTEREST. The increase in capitalized interest for 1998,
compared to 1997 and 1996, resulted primarily from an increase in the amount of
capital expenditures subject to interest capitalization during 1998
($137,956,000) compared to 1997 ($96,530,000) and 1996 ($68,740,000), and from
an increase in the computed 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 during the
latter half of 1997 and 1998 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.
FOREIGN CURRENCY TRANSACTION GAIN (LOSS)
The foreign currency transaction gain and loss each resulted primarily from
the fluctuation against the U.S. dollar of cash and other monetary assets and
liabilities denominated in Thai baht that were on the Company's subsidiary's
financial statements during the respective periods. In early July 1997, the
government of the Kingdom of Thailand announced that the value of the baht would
be set against the dollar and other currencies under a "managed float" program
arrangement. This led to a substantial decline in value of the Thai baht
compared to the U.S. dollar, resulting in the foreign currency transaction
losses during 1997. During 1998, the value of the Thai baht has generally
strengthened against the U.S. dollar, resulting in corresponding foreign
currency transaction gains. However, the Company cannot predict what the Thai
baht to dollar exchange rate may be in the future. Moreover, it is anticipated
that this exchange rate will remain volatile. As of December 31, 1998, the
Company was not a party to any financial instrument that was intended to
constitute a foreign currency hedging arrangement.
INCOME TAX BENEFIT (EXPENSE)
The Company's income tax benefit for 1998, compared to its income tax
expenses for 1997 and 1996, resulted primarily from a pre-tax loss resulting
from substantially lower revenues in the United States and the tax benefit of
accrued foreign losses from the Company's operations in the Kingdom of Thailand.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The Company's Consolidated Statement of Cash Flows for 1998 reflects net
cash provided by operating activities of $70,929,000. In addition to net cash
provided by operating activities, the Company received net proceeds of
$1,034,000 from the exercise of stock options, $7,164,000 from the sale of
certain non-strategic properties and tubular stock, and had net borrowings of
$136,447,000 under its Credit
33
Agreement and other senior debt facilities. In addition, on January 15, 1999,
the Company consummated the offering of $150,000,000 of its 2009 Notes.
During 1998, the Company invested $201,946,000 of such cash flow in capital
projects, retired a production payment obligation for $15,246,000 related to the
Arch acquisition, spent $2,961,000 to purchase proved reserves, paid $4,531,000
($0.03 per share for each quarter of 1998) in cash dividends to holders of the
Company's common stock, paid $2,635,000 in debt issuance expenses and paid a net
amount of $621,000 in miscellaneous other expenditures. As of December 31, 1998,
the Company's cash and cash investments were $7,959,000 and its long-term debt
stood at $434,947,000.
FUTURE CAPITAL REQUIREMENTS
The Company's capital and exploration budget for 1999, which does not
include any amounts that may be expended for the purchase of proved reserves or
any interest which may be capitalized resulting from projects in progress, was
established by the Company's Board of Directors at $170,000,000. The Company
currently anticipates that its available cash and cash investments, cash
provided by operating activities, funds available under its Credit Agreement and
uncommitted credit lines and amounts that the Company currently believes that it
can obtain from external sources including the issuance of new debt and
convertible preferred securities, or asset sales, will be sufficient to fund the
Company's ongoing operating, interest and general and administrative expenses,
any currently anticipated costs associated with the Company's projects during
1999, and future dividend payments at current levels (including a dividend
payment of $0.03 per share to be paid on February 26, 1999 to shareholders of
record on February 12, 1999). Subject to favorable market conditions and other
factors, the Company also currently intends to issue convertible preferred
equity securities during 1999 to assist in funding its future capital and
exploration plans. The declaration of future dividends on the Company's common
stock will depend upon, among other things, the Company's future earnings and
financial condition, liquidity and capital requirements, its ability to pay
dividends under certain covenants contained in its debt instruments, the general
economic and regulatory climate and other factors deemed relevant by the
Company's Board of Directors.
OTHER MATERIAL LONG-TERM COMMITMENTS
As of February 9, 1996, Tantawan Services, L.L.C. ("TS"), a company that is
currently a wholly owned subsidiary of the Company, entered into a Bareboat
Charter Agreement (the "Charter") with Tantawan Production B.V. for the charter
of the FPSO for use in the Tantawan Field. See "Business--International
Operations." The term of the Charter is for a period ending July 31, 2008,
subject to extension. In addition, TS has a purchase option on the FPSO
throughout the term of the Charter. TS has also contracted with another company,
SBM Marine Services Thailand Ltd., to operate the FPSO on a reimbursable basis
throughout the initial term of the Charter. Performance of both the Charter and
the agreement to operate the FPSO are non-recourse to TS and the Company.
However, performance is secured by a negative pledge on any hydrocarbons stored
on the FPSO and is guaranteed by each of the working interest holders in the
Tantawan Field, including Thaipo. Thaipo's guarantee is limited to its
percentage interest in the Tantawan Field (currently 46.34%). The Charter
currently provides for an estimated charter hire commitment of $24,000,000 per
year ($11,122,000 net to Thaipo) for the first ten years and a decreasing amount
thereafter.
As of August 24, 1998, Thaipo and its joint venture partners (collectively,
the "Charterers") entered into a Bareboat Charter Agreement (the "BCA") with
Watertight Shipping B.V. for the charter of the FSO. See
"Business--International Operations." The term of the BCA is for a period of ten
years commencing on the date that the FSO is ready to begin operations in the
Benchamas Field. In addition, the Charterers have a purchase option on the FSO
throughout the term of the BCA. The Charterers have also contracted with another
company, Tanker Pacific (Thailand) Co. Ltd, to operate the FSO on a fixed fee
basis throughout the initial term of the BCA. Performance of both the BCA and
the agreement to operate the FSO are non-recourse to the Company. However the
obligations of each joint venturer are full recourse to each joint venturer, but
the obligations are several, meaning that each joint venturer's obligations are
limited to its percentage interest in the Thailand Concession. Collectively, the
BCA and the operating
34
agreement currently provide for an estimated expense of chartering and operating
the FSO of $11,253,000 per year ($5,215,000 net to Thaipo), which will commence
after the FSO is installed in the Benchamas Field in late May or June of this
year.
CAPITAL STRUCTURE
CREDIT AGREEMENT AND UNCOMMITTED CREDIT LINES. Effective August 1, 1997, the
Company entered into an amended and restated Credit Agreement, which was amended
most recently on December 21, 1998. The Credit Agreement provides for a
$200,000,000 revolving/term credit facility which will be fully revolving until
July 1, 2000, after which the balance will be due in eight quarterly term loan
installments, commencing October 31, 2000. The amount that may be borrowed under
the Credit Agreement may not exceed a borrowing base which is composed of
domestic, Canadian and Thai properties. Generally, the borrowing base is
determined semi-annually by the lenders in accordance with the Credit Agreement,
based on the lenders' usual and customary criteria for oil and gas transactions.
As of February 1, 1999, the Company's total borrowing base was set at
$140,000,000, which amount cannot be reduced until after April 30, 1999.
However, due to limitations on total indebtedness under the Credit Agreement,
the Company is currently limited to borrowing only $135,000,000 under the Credit
Agreement and its other senior debt arrangements. The Credit Agreement 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, and limitations on indebtedness (including a total
indebtedness limit of $500,000,000), creation of liens, the prepayment of
subordinated debt, the payment of dividends, mergers and consolidations,
investments and asset dispositions. In addition, the Company is prohibited from
pledging borrowing base properties as security for other debt. Borrowings under
the Credit Agreement bear interest at a rate based upon the percentage of the
borrowing base that is being utilized, ranging from a base (prime) rate or LIBOR
plus 1.25% to a base rate plus 0.25% or LIBOR plus 2.0%, at the Company's
option. Borrowings under the Credit Agreement currently bear interest at a base
rate or LIBOR plus 1.75%, at the Company's option. A commitment fee on the
unborrowed amount under the Credit Agreement is also charged and is based upon
the percentage of the borrowing base that is being utilized, ranging from 0.25%
to 0.375%. The commitment fee is currently 0.375% per annum on the unborrowed
amount under the Credit Agreement. As of February 15, 1999, there was
$102,000,000 outstanding under the Credit Agreement.
As of February 15, 1999, the Company is a party to separate letter
agreements with two banks under which each bank may provide an uncommitted money
market line of credit. One of the agreements provides for a $20,000,000 line of
credit, and the other provides for a $10,000,000 line of credit. Both lines of
credit are on an as available or as offered basis and neither bank has any
obligation to make any advances under its line of credit. Although loans made
under each letter agreement are for a maximum term of 30 days, they are
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 its Credit
Agreement. Each letter agreement permits either party to terminate such letter
agreement at any time. Under its Credit Agreement, the Company is currently
limited to incurring a maximum of $20,000,000 of additional senior debt, which
would include debt incurred under both lines of credit and under the banker's
acceptances discussed below. Further, the 2007 Notes and the 2009 Notes also
restrict the incurrence of additional senior indebtedness. See "; 2007 Notes"
and "; 2009 Notes." As of December 31, 1998, there was $4,000,000 outstanding
under one of the lines of credit at an interest rate of 6.1%
BANKER'S ACCEPTANCES. On June 3, 1998, the Company entered into a Master
Banker's Acceptance Agreement under which one of the Company's lenders has
offered to accept up to $20,000,000 in bank drafts from the Company. 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 are for a maximum term of 182 days; however, they are 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 Agreement.
Under its Credit Agreement, the Company is currently limited to incurring a
maximum of $20,000,000 of additional senior debt, which would include banker's
acceptances as well as debt incurred
35
under the lines of credit discussed previously. Further, the 2007 Notes and the
2009 Notes offered also restrict the incurrence of additional senior
indebtedness. See "; 2007 Notes" and "; 2009 Notes." The Master Banker's
Acceptance Agreement permits either party to terminate the letter agreement at
any time upon five business days notice. As of December 31, 1998, bank drafts in
the principal amount of $10,947,000 bearing interest at an average rate of 5.9%
were outstanding under this agreement.
2009 NOTES. On January 15, 1999, the Company issued $150,000,000 principal
amount of 2009 Notes. The proceeds from the issuance of the 2009 Notes were used
to repay amounts outstanding under the Credit Agreement. The 2009 Notes bear
interest at a rate of 10 3/8%, payable semi-annually in arrears on February 15
and August 15 of each year, commencing August 15, 1999. The 2009 Notes are
general unsecured senior subordinated obligations of the Company, are
subordinated in right of payment to the Company's senior indebtedness, which
currently includes the Company's obligations under the Credit Agreement, its
unsecured credit lines and its banker's acceptances, are equal in right of
payment to the 2007 Notes, but are senior in right of payment to the Company's
subordinated indebtedness, which currently includes the 2006 Notes. The Company,
at its option, may redeem the 2009 Notes in whole or in part, at any time on or
after February 15, 2004, at a redemption price of 105.188% of their principal
value and decreasing percentages thereafter. No sinking fund payments are
required on the 2009 Notes. The 2009 Notes are redeemable at the option of any
holder, upon the occurrence of a change of control (as defined in the indenture
governing the 2009 Notes), at 101% of their principal amount. The indenture
governing the 2009 Notes also imposes certain covenants on the Company that are
substantially identical to the covenants contained in the indenture governing
the 2007 Notes, including covenants limiting: incurrence of indebtedness
including senior indebtedness; restricted payments; the issuance and sales of
restricted subsidiary capital stock; transactions with affiliates; liens;
disposition of proceeds of asset sales; non-guarantor restricted subsidiaries;
dividends and other payment restrictions affecting restricted subsidiaries; and
mergers, consolidations and the sale of assets.
2007 NOTES. On May 22, 1997, the Company issued $100,000,000 principal
amount of 2007 Notes. The 2007 Notes bear interest at a rate of 8 3/4%, payable
semi-annually in arrears on May 15 and November 15 of each year. The 2007 Notes
are general unsecured senior subordinated obligations of the Company, are
subordinated in right of payment to the Company's senior indebtedness, which
currently includes the Company's obligations under the Credit Agreement, its
unsecured credit lines and its banker's acceptances, are equal in right of
payment to the 2009 Notes, but are senior in right of payment to the Company's
subordinated indebtedness, which currently includes the 2006 Notes. The Company,
at its option, may redeem the 2007 Notes in whole or in part, at any time on or
after May 15, 2002, at a redemption price of 104.375% of their principal value
and decreasing percentages thereafter. No sinking fund payments are required on
the 2007 Notes. The 2007 Notes are redeemable at the option of any holder, upon
the occurrence of a change of control (as defined in the indenture governing the
2007 Notes), at 101% of their principal amount. The indenture governing the 2007
Notes also imposes certain covenants on the Company that are substantially
identical to the covenants contained in the indenture governing 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.
2006 NOTES. The outstanding principal amount of 2006 Notes was $115,000,000
as of December 31, 1998. The 2006 Notes are convertible into Common Stock at
$42.185 per share, subject to adjustment upon the occurrence of certain events.
The 2006 Notes bear interest at a rate of 5 1/2% and will be redeemable at the
option of the Company, in whole or in part, at any time on or after June 15,
1999, at a redemption price of 103.85% of their principal amount and decreasing
percentages thereafter. No sinking fund payments are required on the 2006 Notes.
The 2006 Notes are redeemable at the option of any holder, upon the occurrence
of a repurchase event (a change of control and other circumstances as defined in
the indenture governing the 2006 Notes), at 100% of the principal amount.
