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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 2000
[_] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
for the transition period from to
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 Identification No.)
incorporation or organization)
5 Greenway Plaza, P.O. Box 2504
Houston, Texas 77252-2504
(Address of principal executive (Zip Code)
offices)
Registrant's telephone number, including area code: (713) 297-5000
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each exchange on which
Common Stock, $1 par value registered:
New York Stock Exchange
Preferred Stock Purchase Rights Pacific Exchange
Pogo Trust I 6 1/2% Cumulative New York Stock Exchange
Quarterly Income New York Stock Exchange
Convertible Preferred Securities,
Series A
Securities registered pursuant to Section 12(g) of the Act:
5 1/2% Convertible Subordinated Notes due June 15, 2006
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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. [X]
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 $595,449,518 as of March 1, 2000 (based on $26.91 per share, the
last sale price of the Common Stock as reported on the New York Stock Exchange
Composite Tape on such date).
40,770,183 shares of the registrant's Common Stock were outstanding as of
March 1, 2001.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 24, 2001 (to be filed not later
than 120 days after December 31, 2000) 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, 2000 (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") and its subsidiaries, 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"). 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
. our ability to successfully and profitably find and produce oil and gas
. uncertainties associated with the United States and worldwide economies
. current and potential governmental regulatory actions in countries where
the Company owns an interest
. substantial competition from larger companies
. the Company's ability to implement cost reductions
. 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 Company's ability to successfully complete the merger with NORIC
Corporation ("NORIC") and to integrate the operations of its subsidiary,
North Central Oil Corporation ("North Central") into the Company
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.
1
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.
PART I
ITEM 1. Business.
The Company was incorporated in 1970 and is engaged in oil and gas
exploration, development, acquisition 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, 2000, the Company had interests in
99 lease blocks offshore Louisiana and Texas, approximately 341,376 gross acres
onshore in the United States and Canada, approximately 714,053 gross acres
offshore in the Kingdom of Thailand, approximately 193,631 gross acres in the
Danish and U.K. sectors of the North Sea and approximately 778,136 gross acres
in Hungary.
On November 19, 2000, the Company entered into an agreement and plan of
merger with NORIC and certain shareholders of NORIC signatories thereto, which
provided for the merger (the "Merger") of the Company and NORIC. The Company
expects the Merger to occur in mid-March following satisfaction of all
conditions precedent including approval by the Company's shareholders at a
meeting scheduled for March 13, 2001. The principal asset of NORIC is its
wholly-owned subsidiary, North Central, a company that explores for and
produces oil and natural gas principally in onshore and offshore Gulf Coast
areas and Wyoming. A more complete description of North Central and the Merger
is set forth in the Company's definitive proxy statement filed with the
Commission on February 6, 2001. Following consummation of the Merger, the
Company will file a copy of North Central's audited annual consolidated
financial statements for the year ended December 31, 2000. Except where
expressly noted, the information contained in this Annual Report relates only
to the Company and does not include either historical information regarding
North Central or the future impact of the Merger on the Company.
The Company organizes its exploration and production activities principally
into four operating divisions and a New Ventures Group. The operating divisions
are its Offshore Division, which is responsible for the Company's operations
offshore Texas and Louisiana in the Gulf of Mexico, its Western Division, which
is active in the Permian Basin area in New Mexico and West Texas, its Onshore
Division, which includes the Company's onshore operations principally in South
Texas, East Texas, Louisiana and Western Canada (principally in the provinces
of Alberta and British Columbia) and the International Division, which has
responsibility for the Company's operations on its Block B8/32 Concession in
the Kingdom of Thailand (the "Thailand Concession"), as well as the Company's
exploration licenses in the North Sea. The Company's New Ventures Group is
currently responsible for the Company's exploration activities in Hungary.
Domestic Offshore Operations
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 33% of the Company's proved reserves were located
as of December 31, 2000. During 2000, approximately 44% of the Company's
natural gas production and approximately 27% of its oil and condensate
production was from its domestic offshore properties, contributing
approximately 35% of the Company's consolidated oil and
2
gas revenues. The Company's exploration and development efforts are primarily
focused in shallower waters of the Outer Continental Shelf where the Company
held interests in 79 lease blocks on December 31, 2000. In recent years, the
Company has expanded its exploration efforts further offshore into deeper
waters where the Company currently believes there are selective opportunities
for discovering and profitably producing substantial quantities of oil and gas.
As of December 31, 2000, the Company has interests in 20 lease blocks in water
depths that range from 600 feet to approximately 4,900 feet.
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 2000 were approximately $63,600,000, or 12% higher than the Company's
domestic offshore capital and exploration expenditures of approximately
$56,900,000 (excluding approximately $1,500,000 of net property acquisitions)
for 1999, and 6% lower than the Company's domestic offshore capital and
exploration expenditures of approximately $68,000,000 (excluding approximately
$5,000,000 of net property acquisitions) for 1998. The increase in the
Company's domestic offshore capital and exploration expenditures for 2000,
compared with 1999, resulted primarily from increased exploratory and
development drilling and exploration expenditures on new 3-D seismic data. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." The Company has currently budgeted approximately $124,000,000 for
capital and exploration expenditures during 2001 in the Gulf of Mexico. A
substantial portion of this budget, over $60,000,000, is related to fabrication
and installation of a platform on the Company's recently discovered Main Pass
Blocks 61/62 Field and installation of subsea completions and platform tiebacks
at the Company's Ewing Banks Blocks 871/872 Field and Mississippi Canyon Blocks
661/705 Field, all of which are currently expected to come on production prior
to the end of 2001. The Company maintains a significant presence in the Gulf of
Mexico where it participated in drilling 27 successful wells during 2000,
bringing the total number of producing oil and gas wells in the Gulf of Mexico
that the Company held an interest to 182 at December 31, 2000.
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 34 of the 99 offshore leases in which it had an interest on December 31,
2000.
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
well slots, water depth, currents, and sea floor conditions. Over the last
several years, gross construction and installation cost of production platforms
and related facilities located in shallower waters 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.
However, the Company's wholly-owned Main Pass Blocks 61/62 Field platform,
which will be installed in 2001, is currently expected to cost approximately
$29,000,000. Wells, platforms and related facilities are typically much more
expensive in the deeper waters of the Gulf of Mexico. Occasionally, deep water
developments can be performed by means of "subsea completion" technology with
the production then piped back to an existing platform. The Company will
participate in two subsea completion developments during
3
2001, at its Ewing Banks Blocks 871/872 Field and its Mississippi Canyon Blocks
661/705 Field, where the total facilities costs for both projects are currently
estimated to be approximately $52,000,000 ($36,000,000 net to the Company's
working interest). The Company believes that future development projects in the
deep water areas of the Gulf of Mexico may require similar capital commitments,
each of which must be justified in the then current and anticipated future
product price environment.
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, 2000, the Company owned interests in
93 federal leases and 6 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 2000, the Company was successful in
acquiring interests in six lease blocks through federal Outer Continental Shelf
oil and gas lease sales and two lease blocks 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.
Onshore Operations
The Company's Onshore Division has staffs in Houston, Texas and Calgary,
Alberta, Canada. The Company's Western Division has an office in Midland,
Texas. The Company conducts its onshore operations in the United States
directly and through its wholly-owned subsidiary, Arch Petroleum Inc. ("Arch").
The Company conducts its operations in Canada through its wholly-owned
subsidiary, Pogo Canada Ltd. The Company's onshore operations constitute a
growing area of the Company's reserves and production. Onshore reserves as of
December 31, 2000, accounted for approximately 27% of the Company's total
proved reserves. During 2000, approximately 20% of the Company's natural gas
production and 25% of its oil and condensate production was from its onshore
properties, contributing approximately 26% of the Company's consolidated oil
and gas revenues. If the Merger with North Central is successfully completed,
the Company currently anticipates that North Central's onshore operations will
be integrated into the Company's Onshore and Western Divisions.
Exploration and Development
A major drilling objective of the Company 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 451 wells
in the Permian Basin and West Texas areas through December 31, 2000, including
42 wells in 2000. The Company believes that during the past eight 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 119,000 gross acres. Fields in the
Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of
the Permian Basin are generally characterized by multiple producing zones in
most wells. 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.
4
In Southwest Louisiana, the Company has participated in drilling 30 wells
since 1996, including five wells in 2000, 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. The Company recently acquired a 3-D seismic survey
covering approximately 39,000 acres in Southwest Louisiana. Interpretation of
this data has identified seven drilling opportunities on acreage controlled by
the Company, the first of which was being drilled as of December 31, 2000. The
Company is also active in the James Lime play in North Texas and the Barnett
Shale play in North Central Texas. In Canada, Pogo Canada Ltd. operates
primarily in the province of Alberta, where it drilled four successful wells in
2000 and has currently budgeted to drill another nine wells in 2001.
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 $55,100,000 (excluding approximately $8,400,000 of net property
acquisitions) for 2000, or 114% higher than the Company's onshore capital and
exploration expenditures of approximately $25,700,000 (excluding approximately
$25,100,000 of net property acquisitions) for 1999, and 13% higher than the
Company's onshore capital and exploration expenditures of 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. The increase in the Company's onshore capital and exploration
expenditures for 2000, compared to 1999 and 1998, resulted primarily from
increased exploratory and development drilling in all of its onshore core
areas. The Company has currently budgeted approximately $64,500,000 for capital
and exploration expenditures during 2001 in its onshore U.S. and Canadian
areas. These amounts are exclusive of any capital and exploration expenditures
on North Central properties after they are acquired, which the Company
currently expects to be in the range of $75,000,000 for the calendar year.
Lease Acquisitions
As it has in recent years, in 2000 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, 2000, the Company held interests in approximately 99,000 gross
(44,000 net) acres onshore in the United States and Canada.
International Operations
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas throughout the world. During 2000,
the Company reorganized a substantial portion of its international operations
under a new Dutch holding company known as Pogo Overseas Production B.V.
Currently, a wholly-owned subsidiary of Pogo Overseas Production, Thaipo
Limited ("Thaipo") maintains an office in Bangkok, Thailand from which it
oversees operations on the Thailand Concession. 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 Chevron
Offshore (Thailand) Limited ("Chevron") (46.34%), a subsidiary of Chevron
Corporation, and Palang Sophon Limited ("Palang") (7.32%). Through its majority
ownership of Palang, Chevron owns or controls, directly or indirectly, 53.66%
of the working interests in the Thailand Concession. Chevron is currently the
operator of the Thailand Concession. Through voting procedures in the joint
operating agreement governing the Thailand Concession, and the close working
relationship between Chevron's and Thaipo's exploration staffs, Thaipo
continues to exert substantial influence over the development of the Thailand
Concession. As of December 31, 2000, the Company's proved reserves located in
the Kingdom of Thailand accounted for approximately 40% of the Company's total
proved reserves. During 2000, approximately 36% of the Company's natural gas
production and 48% of its oil and condensate production came from its
operations on the Thailand Concession, contributing approximately 38% of the
Company's consolidated oil and gas revenues.
5
Exploration and Development
The Company's international capital and exploration expenditures were
approximately $53,400,000 for 2000, or 52% lower than the Company's
international capital and exploration expenditures of approximately
$111,500,000 for 1999 and 50% lower than the Company's international capital
and exploration expenditures of approximately $107,400,000 for 1998. The
decrease in the Company's international capital and exploration expenditures
for 2000, compared to 1999 and 1998, resulted primarily from decreased
expenditures due to completion of the Benchamas Field Phase I development which
was substantially completed in 1999, that was not entirely offset by increased
exploration drilling expenditures in the Kingdom of Thailand and increased
exploration expenditures in Hungary and the North Sea. Substantially all of the
Company's international capital expenditures for 2000 were related to the
Company's license in the Kingdom of Thailand. However, during 2000, the Company
incurred approximately $3,600,000 in exploration expenditures in Hungary, the
North Sea and other parts of the world, with a majority of these expenditures
related to 2-D seismic data acquisition in Hungary. The Company has currently
budgeted approximately $86,600,000 for capital and exploration expenditures
during 2001 in Thailand and other areas outside North America, including
Hungary and the North Sea. Approximately $30,000,000 of these funds will be
used to order, build and construct six platforms to be installed in the Kingdom
of Thailand and almost $17,000,000 is budgeted for 3-D seismic surveys and
exploratory drilling in Hungary.
Thailand Concession
Benchamas Field. In July 1997, the government of Thailand designated a
portion of the Thailand Concession comprising approximately 102,000 acres as
the Benchamas and Pakakrong production area or the "Benchamas Field."
Production from the Benchamas Field commenced production in July 1999 from
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 is processed and separated. The
natural gas is sold to The Petroleum Authority of Thailand ("PTT") and
delivered into export pipelines for transportation to shore, while the oil and
condensate produced from the field is 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 is moored in the Benchamas
Field. Its capacity is approximately 1,400,000 Bbls of crude and condensate.
Benchamas Field Phase I development was completed during the first quarter of
2000. It resulted in the drilling of 55 wells in the field, including 38
producing wells (14 of which were horizontal wells) and 17 water injection
wells. Current Benchamas Field Phase II development plans call for the
construction and installation of up to five more platforms in the field, with
installation of the first platform currently expected to commence in the fourth
quarter of 2001.
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 approximately 40
wells producing from five platforms. 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 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."
Maliwan Field. In September 1997, the government of Thailand designated an
additional approximately 91,000 acres of the Thailand Concession as the Maliwan
production area or the "Maliwan Field." Development plans for this area are
currently under way. Three additional wells were drilled in this area during
2000 and additional wells are planned for 2001. Current plans call for setting
a small platform in the Maliwan
6
Field and to commence producing from it in the fourth quarter of 2001. Initial
production from this first platform will be taken to the Benchamas Field
production handling facilities for processing and sale.
Other Portions of the Thailand Concession. Thaipo and its joint venture
partners have identified other potentially promising areas on the Thailand
Concession and surrounding acreage. In November 2000, approximately 124,000
additional acres of the Thailand Concession, known as the North Jarmjuree area,
were designated as a production area. Development plans for this area are still
being formulated. Two exploration wells were drilled in this area during 2000.
Another five wells are currently budgeted for 2001 in the North Jarmjuree and
surrounding areas. During 2000, Thaipo and its joint venture partners drilled
three wells on areas of the Thailand Concession that are not currently
designated as production areas and have currently budgeted to drill additional
exploration wells, commencing in February 2001. Interpretation of the data
provided by these wells and 3-D seismic data covering these areas is ongoing.
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. A key focus of Thaipo and its joint venture partners has
been to reduce the average cost of the platforms that they install so as to
improve the overall economics of the project. The gross cost of the first five
production platforms and related facilities in the Tantawan Field and the first
three production platforms in the Benchamas Field averaged approximately
$20,000,000 per platform. However, employing advanced platform facility design
and advanced drilling and completion techniques, including slimhole, batch and
horizontal drilling, the six new minimum facility platforms that have been
ordered for installation in late 2001 and 2002 are expected to cost closer to
$9,000,000 per platform. 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 and the
amount of facilities required to be placed on the platform.
Other Areas of the World
North Sea. On December 1, 1998, Pogo North Sea Ltd., a British subsidiary of
the Company, together with two joint venture 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 involved the acquisition, processing and
interpretation of 3-D seismic data over the block. This work commitment has
been satisfied. The initial exploratory term of this license expires on
December 1, 2004, unless otherwise extended or a production license is granted.
Pogo North Sea Ltd. and its joint venture partners have acquired 3-D seismic
data over the license and the surrounding area and are currently evaluating it
for potential drilling prospects.
On August 5, 1999, the Danish government approved the assignment of a 40%
working interest in License 13/98 covering approximately 81,000 acres in the
Danish sector of the North Sea. The Company's license interest is currently
held by a Danish subsidiary known as Pogo Denmark ApS. The initial term of the
license goes through June 14, 2004, unless otherwise extended or a production
license is granted. Pogo Denmark ApS and its joint venture partners have
acquired and interpreted 2-D and new 3-D seismic surveys over the license. A
prospect has been identified and an exploratory well to test this prospect is
currently budgeted for the latter part of this year.
Hungary. On April 20, 1999, the Company's subsidiary Pogo Hungary Ltd.
("Pogo Hungary") was awarded a license to explore for oil and gas on
approximately 778,000 acres in the Szolnok and Tompa areas of central and south
central Hungary. The exploration term of the license is four years, with areas
where commercial accumulation of hydrocarbons being held through the economic
productive life of such reserves. During 2000, Pogo Hungary acquired over 888
kilometers of modern 2-D seismic data in the Szolnok area.
7
Interpretation of this data is ongoing. During the last quarter of 2000, Pogo
Hungary commenced simultaneous acquisition of two 3-D seismic surveys. One 3-D
survey covers approximately 129,000 acres, or a substantial portion, of the
Tompa area, and the other covers approximately 42,000 acres of the Szolnok area
and is referred to as the Kenderes 3-D survey. Pogo Hungary has identified
another highly prospective area in the southern portion of the Szolnok area
known as the Koros area, where it currently intends to acquire another 3-D
survey during the latter half of this year. Depending upon the results of these
surveys, Pogo Hungary has currently budgeted a multi-well drilling program for
the latter half of this year in both the Tompa and Szolnok areas. In addition,
Pogo Hungary continues to evaluate other international opportunities that are
consistent with the Company's international exploration strategy and expertise.
Contractual Terms Governing the Thailand Concession and Related Production
The Thailand Concession was granted in August 1991. The initial exploratory
term for the Thailand Concession expired on July 31, 2000. However, Thaipo and
its joint venture partners were granted an extension of the exploration through
July 1, 2001. Similar one-year extensions can also be applied for through July
1, 2005. Thaipo and its joint venture partners intend to continue to apply for
extensions until they believe that all of the acreage has been adequately
evaluated. 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 extension, generally for a term of ten years. See also
"Miscellaneous; Sales." To date, the Benchamas Field, Tantawan Field, Maliwan
Field and North Jarmjuree 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 local 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 the Benchamas Field. The terms of the Gas Sales
Agreement currently include a minimum daily contract quantity ("DCQ") of 125
MMcf per day, subject to certain exceptions and will in the future be based on
a percentage of the remaining proved reserves, but in any event, will not be
less than 125 MMcf per day. In addition, the Gas Sales Agreement gives PTT the
right to nominate in any given week, 115% of DCQ or approximately 144 MMcf per
day. During 2000, gas sales to PTT averaged approximately 145 MMcf per day. Due
to an abundance of natural gas under contract to PTT from other producers, PTT
has generally not taken significantly more than this amount. The DCQ is the
minimum daily volume that PTT has agreed to take, or pay for if not taken,
under the agreement. Thaipo and its joint venture partners are subject to
certain penalties if they are unable to meet the DCQ, principal among which is
a decrease in sales price of up to 25% of the then current sales price. Thaipo
is currently meeting the minimum DCQ requirements, however, there can be no
assurance that Thaipo will be able to continue to meet them in the future, in
which case the penalty provisions of the Gas Sales Agreement would reduce the
price received by Thaipo for its gas sold to PTT under the Gas Sales Agreement.
