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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                            ------------------------

                                   FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
   SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999

[ ] 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)

<TABLE>
<S>                              <C>
           DELAWARE                        74-1659398
(STATE OR OTHER JURISDICTION OF         (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION)         IDENTIFICATION NO.)
5 GREENWAY PLAZA, P.O. BOX 2504
        HOUSTON, TEXAS                     77252-2504
(ADDRESS OF PRINCIPAL EXECUTIVE
            OFFICES)                       (ZIP CODE)
</TABLE>

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 297-5000
          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

<TABLE>
<CAPTION>
                                                       NAME OF EACH EXCHANGE
           TITLE OF EACH CLASS:                         ON WHICH REGISTERED:
           --------------------                        ---------------------
<S>                                          <C>
        COMMON STOCK, $1 PAR VALUE                    NEW YORK STOCK EXCHANGE
                                                          PACIFIC EXCHANGE

      PREFERRED STOCK PURCHASE RIGHTS                 NEW YORK STOCK EXCHANGE
                                                          PACIFIC EXCHANGE

 POGO TRUST I 6 1/2% CUMULATIVE QUARTERLY             NEW YORK STOCK EXCHANGE
 INCOME CONVERTIBLE PREFERRED SECURITIES,
                 SERIES A
</TABLE>

          SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
            5 1/2% CONVERTIBLE SUBORDINATED NOTES DUE JUNE 15, 2006
                            ------------------------

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes  [X] No  [ ].

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [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 $690,675,734 as of March 16, 2000 (based on $25.875 per share, the
last sale price of the Common Stock as reported on the New York Stock Exchange
Composite Tape on such date).

     40,348,775 shares of the registrant's Common Stock were outstanding as of
March 16, 2000.

                       DOCUMENT INCORPORATED BY REFERENCE

     Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 25, 2000 (to be filed not later than
120 days after December 31, 1999) are incorporated by reference in Part III of
this Form 10-K.

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<PAGE>   2

                           FORWARD LOOKING STATEMENTS

     The statements included or incorporated by reference in this Report on Form
10-K for the year ended December 31, 1999 (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

     - uncertainties associated with the United States and worldwide economies

     - current and potential governmental regulatory actions in countries where
       the Company owns an interest

     - substantial competitor production increases resulting in oversupply and
       declining prices

     - the Company's ability to implement cost reductions

     - 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

     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.

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                              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, 1999, the Company had interests in
102 lease blocks offshore Louisiana and Texas, approximately 340,047 gross acres
onshore in the United States and Canada, approximately 734,140 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.

     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 27% of the Company's proved reserves were located as
of December 31, 1999. During 1999, approximately 51% of the Company's natural
gas production and approximately 42% of its oil and condensate production was
from its domestic offshore properties, contributing approximately 45% of the
Company's consolidated oil and gas revenues. Although the Company's operations
were historically focused in shallower waters of the Outer Continental Shelf,
the Company has recently expanded its exploration efforts further offshore into
deeper waters where the Company currently believes the opportunities for
discovering substantial quantities of oil and gas exist. As of December 31,
1999, the Company has interests in 18 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 1999 were approximately $56,900,000 (excluding approximately $1,500,000 of
net property acquisitions), or 16% lower than the Company's domestic offshore
capital and exploration expenditures of approximately $68,000,000 for 1998
(excluding approximately $5,000,000 of net property acquisitions) and 34% lower
than the Company's domestic offshore capital and exploration expenditures of
approximately $86,300,000 (exclud-

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<PAGE>   4

ing approximately $900,000 of net property acquisitions) for 1997. The decrease
in the Company's domestic offshore capital and exploration expenditures for
1999, compared with 1998 and 1997, resulted primarily from the Company's
decision to decrease its exploration drilling and workover and recompletion
activity in light of poor oil and gas prices in the first half of the year. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." The Company maintains a significant presence in the Gulf of Mexico
where it participated in drilling 15 successful wells during 1999, bringing the
total number of producing oil and gas wells in the Gulf of Mexico that the
Company held an interest to 211 at December 31, 1999.

     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 32 of the 102 offshore leases in which it had an interest on December 31,
1999.

     Platforms and related facilities are installed on an offshore lease block
when, in the judgment of the lease interest owners, the necessary capital
expenditures are justified. A decision to install a platform generally is made
after the drilling of one or more exploratory wells with contracted drilling
equipment. Platform costs vary depending on, among other factors, the number of
slots, water depth, currents, and sea floor conditions. Over the five years
ended December 31, 1999, the 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. Wells, platforms and related facilities are typically
much more expensive in the deeper waters of the Gulf of Mexico. The Company has
participated in the construction of one platform and related facilities on its
deep water block at Viosca Knoll Block 823 at a total capital commitment of
approximately $142,500,000 ($15,390,000 net to the Company's working interest).
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 participated in one subsea completion development during
1999 at Garden Banks Block 367, at a gross cost of approximately $26,000,000
($6,500,000 net to the Company's working interest). The Company is currently
planning to commence construction of at least one additional subsea development
during 2000. 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. In order to better manage the risks of large projects in the
deep water Gulf of Mexico, the Company generally seeks to have a smaller
ownership interest in these lease blocks than it averages in shallower waters.

  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, 1999, the Company owned interests in 96 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 1999, the Company was successful in acquiring
interests in three 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

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<PAGE>   5

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, 1999,
accounted for approximately 29% of the Company's total proved reserves. During
1999, approximately 22% of the Company's natural gas production and 36% of its
oil and condensate production was from its onshore properties, contributing
approximately 27% of the Company's consolidated oil and gas revenues.

  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 409 wells
in the Permian Basin and West Texas areas through December 31, 1999, including
20 wells in 1999. The Company believes that during the past seven 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 113,000 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.

     In Southwest Louisiana, the Company participated in drilling 23 wells since
1996, including three wells in 1999, 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 is currently participating in a 3-D seismic
survey covering approximately 39,000 acres in Southwest Louisiana that should be
completed late in the second quarter of 2000.

     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 $25,700,000 (excluding approximately $25,100,000 of net property
acquisitions) for 1999, or 47% lower 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 Petroleum Inc. ("Arch")) for 1998 and 57%
lower than the Company's onshore capital and exploration expenditures of
approximately $60,000,000 (excluding approximately $1,700,000 of net property
acquisitions) for 1997. The decrease in the Company's onshore capital and
exploration expenditures for 1999, compared to 1998 and 1997, resulted primarily
from the Company's decision to curtail non-essential drilling in light of poor
oil and gas prices and to focus on workover and recompletion work, that was not
entirely offset by increased capital and exploration expenditures in Canada
where the Company acquired its interest in Pogo Canada Ltd. in August 1998.

                                        4
<PAGE>   6

  Lease Acquisitions

     As it has in recent years, in 1999 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, 1999, the Company held interests in approximately 340,000 gross
(186,000 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. Currently, the
Company maintains an office in Bangkok, Thailand from which it oversees its
operations on the Thailand Concession through its wholly-owned subsidiary Thaipo
Limited ("Thaipo"). Thaipo currently owns, directly or indirectly, a 46.34%
working interest in the entire Thailand Concession. The remainder of the working
interest is owned, directly or indirectly by 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. Effective October 1, 1999, Thaipo turned over operatorship
of the Thailand Concession to Chevron. 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, 1999, the Company's proved reserves located in the Kingdom of
Thailand accounted for approximately 44% of the Company's total proved reserves.
During 1999, approximately 28% of the Company's natural gas production and 22%
of its oil and condensate production came from its operations on the Thailand
Concession, contributing approximately 24% of the Company's consolidated oil and
gas revenues.

  Exploration and Development

     The Company's international capital and exploration expenditures were
approximately $111,500,000 for 1999, or 4% higher than the Company's
international capital and exploration expenditures of approximately $107,400,000
for 1998 and 26% higher than the Company's international capital and exploration
expenditures of approximately $88,300,000 (excluding approximately $28,600,000
of net property acquisitions) for 1997. The increase in the Company's
international capital and exploration expenditures for 1999, compared to 1998,
resulted primarily from increased exploration expenditures and development
drilling in the Tantawan and Benchamas Fields that was not entirely offset by a
decrease in exploration drilling expenditures and in spending related to
platform and facilities construction for the Benchamas Field. The increase in
the Company's international capital and exploration expenditures for 1999,
compared to 1997, resulted primarily from increased platform and facilities
construction costs related to development of the Benchamas Field and, to a
lesser extent, increased drilling activity in the Tantawan and Benchamas Fields
in 1999, as compared to 1997. Substantially all of the Company's international
capital and exploration expenditures for 1999 were related to the Company's
license in the Kingdom of Thailand.