36
2004 NOTES. The Company's 2004 Notes were called for redemption on March
16, 1998, at a price equal to 103.30% of their principal amount. Prior thereto,
holders of all but $95,000 principal amount of the 2004 Notes chose to convert
their 2004 Notes into Common Stock at a conversion price of $22.188 per common
share, rather than receive cash for their 2004 Notes resulting in the issuance
of 3,879,726 shares of Common Stock.
OTHER MATTERS
INFLATION. Publicly held companies are asked to comment on the effects of
inflation on their business. Currently annual inflation in terms of the decrease
in the general purchasing power of the U.S. dollar is running much below the
general annual inflation rates experienced in the past. While the Company, like
other companies, continues to be affected by fluctuations in the purchasing
power of the U.S. dollar due to inflation, such effect is not currently
considered significant.
SOUTHEAST ASIA ECONOMIC ISSUES. A substantial portion of the Company's oil
and gas operations are conducted in Southeast Asia, and a substantial portion of
its natural gas and liquid hydrocarbon production is sold there. Southeast Asia
in general, and the Kingdom of Thailand in particular, have experienced severe
economic difficulties which have been characterized by sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. The government of the Kingdom of Thailand and other
governments in the region are currently acting to address these issues. However,
the economic difficulties currently being experienced in Thailand, together with
the volatility of the Thai baht against the U.S. dollar, will continue to have a
material impact on the Company's operations in the Kingdom of Thailand, together
with the prices that the company receives for its oil and natural gas production
there. See "--Results of Operations; Oil and Gas Revenues" and "--Results of
Operations; Foreign Currency Transaction Gain (Loss)."
All of the Company's current natural gas production from the Thailand
Concession is committed under a long-term Gas Sales Agreement to PTT at a price
denominated in Thai baht which is determined in accordance with a formula that
is intended to ameliorate, at least in part, any decline in the purchasing power
of the Thai baht against the U.S. dollar. See "Business--International
Operations; Contractual Terms Governing the Thailand Concession" and
"Business--Miscellaneous; Sales." Although the Company currently believes that
PTT will honor its commitments under the Gas Sales Agreement, a failure by PTT
to honor such commitments could have a material adverse effect on the Company.
The Company's crude oil and condensate production from the Thailand
Concession is currently sold on a tanker load by tanker load basis. Prices that
the Company receives for such production are based on world benchmark prices,
which are denominated in U.S. dollars, and are typically paid in U.S. dollars.
See "Business--International Operations; Contractual Terms Governing the
Thailand Concession and Related Production" and "Business--Miscellaneous;
Sales." The Company believes that the current economic difficulties in Southeast
Asia have resulted in a decreased demand for petroleum products in the region,
which has contributed to the recent general decline in crude oil and condensate
prices throughout the world. This price decline has had an adverse effect on all
oil and gas companies that sell their production on the world spot markets,
including the Company, without regard to where their respective production is
located.
YEAR 2000 READINESS DISCLOSURE. Many computer software systems, as well as
certain hardware and equipment using date-sensitive data, were structured to use
a two-digit date field meaning that they may not be able to properly recognize
dates in the year 2000. The Company is addressing this issue through a process
that entails evaluation of the Company's critical software and, to the extent
possible, its hardware and equipment to identify and assess Year 2000 issues and
to remediate, replace or establish alternative procedures addressing non-Year
2000 compliant systems, hardware and equipment.
The Company has substantially completed an inventory of its systems and
equipment including computer systems and business applications. Based upon this
review, the Company currently believes that all of its critical software and
computer hardware systems are either Year 2000 compliant or will be within the
next six months. The Company continues to inventory its equipment and facilities
to determine if they
37
contain embedded date-sensitive technology. If problems are discovered,
remediation, replacement or alternative procedures for non-compliant equipment
and facilities will be undertaken on a business priority basis. This process
will continue and, depending upon the equipment and facilities, is scheduled for
completion during the first three quarters of 1999. As of December 31, 1998, the
Company had incurred approximately $50,000 in expenses related to its Year 2000
compliance efforts. These costs are currently being expensed as they are
incurred. However, in certain instances the Company may determine that replacing
existing equipment may be more efficient, particularly where additional
functionality is available. These replacements may be capitalized and therefore
would reduce the estimated 1999 expenses associated with the Year 2000 issue.
The Company currently expects total out-of-pocket costs to become Year 2000
compliant to be less than $1,000,000. The Company currently expects that such
costs will not have a material adverse effect on the Company's financial
condition, operations or liquidity.
The foregoing timetable and assessment of costs to become Year 2000
compliant reflect management's current best estimates. These estimates are based
on many assumptions, including assumptions about the cost, availability and
ability of resources to locate, remediate and modify affected systems, equipment
and facilities. Based upon its activities to date, the Company does not
currently believe that these factors will cause results to differ significantly
from those estimated. However, the Company cannot reasonably estimate the
potential impact on its financial condition and operations if key third parties
including, among others, suppliers, contractors, joint venture partners,
financial institutions, customers and governments do not become Year 2000
compliant on a timely basis. The Company is contacting many of these third
parties to determine whether they will be able to resolve in a timely fashion
their Year 2000 issues as they may affect the Company.
In the event that the Company is unable to complete the remediation or
replacement of its critical systems, facilities and equipment, establish
alternative procedures in a timely manner, or if those with whom the Company
conducts business are unsuccessful in implementing timely solutions, Year 2000
issues could have a material adverse effect on the Company's liquidity and
results of operations. At this time, the potential effect in the event the
Company and/or third parties are unable to timely resolve their Year 2000
problems is not determinable; however, the Company currently believes that it
will be able to resolve its own Year 2000 issues in a timely manner.
The disclosure set forth in this section is provided pursuant to Securities
Act Release No. 33-7558. As such it is protected as a forward-looking statement
under the Private Securities Litigation Reform Act of 1995. See "Forward-Looking
Statements." This disclosure is also subject to protection under the Year 2000
Information and Readiness Disclosure Act of 1998, Public Law 105-271, as a "Year
2000 Statement" and "Year 2000 Readiness Disclosure" as defined therein.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to market risk, including adverse changes in
commodity prices, interest rates and foreign currency exchange rates as
discussed below.
COMMODITY PRICE RISK
The Company produces, purchases and sells natural gas, crude oil, condensate
and NGLs. As a result, the Company's financial results can be significantly
affected as these commodity prices fluctuate widely in response to changing
market forces. In the past, the Company has made limited use of a variety of
derivative financial instruments only for non-trading purposes as a hedging
strategy to manage commodity prices associated with oil and gas sales and to
reduce the impact of commodity price fluctuations. See "Business--Competition
and Market Conditions." As discussed earlier, the Company was not party to any
derivative financial instruments during 1998.
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. Currently, the Company has no open interest rate
38
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 December 31, 1998:
FAIR
1999 2000 2001 2002 2003 THEREAFTER TOTAL
----- --------- ---------- --------- ----- ---------- ----------
Liabilities--Long-Term Debt:
Variable Rate.......................... $ 0 $ 32,992 $ 120,971 $ 65,984 $ 0 $ 0 $ 219,947
Average Interest Rate.................. -- 7.3% 7.3% 7.3% -- -- 7.3%
Fixed Rate............................. $ 0 $ 0 $ 0 $ 0 $ 0 $ 215,000 $ 215,000
Average Interest Rate.................. -- -- -- -- -- 7.0% 7.0%
VALUE
----------
Liabilities--Long-Term Debt:
Variable Rate.......................... $ 219,947
Average Interest Rate.................. --
Fixed Rate............................. $ 172,637
Average Interest Rate.................. --
FOREIGN CURRENCY EXCHANGE RATE RISK
The Company conducts business in Thai baht 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. The Company conducts a
substantial portion of its oil and gas production and sales in Southeast Asia.
Southeast Asia in general, and the Kingdom of Thailand in particular, have
experienced severe economic difficulties, including sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Results of Operations; Foreign Currency
Transaction Gain (Loss") and "--Liquidity and Capital Resources; Other Matters;
Southeast Asia Economic Issues." However, the economic difficulties in Thailand
and the volatility of the Thai baht against the U.S. dollar will continue to
have a material impact on the Company's Thailand operations and prices that the
Company receives for its oil and gas production there. Although the Company's
sales to PTT under the Gas Sales Agreement are denominated in baht, because
predominantly all of the Company's crude oil sales and its capital and most
other expenditures in the Kingdom of Thailand are dominated in U.S. dollars, the
U.S. dollar is the functional currency for the Company's operations in the
Kingdom of Thailand.
Exposure from market rate fluctuations related to activities in Canada,
where the Company's functional currency is the Canadian dollar, is not material
at this time.
39
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10K
FOR THE YEAR ENDED DECEMBER 31, 1998
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
40
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Pogo Producing Company:
We have audited the accompanying consolidated balance sheets of Pogo
Producing Company (a Delaware corporation) and subsidiaries as of December 31,
1998 and 1997, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Pogo Producing Company and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 19, 1999
41
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
---------- ---------- ----------
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Revenues:
Oil and gas................................................................ $ 200,154 $ 284,851 $ 203,364
Pipeline sales and other................................................... 2,649 1,449 613
---------- ---------- ----------
Total.................................................................... 202,803 286,300 203,977
---------- ---------- ----------
Operating Costs and Expenses:
Lease operating............................................................ 71,213 63,501 37,628
General and administrative................................................. 26,356 21,412 18,028
Exploration................................................................ 9,802 10,530 16,777
Dry hole and impairment.................................................... 41,736 9,631 8,579
Depreciation, depletion and amortization................................... 110,916 103,157 61,857
---------- ---------- ----------
Total.................................................................... 260,023 208,231 142,869
---------- ---------- ----------
Operating Income (Loss)...................................................... (57,220) 78,069 61,108
Interest:
Charges.................................................................... (24,682) (21,886) (13,203)
Income..................................................................... 719 453 232
Capitalized................................................................ 9,381 6,175 4,244
Foreign Currency Transaction Gain (Loss)................................... 953 (7,604) --
---------- ---------- ----------
Income (Loss) Before Taxes and Extraordinary Item............................ (70,849) 55,207 52,381
---------- ---------- ----------
Income Tax Benefit (Expense)................................................. 27,751 (18,091) (18,800)
---------- ---------- ----------
Income (Loss) Before Extraordinary Item...................................... (43,098) 37,116 33,581
Extraordinary Loss on Early Extinguishment of Debt, net of taxes............. -- -- (821)
---------- ---------- ----------
Net Income (Loss)............................................................ $ (43,098) $ 37,116 $ 32,760
---------- ---------- ----------
---------- ---------- ----------
Earnings per Share:
Basic
Before extraordinary item................................................ $ (1.14) $ 1.11 $ 1.01
Extraordinary item....................................................... -- -- (0.02)
---------- ---------- ----------
Net income (Loss)............................................................ $ (1.14) $ 1.11 $ 0.99
---------- ---------- ----------
---------- ---------- ----------
Diluted
Before extraordinary item................................................ $ (1.14) $ 1.06 $ 0.97
Extraordinary item....................................................... -- -- (0.02)
---------- ---------- ----------
Net income (Loss)........................................................ $ (1.14) $ 1.06 $ 0.95
---------- ---------- ----------
---------- ---------- ----------
Dividends per Common Share................................................... $ 0.12 $ 0.12 $ 0.12
---------- ---------- ----------
---------- ---------- ----------
The accompanying notes to consolidated financial statements are an integral part
hereof.
42
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
------------------------
1998 1997
----------- -----------
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE
AMOUNTS)
ASSETS
Current Assets:
Cash and cash investments............................................................ $ 7,959 $ 19,646
Accounts receivable.................................................................. 24,054 39,540
Other receivables.................................................................... 38,977 46,951
Inventory--product................................................................... 969 713
Inventories--tubulars................................................................ 10,594 8,334
Other................................................................................ 2,814 4,087
----------- -----------
Total current assets............................................................... 85,367 119,271
----------- -----------
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties being amortized.................................................. 1,485,125 1,321,817
Unevaluated properties and properties under development, not being amortized....... 215,244 110,231
Other, at cost....................................................................... 17,915 12,619
----------- -----------
1,718,284 1,444,667
Less--accumulated depreciation, depletion, and amortization, including $6,862 and
$6,004 respectively, applicable to other property.................................. 992,759 917,363
----------- -----------
725,525 527,304
----------- -----------
Foreign Taxes Receivable............................................................... 23,482 12,025
Debt Issue Expenses.................................................................... 7,727 7,200
Other.................................................................................. 20,295 10,817
----------- -----------
$ 862,396 $ 676,617
----------- -----------
----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable--operating activities............................................... $ 12,197 $ 13,639
Accounts payable--investing activities............................................... 90,102 90,833
Accrued interest payable............................................................. 3,226 3,130
Accrued payroll and related benefits................................................. 1,952 1,938
Other................................................................................ 2 632
----------- -----------
Total current liabilities.......................................................... 107,479 110,172
Long-Term Debt......................................................................... 434,947 348,179
Deferred Federal Income Tax............................................................ 53,869 57,502
Deferred Credits....................................................................... 16,441 14,658
----------- -----------
Total liabilities.................................................................. 612,736 530,511
----------- -----------
Shareholders' Equity:
Preferred stock, $1 par; 2,000,000 shares authorized................................. -- --
Common stock, $1 par; 100,000,000 shares authorized, and 40,136,254 and 33,552,702
shares issued, respectively........................................................ 40,136 33,553
Additional capital................................................................... 290,655 144,848
Retained earnings (deficit).......................................................... (79,600) (31,971)
Treasury stock (15,575 shares) and other, at cost.................................... (1,531) (324)
----------- -----------
Total shareholders' equity......................................................... 249,660 146,106
----------- -----------
$ 862,396 $ 676,617
----------- -----------
----------- -----------
The accompanying notes to consolidated financial statements are an integral part
hereof.