The sales price under the Gas Sales Agreement 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. As of
December 31, 2000, the Company was receiving an average price of approximately
$2.33 per Mcf under the Gas Sales Agreement. 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."
8
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, Pogo
Onshore Pipeline Company, the Company owns and operates a six inch in diameter
pipeline that runs from just outside of Fort Worth, Texas to Wichita Falls,
Texas. Industrial Natural Gas, L.C., a subsidiary of the Company, markets the
sale and transmission of natural gas through this 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. As part of the Company's ongoing efforts to focus
on its core business of finding and producing oil and natural gas, the Company
is exploring sales opportunities for these and other non-core assets if a
favorable price can be obtained. The Company does not currently expect that the
sale of any or all of these non-core assets would have a substantial material
impact on the Company's business or operations, taken as a whole.
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 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.
Pogo may not be able to successfully market all of the oil and natural gas
we find and could produce on the Thailand Concession. Currently, the only
purchaser of natural gas is PTT, which maintains a monopoly over gas
transmission and distribution in Thailand, including ownership of the two major
(34 inches and 36 inches in diameter, respectively) natural gas pipelines that
traverse our Thailand Concession. 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 Blend crude oil benchmark price. Oil sales from our Thailand
Concession are influenced by a number of factors including, among others,
tanker availability, world-wide crude oil demand, size of the lifting and the
perceived quality of crude oil produced. In addition, because much of the oil
produced from the Thailand Concession is associated with natural gas,
limitations on Thaipo's ability to produce natural gas could limit crude oil
production as well. The crude oil purchaser is generally responsible for
sending a tanker to off load the oil and condensate it has purchased. Crude oil
and condensate production from the Benchamas Field is initially stored aboard
the FSO and such production is currently also sold on a tanker load by tanker
load basis, similar to the way Tantawan Field crude is currently marketed.
Crude oil and condensate from the northern portion of the Maliwan Field, which
is currently under development, is currently expected to also be processed at
the Benchamas processing facilities and stored aboard the FSO for sale. 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 (exclusive of forward
gas sales contracts) 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
9
one month at a time at the price that is then currently available. Other than
any oil and natural gas 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. With the exception of PTT, to
whom all of the Company's gas production in Thailand is sold, and Enron Corp.
and its affiliates, to whom total sales constituted 13% of the Company
consolidated domestic revenues, sales to no customer in 2000 constituted more
than 10% of the Company's consolidated Thai or domestic revenues.
Risks Associated with Acquisitions
From time to time the Company acquires, and may acquire in the future,
additional interests in oil and gas properties, either through acquisition of
the properties themselves or, as in the case of the Arch and North Central
acquisitions, indirectly through the purchase of an equity interest in the
entity owning such properties. The successful acquisition of such properties
requires an assessment of several factors, including recoverable reserves,
projected future cash flows, which are in part based upon future oil and gas
prices, current and projected operating, general and administrative and other
costs, contingent liabilities associated with the properties or entities
acquired, including potential environmental and other liabilities.
The accuracy of the Company's assessment of these factors is inherently
uncertain. To the extent reasonably practicable and possible under the specific
circumstances of each acquisition, the Company performs a review of the
properties or entities prior to their acquisition. The Company believes that
its review procedures are generally consistent with current industry practices.
The Company's review and assessment process will not reveal all existing or
potential problems nor will it permit the Company to become sufficiently
familiar with the properties or entities to fully assess their deficiencies and
capabilities. Even when problems are identified, the other party may be
unwilling or unable to provide effective contractual protection against all or
a part of the problems. The Company is generally not entitled to contractual
indemnification for many liabilities, acquiring the properties on an "as is,
where is" basis. In addition, successful acquisitions frequently require the
successful integration of operations, equipment and, in the case of indirect
acquisitions, personnel. There can be no assurance that the Company will be
able to successfully integrate operations and properties that it acquires and
still achieve the anticipated synergies, cost savings and efficiencies.
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 addition, the decisions of
the Organization of Petroleum Exporting Countries relating to export quotas
also affect the price of crude oil. The average prices that we currently
receive for our production are near historic highs. A future drop in oil or gas
prices could have a material adverse effect on our cash flow and profitability.
Sustained periods of low prices could cause us to shut in existing production
and could also have a material adverse effect on the Company's operations and
financial condition. It could also result in a reduction of funds available
under the Company's bank credit facilities.
Because it is impossible to predict future oil and gas price movements with
any certainty, the Company from time to time enters into contracts to hedge
against future market price changes on a portion of its production. 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 to limit the negative effect of price declines, some
forms of hedging transactions could effectively limit the Company's
participation in price increases for the covered period, which increases could
be significant. As of December 31, 2000, the
10
Company was a party to the natural gas hedging contracts described in
"Quantitative and Qualitative Disclosure About Market Risk." When the Company
does engage in hedging activities, it frequently 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. In periods of increased drilling
activity resulting from high commodity prices such as the Company is currently
experiencing, demand exceeds availability for drilling rigs, drilling vessels,
supply boats and personnel experienced in the oil and gas industry in general,
and the offshore oil and gas industry in particular. This may lead to
difficulty and delays in consistently obtaining certain services and equipment
from vendors, obtaining drilling rigs and other equipment at favorable rates
and scheduling equipment fabrication at factories and fabrication yards. This
in turn may lead to projects being delayed or experiencing increased costs.
In periods during which the industry experiences a substantial decline in
oil and gas prices, many of the Company's partners, particularly the smaller
ones, can experience 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 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
11
"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 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 that have varying terms. The
following table shows the Company's interest in developed and undeveloped oil
and gas acreage under lease as of December 31, 2000:
Developed Undeveloped
Acreage(a) Acreage(b)
--------------- -------------------
Gross Net Gross Net
------- ------- --------- ---------
Domestic Offshore
Louisiana (State)......................... 3,167 1,564 1,571 727
Louisiana (Federal)....................... 171,287 47,008 176,129 75,388
Texas (Federal)........................... 28,800 6,687 51,145 14,082
------- ------- --------- ---------
Total Domestic Offshore................. 203,254 55,259 228,845 90,197
------- ------- --------- ---------
Onshore
Louisiana................................. 4,177 1,061 9,344 4,209
New Mexico................................ 39,919 27,996 85,248 64,649
Texas..................................... 24,054 9,148 76,752 44,671
Canada.................................... 20,752 3,035 78,197 41,068
Other..................................... 2,853 333 80 15
------- ------- --------- ---------
Total Onshore........................... 91,755 41,573 249,621 154,612
------- ------- --------- ---------
------- ------- --------- ---------
Total North America..................... 295,009 96,832 478,466 244,809
------- ------- --------- ---------
International
Gulf of Thailand.......................... 385,035 178,431 329,018 152,471
North Sea................................. -- -- 112,729 45,092
Hungary................................... -- -- 778,136 778,136
Denmark................................... -- -- 80,902 32,361
------- ------- --------- ---------
Total International..................... 385,035 178,431 1,300,785 1,008,060
------- ------- --------- ---------
Total Company........................... 680,044 275,263 1,779,251 1,252,869
======= ======= ========= =========
--------
(a) "Developed acreage" consists of lease acres spaced or assignable to
production (including acreage held by production) 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 Benchamas Field, the Tantawan Field, the Maliwan
Field and the North Jarmjuree production area.
12
(b) Approximately 24% of the Company's total domestic offshore net undeveloped
acreage and approximately 13% of the Company's total onshore net
undeveloped acreage are under leases that have terms expiring in 2001
(unless otherwise extended). Approximately 32% of total domestic offshore
net undeveloped acreage and approximately 7% of total onshore net
undeveloped acreage are under leases with terms expiring in 2002 (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,
2001, unless designated as a production area or another extension to the
exploration term is granted by the Thai government. See "International
Operations; Contractual Terms Governing the Thailand Concession and Related
Production."
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 (125 net acres) offshore Louisiana.
Productive Wells and Drilling Activity
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 2000. 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
Oil Gas
Wells(a) Wells(a)
----------- ----------
Gross Net Gross Net
----- ----- ----- ----
Offshore United States................................ 101 28.5 81 25.3
Onshore (U.S. and Canada)............................. 763 512.2 120 53.5
Kingdom of Thailand................................... 52 23.9 39 17.9
--- ----- --- ----
Total............................................... 916 564.6 240 96.7
=== ===== === ====
--------
(a) One or more completions in the same bore hole are counted as one well. The
data in the above table includes 14 gross (3.9 net) oil wells and 4 gross
(1.2 net) natural gas wells with multiple completions.
13
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 commercially producible
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 hydrocarbons. A
well is considered a dry hole upon reporting of permanent abandonment to the
appropriate agency.
2000 1999 1998
--------------- --------------- ---------------
Productive Dry Productive Dry Productive Dry
---------- ---- ---------- ---- ---------- ----
Gross Wells:
Offshore United States
Exploratory.............. 4.0 5.0 4.0 -- 5.0 1.0
Development.............. 23.0 3.0 11.0 -- 2.0 --
Onshore United States and
Canada
Exploratory.............. 14.0 5.0 3.0 3.0 9.0 4.0
Development.............. 39.0 -- 23.0 1.0 32.0 1.0
Offshore Kingdom of
Thailand
Exploratory.............. 7.0 3.0 4.0 -- 12.0 --
Development.............. 24.0 -- 42.0 -- 12.0 --
----- ---- ----- ---- ----- ----
Total.................. 111.0 16.0 87.0 4.0 72.0 6.0
===== ==== ===== ==== ===== ====
Net Wells:
Offshore United States
Exploratory.............. 2.16 2.37 1.32 -- 1.07 .25
Development.............. 6.19 1.00 3.37 -- .80 --
Onshore United States and
Canada
Exploratory.............. 3.81 2.46 1.63 1.65 5.08 2.19
Development.............. 28.09 -- 13.89 .80 22.61 .34
Offshore Kingdom of
Thailand
Exploratory.............. 3.24 1.39 1.85 -- 5.56 --
Development.............. 11.12 -- 19.46 -- 5.56 --
----- ---- ----- ---- ----- ----
Total.................. 54.61 7.22 41.52 2.45 40.68 2.78
===== ==== ===== ==== ===== ====
Average Production (Lifting) Costs
The following table shows the average production (lifting) costs per unit of
production during the periods indicated. For a discussion of the Company's
average daily production and the average sales prices received by the Company
for such production see "Selected Financial Data Production (Sales) Data" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations; Oil and Gas Revenues."
2000 1999 1998
---- ----- -----
Average Production (lifting) Costs(a):
Located in the United States
Natural Gas, Crude Oil, Condensate and Natural Gas Liquids
(per Mcfe)................................................. $.82 $ .69 $ .61
==== ===== =====
Located in Canada
Natural Gas, Crude Oil, Condensate and Natural Gas Liquids
(per Mcfe)................................................. $.88 $1.10 $ .65
==== ===== =====
Located in the Kingdom of Thailand
Natural Gas, Crude Oil and Condensate (per Mcfe)............ $.69 $ .99 $1.10
==== ===== =====
Total Company............................................. $.77 $ .77 $ .71
==== ===== =====
--------
(a) Production costs were converted to common units of measure on the basis of
relative energy content. Such production costs exclude all depletion and
amortization associated with property and equipment.
14
Reserves
The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 2000, 1999 and 1998, 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 petroleum engineers, in accordance with criteria prescribed by the
Commission.
Due in part to natural gas prices being at or near their historic highs on
December 31, 2000, the Company does not currently believe that the calculation
of estimated future net revenues using the assumptions prescribed by Commission
guidelines and generally described below is representative of the true value of
future net revenues from the Company's proved reserves. 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 operating costs and other costs relating to such production may also
increase or decrease from existing levels.
As of December 31,
------------------------------
2000 1999 1998
---------- ---------- --------
Total Proved Reserves:
Oil, condensate, and natural gas liquids
(MBbls)
Located in the United States and Canada....... 58,257 42,120 33,699
Located in the Kingdom of Thailand............ 37,065 36,656 33,811
---------- ---------- --------
Total Company............................... 95,322 78,776 67,510
========== ========== ========
Natural Gas (MMcf)
Located in the United States and Canada....... 216,679 221,110 271,780
Located in the Kingdom of Thailand............ 153,304 153,588 168,389
---------- ---------- --------
Total Company............................... 369,983 374,698 440,169
========== ========== ========
Present value of estimated future net revenues,
before income taxes (in thousands)(a)
Located in the United States and Canada....... $1,948,894 $ 585,052 $294,629
Located in the Kingdom of Thailand............ 506,021 569,594 200,597
---------- ---------- --------
Total Company............................... $2,454,915 $1,154,646 $495,226
========== ========== ========
Total Proved Developed Reserves:
Oil, condensate, and natural gas liquids
(MBbls)
Located in the United States and Canada....... 35,910 35,487 29,070
Located in the Kingdom of Thailand............ 24,747 18,408 4,298
---------- ---------- --------
Total Company............................... 60,657 53,895 33,368
========== ========== ========
Natural Gas (MMcf)
Located in the United States and Canada....... 152,742 157,216 184,630
Located in the Kingdom of Thailand............ 87,236 88,041 40,424
---------- ---------- --------
Total Company............................... 239,978 245,257 225,054
========== ========== ========
Present value of estimated future net revenues,
before income taxes (in thousands)(a)
Located in the United States and Canada....... $1,246,068 $ 472,856 $242,574
Located in the Kingdom of Thailand............ 445,033 304,275 28,244
---------- ---------- --------
Total Company............................... $1,691,101 $ 777,131 $270,818
========== ========== ========
--------
(a) The Company believes, for the reasons set forth in succeeding paragraphs,
that the present value of estimated future net revenues set forth in the
Annual Report and calculated in accordance with Commission 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.
15
Natural gas liquids comprised approximately 7% of the Company's total proved
liquids reserves and approximately 7% of the Company's proved developed liquids
reserves as of December 31, 2000. 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.
As set forth in the following table, in computing future revenues from gas
reserves attributable to the Company's domestic interests, prices in effect at
December 31, 2000 were used, including current market prices, contract prices
and fixed and determinable price escalations where applicable. In accordance
with Commission guidelines, the gas prices that were used make no allowances
for seasonal variations in gas prices that 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, 2000 were used and 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, 2000, in accordance with Commission 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 Malaysian
Tapis Blend benchmark crude on December 31, 2000, 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 Commission 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,
--------------------
2000 1999 1998
------ ------ ------
Initial Weighted Average Price (in U.S. dollars):
Oil, condensate, and natural gas liquids (per Bbl)
Located in the United States and Canada.............. $26.10 $25.55 $10.45
====== ====== ======
Located in the Kingdom of Thailand................... $24.23 $25.08 $12.68
====== ====== ======
Natural Gas (per Mcf)
Located in the United States and Canada.............. $10.14 $ 2.14 $ 2.01
====== ====== ======
Located in the Kingdom of Thailand................... $ 2.27 $ 1.99 $ 1.81
====== ====== ======
In accordance with Commission guidelines for calculating future net
revenues, the 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
16
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 2000. 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 that are not
currently producing may start producing earlier or later than anticipated in
the estimates of future production rates.
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 Commission 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 2000, 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 Commission; 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 federal income tax
laws. 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
17
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.
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. 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. 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. The
amount of financial responsibility that must be demonstrated for most Company
offshore platforms is $35,000,000. 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
foreign 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,
provincial and local initiatives to further regulate the disposal of oil and
gas wastes are also pending in certain jurisdictions, 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
18
environmental control facilities would have been incurred absent environmental
regulations as prudent, safe oilfield practice. During 2000, the Company
incurred capital expenditures of approximately $1,128,000 for environmental
control facilities, primarily relating to the cost of converting a well into a
salt water disposal well, installation of pit and firewall spill liners, and
routine site restoration costs. The Company has budgeted approximately
$2,600,000 for expenditures involving environmental control facilities during
2001, including, among other things, the conversion of two wells to salt water
disposal wells, anticipated site restoration costs and the installation of
environmental control equipment.
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. The
MMS is currently engaged in developing new oil and gas valuation regulations
for royalty purposes. The gas rule was published in final form on December 16,
1997. Industry trade associations challenged portions of the rule and, on March
28, 2000, a district court invalidated the challenged regulations. The MMS has
appealed the court's decision, and the appeal remains pending. The oil rule was
published in final form on March 15, 2000. Portions of this rule have also been
challenged by industry trade associations in court and the case remains
pending, with no resolution expected in the near future. We are not in a
position to predict the outcome of the litigation, but the Company believes
that the impact of the final rules that emerge from the court review will not
impact the Company to any greater extent than other similarly situated
producers.
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 served 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.
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. 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.
19
Employees
As of December 31, 2000, the Company and its subsidiaries had 161 full-time
employees, including seven 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 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.
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 December 31, 2000 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 Executive Officer 54 1991
Stuart P. Burbach....... Executive Vice President--Exploration 48 1998
Jerry A. Cooper......... Senior Vice President and Western Division Manager 52 1998
R. Phillip Laney........ Senior Vice President and Manager of Worldwide New Ventures 60 1998
John O. McCoy, Jr....... Senior Vice President and Chief Administrative Officer 49 1998
J. D. McGregor.......... Senior Vice President--Sales 56 1998
Barry W. Acomb.......... Vice President and Offshore Division Manager 48 1999
Bruce E. Archinal....... Vice President and Onshore Division Manager 48 1997
David R. Beathard....... Vice President--Engineering 42 1997
Stephen R. Brunner...... Vice President--Operations 42 1997
Frank Davis III......... Vice President--Land 54 1997
Thomas E. Hart.......... Vice President and Chief Accounting Officer 57 1999
Gerald A. Morton........ Vice President--Law and Corporate Secretary 42 1997
S. Clay Robinson, Jr.... Vice President and International Division Manager 46 1999
James P. Ulm, II........ Vice President and Chief Financial Officer 37 1999
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. Cooper, who joined the Company in 1979, served as Vice President and
Western Division Manager for the Company since 1990; 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
20
Vice President--Sales since 1988; Mr. Acomb served as Offshore Division
Exploration Manager since joining the Company in 1994; Mr. Archinal, who joined
the Company in 1982, served as the Company's Onshore Division Manager since
1994; Mr. Beathard, who joined the Company in 1982, served as Manager of
Petroleum Engineering for the Company since 1991; Mr. Brunner, who joined the
Company in 1994, served as Resident Manager of the Company's Thailand
operations since 1995; Mr. Davis, who joined the Company in 1978, served as
Land Manager for the Company since 1991; Mr. Hart was Vice President and
Controller since 1988 and prior thereto was Controller since joining the
Company in 1977; Mr. Morton was Associate General Counsel since joining the
Company in 1993; Mr. Robinson served as International Division Exploration
Manager since joining the Company in 1996; and Mr. Ulm served as Treasurer of
Newfield Exploration Company from 1995 until joining the Company as its Vice
President and Chief Financial Officer in August of 1999.
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 Exchange.