  Thailand Concession

     Benchamas Field. In July 1997, the government of Thailand designated
another portion of the Thailand Concession comprising approximately 102,000
acres as the Benchamas and Pakakrong production area or the "Benchamas Field."
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. The Company currently
expects to complete drilling the first phase of the Benchamas Field development
during the first quarter of 2000. The phase I field development plans provide

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for 55 wells in the field, including 38 producing wells (14 of which will be
horizontal wells) and 17 water injection wells. Current Benchamas Field
development plans also call for the commencement of design and fabrication work
on three more platforms for 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. A fifth platform was installed and
commenced production in 1999. Currently, there are 37 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."

     Other Portions of the Thailand Concession. In September 1997, the
government of Thailand designated an additional 91,000 acres of the Thailand
Concession as the Maliwan production area. Development plans for this concession
area are currently under way. One additional well was drilled in this area
during 1999 and additional wells are planned for 2000. In addition, Thaipo and
its joint venture partners have identified other potentially promising areas on
the Thailand Concession. In February 2000, the Company and its joint venture
partners submitted an application to have up to approximately 120,000 additional
acres of the concession, known as the North Jarmjuree area, designated as a
production area. Through February 1, 2000, Thaipo and its joint venture partners
have drilled ten wells on areas of the Thailand Concession that are not
currently designated as production areas. Interpretation of the data provided by
these wells and 3-D seismic data covering these areas is ongoing. Thaipo and its
joint venture partners also currently plan to drill additional exploration wells
in these areas during 2000.

     Platforms are installed on the Thailand Concession in fields where, in the
judgment of Thaipo and its joint venture partners, the necessary capital
expenditures are justified. A decision to install a platform generally is made
after the drilling of one or more exploratory wells with contracted drilling
equipment and the area where the platform would be located has been designated a
production area by the government of the Kingdom of Thailand. See
"-- Contractual Terms Governing the Thailand Concession and Related Production."
Platforms are used to accommodate both development drilling and additional
exploratory drilling. Over the four years ended December 31, 1999, 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
have averaged approximately $20,000,000 per platform. The Company and its joint
venture partners have been working to employ advanced platform facility design
and advanced drilling and completion techniques, including slimhole, batch and
horizontal drilling, to reduce the cost of developing the Thailand Concession.
The Company believes that future satellite platforms and related facilities may
be installed for as little as approximately $15,000,000 per platform in the
future. Platform costs vary and more (or less) expensive platforms could be
required in the future depending on, among other factors, the number of slots,
water depth, currents and sea floor conditions.

  Other Areas of the World

     On December 1, 1998, 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 will involve the
acquisition, processing and interpretation of 3-D seismic data over the block.
The initial exploratory term of this license expires on December 1, 2004, unless
otherwise extended or a production license is granted.

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     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 initial term of the license goes through
June 14, 2004, unless otherwise extended or a production license is granted.
However, a "drill or drop" election must be made by the concessionaires prior to
December 31, 2000.

     On April 20, 1999, the Company's subsidiary Pogo Hungary Kft.("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. The Company has signed a contract and
currently expects to commence acquiring over 850 kilometers of modern 2-D
seismic data in the Szolnok area early in the second quarter. In addition, the
Company 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 exploratory term
for those portions of the Thailand Concession that have not yet been designated
a production area (comprising approximately 354,000 acres exclusive of the North
Jarmjuree area over which a production license has been requested) expires July
31, 2000. Thaipo and its joint venture partners will be obligated to relinquish
50% of this acreage but will be permitted to, and currently intend to, apply for
an extension of the exploration term on the remaining acreage. Such an
extension, if granted, would extend the exploration term on the remaining
acreage through July 1, 2001. Similar one-year extensions could also be applied
for and granted through July 1, 2005. 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 and the Maliwan area 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 anticipated gas production from 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. 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. During a
period extending from October 1, 1998 through early August 1999, as a result of
declining production from existing wells in the Tantawan Field, the need to
shut-in existing wells while drilling additional wells from the same platform,
and the decision to emphasize oil and condensate production from the Tantawan
Field, the Company and its joint venture partners delivered less natural gas
than was nominated by PTT under the Gas Sales Agreement. This resulted in the
Company receiving only 75% of the current contract price on a portion of its
natural gas sales to PTT during that time. Although the Company is currently
meeting the minimum DCQ requirements, there can be no assurance that the Company
will be able to continue to meet them in the future, in which case the penalty
provisions of the Gas Sales Agreement would again reduce the price received by
the Company for its gas sold to PTT from the Tantawan and Benchamas Fields.

     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

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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, 1999, the
Company was receiving a price of approximately $1.99 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."

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 the Saginaw pipeline, a
six inches in diameter pipeline that runs from just outside of Fort Worth, Texas
to Wichita Falls, Texas. Industrial Natural Gas, L.C., a subsidiary of the
Company, markets the sale and transmission of natural gas through the Saginaw
pipeline.

     In addition, the Company owns an approximately 19% interest in a cryogenic
gas processing plant near Erath, Louisiana, which entitles it to process up to
186 MMcf of natural gas and 5,478 Bbls of natural gas liquids per day. The plant
is not currently operating at full capacity.

  Sales

     The marketing of offshore oil and gas production is subject to the
availability of pipelines and other transportation, processing and refining
facilities, as well as the existence of adequate markets. As a result, even if
hydrocarbons are discovered in commercial quantities, a substantial period of
time may elapse before commercial production commences. If pipeline facilities
in an area are insufficient, the Company may have to await the construction or
expansion of pipeline capacity before production from that area can be marketed.
The Company's domestic offshore properties are generally located in areas where
a pipeline infrastructure is well developed and there is adequate availability
in such pipelines to transport the Company's current and projected future
production.

     The Company's Thailand Concession is traversed by two major (34 inches and
36 inches in diameter, respectively) natural gas pipelines that are owned and
operated by PTT and which come within approximately 25 miles of the Tantawan
Field (and are slightly closer to the Benchamas Field). Thaipo and its joint
venture partners in the Tantawan Field signed a long-term gas sales contract
with PTT in November 1995, which has since been amended to include production
from the Benchamas Field. All oil and condensate production from the Tantawan
Field is initially stored aboard the FPSO and is then sold to various third
parties, including PTT, on a tanker load by tanker load basis at prices based on
then current world oil prices, typically with reference to the Malaysian Tapis
crude oil benchmark price. The buyer is responsible for sending a tanker to off
load the oil and condensate it has purchased. 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. 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 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

                                        8
<PAGE>   10

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. The Company had no customers
in 1999 to whom total sales constituted more than 10% of the Company's
consolidated 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 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
apart 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.

  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. In the past, when natural gas prices in the
United States were low, the Company at times elected to curtail a portion of its
production. In the future, the Company may again elect to curtail certain
quantities of its natural gas production.

     Because it is impossible to predict future oil and gas price movements with
any certainty, the Company from time to time enters into contracts on a portion
of its production to hedge against the volatility in oil and gas prices. Such
hedging transactions, historically, have never exceeded 50% of the Company's
total oil and gas production on an energy equivalent basis for any given period.
While intended to limit the negative effect of price declines, such transactions
could effectively limit the Company's participation in price increases for the
covered period, which increases could be significant. As of December 31, 1999,
the Company was a party to natural gas futures contracts and crude oil swap
arrangements as described in "Quantitative and Qualitative Disclosure About
Market Risk." When the Company does engage in such hedging activities, it may
satisfy its obligations with its own production or by the purchase (or sale) of
third party production. The Company may also cancel all delivery obligations by
offsetting such obligations with equivalent agreements, thereby effecting a
purely cash transaction.

  Operating and Uninsured Risks

     The Company's operations are subject to risks inherent in the exploration
for and production of oil and natural gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
pollution and other environmental risks. Offshore oil and gas operations are
subject to the additional hazards

                                        9
<PAGE>   11

of marine and helicopter operations, such as capsizing, collision and adverse
weather and sea conditions. These hazards could result in substantial losses to
the Company due to injury or loss of life, severe damage to and destruction of
property and equipment, pollution and other environmental damage and suspension
of operations. The Company carries insurance which it believes is in accordance
with customary industry practices, but is not fully insured against all risks
incident to its business.