43
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
---------- ---------- ----------
(EXPRESSED IN THOUSANDS)
Cash flows from operating activities:
Cash received from customers................................................ $ 222,433 $ 272,004 $ 195,931
Federal income taxes received............................................... -- 7,037 --
Operating, exploration, and general and administrative expenses paid........ (116,272) (86,445) (74,512)
Interest paid............................................................... (26,221) (20,713) (12,960)
Federal income taxes paid................................................... -- (19,500) (12,500)
Value added taxes paid...................................................... (6,161) (1,630) (1,344)
Other....................................................................... (2,850) (21) (1,717)
---------- ---------- ----------
Net cash provided by operating activities................................. 70,929 150,732 92,898
---------- ---------- ----------
Cash flows from investing activities:
Capital expenditures........................................................ (201,946) (197,326) (172,032)
Purchase of proved reserves................................................. (2,961) (31,234) --
Proceeds from the sale of property and tubular stock........................ 7,164 387 100
---------- ---------- ----------
Net cash used in investing activities..................................... (197,743) (228,173) (171,932)
---------- ---------- ----------
Cash flows from financing activities:
Proceeds from issuance of new debt.......................................... -- 100,000 115,000
Borrowings under senior debt agreements..................................... 449,947 502,000 208,000
Payments under senior debt agreements....................................... (313,500) (500,000) (201,000)
Proceeds from exercise of stock options..................................... 1,034 3,874 3,378
Payment of cash dividends on common stock................................... (4,531) (4,012) (3,979)
Debt issue expenses paid.................................................... (2,635) (3,165) (3,116)
Purchase of 8% debentures due 2005.......................................... -- -- (40,699)
Principal payment of production payment obligation.......................... (15,246) -- --
Other....................................................................... (621) -- --
---------- ---------- ----------
Net cash provided by financing activities................................. 114,448 98,697 77,584
---------- ---------- ----------
Effect of exchange rate changes on cash....................................... 679 (4,664) 23
---------- ---------- ----------
Net increase (decrease) in cash and cash investments.......................... (11,687) 16,592 (1,427)
Cash and cash investments at the beginning of the year........................ 19,646 3,054 4,481
---------- ---------- ----------
Cash and cash investments at the end of the year.............................. $ 7,959 $ 19,646 $ 3,054
---------- ---------- ----------
---------- ---------- ----------
Reconciliation of net income to net cash provided by operating activities:
Net income (loss)........................................................... $ (43,098) $ 37,116 $ 32,760
Adjustments to reconcile net income to net cash provided by operating
activities
Extraordinary losses on early extinguishments of debt, net of taxes....... -- -- 821
Foreign currency transaction (gain) loss.................................. (953) 7,604 --
(Gains) losses on sales................................................... 92 (1,100) 165
Depreciation, depletion and amortization.................................. 110,916 103,157 61,857
Dry hole and impairment................................................... 41,736 9,631 8,579
Interest capitalized...................................................... (9,381) (6,175) (4,244)
(Decrease) increase in deferred income taxes.............................. (24,250) 12,999 7,175
Change in assets and liabilities:
(Increase) decrease in accounts receivable.............................. 15,307 (12,483) (8,211)
Increase in inventory product........................................... (259) (713) --
(Increase) decrease in other current assets............................. 1,258 (6,470) 81
Increase in other assets................................................ (20,551) (7,418) (5,228)
Increase (decrease) in accounts payable................................. (1,122) 8,998 (2,079)
Increase in accrued interest payable.................................... 95 1,173 243
Increase in accrued payroll and related benefits........................ 14 448 251
Increase (decrease) in other current liabilities........................ (637) 469 60
Increase in deferred credits............................................ 1,762 3,496 668
---------- ---------- ----------
Net cash provided by operating activities..................................... $ 70,929 $ 150,732 $ 92,898
---------- ---------- ----------
---------- ---------- ----------
The accompanying notes to consolidated financial statements are an integral part
hereof.
44
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
RETAINED TREASURY
SHARES COMMON ADDITIONAL EARNINGS STOCK AND SHAREHOLDERS'
OUTSTANDING STOCK CAPITAL (DEFICIT) OTHER EQUITY
----------- ----------- ----------- ----------- ----------- -------------
(DOLLARS EXPRESSED IN THOUSANDS)
BALANCE AT DECEMBER 31, 1995............ 32,991,397 $ 33,007 $ 132,881 $ (93,856) $ (324) $ 71,708
Net income.............................. -- -- -- 32,760 -- 32,760
Foreign currency translation gain....... -- -- -- -- 23 23
Exercise of stock options............... 274,714 274 4,924 -- -- 5,198
Shares issued in connection with the
Long-Term Incentive Plan.............. 5,896 6 246 -- -- 252
Shares issued in connection with the
conversion of--
8% Debentures....................... 32,898 33 1,267 -- -- 1,300
2004 Notes.......................... 901 1 19 -- -- 20
Dividends ($0.12 per common share)...... -- -- -- (3,979) -- (3,979)
----------- ----------- ----------- ----------- ----------- -------------
BALANCE AT DECEMBER 31, 1996............ 33,305,806 33,321 139,337 (65,075) (301) 107,282
Net income.............................. -- -- -- 37,116 -- 37,116
Foreign currency translation loss....... -- -- -- -- (23) (23)
Exercise of stock options............... 229,024 230 5,461 -- -- 5,691
Shares issued in connection with the
conversion of 2004 Notes.............. 2,297 2 50 -- -- 52
Dividends ($0.12 per common share)...... -- -- -- (4,012) -- (4,012)
----------- ----------- ----------- ----------- ----------- -------------
BALANCE AT DECEMBER 31, 1997............ 33,537,127 33,553 144,848 (31,971) (324) 146,106
Net loss................................ -- -- -- (43,098) -- (43,098)
Foreign currency translation loss....... -- -- -- -- (1,207) (1,207)
Exercise of stock options............... 147,240 147 1,835 -- -- 1,982
Shares issued in connection with the
conversion of 2004 Notes.............. 3,879,726 3,880 80,712 -- -- 84,592
Shares issued for common stock of
acquired company...................... 1,665,491 1,665 38,818 -- -- 40,483
Shares issued for exchangeable
convertible preferred stock of
acquired company...................... 699,273 699 19,301 -- -- 20,000
Shares issued for convertible debt of
acquired company...................... 174,818 175 4,825 -- -- 5,000
Shares issued as compensation........... 17,004 17 316 -- -- 333
Dividends ($0.12 per common share)...... -- -- -- (4,531) -- (4,531)
----------- ----------- ----------- ----------- ----------- -------------
BALANCE AT DECEMBER 31, 1998............ 40,120,679 $ 40,136 $ 290,655 $ (79,600) $ (1,531) $ 249,660
----------- ----------- ----------- ----------- ----------- -------------
----------- ----------- ----------- ----------- ----------- -------------
The accompanying notes to consolidated financial statements are an integral part
hereof.
45
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
Pogo Producing Company was incorporated in 1970. Pogo Producing Company and
its subsidiaries (the "Company") are engaged in oil and gas exploration,
development and production activities on its properties located offshore in the
Gulf of Mexico and onshore in the United States and Canada and internationally
in the Gulf of Thailand and the United Kingdom. The Company has interests in 105
lease blocks offshore Louisiana and Texas, approximately 303,000 gross acres
onshore in the United States, approximately 117,000 gross acres onshore in
Canada, approximately 734,000 gross acres offshore in the Kingdom of Thailand
and two lease blocks in the United Kingdom North Sea totaling approximately
113,000 gross acres.
ACQUISITION
In August 1998, a wholly-owned subsidiary of the Company merged with Arch
Petroleum Inc. ("Arch") in a tax-free, stock for stock transaction, accounted
for as a purchase, through which Arch became a wholly owned subsidiary of the
Company.
The merger agreement provided for a fixed exchange ratio of one share of the
Company's common stock for each 10.4 shares of Arch common stock. In addition,
holders of Arch preferred stock received one share of the Company's common stock
for each 1.04 shares of Arch preferred stock held. As a result, approximately
2,500,000 shares of the Company's common stock (valued at approximately $64.8
million) were issued in exchange for Arch preferred and common stock and its
convertible debt. The value of the approximately 2,500,000 shares of the
Company's common stock in excess of the book value of the net assets acquired
(approximately $52.9 million) has been allocated to oil and gas properties and
is being amortized using the units of production method over the life of the oil
and gas reserves acquired. Expenses related to the acquisition of approximately
$2,285,000 ($1,485,000 after taxes) have been expensed. Under the purchase
method of accounting for the acquisition, the Arch results of operations are
included in the consolidated results of operations from August 17, 1998, the
date of acquisition, through December 31, 1998.
The following summary presents unaudited pro forma consolidated results of
operations as if the acquisition had occurred at the beginning of each period
presented. The pro forma results are for illustrative purposes only and are not
necessarily indicative of the operating results that would have occurred had the
acquisition been consummated at that date, nor are they necessarily indicative
of future operating results.
YEAR ENDED DECEMBER
31,
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
----------------------
1998 1997
---------- ----------
Revenues............................................................................... $ 217,915 $ 366,803
Net income (loss)...................................................................... $ (48,369) $ 36,691
Earnings (loss) per share:
Basic................................................................................ $ (1.22) $ 1.02
Diluted.............................................................................. $ (1.22) $ 0.98
46
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
USE OF ESTIMATES
The preparation of these financial statements requires the use of certain
estimates by management in determining the Company's assets, liabilities,
revenues and expenses. Depreciation, depletion and amortization of oil and gas
properties and the impairment of oil and gas properties are determined using
estimates of proved oil and gas reserves. There are numerous uncertainties in
estimating the quantity of proved reserves and in projecting the future rates of
production and timing of development expenditures. Oil and gas reserve
engineering must be recognized as a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way. Proved
reserves of crude oil, condensate, natural gas and natural gas liquids are
estimated quantities that geological and engineering data demonstrate with
reasonable certainty to be recoverable in the future from known reservoirs under
existing conditions.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Pogo Producing
Company and its subsidiary and affiliated companies, after elimination of all
significant intercompany transactions. Majority owned subsidiaries are fully
consolidated. Minority owned subsidiaries or affiliates are pro rata
consolidated in the same manner as the Company, and the oil and gas industry
generally, accounts for its operating or working interest in oil and gas joint
ventures.
PRIOR-YEAR RECLASSIFICATIONS
Certain prior-year amounts have been reclassified to conform with the
current year presentation.
FOREIGN CURRENCY
The U.S. dollar is the functional currency for all areas of operations of
the Company except Canada. Accordingly, monetary assets and liabilities and
items of income and expense denominated in a foreign currency are remeasured to
U.S. dollars at the rate of exchange in effect at the end of each month and the
resulting gains or losses on foreign currency transactions are included in the
consolidated statements of income for the period. The Canadian dollar is the
functional currency for the Company's Canadian operations. Accordingly, monetary
assets and liabilities and items of income and expense denominated in Canadian
dollars are translated to U.S. dollars at the rate of exchange in effect at the
end of each month and the resulting gains or losses on Canadian currency
transactions are included in the consolidated statement of shareholders' equity
for the period.
INVENTORY--PRODUCT
Crude oil and condensate from the Company's Tantawan field located in the
Kingdom of Thailand is produced into a floating production, storage and off
loading ("FPSO") system and sold periodically as an economic barge quantity is
accumulated. The product inventory at December 31, 1998 consists of
approximately 90,000 barrels of crude oil and condensate, net to the Company's
interest, and is carried at its estimated net realizable value of $10.76 per
barrel.
INVENTORIES--TUBULARS
Tubular Inventories consist primarily of goods used in the Company's
operations and are stated at the lower of average cost or market value.
47
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
INTEREST CAPITALIZED
Interest costs related to financing major oil and gas projects in progress
are capitalized until the projects are evaluated or until production commences
if the projects are evaluated as successful.
EARNINGS PER SHARE
Earnings (loss) per common share (basic earnings per share) are based on the
weighted average number of shares of common stock outstanding during the
periods. Earnings (loss) per common 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.