Low High
--- ----
1999
1st Quarter............................................... 8 15/16 14 1/2
2nd Quarter............................................... 11 15/16 21 3/8
3rd Quarter............................................... 18 1/8 23 7/16
4th Quarter............................................... 15 5/8 21
2000
1st Quarter............................................... 18 3/8 28 3/4
2nd Quarter............................................... 21 1/8 29 3/4
3rd Quarter............................................... 18 29 7/16
4th Quarter............................................... 22 1/2 33 3/16
As of March 1, 2001, there were 2,550 holders of record of the Company's
Common Stock.
In each of 1999 and 2000, 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.
The Company's revolving credit facility 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") contain covenants that may
restrict the ability of the Company to pay dividends on the Company's Common
Stock. The Company does not currently believe that any of these agreements will
restrict the Company's ability to pay dividends on its Common Stock at any time
in the reasonably foreseeable future. In addition, the 6 1/2% Cumulative
Quarterly Income Convertible Preferred Securities, Series A (the "Trust
Preferred Securities") issued by the Company's subsidiary, Pogo Trust I,
prohibit the Company from paying dividends on the Company's Common Stock if
dividends have not been paid on the Trust Preferred Securities.
21
ITEM 6. Selected Financial Data.
For the Year Ended December 31,
------------------------------------------------
2000 1999 1998 1997 1996
---------- -------- -------- -------- --------
(Expressed in thousands, except per share and
production data)
Financial Data
Revenues:
Crude oil and condensate.... $ 272,932 $109,803 $ 74,703 $112,603 $ 96,908
Natural gas................. 190,401 111,152 116,148 158,500 94,589
Natural gas liquids......... 15,869 9,544 9,303 13,748 11,867
---------- -------- -------- -------- --------
Oil and gas revenues........ 479,202 230,499 200,154 284,851 203,364
Pipeline sales and other.... 15,113 7,159 2,741 349 778
Gains (losses) on sales..... 3,676 37,458 (92) 1,100 (165)
---------- -------- -------- -------- --------
Total...................... $ 497,991 $275,116 $202,803 $286,300 $203,977
========== ======== ======== ======== ========
Income (loss) before
cumulative effect of change
in accounting principle and
extraordinary item.......... $ 89,023 $ 22,134 $(43,098) $ 37,116 $ 33,581
Extraordinary loss........... -- -- -- -- (821)
Cumulative effect of change
in accounting principle..... (1,768) -- -- -- --
---------- -------- -------- -------- --------
Net income (loss)............ $ 87,255 $ 22,134 $(43,098) $ 37,116 $ 32,760
========== ======== ======== ======== ========
Per share data:
Income (loss) before
cumulative effect of change
in accounting principle and
extraordinary item--
Basic...................... $ 2.20 $ 0.55 $ (1.14) $ 1.11 $ 1.01
Diluted.................... $ 1.99 $ 0.55 $ (1.14) $ 1.06 $ 0.97
Cash dividends on common
stock...................... $ 0.12 $ 0.12 $ 0.12 $ 0.12 $ 0.12
Price range of common stock:
High....................... $ 33.19 $ 23.44 $ 34.69 $ 49.88 $ 48.38
Low........................ $ 18.00 $ 8.94 $ 9.81 $ 27.00 $ 24.38
Weighted average number of
common shares outstanding... 40,445 40,178 37,902 33,421 33,203
Long-term debt at year end... $ 365,000 $375,000 $434,947 $348,179 $246,230
Minority interest at year
end......................... $ 144,913 $144,751 $ -- $ -- $ --
Shareholders' equity at year
end......................... $ 358,271 $268,512 $249,660 $146,106 $107,282
Total assets at year end..... $1,083,522 $948,193 $862,396 $676,617 $479,242
Production (Sales) Data
Net daily average production
and weighted average price:
Natural gas (Mcf per day).. 164,600 141,600 159,000 181,700 107,700
Price (per Mcf)............ $ 3.16 $ 2.15 $ 2.00 $ 2.39 $ 2.40
Crude oil-condensate (Bbl
per day).................. 25,788 16,036 15,775 15,927 11,968
Price (per Bbl)............ $ 28.92 $ 18.76 $ 12.97 $ 19.37 $ 22.12
Natural gas liquids (Bbl
per day).................. 2,141 2,077 2,422 2,923 2,173
Price (per Bbl)............ $ 20.25 $ 12.59 $ 10.52 $ 12.89 $ 14.92
Capital Expenditures
Oil and gas:
Domestic Offshore--
Exploration................ $ 18,700 $ 12,600 $ 20,200 $ 18,700 $ 16,800
Development................ 43,700 43,200 42,500 59,800 73,900
Purchase of reserves....... -- -- 5,000 900 --
Onshore North America--
Exploration................ 19,700 9,800 16,500 18,100 10,400
Development................ 34,700 19,800 28,100 38,400 27,800
Purchase of reserves....... 8,400 19,500 133,100 1,700 --
International--
Exploration................ 9,400 3,500 11,600 21,700 8,500
Development................ 51,500 106,300 95,500 62,500 54,700
Purchase of reserves....... -- -- -- 29,300 --
---------- -------- -------- -------- --------
Total oil and gas.......... 186,100 214,700 352,500 251,100 192,100
Other........................ 700 2,200 6,300 4,000 1,600
---------- -------- -------- -------- --------
Total....................... $ 186,800 $216,900 $358,800 $255,100 $193,700
========== ======== ======== ======== ========
22
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
On November 20, 2000, the Company announced that it had entered into an
agreement and plan of merger with NORIC and certain NORIC shareholders. The
Company has called a special meeting of shareholders for March 13, 2001 to
obtain shareholder approval of the Merger. If the Company's shareholders
approve the Merger, the Company currently expects that the Merger will be
completed within several days after the shareholders' meeting. The Company will
account for the Merger using the purchase method of accounting. Because the
Merger has not yet been consummated, none of the information set forth in this
Management's Discussion and Analysis of Financial Condition and Results of
Operations or elsewhere in this Annual Report reflects the impact of the Merger
or of the Company's future combined operation, except as expressly noted. On
August 17, 1998, a wholly owned subsidiary of the Company merged with and into
Arch in a stock-for-stock tax-free merger accounted for as a purchase. In
connection with the merger, the Company repaid $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 net income for 2000 of $87,255,000 or $2.16 per share
($97,704,000 or $1.95 per share on a diluted basis), compared to net income for
1999 of $22,134,000 or $0.55 per share (on both a basic and a diluted basis)
and a net loss of $43,098,000 or $1.14 per share (on both a basic and a diluted
basis) for 1998. Net income in 2000 was adversely affected by a one time
$1,768,000 non-cash charge related to a change in accounting principles
required by the Commission. Historically, the Company recorded oil and
condensate inventory held for sale (principally in the FPSO and FSO in
Thailand) at fair market value as of the close of the accounting period.
However, the Commission recently announced that it would require such inventory
to be recorded as inventory at cost. The $1,768,000 one-time charge reflects a
catch up adjustment for years prior to 2000. The Company does not currently
expect to incur any similar charges related to this issue in the future. Among
other items affecting net income for 2000 and 1999 were net gains of $3,676,000
and $37,458,000, respectively, related to the Company's sale of certain non-
strategic properties as part of its asset maximization plan. Net income for
1998 was affected by 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.
Earnings per common share are based on the weighted average number of common
shares outstanding for 2000 of 40,445,000 (50,155,000 on a diluted basis),
compared to 40,178,000 (40,390,000 on a diluted basis) for 1999 and 37,902,000
(on both a basic and a diluted basis) for 1998. The increase in the weighted
average number of common shares outstanding for 2000, compared to 1999,
resulted primarily from 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 2000, compared to 1998,
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 earnings per share computation on a diluted
basis in 2000 primarily reflects additional shares of common stock issuable
upon the assumed conversion of the Company's 5 1/2% Convertible Subordinated
Notes due 2006 (the "2006 Notes") and the Trust Preferred Securities, 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. The earnings per share computation on a diluted
basis in 1998
23
is identical to the basic earnings per share computation because there were no
securities of the Company that were dilutive during the period. In addition,
the number of common shares outstanding in the diluted computation is adjusted
to include dilutive shares that are assumed to have been issued by the Company
in connection with outstanding options, less treasury shares that are assumed
to have been purchased by the Company from the option proceeds.
Total Revenues
The Company's total revenues for 2000 were $497,991,000, an increase of
approximately 81% compared to total revenues of $275,116,000 for 1999, and an
increase of approximately 146% from total revenues of $202,803,000 for 1998.
The increase in the Company's total revenues for 2000, compared to 1999 and
1998, resulted primarily from increased oil and gas revenues and an increase in
pipeline sales, that was partially offset, in comparison with 1999, by a
decrease in gains on property sales.
Oil and Gas Revenues
The Company's oil and gas revenues for 2000 were $479,202,000, an increase
of approximately 108% from oil and gas revenues of $230,499,000 for 1999, and
an increase of approximately 139% from oil and gas revenues of $200,154,000 for
1998. The following table reflects an analysis of variances in the Company's
oil and gas revenues (expressed in thousands) between 2000 and the previous two
years:
2000 Compared to
-----------------
1999 1998
-------- --------
Increase (decrease) in oil and gas revenues resulting
from variances in:
Natural gas--
Price................................................. $ 52,148 $ 67,271
Production............................................ 27,101 6,982
-------- --------
$ 79,249 $ 74,253
======== ========
Crude oil and condensate--
Price................................................. $ 59,457 $ 91,800
Production............................................ 103,672 106,429
-------- --------
$163,129 $198,229
-------- --------
Natural Gas Liquids.................................... $ 6,325 $ 6,566
-------- --------
Increase (decrease) in oil and gas revenues........... $248,703 $279,048
======== ========
The increase in the Company's oil and gas revenues in 2000, compared to 1999
and 1998, is related to increases in the Company's crude oil and condensate
production volumes, the average prices that the Company received for such
production volumes, and, to a lesser extent, increases in the average price
that the Company received for its natural gas and NGL production and an
increase in natural gas production. The increase in oil and gas revenues for
2000, compared to 1998, was partially offset by a decline in NGL production.
24
% Change % Change
2000 1999 2000 to 1999 1998 2000 to 1998
------ ------ ------------ ------ ------------
Comparison of Increases
(Decreases) in:
Natural Gas
Average prices
North America................. $ 3.69 $ 2.31 60 $ 2.09 77
Kingdom of Thailand (Thai
Baht)(a)..................... 79 61 30 70 13
Company-wide average price.. $ 3.16 $ 2.15 47 $ 2.00 58
Average daily production
volumes (MMcf per day)
North America................. 106.2 102.6 4 122.2 (13)
Kingdom of Thailand(a)........ 58.4 39.0 50 36.8 59
------ ------ ------
Company-wide average daily
production................. 164.6 141.6 16 159.0 4
====== ====== ======
Crude Oil and Condensate
Average prices
North America................. $27.83 $17.43 60 $12.94 115
Kingdom of Thailand(a)........ $30.10 $23.49 28 $13.17 129
Company-wide average price.. $28.92 $18.76 54 $12.97 123
Average daily production
volumes (Bbls per day)
North America................. 13,432 12,517 7 13,214 2
Kingdom of Thailand(a)........ 12,356 3,519 251 2,561 382
------ ------ ------
Company-wide average daily
production................. 25,788 16,036 61 15,775 63
====== ====== ======
Total Liquid Hydrocarbons
Company-wide average daily
production
(Bbls per day)............... 27,929 18,112 54 18,197 53
--------
(a) Production from the Benchamas Field commenced in July 1999. Prices received
for the Company's natural gas production during the period from October
1998 through August 1999 when the Company did not meet the contractual DCQ
were negatively affected by the contractual provisions of the Gas Sales
Agreement.
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. During
2000, in addition to the two semi-annual adjustments, there was one additional
adjustment resulting primarily from the fluctuation of the Baht against the
dollar. In addition, prices received by the Company for its natural gas
production during the period from October 1, 1998 through August 1999 were
adversely affected by certain penalty provisions in the Gas Sales Agreement.
See "Business International Operations; Contractual Terms Governing the
Thailand Concession and Related Production." Due to the relative stability of
the Baht-U.S. dollar exchange rate throughout much of 1999 and 2000,
adjustments to the price that the Company receives under the Gas Sales
Agreement have not been as frequent as they were in 1998. See "Foreign Currency
Transaction Gain (Loss)," and "Liquidity and Capital Resources; Other Matters;
Southeast Asia Economic Issues."
25
Production. The increase in the Company's natural gas production during
2000, compared to 1999 and 1998, was primarily related to increased production
from the Company's Thailand Concession resulting from a successful infill
drilling program in the Tantawan Field and commencement of production from the
Benchamas Field and production from the Company's Garden Banks Block 367
project, which was partially offset by decreased production from the Company's
East Cameron Block 334 "E" platform and natural production declines from other
Company properties. The decline in North American natural gas production from
2000 to 1998 primarily related to the sale, in early 1999 of the Company's
interest in the Lopeno Field, decreased production from the Company's East
Cameron Block 334 "E" platform and natural production declines from other
Company properties, that was not entirely offset by increased production from
the Company's Garden Banks Block 367 project and other development projects.
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. Commencing in July
1999 when production began from the Benchamas Field, crude oil and condensate
from that field has been stored on the FSO and sold as economic quantities were
accumulated. Prices that the Company receives for its crude oil and condensate
production from Thailand are based on world benchmark prices, typically as a
differential to Malaysian Tapis Blend crude and are denominated in dollars. The
differential has varied over the years and is influenced by a number of factors
including, among others, tanker availability, world-wide crude oil demand, the
size of the lifting and the perceived quality of the production from the
Tantawan and Benchamas Fields. Over the last year, the differential has
generally ranged anywhere from $0.90 above the Tapis Blend benchmark to $0.92
below. In addition, the Company is generally paid for its crude oil and
condensate production from Thailand in U.S. dollars. As discussed previously
under "Results of Operations; Net Income (Loss)," the Company records all crude
oil held in the FPSO and the FSO at the end of an accounting period as
inventory held at cost. When such crude oil is sold, usually during the
following month, the difference between the cost of the crude oil and the sales
price is recorded as income.
Production. The increase in the Company's crude oil and condensate
production during 2000, compared to 1999 and 1998, resulted primarily from
increased production from the Company's Thailand Concession due to a full
year's production from the Benchamas Field, and increased production from the
Company's Western Division properties, which was partially offset by a decline
in production from certain of the Company's other domestic properties,
principally in the offshore Gulf of Mexico.
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
increase in NGL revenues for 2000, compared with 1999 and 1998, primarily
related to an increase in the average price that the Company received for its
NGL and, with respect to 1999, a small increase in NGL production. The increase
in NGL revenues for 2000, compared to 1999, was partially offset by a decrease
in the Company's NGL production volumes.
26
Costs and Expenses
% Change % Change
2000 1999 2000 to 1999 1998 2000 to 1998
------------ ------------ ------------ ------------ ------------
Comparison of Increases (Decreases)
in:
Lease Operating
Expenses
North America........ $ 60,072,000 $ 48,121,000 25 $ 48,158,000 25
Kingdom of Thailand.. 33,568,000 21,815,000 54 20,913,000 61
------------ ------------ ------------
Total Lease
Operating
Expenses.......... $ 93,640,000 $ 69,936,000 34 $ 69,071,000 36
============ ============ ============
General and
Administrative
Expenses............. $ 34,568,000 $ 29,865,000 16 $ 26,356,000 31
Exploration Expenses.. $ 15,291,000 $ 5,982,000 156 $ 9,802,000 56
Dry Hole and
Impairment Expenses.. $ 28,608,000 $ 4,594,000 523 $ 41,736,000 (31)
Depreciation,
Depletion and
Amortization (DD&A)
Expenses............. $131,151,000 $104,266,000 26 $110,916,000 18
DD&A rate............ $ 1.08 $ 1.12 (4) $ 1.12 (4)
Mcfe produced........ 121,580,000 91,351,000 33 97,894,000 24
Pipeline operating and
natural gas
purchases............ $ 15,090,000 $ 6,481,000 133 $ 2,142,000 604
Interest
Charges.............. $ 34,064,000 $ 35,874,000 (5) $ 24,682,000 38
Capitalized Interest
Expense............. $ 20,918,000 $ 17,733,000 18 $ 9,381,000 123
Minority Interest
Dividends and costs
associated with
preferred securities
of a subsidiary
trust................ $ 9,965,000 $ 5,914,000 68 -- N/A
Foreign Currency
Transaction Gains
(Loss)............... $ (3,174,000) $ 572,000 N/A $ 953,000 N/A
Income Tax Benefit
(Expense)............ $(66,969,000) $ (9,583,000) 599 $ 27,751,000 N/A
Lease Operating Expenses
The increase in North American lease operating expenses for 2000, compared
to 1999 and 1998, were primarily attributable to an increase of approximately
$6,400,000 in severance taxes resulting from increased oil and gas prices,
repair costs related to higher than expected tubing and completion failure rate
number of offshore wells and generally increased costs resulting from an
industry-wide increase in demand for oil field services and equipment. In
addition, lease operating expenses for 1998 were reduced by $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 2000, compared to 1999 and 1998, was primarily
related to a full year's operations in Benchamas Field which commenced
production in July 1999, increased well maintenance and the presence in 1999 of
a special credit related to contract services for which no equivalent benefit
was experienced in 2000. A substantial portion of the Company's lease operating
expenses in the Kingdom of Thailand relate to lease payments made in connection
with the bareboat charter of the FPSO for the Tantawan Field and the FSO for
the Benchamas Field. Collectively, these lease payments accounted for
$15,109,000, $13,619,000 and $11,122,000 (net to the Company's interest) of the
Company's Thailand lease operating expenses for 2000, 1999 and 1998,
respectively. The Company currently expects these lease payments to decrease by
approximately $526,000 (net to the Company's interest) for 2001 and in future
years. See "Liquidity and Capital Resources; Capital Requirements; Other
Material Long-Term Commitments."
General and Administrative Expenses
The increase in general and administrative expenses for 2000, compared with
1999 and 1998, was related to a decrease in the net amount of general and
administrative expenses billed to joint venture partners, increased expenses
associated with the Company's Thailand operations, as well as normal salary and
concomitant benefit expense adjustments and, with respect to 1998, an increase
in the Company's work force,
27
that was partially offset by a number of non-recurring expenses in 1998 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 costs related to closing Arch's office in Ft. Worth, Texas.
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 increase
in exploration expenses for 2000, compared to 1999 and 1998, resulted primarily
from increased seismic acquisition costs in the offshore Gulf of Mexico, a
major seismic data reprocessing project in Thailand and the acquisition of 2-D
and 3-D seismic data in Hungary and 3-D seismic data in the North Sea.
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 the Financial
Accounting Standards Board's Statement of Financial Accounting Standards
("SFAS") No. 121 due to decreases in expected reserves from producing wells.