     Drilling activities are subject to numerous risks, including the risk that
no commercially productive hydrocarbon reserves will be encountered. The cost of
drilling, completing and operating wells and of installing production facilities
and pipelines is often uncertain. The Company's drilling operations may be
curtailed, delayed or canceled as a result of numerous factors, including title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery or availability of material, equipment and
fabrication yards. The availability of a ready market for the Company's natural
gas production depends on a number of factors, including the demand for and
supply of natural gas, the proximity of natural gas reserves to pipelines, the
capacity of such pipelines and government regulations.

     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 "-- 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.

                                       10
<PAGE>   12

  Acreage

     The Company owns interests in developed and undeveloped oil and gas acreage
in various parts of the world. These ownership interests generally take the form
of "working interests" in oil and gas leases which have varying terms. The
following table shows the Company's interest in developed and undeveloped oil
and gas acreage under lease as of December 31, 1999:

<TABLE>
<CAPTION>
                                               DEVELOPED              UNDEVELOPED
                                               ACREAGE(A)              ACREAGE(B)
                                           ------------------    ----------------------
                                            GROSS       NET        GROSS         NET
                                           -------    -------    ---------    ---------
<S>                                        <C>        <C>        <C>          <C>
Domestic Offshore
  Louisiana (State)......................    4,516      2,182        1,169          584
  Louisiana (Federal)....................  166,500     45,529      160,304       64,013
  Texas (Federal)........................   40,320     10,855       74,185       20,994
                                           -------    -------    ---------    ---------
  Total Domestic Offshore................  211,336     58,566      235,658       85,591
                                           -------    -------    ---------    ---------
Onshore
  Louisiana..............................    3,583        926       10,178        4,402
  New Mexico.............................   37,912     22,536       75,396       56,641
  Texas..................................   20,500      8,568       77,308       43,156
  Canada.................................   24,407      3,817       90,085       45,803
  Other..................................    3,200        333          198           35
                                           -------    -------    ---------    ---------
          Total Onshore..................   89,602     36,180      253,165      150,037
                                           -------    -------    ---------    ---------
          Total North America............  300,938     94,746      488,823      235,628
                                           -------    -------    ---------    ---------
International
  Gulf of Thailand.......................  260,407    120,682      473,733      219,530
  North Sea..............................       --         --      112,729       45,092
  Hungary................................       --         --      778,136      778,136
  Denmark................................       --         --       80,902       32,361
                                           -------    -------    ---------    ---------
          Total International............  260,407    120,682    1,445,500    1,075,119
                                           -------    -------    ---------    ---------
          Total Company..................  561,345    215,428    1,934,323    1,310,747
                                           =======    =======    =========    =========
</TABLE>

---------------

(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, Tantawan Field and the Maliwan
    production area.

(b) Approximately 22% of the Company's total domestic offshore net undeveloped
    acreage and approximately 17% of the Company's total onshore net undeveloped
    acreage are under leases that have terms expiring in 2000 (unless otherwise
    extended). Approximately 20% of total domestic offshore net undeveloped
    acreage and approximately 16% of total onshore net undeveloped acreage are
    under leases that terms expiring in 2001 (unless otherwise extended). All of
    the Company's undeveloped acreage in the Kingdom of Thailand must be
    relinquished to the Thai government on July 31, 2000, unless designated as a
    production area or unless the exploration term is extended. See
    "-- International Operations; Contractual Terms Governing the Thailand
    Concession and Related Production."

     In addition, the Company holds certain other types of mineral interests,
including fee interests (which never expire) and royalty interests (which
generally terminate when the underlying mineral lease expires). The Company owns
varying fee and royalty interests in 10,800 gross acres in Texas and a royalty
interest in 5,000 gross acres (1,250 net acres) offshore Louisiana.

                                       11
<PAGE>   13

  Productive Wells and Drilling Activity

     The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1999. 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.

<TABLE>
<CAPTION>
                                                                                 NATURAL GAS
                                                               OIL WELLS(A)       WELLS(A)
                                                              --------------    -------------
                                                              GROSS     NET     GROSS    NET
                                                              -----    -----    -----    ----
<S>                                                           <C>      <C>      <C>      <C>
Offshore United States......................................   130      28.9      81     25.2
Onshore (U.S. and Canada)...................................   756     469.6     112     45.3
Kingdom of Thailand.........................................    10       4.6      53     24.6
                                                               ---     -----     ---     ----
          Total                                                896     503.1     246     95.1
                                                               ===     =====     ===     ====
</TABLE>

---------------

(a) One or more completions in the same bore hole are counted as one well. The
    data in the above table includes 5 gross (1.3 net) oil wells and 5 gross
    (1.6 net) natural gas wells with multiple completions.

     The following table shows the number of successful gross and net
exploratory and development wells in which the Company has participated and the
number of gross and net wells abandoned as dry holes during the periods
indicated. An onshore well is considered successful upon the installation of
permanent equipment for the production of hydrocarbons or when electric logs run
to evaluate such wells indicate the presence of 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

                                       12
<PAGE>   14

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.

<TABLE>
<CAPTION>
                                                        1999                  1998                  1997
                                                 ------------------    ------------------    -------------------
                                                 PRODUCTIVE    DRY     PRODUCTIVE    DRY     PRODUCTIVE     DRY
                                                 ----------    ----    ----------    ----    ----------    -----
<S>                                              <C>           <C>     <C>           <C>     <C>           <C>
Gross Wells:
  Offshore United States
    Exploratory................................      4.0         --        5.0        1.0        4.0         1.0
    Development................................     11.0         --        2.0         --       12.0         3.0
  Onshore United States and Canada
    Exploratory................................      3.0        3.0        9.0        4.0       18.0        12.0
    Development................................     23.0        1.0       32.0        1.0       50.0         3.0
Offshore Kingdom of Thailand
    Exploratory................................      4.0         --       12.0         --       18.0         1.0
    Development................................     42.0         --       12.0         --       16.0          --
                                                   -----       ----      -----       ----      -----       -----
         Total.................................     87.0        4.0       72.0        6.0      118.0        20.0
                                                   =====       ====      =====       ====      =====       =====
Net Wells:
Offshore United States
    Exploratory................................     1.32         --       1.07        .25       1.21         .25
    Development................................     3.37         --        .80         --       4.15        1.05
Onshore United States and Canada
    Exploratory................................     1.63       1.65       5.08       2.19      11.27        7.40
    Development................................    13.89        .80      22.61        .34      30.18        1.41
  Offshore Kingdom of Thailand
    Exploratory................................     1.85         --       5.56         --       8.34         .46
    Development................................    19.46         --       5.56         --       5.11          --
                                                   -----       ----      -----       ----      -----       -----
         Total.................................    41.52       2.45      40.68       2.78      60.26       10.57
                                                   =====       ====      =====       ====      =====       =====
</TABLE>

  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."

<TABLE>
<CAPTION>
                                                              1999    1998     1997
                                                              ----    -----    -----
<S>                                                           <C>     <C>      <C>
Average Production (lifting) Costs(a):
  Located in the United States and Canada
     Natural Gas, Crude Oil, Condensate and Natural Gas
      Liquids (per Mcfe)....................................  $.69    $ .61    $ .49
  Located in the Kingdom of Thailand
     Natural Gas, Crude Oil and Condensate (per Mcfe)(b)....  $.99    $1.10    $1.12
</TABLE>

---------------

(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.

(b) The major contributing factor to lifting costs are lease operating expenses.
    A substantial portion of the Company's lease operating expenses in the
    Kingdom of Thailand relate to lease payments made by a subsidiary of the
    Company in connection with its bareboat charter of the FPSO and the FSO,
    which collectively amounted to $17,588,000 net to the Company during 1999.
    See "Management's Discussion and Analysis of Financial Condition and Results
    of Operations -- Liquidity and Capital Resources; Future Capital
    Requirements; Other Material Long -- Term Commitments."

                                       13
<PAGE>   15

  Reserves

     The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1999, 1998 and 1997, 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.