FOR THE YEAR ENDED DECEMBER 31,
1998
----------------------------------
INCOME SHARES PER SHARE
---------- --------- -----------
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE................................. $ (43,098) 37,902 $ (1.14)
---------- --------- -----------
---------- --------- -----------
Antidilutive securities:
Shares assumed not issued from options to purchase common shares as the
exercise prices are above the average market price for the period or the
effect of the assumed exercise would be antidilutive.................... -- 2,464 $ 19.37
Interest expense incurred, net of taxes, and shares not issued related to
the assumed non-conversion at $42.185 per share of the 2006 Notes....... $ 4,111 2,726 $ 1.51
Interest expense avoided, net of taxes, and shares issued from the assumed
conversion at $22.188 per share of the 2004 Notes....................... $ 478 594 $ 0.80
FOR THE YEAR ENDED DECEMBER 31,
1997
-----------------------------------
INCOME SHARES PER SHARE
----------- --------- -----------
BASIC EARNINGS PER SHARE..................................................... $ 37,116 33,421 $ 1.11
Effect of potential dilutive securities:
Shares assumed issued from the exercise of options to purchase common
shares, net of treasury shares assumed purchased from the proceeds, at
the average market price for the period.................................. -- 758 --
Interest expense avoided, net of taxes, and shares issued from the assumed
conversion at $22.188 per share of the 2004 Notes........................ 3,082 3,885 --
----------- --------- -----------
DILUTED EARNINGS PER SHARE................................................... $ 40,198 38,064 $ 1.06
----------- --------- -----------
----------- --------- -----------
Antidilutive securities:
Shares assumed not issued from options to purchase common shares as the
exercise prices are above the average market price for the period........ -- 471 $ 40.82
Interest expense incurred, net of taxes, and shares not issued related to
the assumed non-conversion at $42.185 per share of the 2006 Notes........ $ 4,111 2,726 $ 1.51
48
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31,
1996
-----------------------------------
INCOME(A) SHARES PER SHARE
----------- --------- -----------
BASIC EARNINGS PER SHARE..................................................... $ 33,581 33,203 $ 1.01
Effect of potential dilutive securities:
Shares issued from the assumed exercise of options to purchase common
shares, net of treasury shares assumed purchased from the proceeds, at
the average market price for the period.................................. -- 831 --
Interest expense avoided, net of taxes, and shares issued from the assumed
conversion at $22.188 per share of the 2004 Notes........................ 3,083 3,886 --
----------- --------- -----------
DILUTED EARNINGS PER SHARE................................................... $ 36,664 37,920 $ 0.97
----------- --------- -----------
----------- --------- -----------
Antidilutive securities:
Shares assumed not issued from options to purchase common shares as the
exercise prices are above the average market price for the period........ -- 20 $ 40.94
Interest expense incurred, net of taxes, and shares not issued related to
the assumed non-conversion at $39.50 per share of the 8% Debentures,
retired on June 28, 1996................................................. $ 1,179 521 $ 2.26
Interest expense incurred, net of taxes, and shares not issued related to
the assumed non-conversion at $42.185 per share of the 2006 Notes........ $ 2,238 1,472 $ 1.52
- ------------------------
(a) Computed on income before extraordinary item
PRODUCTION IMBALANCES
Owners of an oil and gas property often take more or less production from a
property than entitled to based on their ownership percentages in the property.
This results in a condition known in the industry as a production imbalance. The
Company follows the "take" (cash) method of accounting for production
imbalances. Under this method, the Company recognizes revenues on production as
it is taken and delivered to its purchasers. The Company's crude oil imbalances
are not significant. At December 31, 1998, the Company had taken approximately
2,680 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 2,363 MMcf more than its entitlement on
other properties placing the Company at year-end in a net under-delivered
position of approximately 317 MMcf of natural gas based on its working interest
ownership in the properties.
OIL AND GAS ACTIVITIES AND DEPRECIATION, DEPLETION AND AMORTIZATION
The Company follows the successful efforts method of accounting for its oil
and gas activities. Under the successful efforts method, lease acquisition costs
and all development costs are capitalized. Proved properties are reviewed
whenever events or changes in circumstances indicate that the value of such
property on the Company's books may not be recoverable. Unproved properties are
reviewed quarterly to determine if there has been impairment of the carrying
value, with any such impairment charged to expense in the period. Proved oil and
gas properties are reviewed when circumstances suggest the need for such a
review and, if required, the proved properties are written down to their
estimated fair value. Estimated fair value includes the estimated present value
of all reasonably expected future production, prices, and costs. As a result of
poor reservoir performance and persistent low oil and gas prices, the Company
performed such a review in 1998 and expensed $30,813,000 related to its domestic
oil and gas properties which is included in the Consolidated Statements of
Income as dry hole and impairment expense. Exploratory drilling costs are
capitalized until the results are determined. If proved reserves are
49
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
not discovered, the exploratory drilling costs are expensed. Other exploratory
costs are expensed as incurred. The provision for depreciation, depletion and
amortization is based on the capitalized costs as determined above, plus future
costs to abandon offshore wells and platforms, and is on a cost center by cost
center basis using the units of production method. The Company generally creates
cost centers on a field by field basis for oil and gas activities in the Gulf of
Mexico and the Gulf of Thailand. Generally, the Company establishes cost centers
on the basis of an oil or gas trend or play for its onshore oil and gas
activities.
In connection with the Company's ongoing asset rationalization process, the
Company has designated certain domestic oil and gas properties to be disposed of
during 1999. At the time of designation, no impairment loss was indicated. The
carrying amount of the properties at December 31, 1998 was $29,637,000, and they
contributed $7,253,000, $7,563,000 and $2,013,000 to operating income in 1998,
1997 and 1996, respectively.
Other properties are depreciated using a straight-line method in amounts
which in the opinion of management are adequate to allocate the cost of the
properties over their estimated useful lives.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the purpose of cash flows, the Company considers all highly liquid
investments with a maturity date of three months or less to be cash equivalents.
Significant transactions may occur which do not directly affect cash balances
and as such will not be disclosed in the Consolidated Statements of Cash Flows.
Certain such noncash transactions are disclosed in the Consolidated Statements
of Shareholders' Equity relating to shares issued in connection with the
Long-Term Incentive Plan and the conversion of debentures into Common Stock in
1997 and 1998 and the acquisition of Arch in 1998.
COMMITMENTS AND CONTINGENCIES
The Company has commitments for operating leases for office space in
Houston, Midland, Calgary and Bangkok and commitments for an operating lease and
operating expenses related to an FPSO and FSO in the Gulf of Thailand. Rental
expense for office space was $1,545,000 in 1998, $1,440,000 in 1997, and
$1,054,000 in 1996. Expenses for the FPSO lease and related operating costs were
$15,864,000 in 1998 and $14,809,000 in 1997. Expenses for the FSO lease and
related operating costs are currently expected to commence in May or June of
1999, with total expenses for the floating storage and offloading system ("FSO")
estimated to be approximately $3,077,000 for 1999 and $5,215,000 in the year
2000 and each year thereafter. Future minimum office and FPSO lease expenses and
related FPSO operating expense payments (in thousands of dollars) at December
31, 1998, are as follows:
1999............................................................... $ 19,042
2000............................................................... 21,187
2001............................................................... 19,968
2002............................................................... 19,771
2003............................................................... 19,778
Thereafter......................................................... 89,630
50
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(2) INCOME TAXES
The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1998, are as follows (expressed in
thousands):
1998 1997 1996
---------- ---------- ----------
United States............................................ $ (57,112) $ 62,953 $ 56,380
Foreign.................................................. (13,737) (7,746) (3,999)
---------- ---------- ----------
Total.................................................. $ (70,849) $ 55,207 $ 52,381
---------- ---------- ----------
---------- ---------- ----------
The components of federal income tax expense (benefit) for each of the three
years in the period ended December 31, 1998, are as follows (expressed in
thousands):
1998 1997 1996
---------- --------- ---------
United States, current...................................... $ -- $ 16,000 $ 12,500
United States, deferred (a)................................. (20,750) 5,964 7,162
Foreign, deferred........................................... (7,001) (3,873) (862)
---------- --------- ---------
Total..................................................... $ (27,751) $ 18,091 $ 18,800
---------- --------- ---------
---------- --------- ---------
- ------------------------
(a) Excludes $443,000 of deferred tax benefit on extraordinary loss of
$1,264,000 in 1996.
Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1998, differs from the amounts computed by
applying the statutory federal income tax rate to income before taxes as follows
(expressed as a percent of pre-tax income):
1998 1997 1996
----------- ----------- -----------
Federal statutory income tax rate........................... (35.0)% 35.0% 35.0%
Increases (reductions) resulting from:
Statutory depletion in excess of tax basis................ (0.4) (0.2) (0.2)
Foreign taxes............................................. (3.8) (2.1) 1.1
Other..................................................... -- 0.1 --
----------- ----- -----
(39.2)% 32.8% 35.9%
----------- ----- -----
----------- ----- -----
Deferred income taxes are determined based upon the differences between the
financial statement and tax basis of the Company's assets and liabilities using
enacted tax rates in effect for the years in which the differences are expected
to reverse. Deferred tax assets are recognized if it is more likely than not
that
51
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(2) INCOME TAXES (CONTINUED)
the future tax benefit will be realized. The principal components of the
Company's deferred income tax assets and liabilities include the following at
December 31, 1998 and 1997 (expressed in thousands):
DECEMBER 31,
------------------------
1998 1997
----------- -----------
Deferred tax liabilities:
Intangible drilling costs, capitalized and amortized for financial statement purposes
and deducted for income tax purposes................................................ $ 235,034 $ 204,218
Charges to property and equipment, expensed for financial statement purposes, and
capitalized and amortized for income tax purposes................................... 29,013 12,203
Interest charges, capitalized and amortized for financial statement purposes and
deducted for income tax purposes.................................................... 20,874 19,762
----------- -----------
284,921 236,183
Deferred tax asset:
Differences in depletion and depreciation rates used for tangible assets for financial
and income tax purposes............................................................. (224,271) (178,681)
Net operating loss carryforwards and other ............................................. (6,781) --
----------- -----------
(231,052) (178,681)
----------- -----------
Net deferred tax liability.............................................................. $ 53,869 $ 57,502
----------- -----------
----------- -----------
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1998 and
1997, consists of the following (dollars expressed in thousands):
DECEMBER 31,
----------------------
1998 1997
---------- ----------
Senior debt--
Bank revolving credit agreement:
LIBO Rate based loans, borrowings at December 31, 1998 and 1997, at average interest
rates of 7.4% and 6.5%, respectively................................................ $ 205,000 $ 47,000
Uncommitted credit lines with banks, borrowing at December 31, 1998, at an average
interest rate of 6.1%................................................................. 4,000 --
Banker's acceptance loans, borrowings at an average interest rate of 5.9%............... 10,947 --
---------- ----------
Total senior debt......................................................................... 219,947 47,000
---------- ----------
Subordinated debt--
8 3/4% Senior subordinated notes, due 2007.............................................. 100,000 100,000
5 1/2% Convertible subordinated notes, due 2006......................................... 115,000 115,000
5 1/2% Convertible subordinated notes, due 2004......................................... -- 86,179
---------- ----------
Total subordinated debt................................................................... 215,000 301,179
---------- ----------
Total debt................................................................................ 434,947 348,179
---------- ----------
Amount due within one year................................................................ -- --
---------- ----------
Long-term debt............................................................................ $ 434,947 $ 348,179
---------- ----------
---------- ----------
52
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) LONG-TERM DEBT (CONTINUED)
Effective August 1, 1997, the Company entered into an amended and restated
bank revolving credit agreement (the "Credit Agreement"), which was amended,
most recently on December 21, 1998. The Credit Agreement provides for a
$200,000,000 revolving/term credit facility which will be fully revolving until
July 1, 2000, after which the balance will be due in eight quarterly
installments, commencing on October 31, 2000. The amount that may be borrowed
under the Credit Agreement may not exceed a borrowing base which is composed of
domestic, Canadian and Thai properties. Generally, the borrowing base is
determined semi-annually by the lenders in accordance with the Credit Agreement,
based on the lenders' usual and customary criteria for oil and gas transactions.
As of February 1, 1999, the Company's total borrowing base was set at
$140,000,000, which amount cannot be reduced until after April 30, 1999. The
Credit Agreement 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, and limitations on indebtedness
(including a total indebtedness limit of $500,000,000), creation of liens, the
prepayment of subordinated debt, the payment of dividends, mergers and
consolidations, investments and asset dispositions. In addition, the Company is
prohibited from pledging borrowing base properties as security for other debt.
Borrowings under the Credit Agreement bear interest at a rate based upon the
percentage of the borrowing base that is being utilized, ranging from a base
(prime) rate or LIBOR plus 1.25% to a base rate plus 0.25% or LIBOR plus 2.0%,
at the Company's option. Borrowings under the Credit Agreement currently bear
interest at a base rate or LIBOR plus 1.75%, at the Company's option. A
commitment fee on the unborrowed amount under the Credit Agreement is also
charged and is based upon the percentage of the borrowing base that is being
utilized, ranging from 0.25% to 0.375%. The commitment fee is currently 0.375%
per annum on the unborrowed amount under the Credit Agreement. Due to
limitations on total indebtedness under the Credit Agreement, as of February 1,
1999, the Company may borrow up to $135,000,000 under the Credit Agreement and
its other senior debt arrangements.
As of December 31, 1998, the Company is a party to separate letter
agreements with two banks under which one of the banks may provide a $10,000,000
uncommitted money market line of credit and the other bank may provide a
$20,000,000 uncommitted money market line of credit. Each line of credit is on
an as available or offered basis and neither bank has an obligation to make any
advances under its line of credit. Although loans made under these letter
agreements are for a maximum of 30 days, they are reflected as long-term debt on
the Company's balance sheet because the Company has the ability and intent to
reborrow such amounts under its Credit Agreement. Both letter agreements permit
either party to terminate such letter agreements at any time. Under the Credit
Agreement, the Company is currently limited to incurring a maximum of
$20,000,000 of additional senior debt, which would include debt incurred under
these lines of credit and under the banker's acceptances discussed below.
On June 3, 1998, the Company entered into a Master Banker's Acceptance
Agreement under which one of the Company's lenders has offered to accept up to
$20,000,000 in bank drafts from the Company. 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 are for a maximum term of
182 days; however, they are 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 Agreement. The Master Banker's Acceptance Agreement
permits either party to terminate the letter agreement at any time upon five
business days notice.