The increase in dry hole and impairment expenses for 2000, compared with 1999,
was principally related to an increased number of dry holes drilled in 2000
that resulted from increased drilling in 2000. The decrease in dry hole and
impairment expenses for 2000, compared with 1998, was principally related to
expenses charged in 1998 for the dry hole cost of the Company's Mustang Island
Block A-51 well, and impairment expenses related to several of the Company's
domestic properties as a result of low oil and gas prices and poor reservoir
performance, that was partially offset by an increase in dry hole expense in
2000.
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, 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.
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 2000, compared to 1999 and 1998, resulted primarily from an increase in the
Company's natural gas and liquid hydrocarbon production that was only partially
offset by a decrease in the Company's composite DD&A rate.
The decrease in the composite DD&A rate for all of the Company's producing
fields for 2000, compared to 1999 and 1998, resulted primarily from an
increased percentage of the Company's production coming from certain of the
Company's fields that have DD&A rates that are lower than the Company's recent
historical composite rate, including the Benchamas Field, and a corresponding
decrease in the percentage of the Company's production coming from fields that
have DD&A rates that are higher than the Company's recent historical composite
DD&A rate.
28
Pipeline Operating and Natural Gas Purchases
The Company acquired primarily all of its pipeline interests as part of its
acquisition of Arch on August 17, 1998. The Company purchases natural gas for
transportation through the Pogo Onshore Pipeline, which runs from Wichita
Falls, Texas to just outside of Fort Worth, Texas. This gas is then resold
under firm contracts to its customers. The expense of purchasing the natural
gas is reported on the Company's income statement under pipeline operating and
natural gas purchases. Revenue from the sale of the natural gas is reported as
revenue under pipeline sales and other. The increase in pipeline operating
expenses and natural gas purchase costs for 2000, compared to 1999 and 1998,
primarily relates to increased purchase costs for natural gas due to higher
natural gas prices and, with respect to 1998, the fact that expenses for the
pipeline were recorded for all of 2000, whereas expenses for 1998 did not
commence until the pipeline was acquired as part of the Arch acquisition on
August 17, 1998.
Interest
Interest Charges. The decrease in the Company's interest charges for 2000,
compared to 1999, resulted primarily from a decrease in the debt outstanding,
that was only partially offset by an increase in the average interest rates on
the debt outstanding and increased commitment fees (due to reduced usage of the
revolving credit facility). The increase in the Company's interest charges for
2000, compared to 1998, resulted primarily from an increase in the average
interest rates on the debt outstanding (resulting primarily from the issuance
of the 2009 Notes on January 15, 1999, which bear interest at a 10 3/8% annual
interest rate) and, to a lesser extent, increased debt issuance expense being
amortized that was not entirely offset by a decrease in the amount of debt
outstanding.
Capitalized Interest. The increase in capitalized interest for 2000,
compared to 1999 and 1998, resulted primarily from an increase in the amount of
capital expenditures subject to interest capitalization during 2000
($248,344,000) compared to 1999 ($217,183,000) and 1998 ($137,956,000), that
was only partially offset by a decrease in the computed rate that the Company
uses to apply on such capital expenditures to arrive at the total amount of
capitalized interest. The Company currently expects the amount of capital
expenditures subject to interest capitalization to increase during 2001 due to
fabrication of platforms and facilities to be installed in Thailand and in the
offshore Gulf of Mexico.
Minority Interest--Dividends and Costs Associated with Preferred Securities of
a Subsidiary Trust
Pogo Trust I, a subsidiary business trust, issued $150,000,000 of Trust
Preferred Securities on June 2, 1999. The amounts recorded for 1999 and 2000
under Minority Interest--Dividends and Costs Associated with Preferred
Securities of a Subsidiary Trust principally reflect cumulative dividends and,
to a lesser extent, the amortization of issuance expenses related to the
offering and sale of the Trust Preferred Securities. The increase in payments
in 2000, compared to 1999, primarily reflect the fact that the Trust Preferred
Securities were outstanding throughout 2000, but were only outstanding in the
second half of 1999.
Foreign Currency Transaction Gains (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 precipitous decline in the value of the Baht
against the dollar, resulting in the foreign currency transaction loss recorded
by the Company in 1997. During both 1998 and 1999, the value of the Thai Baht
generally strengthened against the dollar resulting in the gains recorded for
each year. During 2000, the Thai Baht generally weakened against the dollar.
This weakness had been attributed to, among other things, the negative impact
on the economy of high crude oil prices, continued weakness in the banking
sector, and political uncertainty surrounding the recently completed national
elections.
29
The Company cannot predict what the Thai Baht to dollar exchange rate may be in
the future. See "--Liquidity and Capital Resources; Other Matters; Southeast
Asia Economic Issues" and "Business--International Operations; Contractual
Terms Governing the Thailand Concession." As of February 27, 2001, 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 increase in the Company's income tax expense for 2000, compared to 1999,
resulted primarily from increased pre-tax income from North American operations
and from pre-tax income from the Company's operations in the Kingdom of
Thailand that was only partially offset by tax benefits in the United States
for foreign taxes paid and the use, during 1999, of all of the Company's
accrued foreign losses from the Company's operations in the Kingdom of
Thailand. The Company's income tax benefit for 1998 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 2000 reflects net
cash provided by operating activities of $239,059,000. In addition to net cash
provided by operating activities, the Company received net proceeds of
$3,745,000 from the sale of certain non-strategic properties and tubular stock
and $6,115,000 from the exercise of stock options.
During 2000, the Company repaid a net $10,000,000 under its revolving credit
facility and other senior debt agreements, invested $139,062,000 of such cash
flow in capital projects, spent $8,393,000 to purchase proved reserves, paid
$9,750,000 in cash dividends to holders of its Trust Preferred Securities, paid
$4,852,000 ($0.03 per share for each quarter of 2000) in cash dividends to
holders of the Company's common stock and, in connection with the Merger,
purchased natural gas floor contracts for $24,022,000. See "Quantitative and
Qualitative Disclosures About Market Risk--Current Hedging Activity; Natural
Gas." As of February 23, 2001, the Company's cash and cash investments were
$135,922,000, its long-term debt stood at $365,000,000 and it had $150,000,000
in Trust Preferred Securities outstanding.
Future Capital Requirements
The Company's capital and exploration budget for 2001, which does not
include any amounts that may be expended for the purchase of proved reserves or
any interest which may be capitalized resulting from projects in progress, was
established by the Company's Board of Directors at $275,000,000. The Company
currently anticipates that its available cash and cash investments, cash
provided by operating activities and funds available under its new revolving
credit facility to be entered into in connection with the Merger and its
uncommitted credit line will be sufficient to fund anticipated costs and
expenses related to the Merger, the Company's ongoing operating, interest and
general and administrative expenses, any currently anticipated costs associated
with the Company's projects during 2001, and future dividend and distribution
payments at current levels. The declaration of future dividends on the
Company's equity securities will depend upon, among other things, the Company's
future earnings and financial condition, liquidity and capital requirements,
its ability to pay dividends and payments 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.
30
Other Material Long-Term Commitments
Thaipo and its co-venturers in the Tantawan Field (collectively, the
"Charterers") are parties to a 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 Charter expires on July 31, 2008,
subject to extension. In addition, the Charterers have a purchase option on the
FPSO throughout the term of the Charter. SBM Marine Services Thailand Ltd., has
been contracted to operate the FPSO on a reimbursable basis throughout the
initial term of the Charter. Liability on the Charter is full recourse as to
each joint venturer, as to performance but the payment obligations are several,
meaning that each joint venturer's payment obligations under the Charter are
still limited to its percentage interest in the Tantawan Field. Thaipo's
performance and payment obligations are fully and unconditionally guaranteed by
the Company, but only as to Thaipo's pro rata share of the obligations arising
under the Charter. The agreement to operate the FPSO is non-recourse to the
Company. The Charter currently provides for a charter hire commitment of
$24,000,000 per year ($11,122,000 net to Thaipo through January 31, 2007, and a
decreasing amount thereafter. However, as a result of ongoing negotiations with
the lessor of the FPSO and pending partner approval, the Company currently
anticipates that this amount will be reduced to $22,860,000 per year
($10,600,000 net to Thaipo), effective retroactively to January 1, 2001.
As of August 24, 1998, 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 May 15, 1999. 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 payment obligations under the BCA
are several, meaning that each joint venturer's payment obligations are limited
to its percentage interest in the Thailand Concession. The BCA currently
provides for a charter hire commitment of $8,515,000 per year ($3,946,000 net
to Thaipo).
Capital Structure
Credit Facility and Uncommitted Credit Line. The Company has entered into a
reserve-based credit facility (the "Credit Facility"), which was amended most
recently as of November 17, 2000. The Credit Facility provides for a
$250,000,000 revolving credit facility until July 1, 2002, after which the
balance will be due in eight quarterly term loan installments, commencing
October 31, 2002. The amount that may be borrowed may not exceed a borrowing
base which is determined semi-annually and is calculated based upon
substantially all of the Company's proved oil and gas properties. As of March
2, 2001, the Company's borrowing base was set at $225,000,000. The Credit
Facility is governed by various financial and other covenants, including
requirements to maintain positive working capital (excluding current maturities
of debt) and a fixed charge coverage ratio, and limitations on indebtedness
(including a total indebtedness limit of $590,000,000), 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 Facility bear interest, at the Company's option, at
a base (prime) rate plus a variable margin (currently none) or LIBOR plus a
variable margin (currently 1.25%). The margin varies as a function of the
percentage of the borrowing base being utilized. A commitment fee on the
unborrowed amount that is currently available under the Credit Facility is also
charged based upon the percentage of the borrowing base that is being utilized.
As of March 2, 2001, there were no amounts outstanding under the Credit
Facility.
In connection with the NORIC Merger, the Company will terminate the Credit
Facility and enter into a new revolving credit facility. Based on a term sheet
agreed to with the lenders under the proposed new facility, the Company
currently expects that the new credit facility will provide for a $515,000,000
revolving loan facility terminating five years after the closing of the Merger.
The amount that may be borrowed under the new facility may not exceed a
borrowing base which is determined semi-annually and will be calculated based
upon
31
substantially all of the Company's proved oil and gas properties, including
those of North Central. The Company expects that the initial borrowing base
will be set at $475,000,000. The financial and other covenants will be
substantially similar to those contained in the Credit Facility, with the
following exceptions: there will be no express limitation on indebtedness;
there will be a limitation on commodity hedging; and the Company will be
obligated to pledge the stock of North Central and an affiliated subsidiary,
and its inter-company receivables with North Central as security. The new
revolving credit facility will also permit short-term "swing line" loans and
the issuance of up to $50,000,000 in letters of credit as a part of the
facility. Proceeds of the new facility will be used to fund anticipated costs
and expenses related to the Merger, including retiring existing North Central
debt and funding the cash portion of the consideration paid to NORIC
shareholders and for other general corporate purposes.
As of March 2, 2001, the Company also has available an uncommitted money
market line of credit with a commercial bank. The line of credit is on an as
available or as offered basis. Loans made under the line of credit 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
Facility. Under its Credit Facility, the Company is currently limited to
incurring a maximum of $20,000,000 of additional senior debt, which would
include debt incurred under the line 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." The letter agreement permits either party to terminate it
at any time. As of March 2, 2001, no amounts were outstanding under this
agreement.
2009 Notes. On January 15, 1999, the Company issued $150,000,000 principal
amount of 2009 Notes. 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. 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 Facility, its unsecured credit line 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. 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, are
equal in right of payment to the 2009 Notes, but are senior in right of payment
to the Company's subordinated indebtedness. 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. 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 described
previously.
2006 Notes. The outstanding principal amount of 2006 Notes was $115,000,000
as of December 31, 2000. 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%, payable semi-annually in
arrears on June 15 and December 15 of each year. The 2006 Notes are currently
redeemable at the option of the Company, in whole or in part, at any time, at a
redemption price of 103.30% of their principal. The redemption premium will
decline over the next several years.
32
Trust Preferred Securities. Pogo Trust I, a business trust in which the
Company owns all of the issued common securities (the "Trust"), issued
3,000,000 Trust Preferred Securities having a liquidation preference of $50 per
Trust Preferred Security, on June 2, 1999. The proceeds from the issuance of
the Trust Preferred Securities were used to purchase $150,000,000 of the
Company's 6 1/2% Junior Subordinated Convertible Debentures, due 2029 (the
"Debentures"). The Debentures are the sole asset of the Trust. The financial
terms of the Debentures are generally the same as those of the Trust Preferred
Securities. The Trust Preferred Securities accrue and pay distributions
quarterly in arrears at a rate of 6 1/2% per annum on the stated liquidation
amount of $50 per Trust Preferred Security on March 1, June 1, September 1, and
December 1 of each year to securities holders of record on the business day
immediately preceding the distribution payment date. The Company has
guaranteed, on a subordinated basis, distributions and other payments due on
the Trust Preferred Securities to the extent that there are funds available in
the Trust. The Company currently believes that, taken as a whole, the Company's
guarantee of the Trust's obligations under the Preferred Securities constitutes
a full and unconditional guarantee by the Company of the Trust's performance
obligations. The Company may cause the Trust to defer the payment of
distributions for successive periods up to 20 consecutive quarterly periods
unless an event of default on the Debentures has occurred and is continuing.
During such periods, accrued distributions on the Trust Preferred Securities
will compound quarterly and the Company will generally not be permitted to
declare or pay distributions on its common stock or debt securities that rank
equal or junior to the Debentures.
The Trust Preferred Securities are convertible at the option of the holder
at any time into common stock of the Company at the rate of 2.1053 shares of
Company common stock per Trust Preferred Security. This conversion rate will be
subject to adjustment to prevent dilution and is currently equivalent to a
conversion price of $23.75 per share of Company common stock. The Trust
Preferred Securities are mandatorily redeemable upon maturity of the Debentures
on June 1, 2029, or to the extent of any earlier redemption of any Debentures
by the Company and are callable by the Trust at any time after June 1, 2002. In
addition, if certain tax changes occur so that the Trust becomes subject to
federal income taxes or interest payments made by the Company to the Trust on
the Debentures are no longer deductible for federal income tax purposes, the
Trust may liquidate and distribute Debentures to holders of the Trust Preferred
Securities and, in certain circumstances, the Company may shorten the stated
maturity of the Debentures to as early as June 2, 2014.
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, experienced severe
economic difficulties in 1997 and 1998 which were characterized by sharply
reduced economic activity, illiquidity, highly volatile foreign currency
exchange rates and unstable stock markets. Since that time, the economic
situation has generally improved, although the recent worldwide rise in crude
oil prices, continued weakness in the Thai banking sector and political
uncertainty surrounding the recently completed national elections have had a
negative impact on the Thai economy, resulting in a slow decline of the value
of the Baht against the U.S. dollar. The economic health of the Thai economy
and its effect on 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)."
33
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."
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."
34
Interest Rate Risk
From time to time, the Company has entered into various financial
instruments, such as interest rate swaps, to manage the impact of changes in
interest rates. As of February 27, 2001, the Company has no open interest rate
swap or interest rate lock agreements. Therefore, the Company's exposure to
changes in interest rates primarily results from its short-term and long-term
debt with both fixed and floating interest rates. The following table presents
principal or notional amounts (stated in thousands) and related average
interest rates by year of maturity for the Company's debt obligations and their
indicated fair market value at December 31, 2000:
Fair
2000 2001 2002 2003 2004 Thereafter Total Value
---- ---- ---- ---- ---- ---------- -------- --------
Liabilities Long-Term
Debt:
Variable Rate.......... $ 0 $ 0 $ 0 $ 0 $ 0 $ 0 $ 0 $ 0
Average Interest Rate.. -- -- -- -- -- -- -- --
Fixed Rate............. $ 0 $ 0 $ 0 $ 0 $ 0 $365,000 $365,000 $361,682
Average Interest Rate.. -- -- -- -- -- 8.4% 8.4% --
Foreign Currency Exchange Rate Risk
The Company conducts business in Thai Baht, Hungarian Forint and the
Canadian dollar and is therefore subject to foreign currency exchange rate risk
on cash flows related to sales, expenses, financing and investing transactions.
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 denominated in dollars, the dollar is the functional currency for
the Company's operations in the Kingdom of Thailand. As of March 2, 2001, the
Company is not a party to any foreign currency exchange agreement.
Exposure from market rate fluctuations related to activities in Canada,
where the Company's functional currency is the Canadian dollar, and Hungary,
where the Company's functional currency is the Forint, is not material at this
time.
Current Hedging Activity
From time to time, the Company has used and expects to continue to use
hedging transactions with respect to a portion of its oil and gas production to
achieve a more predictable cash flow, as well as to reduce its exposure to
price fluctuations. While the use of these hedging arrangements limits the
downside risk of adverse price movements, they may also limit future revenues
from favorable price movements. The use of hedging transactions also involves
the risk that the counter-parties will be unable to meet the financial terms of
such transactions. All of the Company's recent historical hedging transactions
have been carried out in the over-the-counter market with investment grade
institutions. During 2000, approximately 21% of the Company's equivalent
production was subject to commodity price hedging arrangements. In January
2001, the Company began to account for its hedging activities under SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133").
SFAS 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair market value. The statement requires that
changes in the derivative's fair value be recognized currently in earnings
unless specific
35
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that we must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting. Based on the nature of the Company's derivative instruments
currently outstanding and the historical volatility of oil and gas commodity
prices, we expect that SFAS 133 could increase volatility in our earnings and
other comprehensive income in future periods.
Natural Gas
In anticipation of the NORIC Merger, in late November and early December of
2000, the Company purchased options to sell 70 million cubic feet of natural
gas production per day for the period from April 2001 through December 2002.
These contracts give the Company the right, but not the obligation, to sell
natural gas at a sales price of $4.25 per MMBtu for the period from April 2001
through March 2002 and $4.00 per MMBtu for the period from April 2002 through
December 2002. These contracts are designed to guarantee a minimum "floor"
price for the contracted volumes of production without limiting the Company's
participation in price increases during the covered period. The Company paid
approximately $24 million in cash to enter into these option contracts. As of
December 31, 2000, and March 2, 2001, the Company was a party to the following
hedging arrangements:
NYMEX Contract Price per MMBtu(a)
---------------------------------
Volume Collars
in --------------- Fair Market
Period MMBtu(a) Swaps Floors Ceilings Value(b)
------ -------- ----- ------ -------- -----------
Floor Contracts:
April 2001-March 2002.............. 25,550 -- $4.25 -- $ 6,930,000
April 2002-December 2002........... 19,250 -- $4.00 -- $13,342,000
--------
(a) "MMBtu" means million British Thermal Units.
(b) Fair Market Value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 2000.