<TABLE>
<CAPTION>
                                                                    AS OF DECEMBER 31,
                                                            ----------------------------------
                                                               1999         1998        1997
                                                            ----------    --------    --------
<S>                                                         <C>           <C>         <C>
Total Proved Reserves:
  Oil, condensate, and natural gas liquids (MBbls)
     Located in the United States and Canada..............      42,120      33,699      29,382
     Located in the Kingdom of Thailand...................      36,656      33,811      28,783
                                                            ----------    --------    --------
          Total Company...................................      78,776      67,510      58,165
                                                            ==========    ========    ========
  Natural Gas (MMcf)
     Located in the United States and Canada..............     221,110     271,780     216,720
     Located in the Kingdom of Thailand...................     153,588     168,389     184,768
                                                            ----------    --------    --------
          Total Company...................................     374,698     440,169     401,488
                                                            ==========    ========    ========
  Present value of estimated future net revenues, before
     income taxes (in thousands)(a)
     Located in the United States and Canada..............  $  585,052    $294,629    $406,161
     Located in the Kingdom of Thailand...................     569,594     200,597      56,620
                                                            ----------    --------    --------
          Total Company...................................  $1,154,646    $495,226    $462,781
                                                            ==========    ========    ========
Total Proved Developed Reserves:
  Oil, condensate, and natural gas liquids (MBbls)
     Located in the United States and Canada..............      35,487      29,070      26,168
     Located in the Kingdom of Thailand...................      18,408       4,298       6,982
                                                            ----------    --------    --------
          Total Company...................................      53,895      33,368      33,150
                                                            ==========    ========    ========
  Natural Gas (MMcf)
     Located in the United States and Canada..............     157,216     184,630     179,972
     Located in the Kingdom of Thailand...................      88,041      40,424      59,760
                                                            ----------    --------    --------
          Total Company...................................     245,257     225,054     239,732
                                                            ==========    ========    ========
Present value of estimated future net revenues, before
  income taxes (in thousands)(a)
     Located in the United States and Canada..............  $  472,856    $242,574    $377,530
     Located in the Kingdom of Thailand...................     304,275      28,244      36,692
                                                            ----------    --------    --------
          Total Company...................................  $  777,131    $270,818    $414,222
                                                            ==========    ========    ========
</TABLE>

---------------

(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.

                                       14
<PAGE>   16

     Natural gas liquids comprised approximately 7% of the Company's total
proved liquids reserves and approximately 10% of the Company's proved developed
liquids reserves as of December 31, 1999. 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.

     In computing future revenues from gas reserves attributable to the
Company's domestic interests, prices in effect at December 31, 1999 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 which are likely to cause future yearly average gas prices to be somewhat
lower than December gas prices. For domestic gas sold under contract, the
contract gas price including fixed and determinable escalations, exclusive of
inflation adjustments, was used until the contract expires and then was adjusted
to the current market price for the area and held at this adjusted price to
depletion of the reserves. In computing future revenues from liquids
attributable to the Company's domestic interests, prices in effect at December
31, 1999 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, 1999, 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 Tapis benchmark crude on December 31, 1999, 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:

<TABLE>
<CAPTION>
                                                               AS OF DECEMBER 31,
                                                           --------------------------
                                                            1999      1998      1997
                                                           ------    ------    ------
<S>                                                        <C>       <C>       <C>
Initial Weighted Average Price (in U.S. dollars):
  Oil, condensate, and natural gas liquids (per Bbl)
     Located in the United States and Canada.............  $25.55    $10.45    $16.60
     Located in the Kingdom of Thailand..................  $25.08    $12.68    $16.00
  Natural Gas (per Mcf)
     Located in the United States and Canada.............  $ 2.14    $ 2.01    $ 2.30
     Located in the Kingdom of Thailand..................  $ 1.99    $ 1.81    $ 1.83
</TABLE>

     The estimates of future net revenue from the Company's domestic and
Thailand properties are based on existing law where the properties are located
and are calculated in accordance with Commission guidelines. Operating costs for
the leases and wells include only those costs directly applicable to the leases
or wells. When applicable, the operating costs include a portion of general and
administrative costs allocated directly to the leases and wells under terms of
operating agreements. Development costs are based on authorization for
expenditure for the proposed work or actual costs for similar projects. The
current operating and development costs were held constant throughout the life
of the properties. For properties located onshore, the estimates of future net
revenues and the present value thereof do not consider the salvage value of the
lease equipment or the abandonment cost of the lease since both are relatively
insignificant and tend to offset each other. The

                                       15
<PAGE>   17

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 1999. The future production
rates from reservoirs now on production may be more or less than estimated
because of, among other reasons, mechanical breakdowns and changes in market
demand or allowables set by regulatory bodies. Properties which are not
currently producing may start producing earlier or later than anticipated in the
estimates of future production rates.

     The future prices received by the Company for the sales of its production
may be higher or lower than the prices used in calculating the estimates of
future net revenues and the present value thereof as set forth herein, and the
operating costs and other costs relating to such production may also increase or
decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by the Commission, omitted from
consideration in arriving at such estimates.

     There are numerous uncertainties in estimating the quantity of proved
reserves and in projecting the future rates of production and timing of
development expenditures. Oil and gas reserve engineering must be recognized as
a subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and estimates of other engineers might
differ materially from those of Ryder Scott, the Company's reserve engineers.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing and production subsequent to the date of the estimate may
justify revision of such estimate, which revisions may be material. Accordingly,
reserve estimates are often different from the quantities of oil and gas that
are ultimately recovered.

     The Company is periodically required to file estimates of its oil and gas
reserve data with various U.S. governmental regulatory authorities and agencies,
including the Federal Energy Regulatory Commission ("FERC") and the Federal
Trade Commission; with respect to reserves located in Canada, with the Alberta
Energy Utilities Board and, with respect to reserves located in Thailand, the
Kingdom of Thailand's Department of Mineral Resources and PTT, which the Company
considers a quasi-governmental authority. In addition, estimates are from time
to time furnished to governmental agencies in connection with specific matters
pending before such agencies. The basis for reporting reserves to these
agencies, in some cases, is not comparable to that furnished by Ryder Scott in
accordance with 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 1999, 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 certain provisions
of the federal income tax laws applicable to the petroleum industry. The
principal provisions affecting the Company are those that permit the

                                       16
<PAGE>   18

Company, subject to certain limitations, to deduct as incurred, rather than to
capitalize and amortize, its domestic "intangible drilling and development
costs" and to claim depletion on a portion of its domestic oil and gas
properties based on 15% of its oil and gas gross income from such properties (up
to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent
units of domestic natural gas) even though the Company has little or no basis in
such properties. Under certain circumstances, however, a portion of such
intangible drilling and development costs and the percentage depletion allowed
in excess of basis will be tax preference items that will be taken into account
in computing the Company's alternative minimum tax.

  Environmental Matters

     Domestic oil and gas operations are subject to extensive federal regulation
and, with respect to federal leases, to interruption or termination by
governmental authorities on account of environmental and other considerations
including the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") also known as the "Superfund Law." The recent trend towards
stricter standards in environmental legislation and regulation may continue, and
this could increase costs to the Company and others in the industry. Oil and gas
lessees are subject to liability for the costs of clean-up of pollution
resulting from a lessee's operations, and may also be subject to liability for
pollution damages. The Company maintains insurance against costs of clean-up
operations, but is not fully insured against all such risks. A serious incident
of pollution may, as it has in the past, also result in the Department of the
Interior requiring lessees under federal leases to suspend or cease operation in
the affected area.

     The operators of the Company's properties have numerous applications
pending before the Environmental Protection Agency (the "EPA") for National
Pollution Discharge Elimination System water discharge permits with respect to
offshore drilling and production operations. The issue generally involved is
whether effluent discharges from each facility or installation comply with the
applicable federal regulations.

     The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulations. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by the
OPA.

     The OPA also imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10,000,000 depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. For offshore facilities that have a
worst case oil spill potential of more than 1,000 Bbls (which includes many of
the Company's offshore producing facilities), certain amendments to the OPA that
were enacted in 1996 provide that the amount of financial responsibility that
must be demonstrated for most facilities ranges from $10,000,000 to $35,000,000,
depending upon location, with higher amounts, up to $150,000,000 in certain
limited circumstances. The Company believes that it currently has established
adequate proof of financial responsibility for its offshore facilities at no
significant increase in expense over recent prior years. However, the Company
cannot predict whether these financial responsibility requirements under the OPA
amendments will result in the imposition of substantial additional annual costs
to the Company in the future or otherwise materially adversely affect the
Company. The impact, however, should not be any more adverse to the Company than
it will be to other similarly situated or less capitalized owners or operators
in the Gulf of Mexico.

     The Company's onshore operations are subject to numerous United States and
Canadian federal, state, provincial and local laws and regulations controlling
the discharge of materials into the environment or otherwise relating to the
protection of the environment including CERCLA. Such laws and regulations,

                                       17
<PAGE>   19

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 states and Canadian provinces, and these initiatives
could have a similar impact on the Company.