On May 22, 1997, the Company issued $100,000,000 of 8 3/4% Senior
Subordinated Notes, due 2007 (the "2007 Notes"). The 2007 Notes bear interest at
a rate of 8 3/4%, payable semi-annually in arrears on May 15 and November 15 of
each year. The 2007 Notes are general unsecured senior subordinated
53
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) LONG-TERM DEBT (CONTINUED)
obligations of the Company and are subordinated in right of payment to the
Company's senior indebtedness, which currently includes the Company's
obligations under the Credit Agreement, its unsecured credit lines, and its
banker's acceptances, are equal in right of payment to the 2009 Notes (defined
below) but are senior in right of payment to its subordinated indebtedness,
which currently includes the 2006 Notes. The Company, at its option, may redeem
the 2007 Notes in whole or in part, at any time on or after May 15, 2002, at a
redemption price of 104.375% of their principal value and decreasing percentages
thereafter. No sinking fund payments are required on the 2007 Notes. The 2007
Notes are redeemable at the option of any holder, upon the occurrence of a
change of control (as defined in the indenture governing the 2007 Notes), at
101% of their principal amount. The indenture governing the 2007 Notes also
imposes certain covenants on the Company that are substantially identical to the
covenants contained in the indenture governing 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.
The 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes") are
convertible into Common Stock at $42.185 per share subject to adjustment upon
the occurrence of certain events. The 2006 Notes will be redeemable at the
option of the Company, in whole or in part, at any time on or after June 15,
1999, at a redemption price of 103.85% and decreasing percentages thereafter. No
sinking fund is provided. The 2006 Notes are redeemable at the option of the
holder, upon the occurrence of a repurchase event (a change in control and other
circumstances, as defined), at 100% of the principal amount.
On February 12, 1998, the Company announced its intent to redeem the 5 1/2%
Convertible Subordinated Notes, due 2004 (the "2004 Notes") on March 16, 1998,
at 103.3% of their principal amount plus accrued interest. Holders of
$86,084,000 principal amount of the 2004 Notes elected to convert their notes
into 3,879,726 common shares at $22.188 per share plus $640 in cash for
fractional shares. The value of the shares issued was credited to common stock
and additional capital less unamortized debt issue expense applicable to the
2004 Notes. The remaining $95,000 principal amount of the 2004 Notes were
redeemed for $98,135 representing 103.3% of the principal amount of such 2004
Notes.
Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are none in 1999, $32,992,000 in
2000, $120,971,000 in 2001, $65,984,000 in 2002 and none in 2003. All of the
current maturities reflected above are related to the retirement of the
Company's bank debt. The Company has established a history of refinancing its
senior debt before scheduled maturity payments commence and expects to do so
again before the amortization of senior debt commences in 2000.
On January 15, 1999, the Company issued $150,000,000 of 10 3/8% Senior
Subordinated Notes, due 2009 (the "2009 Notes"). The proceeds from the issuance
of the 2009 Notes were used to repay amounts outstanding under the Company's
Credit Agreement. The 2009 Notes bear interest at a rate of 10 3/8%, payable
semi-annually in arrears on February 15 and August 15 of each year, commencing
August 15, 1999. The 2009 Notes are generally unsecured senior subordinated
obligations of the Company and are subordinated in right of payment to the
Company's senior indebtedness, which currently includes the Company's
obligations under the Credit Agreement, its unsecured credit lines and bankers
acceptances, are equal in right of payment to the 2007 Notes, but are senior in
right of payment to its subordinated indebtedness, which includes the 2006
Notes. The Company, at its option, may redeem the 2009 Notes in whole or in
part, at any time on or after February 15, 2004, at a redemption price of
105.188% of their principal value and decreasing percentages thereafter. No
sinking fund payments are required on the 2009
54
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) LONG-TERM DEBT (CONTINUED)
Notes. The 2009 Notes are redeemable at the option of any holder, upon the
occurrence of a change in control (as defined in the indenture governing the
2009 Notes), at 101% of their principal amount. The indenture governing the 2009
Notes also imposes certain covenants on the Company that are substantially
identical to the covenants contained in the indenture governing the 2007 Notes.
As of February 1, 1999, $15,000,000 was available for dividends under this
limitation, which is currently the Company's most restrictive such covenant.
(4) GEOGRAPHIC SEGMENT REPORTING
The Company's long-lived assets and revenues by segment and geographic area
are as follows:
TOTAL OIL AND
COMPANY GAS PIPELINES OTHER
---------- ---------- ----------- -----------
(EXPRESSED IN THOUSANDS)
Long-Lived Assets:
As of December 31, 1998:
United States.................................................... $ 502,787 $ 493,633 $ 4,992 $ 4,162
Kingdom of Thailand.............................................. 209,552 207,756 -- 1,796
Canada........................................................... 13,186 13,083 -- 103
---------- ---------- ----------- -----------
Total............................................................ $ 725,525 $ 714,472 $ 4,992 $ 6,061
---------- ---------- ----------- -----------
---------- ---------- ----------- -----------
As of December 31, 1997:
United States.................................................... $ 365,142 $ 360,440 $ 243 $ 4,459
Kingdom of Thailand.............................................. 162,162 160,249 -- 1,913
---------- ---------- ----------- -----------
Total............................................................ $ 527,304 $ 520,689 $ 243 $ 6,372
---------- ---------- ----------- -----------
---------- ---------- ----------- -----------
Revenues:
For the year ended December 31, 1998
United States.................................................... $ 165,873 $ 163,438 $ 2,431 $ 4
Kingdom of Thailand.............................................. 35,649 35,445 -- 204
Canada........................................................... 1,281 1,271 -- 10
---------- ---------- ----------- -----------
Total............................................................ $ 202,803 $ 200,154 $ 2,431 $ 218
---------- ---------- ----------- -----------
---------- ---------- ----------- -----------
For the year ended December 31, 1997
United States.................................................... $ 246,965 $ 245,458 $ -- $ 1,507
Kingdom of Thailand.............................................. 39,335 39,393 -- (58)
---------- ---------- ----------- -----------
Total............................................................ $ 286,300 $ 284,851 $ -- $ 1,449
---------- ---------- ----------- -----------
---------- ---------- ----------- -----------
For the year ended December 31, 1996
United States.................................................... $ 203,966 $ 203,364 $ -- $ 602
Kingdom of Thailand.............................................. 11 -- -- 11
---------- ---------- ----------- -----------
Total............................................................ $ 203,977 $ 203,364 $ -- $ 613
---------- ---------- ----------- -----------
---------- ---------- ----------- -----------
55
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(5) SALES TO MAJOR CUSTOMERS
The Company is an oil and gas exploration and production company that
generally sells its oil and gas to numerous customers on a month-to-month basis.
Sales to the following customers exceeded 10% of revenues during any one of the
three years indicated (expressed in thousands):
1998 1997 1996
--------- --------- ---------
Enron Corp. and affiliates................................... $ 29,539 $ 57,965 $ 58,101
Petroleum Authority of Thailand (PTT)........................ $ 23,137 $ 30,108 $ --
Coastal Gas Marketing Company................................ $ -- $ -- $ 18,376
(6) CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1998
and 1997, result from oil and gas sales and joint interest billings to other
companies in the oil and gas industry. This concentration of customers and joint
interest owners may impact the Company's overall credit risk, either positively
or negatively, in that these entities may be similarly affected by industry-wide
changes in economic or other conditions. Such receivables are generally not
collateralized. Historically, credit losses incurred by the Company on
receivables have not been material. No material credit losses were experienced
during 1998 or 1997.
A substantial portion of the Company's oil and gas operations are conducted
in Southeast Asia, and a substantial portion of its natural gas and liquids
hydrocarbon production are sold there. In the last two years, Southeast Asia in
general, and the Kingdom of Thailand in particular, have experienced severe
economic difficulties which have been characterized by sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. The government of the Kingdom of Thailand and other
governments in the region are currently acting to address these issues. However,
the economic difficulties currently being experienced in Thailand, together with
the volatility of the Thai Baht against the U.S. dollar, will continue to have a
material impact on the Company's operations in the Kingdom of Thailand together
with the prices that the Company receives for its oil and natural gas production
there.
All of the Company's current natural gas production from its Thailand
operations are committed under a long-term Gas Sales Agreement to PTT at a price
denominated in Thai Baht. The Company's crude oil and condensate production from
its Thailand operations is currently sold on a tanker load by tanker load basis.
Prices that the Company receives for such crude oil production are based on
world benchmark prices, which are denominated in U.S. dollars and are generally
expected on future crude oil sales to be paid in U.S. dollars. The Company
believes that the current economic difficulties in Southeast Asia have resulted
in a decreased demand for petroleum products in the region, which has
contributed to the recent general decline in crude oil and condensate prices
throughout the world.
(7) EMPLOYEE BENEFITS
The Company has a tax-advantaged savings plan in which all U.S. salaried
employees may participate. Under such plan, a participating employee may
allocate up to 10% of his salary, up to a maximum allowed by law ($10,000 for
1999), and the Company will then match the employee's contribution on a dollar
for dollar basis up to 6% of the employee's salary. Funds contributed by the
employee and the matching funds contributed by the Company are held in trust by
a bank trustee in six separate funds. Amounts contributed by the employee and
earnings and accretions thereon may be used to purchase shares of Common Stock,
invest in a money market fund or invest in four stock, bond, or blended stock
and bond mutual funds according to instructions from the employee. Matching
funds contributed to the savings plan by the
56
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) EMPLOYEE BENEFITS (CONTINUED)
Company are invested only in Common Stock. The Company contributed $701,000 to
the savings plan in 1998, $588,000 in 1997, and $471,000 in 1996.
A trusteed retirement plan has been adopted by the Company for its U.S.
salaried employees. The benefits are based on years of service and the
employee's average compensation for five consecutive years within the final ten
years of service which produce the highest average compensation. The Company
makes annual contributions to the plan in the amount of retirement plan cost
accrued or the maximum amount which can be deducted for federal income tax
purposes. Although the Company has no obligation to do so, the Company currently
provides full medical benefits to its retired U.S. employees and dependents. For
current employees, the Company assumes all or a portion of post retirement
medical and term life insurance costs based on the employee's age and length of
service with the Company. The post retirement medical plan has no assets and is
currently funded by the Company on a pay-as-you-go basis. The Company adopted
Statement of Financial Accounting Standards No. 132, "Employer's Disclosures
about
57
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) EMPLOYEE BENEFITS (CONTINUED)
Pensions and Other Post Retirement Benefits," in 1998. This statement changes
the disclosure requirements, but not the method of measurement or recognition of
these obligations. The following table sets forth the plans' status (in
thousands of dollars) as of December 31, 1998 and 1997.
POST RETIREMENT
RETIREMENT PLAN BENEFITS
---------------------- --------------------
1998 1997 1998 1997
---------- ---------- --------- ---------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year........ $ 11,220 $ 9,350 $ 6,906 $ 5,895
Service cost................................. 938 746 418 459
Interest cost................................ 843 707 374 427
Participant contributions.................... -- -- 4 1
Benefits paid................................ (2,099) (539) (191) (207)
Actuarial (gain) or loss..................... 2,947 956 (1,227) 331
---------- ---------- --------- ---------
Benefit obligation at end of year.............. 13,849 11,220 6,284 6,906
---------- ---------- --------- ---------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of
year......................................... 31,312 24,181 -- --
Actual return on plan assets................. 8,439 7,893 -- --
Employer contributions....................... -- -- 187 206
Participant contributions.................... -- -- 4 1
Benefits paid................................ (2,099) (539) (191) (207)
Administrative expenses...................... (248) (223) -- --
---------- ---------- --------- ---------
Fair value of plan assets at end of year....... 37,404 31,312 -- --
---------- ---------- --------- ---------
RECONCILIATION OF FUNDED STATUS
Funded status.................................. 23,555 20,092 (6,284) (6,906)
Unrecognized actuarial gain.................... (14,670) (13,134) (1,742) (641)
Unrecognized transition (asset) or
obligation................................... (233) (336) 2,132 2,435
Unrecognized past service cost................. (257) (300) -- --
---------- ---------- --------- ---------
Prepaid (accrued) benefit cost at year-end..... $ 8,395 $ 6,322 $ (5,894) $ (5,112)
---------- ---------- --------- ---------
---------- ---------- --------- ---------
Discount rate.................................. 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets................. 9.50% 8.50% -- --
Rate of compensation increase.................. 4.75% 4.89% -- --
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost................................... $ 938 $ 746 $ 418 $ 459
Interest cost.................................. 843 707 374 427
Expected return on plan assets................. (2,926) (2,286) -- --
Amortization of prior service cost............. (43) (43) -- --
Amortization of transition obligation.......... (104) (104) 305 305
Recognized actuarial gain...................... (781) (628) (127) (26)
---------- ---------- --------- ---------
$ (2,073) $ (1,608) $ 970 $ 1,165
---------- ---------- --------- ---------
---------- ---------- --------- ---------
58
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) EMPLOYEE BENEFITS (CONTINUED)
For measurement purposes, a 7% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate is assumed
to decrease gradually to 5% for 2003 and remain at that level thereafter.