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or,
occasionally, the penultimate trading day of a particular contract month. For
any particular floor transaction, the counter-party is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction. The Company is not required to make
any payment in connection with the settlement of a floor transaction. However,
in accordance with SFAS 133, the Company is required to record changes in the
fair value of these floor contracts' premium (the contracts' time value)
currently in earnings with no offset. Based on existing implementation
guidelines issued by the Financial Accounting Standards Board staff, we
recorded a non-cash after-tax charge to earnings of approximately $2,400,000 as
the cumulative effect of adopting SFAS 133 effective January 1, 2001. The pre-
tax cumulative effect represents the difference between the unamortized premium
paid for the floor contracts and the fair value of the contracts' time value as
of January 1, 2001. This charge will be reflected on the Company's first
quarter 2001 financial statements.
Crude Oil
As of December 31, 2000 and March 2, 2001, the Company was not a party to
any commodity price hedging contracts with respect to any of its current or
future crude oil and condensate production.
36
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2000
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
37
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,
2000 and 1999, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 2000. 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 auditing standards generally
accepted in the United States. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2000, the Company changed its method of accounting for product inventory.
ARTHUR ANDERSEN LLP
Houston, Texas
February 9, 2001
38
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(Expressed in thousands,
except per share amounts)
Revenues:
Oil and gas.................................... $479,202 $230,499 $200,154
Pipeline sales and other....................... 15,113 7,159 2,741
Gains (losses) on sales........................ 3,676 37,458 (92)
-------- -------- --------
Total........................................ 497,991 275,116 202,803
-------- -------- --------
Operating Costs and Expenses:
Lease operating................................ 93,640 70,349 69,071
Pipeline operating and natural gas purchases... 15,090 6,481 2,142
General and administrative..................... 34,568 29,452 26,356
Exploration.................................... 15,291 5,982 9,802
Dry hole and impairment........................ 28,608 4,594 41,736
Depreciation, depletion and amortization....... 131,151 104,266 110,916
-------- -------- --------
Total........................................ 318,348 221,124 260,023
-------- -------- --------
Operating Income (Loss).......................... 179,643 53,992 (57,220)
Interest:
Charges........................................ (34,064) (35,874) (24,682)
Income......................................... 2,634 1,208 719
Capitalized.................................... 20,918 17,733 9,381
Minority Interest--Dividends and costs associated
with mandatorily redeemable convertible
preferred securities of a subsidiary trust...... (9,965) (5,914) --
Foreign Currency Transaction Gains (Loss)........ (3,174) 572 953
-------- -------- --------
Income (Loss) Before Taxes and Cumulative Effect
of Change in Accounting Principle............... 155,992 31,717 (70,849)
Income Tax Benefit (Expense)..................... (66,969) (9,583) 27,751
-------- -------- --------
Income (Loss) Before Cumulative Effect of Change
in Accounting Principle......................... 89,023 22,134 (43,098)
Cumulative Effect of Change in Accounting
Principle....................................... (1,768) -- --
-------- -------- --------
Net Income (Loss)................................ $ 87,255 $ 22,134 $(43,098)
======== ======== ========
Earnings (Loss) per Common Share:
Basic
Income (loss) before cumulative effect of
change in accounting principle................ $ 2.20 $ 0.55 $ (1.14)
Cumulative effect of change in accounting
principle..................................... (0.04) -- --
-------- -------- --------
Net income (loss).............................. $ 2.16 $ 0.55 $ (1.14)
======== ======== ========
Diluted
Income (loss) before cumulative effect of
change in accounting principle................ $ 1.99 $ 0.55 $ (1.14)
Cumulative effect of change in accounting
principle..................................... (0.04) -- --
-------- -------- --------
Net income (loss).............................. $ 1.95 $ 0.55 $ (1.14)
======== ======== ========
Dividends per Common Share....................... $ 0.12 $ 0.12 $ 0.12
======== ======== ========
The accompanying notes to consolidated financial statements are an integral
part hereof.
39
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------
2000 1999
------------ ------------
(Expressed in thousands)
ASSETS
Current Assets:
Cash and cash equivalents........................ $ 81,510 $ 6,267
Accounts receivable.............................. 84,381 37,321
Other receivables................................ 27,242 35,870
Inventory--product............................... 3,054 7,209
Inventories--tubulars............................ 8,056 10,352
Price hedge contracts............................ 9,153 --
Other............................................ 1,276 2,370
------------ ------------
Total current assets........................... 214,672 99,389
------------ ------------
Property and Equipment:
Oil and gas, on the basis of successful efforts
accounting
Proved properties being amortized 1,698,404 1,638,321
Unevaluated properties and properties under
development, not being amortized.............. 154,914 144,357
Pipelines, at cost............................... 7,095 6,984
Other, at cost................................... 15,257 13,103
------------ ------------
1,875,670 1,802,765
------------ ------------
Accumulated depreciation, depletion, and
amortization
Oil and gas.................................... (1,053,478) (1,006,542)
Pipelines...................................... (1,780) (1,534)
Other.......................................... (8,758) (7,329)
------------ ------------
(1,064,016) (1,015,405)
------------ ------------
Property and equipment, net...................... 811,654 787,360
------------ ------------
Other Assets:
Price hedge contracts............................ 14,869 --
Debt issue expenses.............................. 10,718 12,686
Foreign value added taxes receivable............. 7,262 12,025
Foreign tax net operating losses................. 3,695 16,237
Other............................................ 20,652 20,496
------------ ------------
57,196 61,444
------------ ------------
$ 1,083,522 $ 948,193
============ ============
The accompanying notes to consolidated financial statements are an integral
part hereof.
40
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
---------------------------
2000 1999
------------- ------------
(Expressed in thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable--operating activities........... $ 27,334 $ 21,724
Accounts payable--investing activities........... 67,703 62,878
Accrued interest payable......................... 7,443 7,457
Accrued dividends associated with preferred
securities of a subsidiary trust................ 813 813
Accrued payroll and related benefits............. 2,285 2,149
Other............................................ 851 208
------------- -----------
Total current liabilities...................... 106,429 95,229
Long-Term Debt..................................... 365,000 375,000
Deferred Income Tax................................ 95,453 51,177
Deferred Credits................................... 13,456 13,524
------------- -----------
Total liabilities.............................. 580,338 534,930
------------- -----------
Commitments and Contingencies (Note 1)............. -- --
Minority Interests:
Company-obligated mandatorily redeemable
convertible preferred securities of a subsidiary
trust, net of unamortized issue expenses........ 144,913 144,751
------------- -----------
Shareholders' Equity:
Preferred stock, $1 par; 2,000,000 shares
authorized...................................... -- --
Common stock, $1 par; 100,000,000 shares
authorized, and 40,659,591 and 40,279,661 shares
issued, respectively............................ 40,660 40,279
Additional capital............................... 298,885 291,909
Retained earnings (deficit)...................... 20,112 (62,291)
Accumulated other comprehensive loss............. (1,062) (1,061)
Treasury stock (15,575 shares), at cost.......... (324) (324)
------------- -----------
Total shareholders' equity..................... 358,271 268,512
------------- -----------
$ 1,083,522 $ 948,193
============= ===========
The accompanying notes to consolidated financial statements are an integral
part hereof.
41
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(Expressed in thousands)
Cash flows from operating activities:
Cash received from customers.................. $446,184 $218,936 $222,433
Federal income taxes received................. 6,000 6,446 --
Operating, exploration and general and
administrative expenses paid................. (152,979) (105,924) (116,272)
Interest paid................................. (32,028) (29,606) (26,221)
Purchase of price hedge contracts............. (24,022) -- --
Federal income taxes paid..................... (9,444) (21,000) --
Value added taxes received (paid)............. 4,763 101 (6,161)
Other......................................... 585 (196) (2,850)
-------- -------- --------
Net cash provided by operating activities.... 239,059 68,757 70,929
-------- -------- --------
Cash flows from investing activities:
Capital expenditures.......................... (139,062) (201,323) (201,946)
Purchase of proved reserves................... (8,393) (20,000) (2,961)
Proceeds from the sale of property and tubular
stock........................................ 3,745 81,944 7,164
-------- -------- --------
Net cash used in investing activities........ (143,710) (139,379) (197,743)
-------- -------- --------
Cash flows from financing activities:
Borrowings under senior debt agreements....... 67,000 260,053 449,947
Payments under senior debt agreements......... (77,000) (470,000) (313,500)
Proceeds from issuance of new debt............ -- 150,000 --
Proceeds from issuance of new financing....... -- 150,000 --
Proceeds from exercise of stock options....... 6,115 1,115 1,034
Payment of preferred dividends of a subsidiary
trust........................................ (9,750) (4,999) --
Payment of cash dividends on common stock..... (4,852) (4,825) (4,531)
Payment of financing issue expenses........... (135) (12,347) (2,635)
Principal payment of production payment
obligation................................... -- -- (15,246)
Other......................................... -- -- (621)
-------- -------- --------
Net cash provided by (used in) financing
activities.................................. (18,622) 68,997 114,448
-------- -------- --------
Effect of exchange rate changes on cash......... (1,484) (67) 679
-------- -------- --------
Net increase (decrease) in cash and cash
equivalents.................................... 75,243 (1,692) (11,687)
Cash and cash equivalents at the beginning of
the year....................................... 6,267 7,959 19,646
-------- -------- --------
Cash and cash equivalents at the end of the
year........................................... $ 81,510 $ 6,267 $ 7,959
======== ======== ========
Reconciliation of net income to net cash
provided by operating activities:
Net income (loss)............................. $ 87,255 $ 22,134 $(43,098)
Adjustments to reconcile net income to net
cash provided by operating activities
Cumulative effect of change in accounting
principle................................... 1,768 -- --
Minority interest............................ 9,965 5,914 --
Foreign currency transaction (gain) loss..... 3,174 (572) (953)
(Gains) losses on sales...................... (3,676) (37,458) 92
Depreciation, depletion and amortization..... 131,151 104,266 110,916
Dry hole and impairment...................... 28,608 4,594 41,736
Interest capitalized......................... (20,918) (17,733) (9,381)
Increase (decrease) in deferred income
taxes....................................... 63,495 (5,337) (31,251)
Change in assets and liabilities:
(Increase) decrease in accounts
receivable................................ (48,425) (13,006) 15,307
(Increase) decrease in inventory--product.. 601 (6,117) (259)
Increase in price hedge contracts.......... (24,022) -- --
Decrease in other current assets........... 1,062 453 1,258
(Increase) decrease in other assets........ 2,902 41 (13,550)
Increase (decrease) in accounts payable.... 5,447 9,714 (1,122)
Increase (decrease) in accrued interest
payable................................... (14) 4,314 95
Increase in accrued payroll and related
benefits.................................. 132 201 14
Increase (decrease) in other current
liabilities............................... 624 210 (637)
Increase (decrease) in deferred credits.... (70) (2,861) 1,762
-------- -------- --------
Net cash provided by operating activities....... $239,059 $ 68,757 $ 70,929
======== ======== ========
The accompanying notes to consolidated financial statements are an integral
part hereof.
42
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Accumulated
Retained Other
Common Additional Earnings Comprehensive Treasury Shareholders' Comprehensive
Stock Capital (Deficit) Income (Loss) Stock Equity Income (Loss)
------- ---------- --------- ------------- -------- ------------- -------------
Balance at December 31,
1997................... $33,553 $144,848 $(31,971) $ -- $(324) $146,106
Net loss................ -- -- (43,098) -- -- (43,098) $(43,098)
Exercise of stock
options................ 147 1,835 -- -- -- 1,982
Shares issued in
connection with the
conversion of 2004
Notes.................. 3,880 80,712 -- -- -- 84,592
Shares issued for stock
and debt of acquired
company................ 2,539 62,944 -- (1,253) -- 64,230
Shares issued as
compensation........... 17 316 -- -- -- 333
Dividends ($0.12 per
common share).......... -- -- (4,531) -- -- (4,531)
Exchange gain on
Canadian currency...... -- -- -- 46 46 46
--------
Comprehensive loss...... -- -- -- -- -- -- $(43,052)
------- -------- -------- ------- ----- -------- ========
Balance at December 31,
1998................... 40,136 290,655 (79,600) (1,207) (324) 249,660
Net income.............. -- -- 22,134 -- -- 22,134 $ 22,134
Exercise of stock
options................ 130 1,267 -- -- -- 1,397
Adjustment for
fractional shares and
other.................. 13 (13) -- -- -- --
Dividends ($0.12 per
common share).......... -- -- (4,825) -- -- (4,825)
Exchange gain on
Canadian currency...... -- -- -- 146 146 146
--------
Comprehensive income.... -- -- -- -- -- -- $ 22,280
------- -------- -------- ------- ----- -------- ========
Balance at December 31,
1999................... 40,279 291,909 (62,291) (1,061) (324) 268,512
Net income.............. -- -- 87,255 -- -- 87,255 $ 87,255
Exercise of stock
options................ 315 5,754 -- -- -- 6,069
Shares issued as
compensation........... 66 1,222 -- -- -- 1,288
Dividends ($0.12 per
common share).......... -- -- (4,852) -- -- (4,852)
Exchange loss on
Canadian currency...... -- -- -- (1) -- (1) (1)
--------
Comprehensive income.... -- -- -- -- -- -- $ 87,254
------- -------- -------- ------- ----- -------- ========
Balance at December 31,
2000................... $40,660 $298,885 $ 20,112 $(1,062) $(324) $358,271
======= ======== ======== ======= ===== ========
The accompanying notes to consolidated financial statements are an integral
part hereof.
43
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, production and acquisition activities in the United States both
offshore in the Gulf of Mexico (primarily in federal waters offshore Louisiana
and Texas) and onshore principally in the states of New Mexico, Texas and
Louisiana. The Company also conducts exploration, development and production
activities internationally in the Kingdom of Thailand (offshore in the Gulf of
Thailand) and Canada (primarily in the provinces of Alberta, British Columbia
and Saskatchewan) and exploration activities in Hungary and the British and
Danish sectors of the North Sea.
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 oil and gas 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. See note 4 of the notes to consolidated financial
statements for a discussion of the Company's accounting for its minority
interest in Pogo Trust I.
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 or the
average for the 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 (or the
average exchange rate for the month with respect to items of income and
expense) and the resulting gains or losses on Canadian currency transactions
are included in the consolidated statement of shareholders' equity for the
period through accumulated other comprehensive income.
44
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Production Imbalances--
Owners of an oil and gas property often take more or less production from a
property than entitled 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 "sales" (takes or cash) method of accounting for
production imbalances whereby the Company recognizes revenues on production as
it is taken and delivered to its purchasers not withstanding its ownership
percentage. The Company's crude oil imbalances are not significant. At December
31, 2000, the Company had taken approximately 2,268 MMcf of natural gas less
than it was entitled to based on its interest in those properties, and
approximately 1,600 MMcf more than its entitlement on other properties placing
the Company at year-end in a net under-delivered position of approximately 668
MMcf of natural gas based on its working interest ownership in the properties.
Inventory--Product
Crude oil and condensate from the Company's producing fields located in the
Kingdom of Thailand are produced into storage vessels and sold periodically as
economic quantities are accumulated. The product inventory at December 31, 1999
consists of approximately 287,000 barrels of crude oil and condensate, net to
the Company's interest, and was carried at its estimated net realizable value
of $25.09 per barrel. Effective January 1, 2000, the Company adopted the
provisions of the Securities and Exchange Commission's (the "SEC") Staff
Accounting Bulletin No. 101, Revenue Recognition. As a result, the oil and gas
exploration and production industry's long-standing practice of recording such
product inventories at their net realizable value will no longer be accepted by
the SEC. The product inventory at December 31, 2000 consists of approximately
350,000 barrels of crude oil and condensate, net to the Company's interest, and
is carried at its estimated average cost of $8.73 per barrel. The cumulative
effect of this change in accounting principle through December 31, 1999
($1,768,000, net of tax benefits of $1,768,000) has been charged to earnings
effective January 1, 2000 and the first three quarters of 2000 have been
restated. The following summary presents the proforma consolidated results of
operations as if the accounting change had occurred as of the beginning of
1998. The proforma results are expressed in thousands of dollars, except for
per share amounts.
2000 1999 1998
-------- -------- --------
Proforma:
Revenues.......................................... $497,991 $268,876 $202,547
Operating income (loss)........................... $179,643 $ 50,456 $(57,055)
Net income (loss)................................. $ 89,023 $ 20,366 $(43,016)
Earnings (loss) per share:
Basic........................................... $ 2.20 $ 0.51 $ (1.14)
Diluted......................................... $ 1.99 $ 0.50 $ (1.14)
As reported:
Earnings (loss) per share:
Basic........................................... $ 2.16 $ 0.55 $ (1.14)
Diluted......................................... $ 1.95 $ 0.55 $ (1.14)
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.
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.
45
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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, 2000
-----------------------------------------
Income(a) Shares Per Share
------------- ----------- -------------
Basic earnings per share............. $ 89,023 40,445 $ 2.20
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.............. 668
Interest expense incurred, net of
taxes, and shares issued related
to the assumed conversion at
$42.185 per share of the 2006
Notes............................. 4,111 2,726
Minority interest expense incurred,
net of taxes, and shares issued
related to the assumed conversion
at $23.75 per share of the Trust
Preferred Securities.............. 6,338 6,316
------------- ----------- -----------
Diluted earnings per share........... $ 99,472 50,155 $ 1.99
============= =========== ===========
--------
(a) Represents income before cumulative effect of change in accounting
principle
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...................... $ -- 219 $ 34.93
For the Year Ended December 31, 1999
-----------------------------------------
Income Shares Per Share
------------- ----------- -------------
Basic earnings per share............. $ 22,134 40,178 $ 0.55
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.............. -- 212 --
------------- ----------- -----------
Diluted earnings per share........... $ 22,134 40,390 $ 0.55
============= =========== ===========
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...................... $ -- 2,388 $ 21.46
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
Minority interest expense incurred,
net of taxes, and shares not
issued related to the assumed non-
conversion at $23.75 per share of
the Trust Preferred Securities,
issued on June 2, 1999............ $ 3,681 3,668 $ 1.00
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 incurred, net of
taxes, and shares not issued
related to the assumed non-
conversion at $22.188 per share of
the 2004 Notes.................... $ 478 594 $ 0.80
46
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 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.
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. 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 depreciation, depletion and
amortization is based on the capitalized costs as determined above, plus future
cost to abandon offshore wells and platforms, and is on a cost center by cost
center basis using the units of production method with lease acquisition costs
amortized over total proved reserves and other costs amortized over proved
developed reserves. 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 an ongoing asset maximization process, the Company had
designated certain non-strategic and/or under performing properties to be
disposed of to generate cash and maximize its focus on properties with greater
exploration potential. These properties, including the previously announced
sale of the Lopeno Field in South Texas were sold in the first quarter of 1999
at an aggregate gain of $37,344,000.
Other properties and equipment 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 conversion of notes into common stock, shares issued as
compensation, and shares issued for stock and debt of an acquired company. The
shares issued for stock and debt of an acquired company is also discussed in
the following Acquisition section of this note.