     The Company is asked to comment on the costs it incurred during the prior
year on capital expenditures for environmental control facilities and the amount
it anticipates incurring during the coming year. The Company believes that, in
the course of conducting its oil and gas operations, many of the costs
attributable to environmental control facilities would have been incurred absent
environmental regulations as prudent, safe oilfield practice. During 1999, the
Company incurred capital expenditures of approximately $929,000 for
environmental control facilities, primarily relating to pit liner and routine
site restoration costs, the installation of certain environmental control
facilities on two platforms installed in the Gulf of Thailand and at three
locations in New Mexico, and the drilling of two salt water disposal wells. The
Company budgeted approximately $4,090,000 for expenditures involving
environmental control facilities during 2000, including, among other things,
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. In a
letter dated May 3, 1993, the MMS announced a reinterpretation of its right to
collect royalty payments from producers on certain settlements in which such
producers and pipeline companies were involved a number of years ago. The MMS
reinterpretation has been challenged in court by various producers and trade
groups representing them. On August 27, 1996, in Independent Petroleum
Association of America, et al. v. Babbit et al., Nos. 95-5210 etc., the United
States Court of Appeals for the District of Columbia Circuit held that the May
3, 1993, reinterpretation was invalid and unenforceable. Unless and until this
or other similar cases are resolved in favor of the MMS' reinterpretation of its
regulations, it is unlikely that the Company or other producers will be legally
required to pay royalties on such settlement agreements. The Company was
involved in several settlement agreements with pipelines that could be subject
to the MMS' new reinterpretation. The MMS has reviewed the Company's and other
producers' settlement agreements, to determine whether it believes any
additional royalty payments may be due and has asserted that additional
royalties may be due in connection with two of the Company's settlement
agreements. Based upon existing case law, the Company has asserted through the
administrative appeals process, and continues to believe, that it does not owe
any additional royalties beyond what it has previously paid. However, in the
event that the MMS is able to successfully assert that additional royalty is due
from the Company in connection with settlement agreements to which the Company
is a party, the Company does not currently believe that such additional
assessment will have a material adverse impact on the financial position or
results of operations of the Company.

     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 have challenged portions of the
rule in American Petroleum Institute, et al. v. Babbitt, Civil Nos. 98-631, et
al. (D.D.C. 1998).

                                       18
<PAGE>   20

The latest version of the oil valuation rules proposed by the MMS was published
on December 30, 1999. A final rule is expected. 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 named in any of these collection efforts, a fact that the Company
believes is primarily due to its never having sold any oil or gas production
from one of its affiliates to another. The Company does not believe that it has
any material liability for underpayment of royalty in connection with affiliate
transactions, including those described above.

     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.

EMPLOYEES

     As of December 31, 1999, the Company and its subsidiaries had 165 full-time
employees, including three in its Bangkok, Thailand office and seven in its
Calgary, Canada office. None of the Company's employees are presently
represented by a union for collective bargaining purposes. The Company considers
its relations with its employees to be excellent.

ITEM 2. PROPERTIES.

     The information appearing in Item 1 of this Annual Report is incorporated
herein by reference.

ITEM 3. LEGAL PROCEEDINGS.

     The Company is a party to various other legal proceedings consisting of
routine litigation incidental to its businesses, but believes that any potential
liabilities resulting from these proceedings are adequately covered by insurance
or are otherwise immaterial at this time. See "Business-Government Regulation;
Other Laws and Regulations."

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.

     Not Applicable.

                                       19
<PAGE>   21

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 March 10, 2000 and the year
each was elected to his present position are as follows:

<TABLE>
<CAPTION>
EXECUTIVE OFFICER                    EXECUTIVE OFFICE              AGE    YEAR ELECTED
-----------------          ------------------------------------    ---    ------------
<S>                        <C>                                     <C>    <C>
Paul G. Van Wagenen......  Chairman of the Board, President and    54         1991
                           Chief Executive Officer
Stuart P. Burbach........  Executive Vice President-Exploration    47         1998
Kenneth R. Good..........  Executive Vice President                62         1998
Jerry A. Cooper..........  Senior Vice President and Western       51         1998
                           Division Manager
R. Phillip Laney.........  Senior Vice President and Manager of    59         1998
                           Worldwide New Ventures
John O. McCoy, Jr. ......  Senior Vice President and Chief         48         1998
                           Administrative Officer
J. D. McGregor...........  Senior Vice President-Sales             55         1998
Barry W. Acomb...........  Vice President and Offshore Division    47         1999
                           Manager
Bruce E. Archinal........  Vice President and Onshore Division     47         1997
                           Manager
David R. Beathard........  Vice President-Engineering              41         1997
Stephen R. Brunner.......  Vice President-Operations               41         1997
Frank Davis III..........  Vice President-Land                     53         1997
Thomas E. Hart...........  Vice President and Chief Accounting     57         1999
                           Officer
Gerald A. Morton.........  Vice President-Law and Corporate        41         1997
                           Secretary
S. Clay Robinson, Jr. ...  Vice President and International        45         1999
                           Division Manager
James P. Ulm, II.........  Vice President and Chief Financial      37         1999
                           Officer
</TABLE>

     Prior to assuming their present positions with the Company, the business
experience of each executive officer for more than the last five years was as
follows: Mr. Van Wagenen, who joined the Company in 1979, served as President
and Chief Operating Officer of the Company since 1990; Mr. Burbach served as
Vice President and Offshore Division Manager since rejoining the Company in
1991; Mr. Good, who joined the Company in 1977, served as Corporate Senior Vice
President of the Company since 1996 and prior thereto served as the Company's
Senior Vice President-Land and Budgets since 1991; Mr. Cooper, who joined the
Company in 1979, served as Vice President and Western Division Manager for the
Company since 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 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 served as Resident Manager of the Company's Thailand operations since
1995, prior to which he was an Operations Manager for the Company since 1994;
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 for the Company since 1993; Mr. Robinson, since
joining the Company in 1996, served as International Division Exploration
Manager; and

                                       20
<PAGE>   22

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.

<TABLE>
<CAPTION>
                                                              LOW         HIGH
                                                              ----        ----
<S>                                                           <C>         <C>
1998
1st Quarter.................................................    26 1/2      34
2nd Quarter.................................................    21 1/2      34 11/16
3rd Quarter.................................................    11 5/8      25 7/8
4th Quarter.................................................     9 13/16    17 1/8
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
</TABLE>

     As of March 3, 2000, there were 3,064 holders of record of the Company's
Common Stock.

     In each of 1998 and 1999, the Company paid four quarterly dividends of
$0.03 per share on its Common Stock. However, the declaration and payment of
future dividends will depend upon, among other things, the Company's future
earnings and financial condition, liquidity and capital requirements, the
general economic and regulatory climate and other factors deemed relevant by the
Company's Board of Directors.

     Pursuant to the Company's revolving credit 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"), the Company may
not, subject to certain exceptions, pay any dividends on its capital stock or
make any other distributions on shares of its capital stock (other than
dividends or distributions payable solely in shares of such capital stock) or
apply any funds, property or assets to the purchase, redemption, sinking fund or
other retirement of its capital stock, if the aggregate amount of all such
dividends, purchases, and redemptions would exceed an amount determined based on
the consolidated income of the Company and its consolidated subsidiaries plus
the proceeds of the issuance of capital stock from and after a specified date
set forth in each respective agreement or, in the case of the revolving credit
facility, if the net worth of the Company is negative. As of December 31, 1999,
$16,516,000 was available for dividends under this limitation in the Indenture
relating to the 2009 Notes, the agreement currently having the most restrictive
covenants. 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
<PAGE>   23

ITEM 6. SELECTED FINANCIAL DATA.