The accumulated post retirement benefit obligation at December 31 is
attributable to the following groups (in thousands of dollars):
POST RETIREMENT
BENEFITS
--------------------
1998 1997
--------- ---------
Retirees and beneficiaries................................................. $ 1,456 $ 1,951
Dependents of retirees..................................................... 1,147 978
Fully eligible active employees............................................ 578 802
Active employees, not fully eligible....................................... 3,103 3,175
--------- ---------
$ 6,284 $ 6,906
--------- ---------
--------- ---------
Assumed health care cost trends have a significant effect on the amount
reported for the health care plan. A one-percentage-point change in assumed
health care cost trend rates would have the following effects (in thousands of
dollars):
ONE PERCENTAGE POINT
------------------------
INCREASE DECREASE
----------- -----------
Effect on total of service and interest cost components for 1998......... $ 157 $ (124)
Effect on year-end 1998 postretirement benefit obligation................ 1,028 (836)
(8) STOCK OPTION PLANS
The Company's stock option plans authorize the granting of options to key
employees and non-employee directors at prices equivalent to the market value at
the date of grant. Options generally become exercisable in three annual
installments commencing one year after the date of grant and, if not exercised,
expire 10 years from the date of grant. The Company accounts for employee
stock-based compensation using the intrinsic value method and since the exercise
price of the options granted is equal to the quoted market price of the
Company's stock at the grant date, no compensation cost has been recognized for
its stock options plans. Had compensation costs been determined based on fair
value at the grant dates for awards made in 1998, 1997 and 1996, the Company's
net income and earnings per share
59
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) STOCK OPTION PLANS (CONTINUED)
would have been reduced to the pro forma amounts indicated below (in thousands
of dollars, except per share amounts):
1998 1997 1996
---------- --------- ---------
Net income (loss):
As reported............................................... $ (43,098) $ 37,116 $ 32,760
Pro forma................................................. $ (44,602) $ 34,220 $ 31,194
Earnings (loss) per share:
As reported Basic......................................... $ (1.14) $ 1.11 $ 0.99
As reported Diluted....................................... $ (1.20) $ 1.06 $ 0.95
Pro forma Basic........................................... $ (1.14) $ 1.04 $ 0.94
Pro forma Diluted......................................... $ (1.20) $ 0.99 $ 0.91
The fair value of grants was estimated on the date of grant using the Black
Scholes option pricing model with the following weighted-average assumptions
used in 1998, 1997 and 1996, respectively: risk free interest rates of 5.31%,
6.10% and 6.25%, expected volatility of 35.58%, 34.63% and 39.15%, dividend
yields of 0.64%, 0.29% and 0.34%, and an expected life of the options of 4 years
in each of the years 1998, 1997 and 1996.
60
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) STOCK OPTION PLANS (CONTINUED)
A summary of the status of the Company's plans as of December 31, 1998, 1997
and 1996, and changes during the years ended on those dates is presented below:
WEIGHTED
AVERAGE
NUMBER OF EXERCISE
OPTIONS PRICE
---------- -----------
Outstanding, December 31, 1995............................................................. 1,575,401 $ 14.56
Granted in 1996.......................................................................... 406,500 $ 34.59
Exercised in 1996........................................................................ (274,714) $ 12.30
----------
Outstanding, December 31, 1996............................................................. 1,707,187 $ 19.70
----------
----------
Exercisable, December 31, 1996............................................................. 1,077,658 $ 14.31
----------
----------
Available for grant, December 31, 1996..................................................... 1,313,393
----------
----------
Weighted average fair value of options granted during 1996................................. $ 13.56
Outstanding, December 31, 1996............................................................. 1,707,187 $ 19.70
Granted in 1997.......................................................................... 480,400 $ 40.49
Exercised in 1997........................................................................ (229,024) $ 16.83
----------
Outstanding, December 31, 1997............................................................. 1,958,563 $ 25.13
----------
----------
Exercisable, December 31, 1997............................................................. 1,196,803 $ 18.15
----------
----------
Available for grant, December 31, 1997..................................................... 832,993
----------
----------
Weighted average fair value of options granted during 1997................................. $ 14.63
Outstanding, December 31, 1997............................................................. 1,958,563 $ 19.70
Granted in 1998.......................................................................... 985,659 $ 19.62
Exercised in 1998........................................................................ (145,317) $ 6.87
Cancelled in 1998........................................................................ (334,748) $ 37.13
----------
Outstanding, December 31, 1998............................................................. 2,464,157 $ 19.37
----------
----------
Exercisable, December 31, 1998............................................................. 1,223,484 $ 19.00
----------
----------
Available for grant, December 31, 1998..................................................... 682,082
----------
----------
Weighted average fair value of options granted during 1998................................. $ 5.35
61
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) STOCK OPTION PLANS (CONTINUED)
The following table summarizes information about stock options outstanding
at December 31, 1998:
OPTIONS OUTSTANDING
---------------------------------------
WEIGHTED OPTIONS EXERCISABLE
AVERAGE -----------------------
REMAINING WEIGHTED WEIGHTED
CONTRACTUAL AVERAGE AVERAGE
RANGE OF NUMBER LIFE EXERCISE NUMBER EXERCISE
OPTION PRICES OUTSTANDING (DAYS) PRICE EXERCISABLE PRICE
- ------------------ ----------- ------------- ----------- ---------- -----------
$ 5.56 to $8.06 317,361 742 $ 6.84 317,361 $ 6.84
$ 12.31 4,000 3,531 $ 12.31 -- --
$ 15.13 to $19.56 1,057,625 3,025 $ 18.25 244,262 $ 16.74
$ 20.28 to $24.81 868,638 2,649 $ 21.39 479,738 $ 22.16
$ 25.38 to $29.06 49,962 3,386 $ 25.72 45,321 $ 25.39
$ 30.23 to $33.94 30,962 2,709 $ 33.75 20,321 $ 33.81
$ 35.13 to $36.00 53,109 2,656 $ 35.97 51,314 $ 35.98
$ 40.62 to $44.00 82,500 3,084 $ 41.00 65,167 $ 41.05
----------- ----------
Total 2,464,157 2,597 $ 19.37 1,223,484 $ 19.00
----------- ----------
----------- ----------
(9) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
CASH AND CASH INVESTMENTS
Fair value is carrying value as no cash equivalents or cash investments are
included in the balances as of December 31, 1998 and 1997.
DEBT
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE
- -------------------------------------------------------- --------------------------------------------------------
Bank revolving credit agreement......................... Fair value is carrying value as of December 31, 1998 and
1997 based on the market value interest rates.
Uncommitted credit lines with banks and banker's
acceptance loans...................................... Fair value is carrying value as of December 31, 1998
based on the market value interest rates.
2007 Notes.............................................. Fair value is 94% and 102.5%, of carrying value as of
December 31, 1998 and 1997, respectively, based on
quoted market values.
2006 Notes.............................................. Fair value is 68.38% and 93.5%, of carrying value as of
December 31, 1998 and 1997, respectively, based on
quoted market values.
2004 Notes.............................................. Fair value is 140.38% of carrying value as of December
31, 1997 based on quoted market value.
62
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1998 and 1997, (in thousands of dollars) are as
follows:
1998 1997
------------------------ ------------------------
CARRYING CARRYING
VALUE FAIR VALUE VALUE FAIR VALUE
----------- ----------- ----------- -----------
Cash and cash investments.................................... $ 7,959 $ 7,959 $ 19,646 $ 19,646
Debt:
Bank revolving credit agreement............................ (205,000) (205,000) (47,000) (47,000)
Uncommitted credit lines with banks........................ (4,000) (4,000) -- --
Banker's acceptance loans.................................. (10,947) (10,947) -- --
2007 Notes................................................. (100,000) (94,000) (100,000) (102,500)
2006 Notes................................................. (115,000) (78,637) (115,000) (107,525)
2004 Notes................................................. -- -- (86,179) (120,978)
The Company occasionally enters into forward and futures contracts to
minimize the impact of oil and gas price fluctuations. However, the Company does
not consider its forward and futures contracts to be financial instruments since
these contracts require or permit settlement by the delivery of the underlying
commodity. Gains and losses on these activities are recognized in revenues when
the hedged production occurs. No such contracts were outstanding as of December
31, 1998 or 1997.
(10) COMPREHENSIVE INCOME
During 1998, the Company adopted the Financial Accounting Standards Board's
Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income" ("SFAS 130"). Currently there are no significant amounts to be included
in the computation of comprehensive income of the Company, as defined, that are
required to be disclosed under the provisions of SFAS 130. The Company did
report a foreign currency translation loss of $1,207,000 in 1998 which is
reflected as a reduction of shareholders' equity and represents less than 2% of
the Company's reported pretax loss for 1998. As such, total comprehensive income
(loss) and net income (loss) are materially the same for each of the three years
in the period ended December 31, 1998.
(11) IMPACT OF SFAS 133--
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"). 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
and that changes in the derivative's fair market value be recognized currently
in earnings unless specific hedge accounting criteria are met. SFAS 133 is
effective for the Company in 2000 but early adoption is allowed. The Company has
not yet quantified the impacts of adopting SFAS 133 or determined the timing or
method of adoption. However, SFAS 133 could increase volatility in earnings and
other comprehensive income should the Company enter into transactions covered by
this pronouncement.
63
UNAUDITED SUPPLEMENTARY FINANCIAL DATA
OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities excludes
non-oil and gas revenues, general and administrative expenses, interest charges,
interest income and interest capitalized. Income tax (expense) or benefit was
determined by applying the statutory rates to pre-tax operating results with
adjustments for permanent differences.
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND CANADA
----------- ---------- ----------- ---------
(EXPRESSED IN THOUSANDS)
1998
-----------------------------------------------
Revenues.......................................................... $ 200,154 $ 163,438 $ 35,445 $ 1,271
Lease operating expense........................................... (68,883) (47,294) (20,913) (676)
Exploration expense............................................... (9,802) (8,835) (289) (678)
Dry hole and impairment expense................................... (41,736) (41,736) -- --
Depreciation, depletion and amortization expense.................. (109,288) (85,969) (22,753) (566)
----------- ---------- ----------- ---------
Pre-tax operating results......................................... (29,555) (20,396) (8,510) (649)
Income tax benefit................................................ 11,916 7,401 4,255 260
----------- ---------- ----------- ---------
Operating results................................................. $ (17,639) $ (12,995) $ (4,255) $ (389)
----------- ---------- ----------- ---------
----------- ---------- ----------- ---------
1997
-----------------------------------------------
Revenues.......................................................... $ 284,851 $ 245,458 $ 39,393 $ --
Lease operating expense........................................... (63,501) (43,934) (19,567) --
Exploration expense............................................... (10,530) (6,242) (4,288) --
Dry hole and impairment expense................................... (9,631) (9,631) -- --
Depreciation, depletion and amortization expense.................. (101,273) (84,443) (16,830) --
----------- ---------- ----------- ---------
Pre-tax operating results......................................... 99,916 101,208 (1,292) --
Income tax (expense) benefit...................................... (30,353) (32,390) 2,037 --
----------- ---------- ----------- ---------
Operating results................................................. $ 69,563 $ 68,818 $ 745 $ --
----------- ---------- ----------- ---------
----------- ---------- ----------- ---------
1996
-----------------------------------------------
Revenues.......................................................... $ 204,142 $ 204,131 $ 11 $ --
Lease operating expense........................................... (37,628) (37,628) -- --
Exploration expense............................................... (16,777) (14,247) (2,530) --
Dry hole and impairment expense................................... (8,579) (8,834) 255 --
Depreciation, depletion and amortization expense.................. (61,033) (60,932) (101) --
----------- ---------- ----------- ---------
Pre-tax operating results......................................... 80,125 82,490 (2,365) --
Income tax (expense) benefit...................................... (27,905) (28,767) 862 --
----------- ---------- ----------- ---------
Operating results................................................. $ 52,220 $ 53,723 $ (1,503) $ --
----------- ---------- ----------- ---------
----------- ---------- ----------- ---------
64
UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(CONTINUED)
The following table sets forth the Company's costs incurred (expressed in
thousands) for oil and gas producing activities during the years indicated.
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND CANADA
---------- ---------- ----------- ---------
Costs incurred
(capitalized unless otherwise indicated):
1998:
Property acquisition..................................... $ 149,903 $ 144,031 $ -- $ 5,872
Exploration
Capitalized............................................ 36,465 24,685 11,631 149
Expensed............................................... 9,802 8,831 293 678
Development.............................................. 156,718 64,052 89,365 3,301
Interest................................................. 9,381 3,209 6,172 --
---------- ---------- ----------- ---------
$ 362,269 $ 244,808 $ 107,461 $ 10,000
---------- ---------- ----------- ---------
---------- ---------- ----------- ---------
Provision for depreciation, depletion and amortization..... $ 109,288 $ 85,969 $ 22,753 $ 566
---------- ---------- ----------- ---------
---------- ---------- ----------- ---------
1997:
Property acquisition..................................... $ 43,109 $ 14,492 $ 28,617 $ --
Exploration
Capitalized............................................ 45,203 24,016 21,187 --
Expensed............................................... 10,530 6,242 4,288 --
Development.............................................. 156,764 95,768 60,996 --
Interest................................................. 6,079 3,331 2,748 --
---------- ---------- ----------- ---------
$ 261,685 $ 143,849 $ 117,836 $ --
---------- ---------- ----------- ---------
---------- ---------- ----------- ---------
Provision for depreciation, depletion and amortization..... $ 101,273 $ 84,443 $ 16,830 $ --
---------- ---------- ----------- ---------
---------- ---------- ----------- ---------
1996:
Property acquisition..................................... $ 5,927 $ 5,927 $ -- $ --
Exploration
Capitalized............................................ 28,968 20,651 8,317 --
Expensed............................................... 16,777 14,258 2,519 --
Development.............................................. 153,028 99,464 53,564 --
Interest................................................. 4,244 4,244 -- --
---------- ---------- ----------- ---------
$ 208,944 $ 144,544 $ 64,400 $ --
---------- ---------- ----------- ---------
---------- ---------- ----------- ---------
Provision for depreciation, depletion and amortization..... $ 61,033 $ 60,932 $ 101 $ --
---------- ---------- ----------- ---------
---------- ---------- ----------- ---------
The following information regarding estimates of the Company's proved oil
and gas reserves, which are located offshore in United States waters of the Gulf
of Mexico, onshore in the United States and Canada and offshore in the Kingdom
of Thailand is based on reports prepared by Ryder Scott Company Petroleum
Engineers. The definitions and assumptions that serve as the basis for the
discussions under the caption "Item 1, Business--Exploration and Production
Data--Reserves" should be referred to in connection with the following
information.