Commitments and Contingencies--
The Company has commitments for operating leases (primarily for office
space) in Houston, Midland, Fort Worth, Calgary and Bangkok and commitments for
operating leases related to an FPSO and FSO in the Gulf of Thailand. Rental
expense for office space was $1,911,000 in 2000, $1,855,000 in 1999, and
$1,545,000 in 1998. Expenses for the FPSO lease were approximately $11,100,000
in each of the years 2000, 1999 and 1998. Expenses for the floating storage and
offloading system ("FSO") (which commenced in May 1999) were approximately
$4,000,000 in 2000 and $2,500,000 in 1999. Future minimum lease expenses at
December 31, 2000 are $17,500,000 in 2001; $17,900,000 in 2002; $17,800,000 in
2003; $17,900,000 in 2004; $17,800,000 in 2005; and $53,600,000 in years
thereafter.
47
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Acquisitions--
On November 19, 2000, the Company entered into an agreement and plan of
merger with NORIC and certain shareholders of NORIC signatories thereto, which
provided for the Merger of the Company and NORIC. The Company expects the
Merger to occur in mid-March following satisfaction of all conditions precedent
including approval by the Company's shareholders on March 13, 2001. The
principal asset of NORIC is North Central, a privately held company that
explores for and produces oil and natural gas principally in onshore and
offshore Gulf Coast areas and Wyoming. Except where expressly noted, the
information in this Annual Report relates only to the Company and does not
include either historical information regarding North Central or the future
impact of the Merger on the Company.
The aggregate merger consideration including assumption of North Central's
debt, is approximately $750,000,000. The merger agreement provides for
consideration to NORIC stockholders of approximately $630,000,000, subject to a
purchase price adjustment, in a combination of 50% cash and 50% Pogo common
stock. The number of shares of stock is determined based on the market price of
Pogo common stock over a 20-trading day period ending five days prior to the
effective time of the merger, subject to a minimum of 11,559,633 shares of Pogo
common stock if the price per share exceeds $27.25 and a maximum of 14,157,303
shares if the price per share is less than $22.25. Adding the approximately
$120,000,000 of North Central's net debt that was assumed would exist at the
closing results in the $750,000,000 total consideration.
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. 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 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. The unaudited proforma consolidated revenues,
net loss and loss per share, as if the acquisition had occurred at the
beginning of 1998 are $217,915,000; ($48,369,000) and ($1.22); respectively.
These unaudited proforma results are presented 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.
Price Risk Management--
The Company from time to time enters into commodity price hedging contracts
with respect to its oil and gas production to limit the volatility of price
movements. Such contracts are accounted for as hedges, in accordance with
Statement of Financial Accounting Standard No. 80 ("SFAS 80"). Gains and losses
on these contracts are recognized in revenue in the period in which the
underlying production is delivered. In 2000, the Company hedged 16,910 MMcf of
gas and 1,509,500 barrels of crude oil (25,967 equivalent MMcf) or
approximately 21% of its equivalent 2000 production and recorded hedge losses
of $11,549,000 in connection with its natural gas contracts and hedge losses of
$9,976,000 in connection with its crude oil contracts. In 1999, the Company
hedged 3,175 MMcf of natural gas and 514,500 barrels of crude oil (6,262
equivalent MMcf) or approximately 7% of its equivalent 1999 production and
recorded hedge gains of $933,000 in connection with its natural gas contracts
and hedge gains of $1,947,000 in connection with its crude oil contracts. No
significant amount of hedge positions were held by the Company in earlier
years. These instruments are measured for correlation at both the inception of
the contract and on an ongoing basis. If these instruments cease to meet
certain criteria for deferral accounting, any subsequent gains or losses are
recognized in revenue. If these instruments are terminated prior to maturity,
resulting gains and losses continue to be deferred until the hedged item is
recognized in revenue. Neither the hedging contracts nor the unrealized gains
or losses on these contracts are recognized in the financial statements. The
Company has currently hedged 44,800 MMcf of its
48
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
forecasted natural gas production using purchased put options or floors. Prior
to January 1, 2001, changes in the value of such contracts were recognized in
earnings when the hedged production occurred. Effective January 1, 2001, the
Company adopted Statement of Financial Accounting Standards No. 133, Accounting
for Derivative Instruments and Hedging Activities ("SFAS 133") which requires
that that changes in the fair value of the option premium (the option's time
value) be reported currently in earnings with no offset. See Note 11.
(2) Income Taxes
The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 2000, are as follows (expressed in
thousands):
2000 1999 1998
-------- ------- --------
United States....................................... $ 67,967 $40,472 $(57,112)
Foreign............................................. 88,025 (8,755) (13,737)
-------- ------- --------
Income (loss) before income taxes and cumulative
effect of change in accounting principle......... $155,992 $31,717 $(70,849)
======== ======= ========
The components of income tax expense (benefit) for each of the three years
in the period ended December 31, 2000, are as follows (expressed in thousands):
2000 1999 1998
------- ------- --------
United States, current.............................. $ 9,000 $21,000 $ --
United States, deferred............................. 12,392 (6,978) (20,750)
Foreign, deferred................................... 45,577 (4,439) (7,001)
------- ------- --------
Income tax expense (benefit)...................... $66,969 $ 9,583 $(27,751)
======= ======= ========
Total income tax expense (benefit) for each of the three years in the period
ended December 31, 2000, differs from the amounts computed by applying the
statutory federal income tax rate to income before taxes as follows (expressed
as a percent of pretax income):
2000 1999 1998
---- ---- ------
Federal statutory income tax rate........................... 35.0% 35.0% (35.0)%
Increases (reductions) resulting from:
Statutory depletion in excess of tax basis.................. (0.8) (0.8) (0.4)
Foreign taxes............................................. 8.7 (4.1) (3.8)
Other..................................................... -- 0.1 --
---- ---- ------
42.9% 30.2% (39.2)%
==== ==== ======
49
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Income Taxes (Continued)
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 the future tax benefit will be realized. The presentation in the
consolidated balance sheets and the principal components of the Company's
deferred income tax assets and liabilities at December 31, 2000 and 1999
(expressed in thousands) are as follows:
December 31,
--------------------
2000 1999
--------- ---------
Deferred United States federal income tax liability...... $ (67,881) $ (51,177)
Deferred foreign income tax liability.................... (27,572) --
Other assets--foreign tax net operating losses........... 3,695 16,237
--------- ---------
Net deferred tax liability............................... $ (91,758) $ (34,940)
========= =========
Deferred tax liabilities:
Domestic--
Intangible drilling costs, capitalized and amortized
for financial statement purposes and deducted for
income tax purposes................................... $(224,389) $(162,526)
Charges to property and equipment, expensed for
financial statement purposes, and capitalized and
amortized for income tax purposes..................... (9,157) (24,254)
Interest charges, capitalized and amortized for
financial statement purposes and deducted for income
tax purposes.......................................... (30,281) (15,037)
Thailand--
Differences in depletion and depreciation rates used
for tangible and intangibles assets for financial and
tax purposes.......................................... (58,699) --
--------- ---------
(322,526) (201,817)
--------- ---------
Deferred tax asset:
Differences in depletion and depreciation rates used
for tangible assets for financial and income tax
purposes.............................................. 194,915 145,630
Foreign net operating loss carryforwards............... 65,302 16,237
Valuation allowance.................................... (30,480) --
Domestic net operating loss carryforwards.............. -- 3,979
Tax credits and other.................................. 1,031 1,031
--------- ---------
230,768 166,877
--------- ---------
Net deferred tax liability............................... $ (91,758) $ (34,940)
========= =========
As of December 31, 2000, the Company has a net operating loss carryforward
applicable to non-U.S. subsidiaries of approximately $126,900,000, which will
begin to expire in 2007. A valuation allowance has been provided for certain of
the deferred tax assets attributable to these loss carryforwards as it is
currently deemed more likely than not that these assets will not be fully
realized.
50
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Long-Term Debt
Long-term debt and the amount due within one year at December 31, 2000 and
1999, consists of the following (dollars expressed in thousands):
December 31,
-----------------
2000 1999
-------- --------
Senior debt--
Bank revolving credit agreement:
LIBOR based loans, borrowings at an average interest rate
of 7.8%................................................... $ -- $ 5,000
Uncommitted credit lines with banks, borrowings at an
average interest rate
of 5.9%.................................................... -- 5,000
-------- --------
Total senior debt............................................. -- 10,000
-------- --------
Subordinated debt--
8 3/4% Senior subordinated notes, due 2007.................. 100,000 100,000
10 3/8% Senior subordinated notes, due 2009................. 150,000 150,000
5 1/2% Convertible subordinated notes, due 2006............. 115,000 115,000
-------- --------
Total subordinated debt....................................... 365,000 365,000
-------- --------
Total debt.................................................... 365,000 375,000
-------- --------
Amount due within one year--.................................. -- --
-------- --------
Long-term debt................................................ $365,000 $375,000
======== ========
The Company entered into a reserve-based credit facility (the "Credit
Facility"), which was amended most recently in November 2000. The Credit
Facility provides for a $250,000,000 revolving credit facility until July 1,
2002, after which the balance will be due in eight quarterly term loan
installments, commencing on October 31, 2002. The amount that may be borrowed
may not exceed a borrowing base which determined semi-annually and is
calculated based upon substantially all of the Company's proved oil and gas
properties. As of December 31, 2000, the Company's borrowing base was set at
$225,000,000. The Credit Facility is governed by various financial and other
covenants, including requirements to maintain positive working capital
(excluding current maturities of debt) and a fixed charge coverage ratio, and
limitations on indebtedness (including a total indebtedness limit of
$590,000,000), 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
Facility bear interest, at the Company's option, at a base (prime) rate plus a
variable margin (currently none) or LIBOR plus a variable margin (currently
1.25%). The margin varies as a function of the percentage of the borrowing base
utilized. A commitment fee on the unborrowed amount at a base rate or LIBOR
plus 1.75%, at the Company's option. A commitment fee on the unborrowed amount
that is currently available under the Credit Facility is also charged based
upon the percentage of the borrowing base that is being utilized.
In connection with the NORIC Merger, the Company plans to terminate the
above Credit Facility and enter into a new revolving credit facility. Based on
a term sheet agreed to with the lenders under the proposed new facility, the
Company currently expects that the new credit facility will provide for a
$515,000,000 revolving loan facility terminating five years after the closing
of the Merger. The amount that may be borrowed under the new facility may not
exceed a borrowing base which is to be determined semi-annually and will be
calculated based upon substantially all of the Company's proved oil and gas
properties, including those of North Central. The Company expects that the
initial borrowing base will be set at $475,000,000. The Company expects the
financial and other covenants will be substantially similar to those contained
in the Credit Facility,
51
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
with the following exceptions: there will be no express limitation on
indebtedness; there will be a limitation on commodity hedging; and the Company
will be obligated to pledge the stock of North Central and an affiliated
subsidiary, and its inter-company receivables with North Central as security.
The new revolving credit facility will also permit short-term "swing line"
loans and the issuance of up to $50,000,000 in letters of credit as a part of
the facility. Proceeds of the new facility will be used to fund the cash
portion of the consideration paid to NORIC shareholders, retire existing North
Central debt and for other general corporate purposes.
As of December 31, 2000, the Company also has available an uncommitted money
market line of credit with a commercial bank. The line of credit is on an as
available or as offered basis. Loans made under the line of credit 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
Facility. Under its Credit Facility, the Company is currently limited to
incurring a maximum of $20,000,000 of additional senior debt, which would
include debt incurred under the line 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. The letter agreement
permits either party to terminate it at any time.
On May 22, 1997, the Company issued $100,000,000 of 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 and are subordinated
in right of payment to the Company's senior indebtedness, are equal in right of
payment to the 2009 Notes, but are senior in right of payment to the Company's
subordinated indebtedness. 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. 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 described below.
On January 15, 1999, the Company issued $150,000,000 principal amount of
2009 Notes. 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. The 2009 Notes
are generally unsecured senior subordinated obligations of the Company, are
subordinated in right of payment to the Company's senior indebtedness, which
currently includes the Company's obligations under the Credit Facility, its
unsecured credit lines and its bankers acceptances, are equal in right of
payment to the 2007 Notes, 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 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. 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 assets sales; non-guarantor restricted subsidiaries;
dividends and other payment restrictions affecting restricted subsidiaries; and
mergers, consolidations and the sale of assets. As of December 31, 2000,
$75,370,000 was available for dividends under this limitation, which is
currently the Company's most restrictive convenant.
The outstanding principal amount of 2006 Notes was $115,000,000 as of
December 31, 2000. The 2006 Notes bear interest at a rate of 5 1/2%, payable
semi-annually in arrears on June 15 and December 15 of each year. 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 are currently
redeemable at the option of the Company, in whole or in part, at any time, at a
redemption price of 103.3% of their principal. The redemption premium will
decline over the next several years.
The Company currently has no maturities or sinking fund requirements during
the next five years in connection with the above long-term debt.
52
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Minority Interest
Pogo Trust I, a business trust in which the Company owns all of the issued
common securities (the "Trust"), issued $150,000,000 (3,000,000 securities
having a liquidation preference of $50 each) of 6 1/2% Cumulative Quarterly
Income Convertible Preferred Securities, Series A (the "Trust Preferred
Securities") on June 2, 1999. The proceeds of the issuance of the Trust
Preferred Securities were used to purchase $150,000,000 of the Company's 6 1/2%
Junior Subordinated Convertible Debentures, due June 1, 2029 (the
"Debentures"). The Debentures are the sole asset of Pogo Trust I. The financial
terms of the Debentures are generally the same as those of the Trust Preferred
Securities. The Trust Preferred Securities accrue and pay distributions
quarterly in arrears at a rate of 6 1/2% per annum on the stated liquidation
amount of $50 per Trust Preferred Security on March 1, June 1, September 1, and
December 1 of each year to security holders of record on the business day
immediately preceding the distribution payment date. The Company has
guaranteed, on a subordinated basis, distributions and other payments due on
the Trust Preferred Securities to the extent that there are funds available in
the Trust. The Company currently believes that, taken as a whole, the Company
guarantee of Pogo Trust I's obligation under the Preferred Securities
constitutes a full and unconditional quarantee by the Company of Pogo Trust I's
performance obligation. The Company may cause the Trust to defer the payment of
distributions for successive periods up to 20 consecutive periods unless an
event of default on the Debentures has occurred and is continuing. During such
periods, accrued distributions on the Trust Preferred Securities will compound
quarterly and the Company will generally not be permitted to declare or pay
distributions on its common stock or debt securities that rank equal or junior
to the Debentures.
The Trust Preferred Securities are convertible at the option of the holder
at any time into common stock of the Company at the rate of 2.1053 shares of
Company common stock per Trust Preferred Security. This conversion rate will be
subject to adjustment to prevent dilution and is currently equivalent to a
conversion price of $23.75 per share of Company stock. The Trust Preferred
Securities are mandatorily redeemable upon maturity of the Debentures on June
1, 2029, or to the extent of any earlier redemption of any Debenture by the
Company and are callable by the Trust at any time after June 1, 2002. In
addition, if certain tax changes occur so that the Trust becomes subject to
federal income taxes or if interest payments made by the Company to the Trust
or the Debentures are no longer deductible for federal income tax purposes, the
Trust may liquidate and distribute Debentures to holders of the Trust Preferred
Securities and, in certain circumstances, the Company may shorten the stated
maturity of the Debentures to as early as June 2, 2014.
The amounts recorded in 2000 and 1999 under Minority Interests--Dividends
and costs associated with preferred securities of a subsidiary trust
principally reflect cumulative dividends and, to a lesser extent, the
amortization of issuance expenses related to the offering and sale of the Trust
Preferred Securities.
53
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Business Segment Information
At December 31, 1998, the Company adopted the Financial Accounting Standard
Board's Statement of Financial Accounting Standards No. 131 ("SFAS 131"),
Disclosures About Segments of an Enterprise and Related Information, which
established Standards for the way enterprises report information about
operating segments and related information. The Company has three reportable
segments, which are primarily in the business of natural gas and crude oil
exploration and production. The accounting policies of the segments are the
same as those described in the summary of significant policies. The Company
evaluates performance based on profit or loss from operations before income and
expense items incidental to oil and gas operations and income taxes. The
Company's reportable segments are managed separately because of their
geographical locations. Financial information by operating segment is presented
below:
Gains
Total Oil (Losses)
Company and Gas Pipelines & Other
-------- -------- --------- --------
(Expressed in thousands)
Long-Lived Assets:
As of December 31, 2000:
United States........................ $462,530 $454,246 $ 5,315 $ 2,969
Kingdom of Thailand.................. 337,317 334,018 -- 3,299
Canada............................... 11,807 11,576 -- 231
-------- -------- ------- -------
Total................................ $811,654 $799,840 $ 5,315 $ 6,499
======== ======== ======= =======
As of December 31, 1999:
United States........................ $440,914 $432,034 $ 5,450 $ 3,430
Kingdom of Thailand.................. 340,204 338,084 -- 2,120
Canada............................... 6,242 6,018 -- 224
-------- -------- ------- -------
Total................................ $787,360 $776,136 $ 5,450 $ 5,774
======== ======== ======= =======
Revenues:
For the year ended December 31, 2000
United States........................ $309,602 $291,266 $15,277 $ 3,059
Kingdom of Thailand.................. 182,965 183,060 -- (95)
Canada............................... 5,424 4,876 -- 548
-------- -------- ------- -------
Total................................ $497,991 $479,202 $15,277 $ 3,512
======== ======== ======= =======
For the year ended December 31, 1999
United States........................ $217,339 $172,683 $ 7,462 $37,194
Kingdom of Thailand.................. 54,444 54,480 -- (36)
Canada............................... 3,333 3,336 -- (3)
-------- -------- ------- -------
Total................................ $275,116 $230,499 $ 7,462 $37,155
======== ======== ======= =======
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
======== ======== ======= =======
Operating income (loss):
For the year ended December 31, 2000
United States........................ $ 86,996 $ 84,491 $ (554) $ 3,059
Kingdom of Thailand.................. 92,735 92,830 -- (95)
Canada............................... (88) (636) -- 548
-------- -------- ------- -------
Total................................ $179,643 $176,685 $ (554) $ 3,512
======== ======== ======= =======
For the year ended December 31, 1999
United States........................ $ 59,130 $ 21,564 $ 372 $37,194
Kingdom of Thailand.................. (3,491) (3,455) -- (36)
Canada............................... (1,647) (1,644) -- (3)
-------- -------- ------- -------
Total................................ $ 53,992 $ 16,465 $ 372 $37,155
======== ======== ======= =======
For the year ended December 31, 1998
United States........................ $(42,743) $(43,036) $ 289 $ 4
Kingdom of Thailand.................. (13,050) (13,254) -- 204
Canada............................... (1,427) (1,437) -- 10
-------- -------- ------- -------
Total................................ $(57,220) $(57,727) $ 289 $ 218
======== ======== ======= =======
54
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) 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. For purposes of comparison, 2000 sales have been presented for those
customers who have in either of the previous two years exceeded 10% of revenues
(expressed in thousands):
2000 1999 1998
------- ------- -------
Petroleum Authority of Thailand (PTT).................. $46,930 $24,315 $23,137
Enron Corp. and affiliates............................. $66,083 $10,911 $29,539
(7) Credit Risk
Substantially all of the Company's accounts receivable at December 31, 2000
and 1999, 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 2000 or 1999.