<TABLE>
<CAPTION>
                                                            FOR THE YEAR ENDED DECEMBER 31,
                                           ------------------------------------------------------------------
                                              1999          1998          1997          1996          1995
                                           ----------    ----------    ----------    ----------    ----------
                                             (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AND PRODUCTION DATA)
<S>                                        <C>           <C>           <C>           <C>           <C>
FINANCIAL DATA
Revenues:
  Crude oil and condensate...............   $109,803      $ 74,703      $112,603      $ 96,908      $ 76,557
  Natural gas............................    111,152       116,148       158,500        94,589        72,032
  Natural gas liquids....................      9,544         9,303        13,748        11,867         8,097
                                            --------      --------      --------      --------      --------
  Oil and gas revenues...................    230,499       200,154       284,851       203,364       156,686
  Pipeline sales and other...............      7,159         2,741           349           778           773
  Gains (losses) on sales................     37,458           (92)        1,100          (165)          100
                                            --------      --------      --------      --------      --------
         Total...........................   $275,116      $202,803      $286,300      $203,977      $157,559
                                            ========      ========      ========      ========      ========
Income (loss) before extraordinary
  item...................................   $ 22,134      $(43,098)     $ 37,116      $ 33,581      $  9,230
Extraordinary losses.....................         --            --            --          (821)           --
                                            --------      --------      --------      --------      --------
Net income (loss)........................   $ 22,134      $(43,098)     $ 37,116      $ 32,760      $  9,230
                                            ========      ========      ========      ========      ========
Per share data:
  Income (loss) before extraordinary
    item --
    Basic................................   $   0.55      $  (1.14)     $   1.11      $   1.01      $   0.28
    Diluted..............................   $   0.55      $  (1.14)     $   1.06      $   0.97      $   0.28
  Cash dividends on Common Stock.........   $   0.12      $   0.12      $   0.12      $   0.12      $   0.12
  Price range of Common Stock:
    High.................................   $  23.44      $  34.69      $  49.88      $  48.38      $  29.00
    Low..................................   $   8.94      $   9.81      $  27.00      $  24.38      $  16.00
Weighted average number of common shares
  outstanding............................     40,178        37,902        33,421        33,203        32,893
Long-term debt...........................   $375,000      $434,947      $348,179      $246,230      $163,249
Trust Preferred Securities, net..........   $144,751            --            --            --            --
Shareholders' equity.....................   $268,512      $249,660      $146,106      $107,282      $ 71,708
Total assets.............................   $948,193      $862,396      $676,617      $479,242      $338,177
PRODUCTION (SALES) DATA
Net daily average and weighted average
  price:
  Natural gas (Mcf per day)..............    141,600       159,000       181,700       107,700       121,000
    Price (per Mcf)......................   $   2.15      $   2.00      $   2.39      $   2.40      $   1.63
  Crude oil-condensate (Bbl per day).....     16,036        15,775        15,927        11,968        11,786
    Price (per Bbl)......................   $  18.76      $  12.97      $  19.37      $  22.12      $  17.80
  Natural gas liquids (Bbl per day)......      2,077         2,422         2,923         2,173         1,998
    Price (per Bbl)......................   $  12.59      $  10.52      $  12.89      $  14.92      $  11.10
CAPITAL EXPENDITURES
Oil and gas:
  Domestic Offshore --
    Exploration..........................   $ 12,600      $ 20,200      $ 18,700      $ 16,800      $ 13,300
    Development..........................     43,200        42,500        59,800        73,900        17,800
    Purchase of reserves.................         --         5,000           900             -            --
  Onshore North America --
    Exploration..........................      9,800        16,500        18,100        10,400         8,800
    Development..........................     19,800        28,100        38,400        27,800        22,400
    Purchase of reserves.................     19,500       133,100         1,700            --         7,900
  Kingdom of Thailand --
    Exploration..........................      3,500        11,600        21,700         8,500         5,500
    Development..........................    106,300        95,500        62,500        54,700        24,400
    Purchase of reserves.................         --            --        29,300            --         4,200
                                            --------      --------      --------      --------      --------
  Total oil and gas......................    214,700       352,500       251,100       192,100       104,300
Other....................................      2,200         6,300         4,000         1,600           500
                                            --------      --------      --------      --------      --------
         Total...........................   $216,900      $358,800      $255,100      $193,700      $104,800
                                            ========      ========      ========      ========      ========
</TABLE>

                                       22
<PAGE>   24

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

     On August 17, 1998, a wholly owned subsidiary of the Company merged with
and into Arch in a stock-for-stock tax-free merger accounted for as a purchase.
In connection with the merger, the Company paid off $51,749,000 of Arch's
existing bank debt and production payment obligations. The Company also
exchanged $5,000,000 of Arch's existing convertible subordinated notes, 727,273
shares of Arch preferred stock (having a liquidation preference of $20,000,000)
and 17,321,804 shares of Arch common stock for approximately 2,500,000 shares of
Common Stock.

RESULTS OF OPERATIONS

  Net Income (Loss)

     The Company reported net income for 1999 of $22,134,000 or $0.55 per share,
compared to a net loss for 1998 of $43,098,000 or $1.14 per share (on both a
basic and a diluted basis) and net income for 1997 of $37,116,000 or $1.11 per
share ($40,198,000 or $1.06 per share on a diluted basis). Among other items
affecting the net income for 1999 were $37,458,000 in net gains related to the
sale by the Company of certain properties during the first quarter of the year
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 1999 of 40,178,000 (40,390,000 on a diluted
basis), compared to 37,902,000 (on both a basic and a diluted basis) for 1998
and 33,421,000 (38,064,000 on a diluted basis) for 1997. The increase in the
weighted average number of common shares outstanding for 1999, compared to 1998
and 1997, resulted primarily from the issuance of 3,882,023 shares of its common
stock upon the conversion of the Company's 5 1/2% Convertible Subordinated Notes
due 2004 (the "2004 Notes") prior to their being redeemed on March 16, 1998, the
issuance as of August 17, 1998 of approximately 2,500,000 shares of common stock
to former holders of Arch capital stock and convertible debt securities in
connection with the Company's acquisition of Arch and, to a lesser extent, the
issuance of common stock upon the exercise of stock options pursuant to the
Company's stock option plans. The earnings per share computation on a diluted
basis in 1998 is identical to the basic earnings per share computation because
there were no securities of the Company that were dilutive during the period.
The earnings per share computation on a diluted basis in 1997 primarily reflects
additional shares of common stock issuable upon the assumed conversion of the
2004 Notes and the elimination of related interest requirements, as adjusted for
applicable federal income taxes and, to a lesser extent, the assumed exercise of
options to purchase common shares. In addition, the number of common shares
outstanding in the diluted computation is adjusted, in accordance with the
Financial Accounting Standards Board's Statement of Financial Accounting
Standards ("SFAS") No. 128, to include dilutive shares that are assumed to have
been issued by the Company in connection with options exercised during the year,
less treasury shares that are assumed to have been purchased by the Company from
the option proceeds. SFAS No. 128 was adopted by the Company in 1997, resulting
in a restatement of the earnings per share calculations for 1997 and all
preceding years.

  Total Revenues

     The Company's total revenues for 1999 were $275,116,000, an increase of
approximately 36% from total revenues of $202,803,000 for 1998, and a decline of
approximately 4% of total revenues of $286,300,000 for 1997. The increase in the
Company's total revenues for 1999, compared to 1998, resulted primarily from the
gains on sales of properties discussed earlier, increases in oil and gas
revenues and an increase in pipeline sales, principally related to the Saginaw
pipeline, which was acquired as part of the Arch acquisition in the third
quarter of 1998. The decrease in the Company's total revenues for 1999, compared
to 1997, resulted primarily from a decrease in oil and gas revenues, that was
only partially offset by the revenues generated by the Company's pipeline sales.

                                       23
<PAGE>   25

  Oil and Gas Revenues

     The Company's oil and gas revenues for 1999 were $230,499,000, a increase
of approximately 15% from oil and gas revenues of $200,154,000 for 1998, and a
decrease of approximately 19% from oil and gas revenues of $284,851,000 for
1997. The following table reflects an analysis of variances in the Company's oil
and gas revenues (expressed in thousands) between 1999 and the previous two
years:

<TABLE>
<CAPTION>
                                                                1999 COMPARED TO
                                                              --------------------
                                                                1998        1997
                                                              --------    --------
<S>                                                           <C>         <C>
Increase (decrease) in oil and gas revenues resulting from
  variances in:
  Natural gas --
    Price...................................................  $  8,706    $(15,853)
    Production..............................................   (13,702)    (31,495)
                                                              --------    --------
                                                              $ (4,996)   $(47,348)
                                                              --------    --------
  Crude oil and condensate-
    Price...................................................  $ 33,310    $ (3,546)
    Production..............................................     1,790         746
                                                              --------    --------
                                                              $ 35,100    $ (2,800)
                                                              --------    --------
  Natural Gas Liquids.......................................  $    241    $ (4,204)
                                                              --------    --------
    Increase (decrease) in oil and gas revenues.............  $ 30,345    $(54,352)
                                                              ========    ========
</TABLE>

     The increase in the Company's oil and gas revenues in 1999, compared to
1998, is related to increases in the average price that the Company received for
its natural gas and oil, condensate and NGL ("liquid hydrocarbons") production
volumes and, to a lesser extent, increases in crude oil and condensate
production, that was partially offset by declines in natural gas and NGL
production volumes. The decrease in the Company's oil and gas revenues in 1999,
compared to 1997, is related to declines in the natural gas and NGL production
volumes and, to a lesser extent the average price that the Company received for
its natural gas and liquid hydrocarbon production volumes, that more than offset
increases in crude oil and condensate production volumes.