65
UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(CONTINUED)
ESTIMATES OF PROVED RESERVES
OIL, CONDENSATE AND NATURAL GAS LIQUIDS (BBLS.)
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND CANADA
----------- ----------- ----------- ---------
Proved Reserves as of December 31, 1995....................... 45,182,002 26,185,010 18,996,992 --
Revisions of previous estimates............................. (499,595) 3,374,647 (3,874,242) --
Extensions, discoveries and other additions................. 9,810,363 3,601,333 6,209,030 --
Estimated 1996 production................................... (4,890,588) (4,890,588) -- --
----------- ----------- ----------- ---------
Proved Reserves as of December 31, 1996....................... 49,602,182 28,270,402 21,331,780 --
Revisions of previous estimates............................. 1,033,664 2,194,936 (1,161,272) --
Extensions, discoveries and other additions................. 9,316,407 4,649,856 4,666,551 --
Purchase of properties...................................... 5,175,501 409,428 4,766,073 --
Sale of properties.......................................... (6,155) (6,155) -- --
Estimated 1997 production................................... (6,957,246) (6,136,957) (820,289) --
----------- ----------- ----------- ---------
Proved Reserves as of December 31, 1997....................... 58,164,353 29,381,510 28,782,843 --
Revisions of previous estimates............................. (263,410) 1,316,467 (1,417,472) (162,405)
Extensions, discoveries and other additions................. 10,111,879 2,767,537 7,341,791 2,551
Purchase of properties...................................... 6,226,804 5,496,985 -- 729,819
Sale of properties.......................................... (28,024) (28,024) -- --
Estimated 1998 production................................... (6,702,038) (5,724,933) (896,200) (80,905)
----------- ----------- ----------- ---------
Proved Reserves as of December 31, 1998....................... 67,509,564 33,209,542 33,810,962 489,060
----------- ----------- ----------- ---------
----------- ----------- ----------- ---------
Proved Developed Reserves as of:
December 31, 1995........................................... 22,487,608 22,487,608 -- --
December 31, 1996........................................... 31,090,407 25,898,414 5,191,993 --
December 31, 1997........................................... 33,149,612 26,167,519 6,982,093 --
December 31, 1998........................................... 33,368,347 28,581,175 4,298,112 489,060
NATURAL GAS (MMCF)
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND CANADA
--------- --------- ----------- ---------
Proved Reserves as of December 31, 1995................ 328,061 196,454 131,607 --
Revisions of previous estimates...................... (30,034) 3,022 (33,056) --
Extensions, discoveries and other additions.......... 102,039 55,592 46,447 --
Estimated 1996 production............................ (39,122) (39,122) -- --
--------- --------- ----------- ---------
Proved Reserves as of December 31, 1996................ 360,944 215,946 144,998 --
Revisions of previous estimates...................... (16,860) (5,582) (11,278) --
Extensions, discoveries and other additions.......... 92,063 49,651 42,412 --
Purchase of properties............................... 30,319 8,919 21,400 --
Sale of properties................................... (1,864) (1,864) -- --
Estimated 1997 production............................ (63,114) (50,350) (12,764) --
--------- --------- ----------- ---------
Proved Reserves as of December 31, 1997................ 401,488 216,720 184,768 --
Revisions of previous estimates...................... (13,376) 7,391 (17,943) (2,824)
Extensions, discoveries and other additions.......... 70,649 55,859 14,418 372
Purchase of properties............................... 38,689 32,259 -- 6,430
Sale of properties................................... (2,738) (2,738) -- --
Estimated 1998 production............................ (54,543) (41,136) (12,854) (553)
--------- --------- ----------- ---------
Proved Reserves as of December 31, 1998................ 440,169 268,355 168,389 3,425
--------- --------- ----------- ---------
--------- --------- ----------- ---------
Proved Developed Reserves as of:
December 31, 1995.................................... 164,679 164,679 -- --
December 31, 1996.................................... 238,032 192,034 45,998 --
December 31, 1997.................................... 239,732 179,972 59,760 --
December 31, 1998.................................... 225,054 181,205 40,424 3,425
66
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--UNAUDITED
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND CANADA
------------ ------------ ----------- ---------
(EXPRESSED IN THOUSANDS)
1998
--------------------------------------------------
Future gross revenues......................................... $ 1,624,242 $ 880,743 $ 732,942 $ 10,557
Future production costs:
Lease operating expense..................................... (540,332) (281,421) (255,252) (3,659)
Future development and abandonment costs...................... (331,607) (167,724) (163,680) (203)
------------ ------------ ----------- ---------
Future net cash flows before income taxes..................... 752,303 431,598 314,010 6,695
Discount at 10% per annum..................................... (257,077) (142,293) (113,413) (1,371)
------------ ------------ ----------- ---------
Discounted future net cash flow before income taxes........... 495,226 289,305 200,597 5,324
Future income taxes, net of discount at 10% per annum......... (72,505) (22,494) (52,132) 2,121
------------ ------------ ----------- ---------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves..................... $ 422,721 $ 266,811 $ 148,465 $ 7,445
------------ ------------ ----------- ---------
------------ ------------ ----------- ---------
1997
--------------------------------------------------
Future gross revenues......................................... $ 1,801,254 $ 1,002,609 $ 798,645 $ --
Future production costs:
Lease operating expense..................................... (604,665) (269,505) (335,160) --
Future development and abandonment costs...................... (401,970) (155,179) (246,791) --
------------ ------------ ----------- ---------
Future net cash flows before income taxes..................... 794,619 577,925 216,694 --
Discount at 10% per annum..................................... (331,838) (171,764) (160,074) --
------------ ------------ ----------- ---------
Discounted future net cash flow before income taxes........... 462,781 406,161 56,620 --
Future income taxes, net of discount at 10% per annum......... (113,316) (93,386) (19,930) --
------------ ------------ ----------- ---------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves..................... $ 349,465 $ 312,775 $ 36,690 $ --
------------ ------------ ----------- ---------
------------ ------------ ----------- ---------
1996
--------------------------------------------------
Future gross revenues......................................... $ 2,318,113 $ 1,491,057 $ 827,056 $ --
Future production costs:
Lease operating expense..................................... (504,899) (259,501) (245,398) --
Future development and abandonment costs...................... (310,839) (126,086) (184,753) --
------------ ------------ ----------- ---------
Future net cash flows before income taxes..................... 1,502,375 1,105,470 396,905 --
Discount at 10% per annum..................................... (547,830) (332,343) (215,487) --
------------ ------------ ----------- ---------
Discounted future net cash flow before income taxes........... 954,545 773,127 181,418 --
Future income taxes, net of discount at 10% per annum......... (268,505) (212,906) (55,599) --
------------ ------------ ----------- ---------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves..................... $ 686,040 $ 560,221 $ 125,819 $ --
------------ ------------ ----------- ---------
------------ ------------ ----------- ---------
67
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--UNAUDITED--CONTINUED
The standardized measure of discounted future net cash flows from the
production of proved reserves is developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods in which they are expected to be produced based on year end economic
conditions.
2. The estimated future gross revenues from proved reserves are priced on
the basis of year end prices, except in those instances where fixed and
determinable natural gas price escalations are covered by contracts.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as certain abandonment
costs based on year end cost estimates, and the estimated effect of future
income taxes. These cost estimates are subject to some uncertainty, particularly
those estimates relating to the Company's properties located in the Kingdom of
Thailand.
The standardized measure of discounted future net cash flows does not
purport to present the fair market value of the Company's oil and gas reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows. All amounts are related to changes
in reserves located in the United States,the Kingdom of Thailand, and Canada, as
noted.
YEAR ENDED DECEMBER 31, 1998
------------------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND CANADA
----------- ----------- ----------- ---------
(EXPRESSED IN THOUSANDS)
Beginning balance................................................ $ 349,465 $ 312,775 $ 36,690 $ --
Revisions to prior years' proved reserves:
Net changes in prices and production costs..................... (165,355) (151,407) (13,948) --
Net changes due to revisions in quantity estimates............. 5,592 13,681 (8,089) --
Net changes in estimates of future development costs........... (10,777) (43,419) 32,642 --
Accretion of discount.......................................... 46,278 40,616 5,662 --
Changes in production rate and other........................... 1,649 (6,485) 7,539 595
----------- ----------- ----------- ---------
Total revisions.............................................. (122,613) (147,014) 23,806 595
New field discoveries and extensions, net of future production
and development costs.......................................... 101,142 55,418 45,338 386
Purchases of properties.......................................... 46,907 41,969 -- 4,938
Sales of properties.............................................. (17,158) (17,158) -- --
Sales of oil and gas produced, net of production costs........... (131,271) (116,144) (14,532) (595)
Previously estimated development costs incurred.................. 155,438 66,073 89,365 --
Net change in income taxes....................................... 40,811 70,892 (32,202) 2,121
----------- ----------- ----------- ---------
Net change in standardized measure of discounted future net
cash flows................................................. 73,256 (45,964) 111,775 7,445
----------- ----------- ----------- ---------
Ending balance................................................... $ 422,721 $ 266,811 $ 148,465 $ 7,445
----------- ----------- ----------- ---------
----------- ----------- ----------- ---------
68
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--UNAUDITED--CONTINUED
YEAR ENDED DECEMBER 31, 1997
-------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
----------- ----------- -----------
(EXPRESSED IN THOUSANDS)
Beginning balance.......................................................... $ 686,040 $ 560,221 $ 125,819
Revisions to prior years' proved reserves:
Net changes in prices and production costs............................... (473,086) (344,493) (128,593)
Net changes due to revisions in quantity estimates....................... (18,624) 9,619 (28,243)
Net changes in estimates of future development costs..................... (83,170) (75,649) (7,521)
Accretion of discount.................................................... 95,455 77,313 18,142
Changes in production rate and other..................................... (31,132) (4,518) (26,614)
----------- ----------- -----------
Total revisions........................................................ (510,557) (337,728) (172,829)
New field discoveries and extensions, net of future production and
development costs........................................................ 79,258 76,687 2,571
Purchase of properties..................................................... 10,189 5,899 4,290
Sales of properties........................................................ (6,069) (6,069) --
Sales of oil and gas produced, net of production costs..................... (221,350) (201,524) (19,826)
Previously estimated development costs incurred............................ 156,764 95,768 60,996
Net change in income taxes................................................. 155,190 119,521 35,669
----------- ----------- -----------
Net change in standardized measure of discounted future net cash
flows................................................................ (336,575) (247,446) (89,129)
----------- ----------- -----------
Ending balance............................................................. $ 349,465 $ 312,775 $ 36,690
----------- ----------- -----------
----------- ----------- -----------
YEAR ENDED DECEMBER 31, 1996
-------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
----------- ----------- -----------
(EXPRESSED IN THOUSANDS)
Beginning balance.......................................................... $ 377,145 $ 295,981 $ 81,164
Revisions to prior years' proved reserves:
Net changes in prices and production costs............................... 304,233 289,182 15,051
Net changes due to revisions in quantity estimates....................... 6,717 53,708 (46,991)
Net changes in estimates of future development costs..................... (132,685) (79,791) (52,894)
Accretion of discount.................................................... 53,248 40,085 13,163
Changes in production rate and other..................................... (72,474) (38,593) (33,881)
----------- ----------- -----------
Total revisions........................................................ 159,039 264,591 (105,552)
New field discoveries and extensions, net of future production and
development costs........................................................ 275,738 173,962 101,776
Sales of properties........................................................ (165,736) (165,736) --
Previously estimated development costs incurred............................ 153,028 99,464 53,564
Net change in income taxes................................................. (113,174) (108,041) (5,133)
----------- ----------- -----------
Net change in standardized measure of discounted future net cash
flows................................................................ 308,895 264,240 44,655
----------- ----------- -----------
Ending balance............................................................. $ 686,040 $ 560,221 $ 125,819
----------- ----------- -----------
----------- ----------- -----------
69
QUARTERLY RESULTS--UNAUDITED
Summaries of the Company's results of operations by quarter for the years
1998 and 1997 are as follows:
QUARTER ENDED
-------------------------------------------
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
--------- --------- --------- ----------
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)
1998
Revenues............................................................. $ 60,730 $ 52,663 $ 46,179 $ 43,231
Gross profit (loss) (a).............................................. $ 8,621 $ 4,758 $ (3,908) $ (40,335)
Net income (loss).................................................... $ 184 $ (2,668) $ (8,322) $ (32,292)(b)
Earnings (loss) per share (c):
Basic.............................................................. $ 0.01 $ (0.07) $ (0.22) $ (0.80)
Diluted............................................................ $ 0.01 $ (0.07) $ (0.22) $ (0.80)
1997
Revenues............................................................. $ 61,314 $ 76,740 $ 77,177 $ 71,069
Gross profit (a)..................................................... $ 27,776 $ 23,953 $ 27,648 $ 20,104
Net income........................................................... $ 12,818 $ 9,174 $ 7,386 $ 7,738
Earnings per share (c):
Basic.............................................................. $ 0.38 $ 0.27 $ 0.22 $ 0.23
Diluted............................................................ $ 0.36 $ 0.26 $ 0.21 $ 0.22
- ------------------------
(a) Represents revenues less lease operating, exploration, dry hole and
impairment, and depreciation depletion and amortization expenses.