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
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.
(8) 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 ($10,500 for
2001), 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 seperate 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 Company are invested only in
common stock. The Company contributed $886,000 to the savings plan in 2000,
$963,000 in 1999, and $701,000 in 1998.
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
55
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(8) Employee Benefits--(Continued)
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 following table
sets forth the plans' status (in thousands of dollars) as of December 31, 2000
and 1999.
Post-Retirement
Retirement Plan Medical Plan
---------------- ----------------
2000 1999 2000 1999
------- ------- ------- -------
Change in benefit obligation
Benefit obligation at beginning of year.. $11,469 $13,849 $ 7,087 $ 6,284
Service cost............................ 1,012 1,177 441 489
Interest cost........................... 920 840 535 418
Participant contributions............... -- -- -- 5
Benefits paid........................... (1,568) (903) (105) (213)
Actuarial (gain) or loss................ 3,146 (3,494) 44 104
------- ------- ------- -------
Benefit obligation at end of year........ $14,979 $11,469 $ 8,002 $ 7,087
======= ======= ======= =======
Change in plan assets
Fair value of plan assets at beginning of
year.................................... $37,299 $37,404 $ -- $ --
Actual return on plan assets............ 2,967 1,075 -- --
Employer contributions.................. -- -- 105 208
Participant contributions............... -- -- -- 5
Benefits paid........................... (1,568) (903) (105) (213)
Administrative expenses................. (361) (277) -- --
------- ------- ------- -------
Fair value of plan assets at end of
year.................................... $38,337 $37,299 $ -- $ --
======= ======= ======= =======
Reconciliation of funded status
Funded status............................ $23,358 $25,830 $(8,002) $(7,087)
Unrecognized actuarial gain.............. (9,239) (14,307) (1,429) (1,544)
Unrecognized transition (asset) or
obligation.............................. (26) (129) 1,522 1,826
Unrecognized past service cost........... (170) (214) -- --
------- ------- ------- -------
Prepaid (accrued) benefit cost at year-
end..................................... $13,923 $11,180 $(7,909) $(6,805)
======= ======= ======= =======
Discount rate............................ 7.50% 7.75% 7.50% 7.75%
Expected return on plan assets........... 9.50% 9.50% -- --
Rate of compensation increase............ 4.75% 4.75% -- --
Components of net periodic benefit cost
Service cost............................. $ 1,012 $ 1,177 $ 441 $ 489
Interest cost............................ 920 840 535 418
Expected return on plan assets........... (3,534) (3,544) -- --
Amortization of prior service cost....... (43) (43) -- --
Amortization of transition (asset)
obligation.............................. (104) (103) 305 305
Recognized actuarial gain................ (994) (1,112) (72) (93)
------- ------- ------- -------
$(2,743) $(2,785) $ 1,209 $ 1,119
======= ======= ======= =======
56
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(8) Employee Benefits--(Continued)
For measurement purposes, a 10.6% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2001. The rate is assumed
to decrease gradually to 5% for 2005 and remain at that level thereafter.
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):
One Percentage
Point
-----------------
Increase Decrease
-------- --------
Effect on total of service and interest cost
components for 2000................................. $ 178 $(142)
Effect on year-end 2000 postretirement benefit
obligation.......................................... $1,200 $(985)
57
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) 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 option plans. Had compensation costs been determined based on
fair value at the grant dates for awards made in 2000, 1999, and 1998, the
Company's net income and earnings per share would have been reduced to the pro
forma amounts indicated below (in thousands of dollars, except per share
amounts):
2000 1999 1998
------- ------- --------
Income (loss) before cumulative
effect of change in accounting principle
As reported....................................... $89,023 $22,134 $(43,098)
Pro forma......................................... $86,091 $20,118 $(44,602)
Net income (loss)
As reported....................................... $87,255 $22,134 $(43,098)
Pro forma......................................... $86,091 $20,118 $(44,602)
Earnings (loss) per share:
Income (loss) before the cumulative
effect of change in accounting principle
As reported--Basic................................ $ 2.20 $ 0.55 $ (1.14)
Pro forma--Basic.................................. $ 2.16 $ 0.51 $ (1.19)
As reported--Diluted.............................. $ 2.16 $ 0.55 $ (1.14)
Pro forma--Diluted................................ $ 1.94 $ 0.51 $ (1.20)
Net income (loss)
As reported--Basic................................ $ 2.16 $ 0.55 $ (1.14)
Pro forma--Basic.................................. $ 2.12 $ 0.51 $ (1.19)
As reported--Diluted.............................. $ 1.95 $ 0.55 $ (1.14)
Pro forma--Diluted................................ $ 1.91 $ 0.51 $ (1.20)
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 2000, 1999 and 1998, respectively: risk free interest rates of 6.03%,
5.92% and 5.31%, expected volatility of 42.85%, 42.73% and 35.58%, dividend
yields of 0.59%, 0.63% and 0.64%, and an expected life of the options of 5
years in 2000, 5 years in 1999, and 4 years in 1998.
58
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Stock Option Plans--(Continued)
A summary of the status of the Company's plans as of December 31, 2000, 1999
and 1998, and changes during the years ended on those dates is presented below:
Weighted
Average
Number of Exercise
Options Price
--------- --------
Outstanding, December 31, 1997............................ 1,958,563 $25.13
Granted in 1998......................................... 985,659 $19.62
Exercised in 1998....................................... (145,317) $ 6.87
Canceled 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
Outstanding, December 31, 1998............................ 2,464,157 $19.37
Granted in 1999......................................... 676,900 $19.03
Exercised in 1999....................................... (130,275) $ 8.57
Canceled in 1999........................................ (5,167) $ 7.31
---------
Outstanding, December 31, 1999............................ 3,005,615 $19.78
=========
Exercisable, December 31, 1999............................ 1,607,395 $20.11
=========
Available for grant, December 31, 1999.................... 205,182
=========
Weighted-average fair value of options granted during
1999..................................................... $ 8.31
Outstanding, December 31, 1999............................ 3,005,615 $19.78
Granted in 2000......................................... 722,800 $20.58
Exercised in 2000....................................... (314,850) $15.33
Canceled in 2000........................................ (5,942) $13.32
---------
Outstanding, December 31, 2000............................ 3,407,623 $20.37
=========
Exercisable, December 31, 2000............................ 2,026,517 $20.72
=========
Available for grant, December 31, 2000.................... 932,677
=========
Weighted-average fair value of options granted during
2000..................................................... $ 9.58
The following table summarizes information about stock options outstanding
at December 31, 2000:
Options Outstanding Options Exercisable
-------------------------------- --------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Number Contractual Exercise Number Exercise
Range of Option Prices Outstanding Life (days) Price Exercisable Price
---------------------- ----------- ----------- -------- ----------- --------
$ 5.63 to $ 7.81........ 106,835 358 $ 6.47 106,835 $ 6.47
$ 12.31 to $ 12.72........ 6,001 2,879 $12.54 1,334 $12.31
$ 15.13 to $ 19.56........ 1,523,961 2,648 $18.64 956,624 $18.32
$ 20.28 to $ 24.81........ 1,555,735 2,660 $21.01 752,966 $21.72
$ 25.38 to $ 29.06........ 49,962 2,725 $25.73 43,629 $25.66
$ 30.23 to $ 33.94........ 30,962 1,979 $33.75 30,962 $33.75
$ 35.13 to $ 36.00........ 51,667 1,982 $35.97 51,667 $35.97
$ 40.62 to $ 44.00........ 82,500 2,354 $41.00 82,500 $41.00
--------- ---------
Total..................... 3,407,623 2,560 $20.37 2,026,517 $20.72
========= =========
59
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(10) 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 Equivalents
Fair value is carrying value.
Debt and Other
Instrument Basis of Fair Value Estimate
------------------------- -----------------------------------------------
Bank revolving credit Fair value is carrying value as of December 31,
agreement 1999 based on the market value interest rates.
Uncommitted credit lines Fair value is carrying value as of December 31,
with banks and banker's 1999 based on the market value interest rates.
acceptance loans
2007 Notes Fair value is 97% and 97.5%, of carrying
value as of December 31, 2000 and 1999,
respectively, based on quoted market values.
2009 Notes Fair value is 104.25% and 106%, of carrying
value as of December 31, 2000 and 1999,
respectively, based on quoted market values.
2006 Notes Fair value is 94.188% and 78.375%, of carrying
value as of December 31, 2000 and 1999,
respectively, based on quoted market values.
Minority interest in Fair value is 140.88% and 101.25%, of carrying
company obligated value as of December 31, 2000 and 1999,
preferred securities respectively, based on quoted market values.
of a subsidiary trust
The carrying value and estimated fair value of the Company's financial
instruments at December 31, 2000 and 1999 (in thousands of dollars) are as
follows:
2000 1999
-------------------- --------------------
Carrying Fair Carrying Fair
Value Value Value Value
--------- --------- --------- ---------
Cash and cash equivalents...... $ 81,510 $ 81,510 $ 6,267 $ 6,267
Debt:
Bank revolving credit
agreement................... -- -- $ (5,000) $ (5,000)
Uncommitted credit lines with
banks....................... -- -- $ (5,000) $ (5,000)
2007 Notes................... $(100,000) $ (97,000) $(100,000) $ (97,500)
2009 Notes $(150,000) $(156,375) $(150,000) $(159,000)
2006 Notes................... $(115,000) $(108,316) $(115,000) $ (90,131)
Minority interest in company
obligated mandatorily
redeemable preferred
securities of a subsidiary
trust, net of unamortized $(150,000) $(211,320) $(150,000) $(151,875)
issue expenses of............. $ 5,087 $ 5,087 $ 5,249 $ 5,249
The Company occasionally enters into hedging contracts to minimize the
impact of oil and gas price fluctuations. See Note 11 for a further discussion
of these contracts.
60
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(11) Hedging Activities
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"). In June 1999, the FASB issued SFAS 137,
Accounting for Derivative Instruments and Hedging Activities--Deferral of the
Effective Date of FASB Statement No. 133. In June 2000, the FASB issued SFAS
138, Accounting for Derivative Instruments and Hedging Activities, an amendment
of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair market
value. The statement requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge criteria are met.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting. The Company
adopted SFAS 133 effective January 1, 2001. Based on the nature of the
Company's derivative instruments currently outstanding and the historical
volatility of oil and gas commodity prices, the Company expects that SFAS 133
could increase volatility in the Company's earnings and other comprehensive
income for future periods.
SFAS 133, in part, allows special hedge accounting. SFAS 133 provides that
the effective portion of the gain or loss on a loss on a derivative instrument
designated and qualifying as a cash flow hedging instrument be reported as a
component of other comprehensive income and be reclassified into earnings in
the same period during which the hedged forecasted transaction affects
earnings. The remaining gain or loss on the derivative instrument, if any, must
be recognized currently in earnings.
Currently, the Company has hedged a portion of its forecasted production
using purchased put options. Under generally accepted accounting principles in
effect prior to SFAS 133, changes in the intrinsic value of such options are
recognized in earnings when the hedged production occurs and the premium paid
for the options is amortized into earnings over the option period on a
straight-line basis. In contrast, SFAS 133 effectively requires that changes in
the fair value of the option premium (the option's time value) be reported
currently in earnings with no offset. Based on existing implementation
guidelines issued by the FASB staff and the fair market value of the Company's
purchased options, the Company recorded a non-cash after-tax charge to earnings
of approximately $2,400,000 as the cumulative effect of adopting SFAS 133
effective January 1, 2001. The pre-tax cumulative effect represents the
difference between the unamortized premium paid for the options and the fair
value of the option's time value as of January 1, 2001.
Price Hedge Contracts--
As of December 31, 2000, the Company purchased options to sell 70 million
cubic feet of natural gas production per day for the period from April 1, 2001
through December 2002. These contracts give the Company the right, but not the
obligation, to sell natural gas at a sales price of $4.25 per MMBtu for the
period from April 2001 through March 2002 and $4.00 per MMBtu for the period
from April 2002 through December 2002. These contracts are designed to
guarantee the Company a minimum "floor" price for the contracted volumes of
production without limiting the Company's participation in price increases
during the covered period. The Company paid $24,022,000 in cash to enter into
these contracts. As of December 31, 2000, the Company was a party to the
following hedging arrangements:
61
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
NYMEX
Contract
Volume Price
in per Fair Market
Contract Period MMBtu(a) MMBtu(a) Value(b)
--------------- -------- -------- -----------
April 2001--March 2002........................ 25,550 $4.25 $ 6,930,000
April 2002--December 2002..................... 19,250 $4.00 $13,342,000
--------
(a) MMBtu means million British Thermal Units.
(b) Fair Market value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 2000.
These hedging transactions are settled based upon the average of the
reporting settlement prices on the NYMEX for the last three trading days or
occasionally, the penultimate trading day of a particular contract month. For
any particular floor transaction, the counter-party is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction. The Company is not required to make
any payment in connection with the settlement of a floor transaction.
As of December 31, 2000 the Company was not a party to any commodity price
hedging contracts with respect to any of its current or future crude oil and
condensate production.
62
POGO PRODUCING COMPANY & SUBSIDIARIES
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 pretax operating
results with adjustments for permanent differences.
Total United Kingdom of
Company States Thailand Canada Other(a)
--------- -------- ---------- ------- --------
(Expressed in thousands)
2000
-------------------------------------------------
Revenues.................... $ 479,202 $291,266 $183,060 $ 4,876 $ --
Lease operating expense..... (93,368) (58,916) (33,568) (884) --
Exploration expense......... (15,291) (6,532) (3,507) (856) (4,396)
Dry hole and impairment
expense.................... (28,608) (28,142) -- (466) --
Depreciation, depletion and
amortization expense....... (129,476) (76,516) (50,968) (1,992) --
--------- -------- -------- ------- -------
Pretax operating results.... 212,459 121,160 95,017 678 (4,396)
Income tax (expense)
benefit.................... (87,307) (41,059) (47,509) (278) 1,539
--------- -------- -------- ------- -------
Operating results........... $ 125,152 $ 80,101 $ 47,508 $ 400 $(2,857)
========= ======== ======== ======= =======
--------
(a) Included in Other are costs associated with initial activities related to
Hungary of $3,396, the British sector of the North Sea of $836, and the
Danish sector of the North Sea of $164.
1999
-------------------------------------------------
Revenues.................... $ 230,499 $172,683 $ 54,480 $ 3,336 $ --
Lease operating expense..... (69,816) (46,341) (21,815) (1,660) --
Exploration expense......... (5,982) (4,147) (1,682) (153) --
Dry hole and impairment
expense.................... (4,594) (4,259) -- (335) --
Depreciation, depletion and
amortization expense....... (102,265) (73,886) (27,174) (1,205) --
--------- -------- -------- ------- -------
Pretax operating results.... 47,842 44,050 3,809 (17) --
Income tax (expense)
benefit.................... (16,315) (14,418) (1,905) 8 --
--------- -------- -------- ------- -------
Operating results........... $ 31,527 $ 29,632 $ 1,904 $ (9) $ --
========= ======== ======== ======= =======
1998
-------------------------------------------------
Revenues.................... $ 200,154 $163,438 $ 35,445 $ 1,271 $ --
Lease operating expense..... (68,883) (47,294) (20,913) (676) --
Exploration expense......... (9,802) (8,831) (293) (678) --
Dry hole and impairment
expense.................... (41,736) (41,736) -- -- --
Depreciation, depletion and
amortization expense....... (109,288) (85,969) (22,753) (566) --
--------- -------- -------- ------- -------
Pretax operating results.... (29,555) (20,392) (8,514) (649) --
Income tax benefit.......... 11,916 7,399 4,257 260 --
--------- -------- -------- ------- -------
Operating results........... $ (17,639) $(12,993) $ (4,257) $ (389) $ --
========= ======== ======== ======= =======
63
POGO PRODUCING COMPANY & SUBSIDIARIES
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 Other(a)
-------- -------- ---------- ------- --------
Costs incurred (capitalized
unless otherwise indicated):
2000:
Property acquisition
Proved.................... $ 8,393 $ 8,393 -- -- --
Unproved.................. 11,213 7,602 1,882 1,729 --
Exploration
Capitalized............... 36,588 23,978 7,518 5,092 --
Expensed.................. 15,291 6,532 3,507 856 4,396
Development................. 108,991 71,621 36,034 1,336 --
Interest.................... 20,918 5,446 15,472 -- --
-------- -------- -------- ------- ------
Total oil and gas costs
incurred................... $201,394 $123,572 $ 64,413 $ 9,013 $4,396
======== ======== ======== ======= ======
Provision for depreciation,
depletion and amortization..... $129,476 $ 76,516 $ 50,968 $ 1,992 $ --
======== ======== ======== ======= ======
--------
(a) Included in the expensed exploration costs reflected in Other are costs
associated with initial activities related to Hungary of $3,396, the
British sector of the North Sea of $836, and the Danish sector of the North
Sea of $164.
1999:
Property acquisition
Proved.................... $ 19,532 $ 19,532 $ -- $ -- $ --
Unproved.................. 7,129 6,506 -- 623 --
Exploration
Capitalized............... 20,263 15,448 3,500 1,315 --
Expensed.................. 5,982 4,147 1,682 153 --
Development................. 150,096 54,204 95,163 729 --
Interest.................... 17,733 6,599 11,134 -- --
-------- -------- -------- ------- ------
Total oil and gas costs
incurred................... $220,735 $106,436 $111,479 $ 2,820 $ --
======== ======== ======== ======= ======
Provision for depreciation,
depletion and amortization..... $102,265 $ 73,886 $ 27,174 $ 1,205 $ --
======== ======== ======== ======= ======
1998:
Property acquisition
Proved.................... $139,346 $133,474 $ -- $ 5,872 $ --
Unproved.................. 10,557 10,557 -- -- --
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 -- --
-------- -------- -------- ------- ------
Total oil and gas costs
incurred................... $362,269 $244,808 $107,461 $10,000 $ --
======== ======== ======== ======= ======
Provision for depreciation,
depletion and amortization..... $109,288 $ 85,969 $ 22,753 $ 566 $ --
======== ======== ======== ======= ======
64
POGO PRODUCING COMPANY & SUBSIDIARIES
UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(Continued)
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.