                                       24
<PAGE>   26

<TABLE>
<CAPTION>
                                                                         % CHANGE               % CHANGE
                                                                           1999                   1999
                                                                            TO                     TO
                                                    1999       1998        1998       1997        1997
                                                   -------    -------    --------    -------    --------
<S>                                                <C>        <C>        <C>         <C>        <C>
Comparison of Increases (Decreases) in:
NATURAL GAS --
  Average prices
    North America................................  $  2.31    $  2.09       11%      $  2.50       (8)%
    Kingdom of Thailand (ThaiBaht)(a)............       61         70      (13)%          60        2%
      Company-wide average price.................  $  2.15    $  2.00        8%      $  2.39      (10)%
  Average daily production volumes (MMcf per day)
    North America................................    102.6      122.2      (16)%       147.2      (30)%
    Kingdom of Thailand (a)......................     39.0       36.8        6%         34.5       13%
                                                   -------    -------                -------
      Company-wide average daily production......    141.6      159.0      (11)%       181.7      (22)%
                                                   =======    =======                =======
CRUDE OIL AND CONDENSATE --
  Average prices
    North America................................  $ 17.43    $ 12.94       35%      $ 19.49      (11)%
    Kingdom of Thailand(a).......................  $ 23.49    $ 13.17       78%      $ 18.60       26%
      Company-wide average price.................  $ 18.76    $ 12.97       45%      $ 19.37       (3)%
  Average daily production volumes (Bbls per day)
    North America................................   12,517     13,214       (5)%      13,711       (9)%
    Kingdom of Thailand (a)......................    3,519      2,561       37%        2,216       59%
                                                   -------    -------                -------
      Company-wide average daily production......   16,036     15,775        2%       15,927        1%
                                                   =======    =======                =======
TOTAL LIQUID HYDROCARBONS --
  Company-wide average daily production (Bbls per
    day).........................................   18,112     18,197       --        18,851       (4)%
                                                   =======    =======                =======
</TABLE>

---------------

(a) Production from the Tantawan Field commenced in February 1997, with a
    start-up phase which extended through March 15, 1997. Production from the
    Benchamas Field commenced in July 1999. Prices received for its gas
    production during the start-up phase of the Tantawan Field and 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. See "Business and Properties -- International
    Operations; Contractual Terms Governing the Thailand Concession and Related
    Production."

  Natural Gas

     Thailand Prices. The price that the Company receives under the Gas Sales
Agreement for its natural gas production from the Thailand Concession normally
adjusts on a semi-annual basis. However, the Gas Sales Agreement provides for
adjustment on a more frequent basis in the event that certain indices and
factors on which the price is based fluctuate outside a given range. 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 volatility of the Thai Baht and
the economic difficulties that prevailed in the Kingdom of Thailand and
throughout Southeast Asia during 1997 and parts of 1998, the price that the
Company received under the Gas Sales Agreement adjusted several times during
1998, and almost monthly in the latter half of 1997. The Company cannot predict
what the Baht to dollar exchange rate may be in the future. Although it has been
relatively stable throughout much of 1999, the exchange rate could again become
volatile in the future. See "-- Foreign Currency Transaction Gain (Loss)," and
"-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic
Issues."

                                       25
<PAGE>   27

     Production. The decrease in the Company's natural gas production during
1999, compared to 1998, was related in large measure to the sale of the Lopeno
Field and other lesser properties in the first quarter of 1999, decreased
production from the Company's East Cameron Block 334 "E" platform and natural
production declines from other Company properties, which were partially offset
by 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. The decrease in the Company's natural gas production
during 1999, compared to 1997, was related in large measure to decreased
production from the Company's East Cameron Block 334 "E" platform, the sale of
the Lopeno Field and other lesser properties in the first quarter of 1999, and
natural production declines from other Company properties, which were partially
offset by production from properties that the Company acquired in its
acquisition of Arch, increased production from the Company's Thailand Concession
and production from the Company's Garden Banks Block 367 project. Commencing on
October 1, 1998 and continuing through August 1999, the Company and its joint
venture partners in the Thailand Concession delivered less natural gas than was
nominated by PTT under the Gas Sales Agreement. This resulted in the Company
receiving only 75% of the then current contract price on a portion of its
natural gas sales to PTT. These penalties are reflected in the average price
that the Company received for its natural gas production described elsewhere in
this Annual Report.

  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 crude and are denominated in dollars. In
addition, the Company is generally paid for its crude oil and condensate
production from Thailand in U.S. dollars.

     Production. The increase in the Company's crude oil and condensate
production during 1999, compared to 1998 and 1997, resulted primarily from
increased production from the Company's Thailand Concession due to commencement
of production from the Benchamas Field, and increased production from the
Company's Western Division properties (including those acquired in its
acquisition of Arch), 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 1999, compared with 1998, primarily related to an
increase in the average price that the Company received for its NGL, that was
only partially offset by a decrease in the Company's NGL production volumes. The
decrease in NGL revenues in 1999, compared with 1997, primarily related to a
decrease in the Company's NGL production and, to a much lesser extent, a decline
in the price that the Company received for its NGL production.

                                       26
<PAGE>   28

Costs and Expenses

<TABLE>
<CAPTION>
                                                                  % CHANGE                      % CHANGE
                                      1999           1998       1999 TO 1998       1997       1999 TO 1997
                                  ------------   ------------   ------------   ------------   ------------
<S>                               <C>            <C>            <C>            <C>            <C>
Comparison of Increases
  (Decreases) in:
  LEASE OPERATING EXPENSES
     North America..............  $ 48,121,000   $ 48,158,000        --        $ 43,934,000        10%
                                  ------------   ------------                  ------------
     Kingdom of Thailand(a).....    21,815,000     20,913,000         4%         19,567,000        11%
                                  ============   ============                  ============
          Total Lease Operating
            Expenses............  $ 69,936,000   $ 69,071,000         1%       $ 63,501,000        10%
  PIPELINE OPERATING AND NATURAL
     GAS PURCHASES..............  $  6,481,000   $  2,142,000       203%                 --       N/A
  GENERAL AND ADMINISTRATIVE
     EXPENSES...................  $ 29,865,000   $ 26,356,000        13%       $ 21,412,000        39%
  EXPLORATION EXPENSES..........  $  5,982,000   $  9,802,000       (39)%      $ 10,530,000       (43)%
  DRY HOLE AND IMPAIRMENT
     EXPENSES...................  $  4,594,000   $ 41,736,000       (89)%      $  9,631,000       (52)%
  DEPRECIATION, DEPLETION AND
     AMORTIZATION (DD&A)
     EXPENSES...................  $104,266,000   $110,916,000        (6)%      $103,157,000         1%
     DD&A rate..................  $       1.12   $       1.12        --        $       0.95        18%
     Mcfe produced..............    91,351,000     97,894,000        (7)%       107,605,000       (15)%
  INTEREST--
     Charges....................  $ 35,874,000   $ 24,682,000        45%       $ 21,886,000        64%
     Capitalized Interest
       Expense..................  $ 17,733,000   $  9,381,000        89%       $  6,175,000       187%
  MINORITY INTEREST -- Dividends
     and costs associated with
     preferred securities of a
     subsidiary trust...........  $  5,914,000             --       N/A                  --       N/A
  FOREIGN CURRENCY TRANSACTION
     GAINS (LOSS)...............  $    572,000   $    953,000       (40)%      $ (7,604,000)      N/A
  INCOME TAX BENEFIT
     (EXPENSE)..................  $ (9,583,000)  $ 27,751,000       N/A        $(18,091,000)      (47)%
</TABLE>

---------------

(a) Production from the Tantawan Field commenced in February 1997, with a
    start-up phase which extended through March 15, 1997. No lease operating
    expenses were incurred in Thailand prior to commencement of production.

  Lease Operating Expenses.

     The increase in North American lease operating expenses for 1999, compared
to 1998, were affected by operating expenses related to the Pogo onshore
pipeline system and other Arch properties for which no corresponding expenses
were recorded during 1998. 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 1999, compared to 1997,
was primarily related to the fact that prior to the commencement of production
in the Tantawan Field on February 1, 1997, no lease operating expenses were
incurred by the Company in Thailand. A substantial portion of the Company's
lease operating expenses in the Kingdom of Thailand relate to lease payments
made 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 $13,619,000, $11,122,000 and $10,200,000 (net to the Company's
interest) of the Company's Thailand lease operating expenses for 1999, 1998 and
1997, respectively. See "-- Liquidity and Capital Resources; Capital
Requirements; Other Material Long-Term Commitments."