(b) The net loss for the fourth quarter of 1998 includes an impairment charge of
approximately $24,500,000 resulting from poor reservoir performance and
persistent low oil and gas prices.
(c) The sum of the individual quarterly earnings (loss) per share may not agree
with year-to-date earnings (loss) per share as each quarterly computation is
based on the weighted average number of common shares outstanding during
that period.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
Not applicable.
70
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information regarding nominees and continuing directors in the Company's
definitive Proxy Statement for its annual meeting to be held on April 27, 1999,
to be filed within 120 days of December 31, 1998 pursuant to Regulation 14A
under the Securities Exchange Act of 1934, as amended (the Company's "1999 Proxy
Statement"), is incorporated herein by reference. See also Item S-K 401(b)
appearing in Part I of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
The information regarding executive compensation in the Company's 1999 Proxy
Statement, other than the information regarding the Compensation Committee
Report on Executive Compensation, is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information regarding ownership of the Company securities by management
and certain other beneficial owners in the Company's 1999 Proxy Statement is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information regarding certain relationships and related transactions
with management in the Company's 1999 Proxy Statement in incorporated herein by
reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Financial Statements and Supplementary Data, Financial Statement
Schedules and Exhibits
PAGE
-----
1. Financial Statements and Supplementary Data:
Report of Independent Public Accountants........................................... 41
Consolidated statements of income.................................................. 42
Consolidated balance sheets........................................................ 43
Consolidated statements of cash flows.............................................. 44
Consolidated statements of shareholders' equity.................................... 45
Notes to consolidated financial statements......................................... 46
Unaudited supplementary financial data............................................. 64
2. Financial Statement Schedules:
All Financial Statement Schedules have been omitted because they are not
required, are not applicable or the information required has been included
elsewhere herein.
71
3. Exhibits:
*3.1 -- Restated Certificate of Incorporation of Pogo Producing Company. (Exhibit 3(a),
Annual Report on Form 10-K for the year ended December 31, 1997, File No.
1-7792).
*3.2 -- Certificate of Designation, Preferences and Rights of Preferred Stock of Pogo
Producing Company, dated March 25, 1987. (Exhibit 3(a)(1), Annual Report on Form
10-K for the year ended December 31, 1987, File No. 0-5468).
*3.3 -- Bylaws of Pogo Producing Company, as amended and restated through January 27, 1998
(Exhibit 3(b), Annual Report on Form 10-K for the year ended December 31,
1998,File No. 1-7792).
*4.1 -- Amended and Restated Credit Agreement dated as of August 1, 1997 among Pogo
Producing Company, certain commercial lending institutions, Bank of Montreal as
the Agent and Banque Paribas as the Co-Agent. (Exhibit 4(a), Quarterly Report on
Form 10-Q for the quarter ended, June 30, 1997, File No. 1-7792).
* 4.2 -- First Amendment dated as of December 21, 1998, to Amended and Restated Credit
Agreement dated as of August 1, 1997 among Pogo Producing Company, certain
commercial lending institutions, Bank of Montreal as the Agent and Banque
Paribas as the Co-Agent. (Exhibit 4.1, Amendment No. 1 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1998, File No. 1-7792).
*4.3 -- Indenture dated as of June 15, 1996 to Fleet National Bank, as Trustee. (Exhibit
4(f), Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File
No. 001-7792).
*4.4 -- Indenture dated as of May 15, 1997 between Pogo Producing Company and Fleet
National Bank (now State Street Bank & Trust Company as successor in interest
under the Indenture) as Trustee (Exhibit 4.3, Registration Statement on Form
S-4, filed July 2, 1997, File No. 333-30613).
*4.5 -- Indenture dated as of January 15,1999 between Pogo Producing Company and State
Street Bank & Trust Company as Trustee (Exhibit 4.2, Registration Statement on
Form S-4, filed February 10, 1999, File No. 333-72129).
*4.6 -- Purchase Agreement dated January 12,1999 between Pogo Producing Company and
Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and
Goldman, Sachs & Co. (Exhibit 4.1, Registration Statement on Form S-4, filed
February 10, 1999, File No. 333-72129).
*4.7 -- Registration Rights Agreement dated January 15,1999 among Pogo Producing Company
and Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and
Goldman, Sachs & Co. (Exhibit 4.3, Registration Statement on Form S-4, filed
February 10, 1999, File No. 333-72129).
*4.8 -- Rights Agreement dated as of April 26, 1994 between Pogo Producing Company and
Harris Trust Company of New York, as Rights Agent. (Exhibit 4, Current Report on
Form 8-K filed April 26, 1994, File No. 1-7792).
*4.9 -- Certificate of Designations of Series A Junior Participating Preferred Stock of
Pogo Producing Company dated April 26, 1994. (Exhibit 4(d), Registration
Statement on Form S-8 filed August 9, 1994, File No. 33-54969).
Pogo Producing Company agrees to furnish to the Commission upon request a copy of
any agreement defining the rights of holders of long-term debt of Pogo Producing
Company and all its subsidiaries for which consolidated or unconsolidated
financial statements are required to be filed under which the total amount of
securities authorized does not exceed 10% of the total assets of Pogo Producing
Company and its subsidiaries on a consolidated basis.
72
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (COMPRISING EXHIBITS 10.1 THROUGH
10.25, INCLUSIVE)
*10.1 -- 1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Company, as
amended and restated effective January 25, 1994. (Exhibit 99, Definitive Proxy
Statement on Schedule 14A, filed March 22, 1994, File No. 1-7792).
*10.2 -- Form of Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option
Plan, as amended and restated effective January 22, 1991. (Exhibit 10(d)(1),
Annual Report on Form 10-K for the year ended December 31, 1991, File No.
0-5468).
*10.3 -- Form of Director Stock Option Agreement under 1989 Incentive and Nonqualified
Stock Option Plan as amended and restated effective January 22, 1991. (Exhibit
10(d)(2), Annual Report on Form 10-K for the year ended December 31, 1991, File
No. 0-5468).
*10.4 -- 1995 Long-Term Incentive Plan. (Exhibit 4(c), Registration Statement on Form S-8
filed May 22, 1996, File No. 333-04233).
10.5 -- 1998 Long-Term Incentive Plan.
*10.6 -- Executive Employment Agreement by and between Pogo Producing Company and Stuart P.
Burbach, dated February 1, 1996. (Exhibit 10(f)(1), Annual Report on Form 10-K
for the year ended December 31, 1995, File No. 001-7792).
10.7 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Stuart P. Burbach, dated effective February 1, 1999.
*10.8 -- Executive Employment Agreement by and between Pogo Producing Company and Jerry A.
Cooper, dated February 1, 1996. (Exhibit 10(f)(2), Annual Report on Form 10-K
for the year ended December 31, 1995, File No. 001-7792).
10.9 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Jerry A. Cooper, dated effective February 1, 1999.
*10.10 -- Executive Employment Agreement by and between Pogo Producing Company and Kenneth
R. Good, dated February 1, 1996. (Exhibit 10(f)(3), Annual Report on Form 10-K
for the year ended December 31, 1995, File No. 001-7792).
10.11 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Kenneth R. Good, dated effective February 1, 1999.
*10.12 -- Executive Employment Agreement by and between Pogo Producing Company and R.
Phillip Laney, dated February 1, 1996. (Exhibit 10(f)(4), Annual Report on Form
10-K for the year ended December 31, 1995, File No. 001-7792).
10.13 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and R. Phillip Laney, dated effective February 1, 1999.
*10.14 -- Executive Employment Agreement by and between Pogo Producing Company and John O.
McCoy, Jr., dated February 1, 1996. (Exhibit 10(f)(5), Annual Report on Form
10-K for the year ended December 31, 1995, File No. 001-7792).
10.15 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and John O. McCoy, Jr., dated effective February 1, 1999.
*10.16 -- Executive Employment Agreement by and between Pogo Producing Company and Paul G.
Van Wagenen, dated February 1, 1996. (Exhibit 10(f)(6), Annual Report on Form
10-K for the year ended December 31, 1995, File No. 001-7792).
10.17 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Paul G. Van Wagenen, dated effective February 1, 1999.
*10.18 -- Executive Employment Agreement by and between Pogo Producing Company and Bruce E.
Archinal, dated as of February 1, 1998 (Exhibit 10(c)(7)(i), Annual Report on
Form 10-K for the year ended December 31, 1997, File No. 001-7792).
73
10.19 -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Bruce E. Archinal, dated effective February 1, 1999.
10.20 -- Executive Employment Agreement by and between Pogo Producing Company and David R.
Beathard, dated as of February 1, 1999.
10.21 -- Executive Employment Agreement by and between Pogo Producing Company and Stephen
R. Brunner, dated as of February 1, 1999.
10.22 -- Executive Employment Agreement by and between Pogo Producing Company and J. D.
McGregor, dated as of February 1, 1999.
10.23 -- Executive Employment Agreement by and between Pogo Producing Company and Gerald A.
Morton, dated as of February 1, 1999.
*10.24 -- Excess Benefits Letter Agreement by and between Pogo Producing Company and Kenneth
R. Good, dated March 2, 1995. (Exhibit 10(g)(1), Annual Report on Form 10-K for
the year ended December 31, 1995, File No. 001-7792).
*10.25 -- Excess Benefits Letter Agreement by and between Pogo Producing Company and Paul G.
Van Wagenen, dated March 2, 1995. (Exhibit 10(g)(2), Annual Report on Form 10-K
for the year ended December 31, 1995, File No. 001-7792).
10.26 -- Amended and Restated Bareboat Charter Agreement by and between Tantawan Services,
L.L.C. and Tantawan Production B.V., dated as of February 9,1996.
10.27 -- Bareboat Charter Agreement by and between Thaipo Limited, Thai Romo Limited,
Palang Sophon Limited, B8/32 Partners Limited and Watertight Shipping B.V. dated
as of August 24, 1998.
*10.28 -- Gas Sales Agreement dated November 7, 1995, among The Petroleum Authority of
Thailand, Thaipo, Limited, Thai Romo Ltd. and The Sophonpanich Co., Ltd.
(Exhibit 10(k), Quarterly Report on Form 10-Q for the quarter ended June 30,
1996, File No. 001-7792).
*10.29 -- The First Amendment to the Gas Sales Agreement dated November 12, 1997, among The
Petroleum Authority of Thailand, B8/32 Partners Limited, Thaipo, Limited, Thai
Romo Limited and Palang Sophon Limited (Exhibit 10(g)(ii), Annual Report on Form
10-K for the year ended December 31, 1998, File No. 001-7792).
21 -- List of Subsidiaries of Pogo Producing Company.
23.1 -- Consent of Independent Public Accountants.
23.2 -- Consent of Independent Petroleum Engineers.
24 -- Powers of Attorney from each Director of Pogo Producing Company whose signature is
affixed to this Form 10-K for the year ended December 31, 1998.
27 -- Financial Data Schedule.
* Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K
None
74
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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)
By: /s/ PAUL G. VAN WAGENEN
-----------------------------------------
Paul G. Van Wagenen
CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF
EXECUTIVE OFFICER
Date: February 26, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on February 26, 1999.
SIGNATURES TITLE
- ------------------------------ --------------------------
/s/ PAUL G. VAN WAGENEN
- ------------------------------
Paul G. Van Wagenen Principal Executive
CHAIRMAN OF THE BOARD, Officer and Director
PRESIDENT AND CHIEF EXECUTIVE
OFFICER
/s/ JOHN W. ELSENHANS
- ------------------------------
John W. Elsenhans Principal Financial
VICE PRESIDENT AND CHIEF Officer
FINANCIAL OFFICER
/s/ THOMAS E. HART
- ------------------------------ Principal Accounting
Thomas E. Hart Officer
VICE PRESIDENT AND CONTROLLER
JERRY M. ARMSTRONG*
- ------------------------------ Director
Jerry M. Armstrong
TOBIN ARMSTRONG*
- ------------------------------ Director
Tobin Armstrong
75
SIGNATURES TITLE
- ------------------------------ --------------------------
JACK S. BLANTON*
- ------------------------------ Director
Jack S. Blanton
W. M. BRUMLEY, JR.*
- ------------------------------ Director
W. M. Brumley, Jr.
JOHN B. CARTER, JR.*
- ------------------------------ Director
John B. Carter, Jr.
WILLIAM L. FISHER*
- ------------------------------ Director
William L. Fisher
GERRIT W. GONG*
- ------------------------------ Director
Gerrit W. Gong
J. STUART HUNT*
- ------------------------------ Director
J. Stuart Hunt
FREDERICK A. KLINGENSTEIN*
- ------------------------------ Director
Frederick A. Klingenstein
JACK A. VICKERS*
- ------------------------------ Director
Jack A. Vickers
*By: /s/ THOMAS E. HART
-------------------------
Thomas E. Hart
ATTORNEY-IN-FACT
76