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, 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
Revisions of previous
estimates.................... 7,274,136 8,922,125 (1,634,802) (13,187)
Extensions, discoveries and
other additions.............. 8,673,230 2,647,306 5,797,988 227,936
Purchase of properties........ 3,698,016 3,698,016 -- --
Sale of properties............ (1,690,467) (1,690,467) -- --
Estimated 1999 production..... (6,688,062) (5,232,860) (1,318,451) (136,751)
----------- ---------- ---------- --------
Proved Reserves as of December
31, 1999....................... 78,776,417 41,553,662 36,655,697 567,058
Revisions of previous
estimates.................... 2,335,209 2,561,793 (480,335) 253,751
Extensions, discoveries and
other additions.............. 24,741,720 19,115,830 5,546,923 78,967
Purchase of properties........ 23,657 23,657 -- --
Sale of properties............ (205,506) (205,506) -- --
Estimated 2000 production..... (10,350,000) (5,571,000) (4,657,000) (122,000)
----------- ---------- ---------- --------
Proved Reserves as of December
31, 2000....................... 95,321,497 57,478,436 37,065,285 777,776
=========== ========== ========== ========
Proved Developed Reserves as of:
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
December 31, 1999............. 53,894,653 35,136,156 18,407,852 350,645
December 31, 2000............. 60,656,634 35,132,295 24,746,563 777,776
65
POGO PRODUCING COMPANY & SUBSIDIARIES
UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(Continued)
Estimates of Proved Reserves
Natural Gas (MMcf)
Total United Kingdom of
Company States Thailand Canada
------- ------- ---------- ------
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
Revisions of previous estimates......... 7,704 27,327 (17,617) (2,006)
Extensions, discoveries and other
additions.............................. 61,717 44,563 16,991 163
Purchase of properties.................. 7,060 7,060 -- --
Sale of properties...................... (90,164) (90,164) -- --
Estimated 1999 production............... (51,788) (37,012) (14,175) (601)
------- ------- ------- ------
Proved Reserves as of December 31, 1999... 374,698 220,129 153,588 981
Revisions of previous estimates......... (2,245) 3,110 (5,518) 163
Extensions, discoveries and other
additions.............................. 56,372 28,623 26,605 1,144
Purchase of properties.................. 2,601 2,601 -- --
Sale of properties...................... (1,195) (1,195) -- --
Estimated 2000 production............... (60,248) (38,647) (21,371) (230)
------- ------- ------- ------
Proved Reserves as of December 31, 2000... 369,983 214,621 153,304 2,058
======= ======= ======= ======
Proved Developed Reserves as of:
December 31, 1997....................... 239,732 179,972 59,760 --
December 31, 1998....................... 225,054 181,205 40,424 3,425
December 31, 1999....................... 245,257 156,398 88,041 818
December 31, 2000....................... 239,978 150,684 87,236 2,058
66
POGO PRODUCING COMPANY & SUBSIDIARIES
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)
2000
---------------------------------------------
Future gross revenues........... $ 4,926,262 $3,624,205 $1,250,223 $ 51,834
Future production costs:
Lease operating expense....... (1,043,108) (550,020) (473,022) (20,066)
Future development and
abandonment costs.............. (316,467) (196,308) (119,476) (683)
----------- ---------- ---------- --------
Future net cash flows before
income taxes................... 3,566,687 2,877,877 657,725 31,085
Discount at 10% per annum....... (1,111,771) (952,332) (151,704) (7,735)
----------- ---------- ---------- --------
Discounted future net cash flow
before income taxes............ 2,454,916 1,925,545 506,021 23,350
Future income taxes, net of
discount at 10% per annum...... (739,740) (597,811) (135,391) (6,538)
----------- ---------- ---------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and gas reserves............... $ 1,715,176 $1,327,734 $ 370,630 $ 16,812
=========== ========== ========== ========
1999
---------------------------------------------
Future gross revenues........... $ 2,752,682 $1,511,517 $1,225,327 $ 15,838
Future production costs:
Lease operating expense....... (744,848) (408,533) (332,786) (3,529)
Future development and
abandonment costs.............. (301,148) (163,862) (136,684) (602)
----------- ---------- ---------- --------
Future net cash flows before
income taxes................... 1,706,686 939,122 755,857 11,707
Discount at 10% per annum....... (552,040) (363,286) (186,263) (2,491)
----------- ---------- ---------- --------
Discounted future net cash flow
before income taxes............ 1,154,646 575,836 569,594 9,216
Future income taxes, net of
discount at 10% per annum...... (285,963) (127,207) (159,126) 370
----------- ---------- ---------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and gas reserves............... $ 868,683 $ 448,629 $ 410,468 $ 9,586
=========== ========== ========== ========
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
=========== ========== ========== ========
67
POGO PRODUCING COMPANY & SUBSIDIARIES
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 escalation's 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, 2000
-------------------------------------------
Total United Kingdom of
Company States Thailand Canada
---------- ---------- ---------- -------
(Expressed in thousands)
Beginning balance................ $ 868,683 $ 448,629 $ 410,468 $ 9,586
Revisions to prior years' proved
reserves:
Net changes in prices and
production costs.............. 817,201 839,536 (26,592) 4,257
Net changes due to revisions in
quantity estimates............ 55,574 63,945 (13,759) 5,388
Net changes in estimates of
future development costs...... (22,657) (43,119) 21,527 (1,065)
Accretion of discount.......... 115,465 57,584 56,959 922
Changes in production rate and
other......................... 110,717 125,761 (13,029) (2,015)
---------- ---------- --------- -------
Total revisions.............. 1,076,300 1,043,707 25,106 7,487
New field discoveries and
extensions, net of future
production and development
costs........................... 494,689 460,239 25,147 9,303
Purchases of properties.......... 11,135 11,135 -- --
Sales of properties.............. (5,712) (5,712) -- --
Sales of oil and gas produced,
net of production costs......... (385,834) (232,350) (149,492) (3,992)
Previously estimated development
costs incurred.................. 109,692 72,690 35,666 1,336
Net change in income taxes....... (453,777) (470,604) 23,735 (6,908)
---------- ---------- --------- -------
Net change in standardized
measure of discounted
future net cash flows..... 846,493 879,105 (39,838) 7,226
---------- ---------- --------- -------
Ending balance................... $1,715,176 $1,327,734 $ 370,630 $16,812
========== ========== ========= =======
68
POGO PRODUCING COMPANY & SUBSIDIARIES
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--Unaudited--(Continued)
Year Ended December 31, 1999
-----------------------------------------
Total United Kingdom of
Company States Thailand Canada
--------- --------- ---------- -------
(Expressed in thousands)
Beginning balance.................. $ 422,721 $ 266,811 $ 148,465 $ 7,445
Revisions to prior years' proved
reserves:
Net changes in prices and
production costs................ 481,570 246,516 228,424 6,630
Net changes due to revisions in
quantity estimates.............. 82,304 127,719 (40,328) (5,087)
Net changes in estimates of
future development costs........ (61,267) (19,920) (40,470) (877)
Accretion of discount............ 49,523 28,931 20,060 532
Changes in production rate and
other........................... 37,017 5,429 30,583 1,005
--------- --------- --------- -------
Total revisions................ 589,147 388,675 198,269 2,203
New field discoveries and
extensions, net of future
production and development costs.. 177,822 66,956 108,230 2,636
Purchases of properties............ 29,421 29,421 -- --
Sales of properties................ (128,555) (128,555) -- --
Sales of oil and gas produced, net
of production costs............... (160,683) (126,342) (32,665) (1,676)
Previously estimated development
costs incurred.................... 152,268 56,376 95,163 729
Net change in income taxes......... (213,458) (104,713) (106,994) (1,751)
--------- --------- --------- -------
Net change in standardized
measure of discounted future
net cash flows.............. 445,962 181,818 262,003 2,141
--------- --------- --------- -------
Ending balance..................... $ 868,683 $ 448,629 $ 410,468 $ 9,586
========= ========= ========= =======
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
========= ========= ========= =======
69
Quarterly Results--Unaudited
Summaries of the Company's results of operations by quarter for the years
2000 and 1999 are as follows:
Quarter Ended
----------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
(Expressed in thousands, except per
share amounts)
2000, As Restated (a):
Revenues.............................. $100,918 $108,020 $129,082 $159,971
Gross profit (b)...................... $ 35,092 $ 44,274 $ 60,716 $ 74,223
Income before cumulative effect of
change in accounting principle....... $ 10,151 $ 16,791 $ 26,182 $ 35,899
Cumulative effect of change in
accounting principle................. $ (1,768) $ -- $ -- $ --
Net income............................ $ 8,383 $ 16,791 $ 26,182 $ 35,899
Earnings (loss) per share (c):
Basic
Income before cumulative effect of
change in accounting principle... $ 0.25 $ 0.42 $ 0.65 $ 0.88
Cumulative effect of change in
accounting principle............. $ (0.04) -- -- --
Net income........................ $ 0.21 $ 0.42 $ 0.65 $ 0.88
Diluted
Income before cumulative effect of
change in accounting principle... $ 0.25 $ 0.39 $ 0.58 $ 0.76
Cumulative effect of change in
accounting principle............. $ (0.04) -- -- --
Net income........................ $ 0.21 $ 0.39 $ 0.58 $ 0.76
2000, As Reported (a):
Revenues.............................. $105,499 $111,997 $129,834
Gross profit (b)...................... $ 38,703 $ 47,310 $ 62,142
Net income............................ $ 11,956 $ 18,309 $ 26,895
Earnings per share (c):
Basic............................... $ 0.30 $ 0.45 $ 0.67
Diluted............................. $ 0.29 $ 0.42 $ 0.59
1999
Revenues.............................. $ 76,046 (d) $ 44,828 $ 69,138 $ 85,104
Gross profit (b)...................... $ 33,987 $ 5,116 $ 18,912 $ 25,842
Net income (loss)..................... $ 14,313 $ (3,006) $ 2,737 $ 8,090
Earnings (loss) per share (c):
Basic............................... $ 0.36 $ (0.07) $ 0.07 $ 0.20
Diluted............................. $ 0.36 $ (0.07) $ 0.07 $ 0.20
--------
(a) The first three quarters of 2000 have been restated to give effect to the
change in accounting for the evaluation of the company's crude oil
inventories from net realizable value to the lower of cost or net
realizable value. Refer to footnote 1, Summary of Significant Accounting
Policies, Inventory--Product for additional information.
(b) Represents revenues less lease operating, pipeline operating and natural
gas purchases, exploration, dry hole, and impairment, and depreciation,
depletion and amortization expenses.
(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 income or loss for that quarter and the
weighted average number of common shares outstanding during that period.
(d) Revenues for the first quarter of 1999 include $37,344,000 related to
gains on the sales of properties.
70
ITEM 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure.
None
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 24, 2001,
to be filed within 120 days of December 31, 2000 pursuant to Regulation 14A
under the Securities Exchange Act of 1934, as amended (the Company's "2001
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 2001 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 2001 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 2001 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................................. 38
Consolidated statements of income........................................ 39
Consolidated balance sheets.............................................. 40
Consolidated statements of cash flows.................................... 42
Consolidated statements of shareholders' equity.......................... 43
Notes to consolidated financial statements............................... 44
Unaudited supplementary financial data................................... 63
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:
*2.1 Agreement and Plan of Merger dated as of November 19, 2000 among Pogo
Producing Company, NORIC Corporation, and the shareholders signatory
thereto (Exhibit 99.1, Current Report on Form 8-K filed November 21,
2000, File No. 1-7792).
*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 Second Amendment dated July 16, 1999, 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, Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999, File No. 1-7792).
*4.4 Fourth Amendment dated May 3, 2000, 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, Quarterly Report on
Form 10-Q for the quarter ended June 30, 2000, File No. 1-7792).
*4.5 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).
*4.6 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).
*4.7 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).
*4.8 Amended and Restated Declaration of Trust of Pogo Trust I dated as of
June 2, 1999 (Exhibit 4.1, Current Report on Form 8-K, filed June 2,
1999, File No. 1-7792).
*4.9 Junior Subordinated Indenture dated as of June 1, 1999, between Pogo
Producing Company and Wilmington Trust Company, as Trustee (Exhibit 4.3,
Current Report on Form 8-K, filed June 2, 1999, File No. 1-7792).
*4.10 Supplemental Indenture No. 1 dated as of June 1, 1999 to Junior
Subordinated Indenture dated as of June 1, 1999, between Pogo Producing
Company and Wilmington Trust Company, as Trustee (Exhibit 4.4, Current
Report on Form 8-K, filed June 2, 1999, File No. 1-7792).
*4.11 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).
*4.12 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).
Other instruments defining the rights of holders of long-term debt of
Pogo Producing Company and its subsidiaries are not being filed because
the total amount of securities authorized by such instruments does not
exceed 10% of the total assets of Pogo Producing Company and its
subsidiaries on a consolidated basis as of December 31, 2000. Pogo
Producing Company hereby agrees to furnish to the Commission a copy of
any such debt instrument upon request.
72
Executive Compensation Plans and Arrangements (comprising Exhibits 10.1
through 10.42, 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 (Exhibit 10.5, Annual Report on Form 10-K
for the year ended December 31, 1999, File No. 001-7792).
*10.6 2000 Incentive Plan (Exhibit B) to the Company's Definitive Proxy
Statement filed on Schedule 14A, March 27, 2000, File No. 001-7792).
*10.7 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).
*10.8 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Stuart P. Burbach, dated effective
February 1, 1999 (Exhibit 10.7, Annual Report on Form 10-K for the year
ended December 31, 1999, File No. 001-7792).
*10.9 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Stuart P. Burbach, dated effective
February 1, 2000 (Exhibit 10.8, Annual Report on Form 10-K for the year
ended December 31, 2000, File No. 001-7792).
10.10 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Stuart P. Burbach, dated effective
February 1, 2001.
*10.11 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).
*10.12 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Jerry A. Cooper, dated effective
February 1, 1999 (Exhibit 10.9, Annual Report on Form 10-K for the year
ended December 31, 1999, File No. 001-7792).
*10.13 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Jerry A. Cooper, dated effective
February 1, 2000 (Exhibit 10.11, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.14 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Jerry A. Cooper, dated effective
February 1, 2001.
*10.15 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).
*10.16 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and R. Phillip Laney, dated effective
February 1, 1999 (Exhibit 10.12, Annual Report on Form 10-K for the
year ended December 31, 1999, File No. 001-7792).
*10.17 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and R. Phillip Laney, dated effective
February 1, 2000 (Exhibit 10.17, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
73
10.18 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and R. Phillip Laney, dated effective
February 1, 2001.
*10.19 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).
*10.20 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and John O. McCoy, Jr., dated effective
February 1, 1999 (Exhibit 10.15, Annual Report on Form 10-K for the
year ended December 31, 1999, File No. 001-7792).
*10.21 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and John O. McCoy, dated effective
February 1, 2000 (Exhibit 10.20, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.22 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and John O. McCoy, dated effective
February 1, 2001.
10.23 Executive Employment Agreement by and between Pogo Producing Company
and Paul G. Van Wagenen, dated February 1, 2001.
*10.24 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).
*10.25 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Bruce E. Archinal, dated effective
February 1, 1999 (Exhibit 10.19, Annual Report on Form 10-K for the
year ended December 31, 1999, File No. 001-7792).
*10.26 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Bruce E. Archinal, dated effective
February 1, 2000 (Exhibit 10.26, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.27 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Bruce E. Archinal, dated effective
February 1, 2001.
*10.28 Executive Employment Agreement by and between Pogo Producing Company
and David R. Beathard, dated as of February 1, 1999 (Exhibit 10.20,
Annual Report on Form 10-K for the year ended December 31, 1999, File
No. 001-7792).
*10.29 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and David R. Beathard, dated effective
February 1, 2000 (Exhibit 10.28, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.30 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and David R. Beathard, dated effective
February 1, 2001.
*10.31 Executive Employment Agreement by and between Pogo Producing Company
and Stephen R. Brunner, dated as of February 1, 1999 (Exhibit 10.21,
Annual Report on Form 10-K for the year ended December 31, 1999, File
No. 001-7792).
*10.32 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Stephen R. Brunner, dated effective
February 1, 2000 (Exhibit 10.30, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.33 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Stephen R. Brunner, dated effective
February 1, 2001.
*10.34 Executive Employment Agreement by and between Pogo Producing Company
and J. D. McGregor, dated as of February 1, 1999 (Exhibit 10.22, Annual
Report on Form 10-K for the year ended December 31, 1999, File No. 001-
7792).
74
*10.35 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and J. D. McGregor, dated effective
February 1, 2000 (Exhibit 10.32, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.36 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and J. D. McGregor, dated effective
February 1, 2001.
*10.37 Executive Employment Agreement by and between Pogo Producing Company
and Gerald A. Morton, dated as of February 1, 1999 (Exhibit 10.23,
Annual Report on Form 10-K for the year ended December 31, 1999, File
No. 001-7792).
*10.38 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Gerald A. Morton, dated effective
February 1, 2000 (Exhibit 10.34, Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 001-7792).
10.39 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and Gerald A. Morton, dated effective
February 1, 2001.
*10.40 Executive Employment Agreement by and between Pogo Producing Company
and James P. Ulm, II, dated as of February 1, 2000 (Exhibit 10.35,
Annual Report on Form 10-K for the year ended December 31, 2000, File
No. 001-7792).
10.41 Extension Agreement to Continue Executive Employment Agreement by and
between Pogo Producing Company and James P. Ulm II, dated effective
February 1, 2001.
*10.42 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).
*10.43 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 (Exhibit 10.26, Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 001-7792).
*10.44 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 (Exhibit 10.27, Annual Report
on Form 10-K for the year ended December 31, 1999, File No. 001-7792).
*10.45 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).
*10.46 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 (Exhibit 21, Annual
Report on Form 10-K for the year ended December 31, 1999, File No. 001-
7792).
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,
2000.
--------
* Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K
(1) Current Report on Form 8-K filed on November 20, 2000, regarding Item
9. Regulation FD Disclosure.
(2) Current Report on Form 8-K filed on November 20, 2000, regarding Item
5. Other Events.
(3) Current Report on Form 8-K filed on November 21, 2000, regarding Item
7. Financial Statements and Exhibits.
(4) Current Report on Form 8-K filed on November 27, 2000, regarding Item
5. Other Events.
75
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)
/s/ Paul G. Van Wagenen
By:__________________________________
Paul G. Van Wagenen
Chairman of the Board, President and
Chief Executive Officer
Date: March 2, 2001
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 March 2, 2001.
Signatures Title
---------- -----
/s/ Paul G. Van Wagenen Principal Executive Officer and
______________________________________ Director
Paul G. Van Wagenen
Chairman of the Board, President and
Chief Executive Officer
/s/ James P. Ulm, II Principal Financial Officer
______________________________________
James P. Ulm, II
Vice President and Chief Financial
Officer
/s/ Thomas E. Hart Principal Accounting Officer
______________________________________
Thomas E. Hart
Vice President and Chief Accounting
Officer
* Director
______________________________________
Jerry M. Armstrong
* Director
______________________________________
Jack S. Blanton
* Director
______________________________________
W. M. Brumley, Jr.
* Director
______________________________________
Robert H. Campbell
* Director
______________________________________
William L. Fisher
* Director
______________________________________
Gerrit W. Gong
* Director
______________________________________
Frederick A. Klingenstein
* Director
______________________________________
Stephen A. Wells
/s/ Thomas E. Hart
*By:_____________________________
Thomas E. Hart
Attorney-in-Fact
76