                                       27
<PAGE>   29

  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. Prior to the acquisition of the Pogo Onshore
Pipeline interests, the Company did not separately report its pipeline operating
expenses or revenues, nor did it purchase any natural gas for resale to
customers of its pipelines. The increase in pipeline operating expenses and
natural gas purchase costs for 1999, compared to 1998, was primarily related to
the fact that expenses for the pipeline were recorded for all of 1999, whereas
expenses for 1998 did not commence until the pipeline was acquired as part of
the Arch acquisition on August 17, 1998.

  General and Administrative Expenses

     The increase in general and administrative expenses for 1999, compared with
1998, was related to increased expenses associated with the Company's Thailand
operations due to commencement of production from the Benchamas Field, as well
as an increase in the size of the Company's work force and normal salary and
concomitant benefit expense adjustments. The increase in general and
administrative expenses for 1999, compared with 1997, was related to increased
expenses associated with the Company's Thailand operations due to commencement
of production from the Benchamas Field, a number of non-recurring expenses
arising in connection with the Company's acquisition of Arch totaling
approximately $2,285,000, that included severance payments to former officers
and employees of Arch, as well as an increase in the size of the Company's work
force and normal salary and concomitant benefit expense adjustments.

  Exploration Expenses

     Exploration expenses consist primarily of rental payments required under
oil and gas leases to hold non-producing properties ("delay rentals") and
geological and geophysical costs which are expensed as incurred. The decrease in
exploration expenses for 1999, compared to 1998, resulted primarily from
decreased geophysical activity by the Company in most of its operational areas
except Thailand, where the Company participated in a significant 3-D survey of
the remainder of the Thailand Concession and a reprocessing of all of the
seismic data covering the Thailand Concession during 1999, and a decrease in
delay rental payments. The decrease in exploration expenses for 1999, compared
to 1997, resulted primarily from decreased geophysical activity by the Company
in all of its operational areas except Canada, which the Company added as a
result of the Arch acquisition in 1998, and a decrease in delay rental payments.

  Dry Hole and Impairment Expenses

     Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled, along with impairments resulting from the application of SFAS No. 121
due to decreases in expected reserves from producing wells. The decrease in dry
hole and impairment expenses for 1999, 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 a decline in
reserves at the Company's East Cameron Block 334/335 Field and its Keystone
Field located in Winkler County, Texas (which the Company sold at year-end 1998)
and disappointing reservoir performance at the Company's South Pass Block 78
Field, for which no expenses of comparable magnitude were recorded in 1999.

  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

                                       28
<PAGE>   30

there has been impairment of the carrying value, with any such impairment
charged to expense in the period. Proved oil and gas properties are reviewed
when circumstances suggest the need for such a review and, if required, the
proved properties are written down to their estimated fair value. Estimated fair
value includes the estimated present value of all reasonably expected future
production, prices and costs. As a result of poor reservoir performance and
persistent low oil and gas prices, the Company performed such a review in 1998
and expensed $30,813,000 related to its domestic oil and gas properties, which
is included in the Consolidated Statements of Income as dry hole and impairment
expense. Exploratory drilling costs are capitalized until the results are
determined. If proved reserves are 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 decrease in the Company's DD&A expenses for 1999,
compared to 1998, resulted primarily from a decrease in the Company's natural
gas and liquid hydrocarbon production, that was only partially offset by a
slight increase in the Company's composite DD&A rate. The increase in the
Company's DD&A expenses for 1999, compared to 1997, resulted primarily from an
increase in the Company's composite rate, that was not entirely offset by a
decline in the Company's natural gas and liquid hydrocarbon production.

     The increase in the composite DD&A rate for all of the Company's producing
fields for 1999, compared to 1997, resulted primarily from an increased
percentage of the Company's production coming from certain of the Company's
fields that have DD&A rates that are higher than the Company's recent historical
composite rate and a corresponding decrease in the percentage of the Company's
production coming from fields that have DD&A rates that are lower than the
Company's recent historical composite DD&A rate. Management currently
anticipates that this trend, as it relates to currently producing properties,
will continue for the foreseeable future, resulting in generally increasing DD&A
rates for the Company's existing producing properties.

  Interest

     Interest Charges. The increase in the Company's interest charges for 1999,
compared to 1998 and 1997, 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, an increase in the average amount of the
Company's outstanding debt and increased debt issuance expense being amortized.

     Capitalized Interest. The increase in capitalized interest for 1999,
compared to 1998 and 1997, resulted primarily from an increase in the amount of
capital expenditures subject to interest capitalization during 1999
($217,183,000), compared to 1998 ($137,956,000) and 1997 ($96,530,000), and from
an increase in the computed rate that the Company uses to apply on such capital
expenditures to arrive at the total amount of capitalized interest. With the
completion of the Benchamas Field and the Garden Banks Block 367 project in the
Gulf of Mexico in third quarter of 1999, management currently expects that
capitalized interest expense should decrease significantly in the next several
quarters.

  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 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.

                                       29
<PAGE>   31

  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 U.S. 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 U.S. dollar resulting in the gains recorded
for each year. The Company cannot predict what the Thai Baht to U. S. dollar
exchange rate may be in the future. Although it has been relatively stable
throughout much of 1999, the exchange rate could become more volatile again 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 March 3, 2000, the Company was
not a party to any financial instrument that was intended to constitute a
foreign currency hedging arrangement.

  Income Tax Benefit (Expense)

     The Company's income tax expense for 1999 and 1997 resulted primarily from
pre-tax income from the Company's North American operations, that was only
partially offset by tax benefits of 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. The Company's income tax
expense for 1999 was also affected by a pre-tax gain on the sale of the Lopeno
Field and was partially reduced by dividends and costs associated with the Trust
Preferred Securities, for which no corresponding expenses were incurred in 1998
or 1997.

LIQUIDITY AND CAPITAL RESOURCES

  Cash Flows

     The Company's Consolidated Statement of Cash Flows for 1999 reflects net
cash provided by operating activities of $68,757,000. In addition to net cash
provided by operating activities, the Company received net proceeds of
$81,944,000 from the sale of certain non-strategic properties and tubular stock
(including the Lopeno Field and other properties) and $1,115,000 from the
exercise of stock options. In addition, on January 15, 1999, the Company
consummated the offering of $150,000,000 of its 2009 Notes and on June 2, 1999,
it received $150,000,000 in proceeds from the issuance of the Trust Preferred
Securities.

     During 1999, the Company repaid a net $209,947,000 under its senior credit
facility and other senior debt agreements, invested $202,281,000 of such cash
flow in capital projects, spent $19,042,000 to purchase proved reserves, paid
$12,347,000 in debt issuance expenses, paid $4,825,000 ($0.03 per share for each
quarter of 1999) in cash dividends to holders of the Company's common stock and
paid $4,999,999 in cash dividends to holders of its Trust Preferred Securities.
As of December 31, 1999, the Company's cash and cash investments were
$6,267,000, its long-term debt stood at $375,000,000 and it had $150,000,000 in
Trust Preferred Securities outstanding.

  Future Capital Requirements

     The Company's capital and exploration budget for 2000, 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 $200,000,000. The Company
currently anticipates that its available cash and cash investments, cash
provided by operating activities and funds available under its revolving credit
facility and uncommitted credit lines, will be sufficient to fund the Company's
ongoing operating, interest and general and administrative expenses, any
currently anticipated costs associated with the Company's projects during 2000,
and future dividend payments at current levels. The declaration of future
dividends on the Company's common stock will depend upon, among other things,
the

                                       30
<PAGE>   32

Company's future earnings and financial condition, liquidity and capital
requirements, its ability to pay dividends under certain covenants contained in
its debt instruments, the general economic and regulatory climate and other
factors deemed relevant by the Company's Board of Directors.

  Other Material Long-Term Commitments

     As of February 9, 1996, Tantawan Services, L.L.C. ("TS"), a company that is
currently a wholly-owned subsidiary of the Company, entered into a Bareboat
Charter Agreement (the "Charter") with Tantawan Production B.V. for the charter
of the FPSO for use in the Tantawan Field. See "Business -- International
Operations." Effective May 1, 1999, TS assigned the charter to Thaipo and its
joint venture partners (the "Charterers"). The term of the Charter is for a
period ending July 31, 2008, subject to extension. In addition, Thaipo and its
joint venture partners 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.
Performance of both the Charter and the agreement to operate the FPSO are
non-recourse to the Company. 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. The Charter
currently provides for a charter hire commitment of $24,000,000 per year
($11,122,000 net to Thaipo) for the first ten years and a decreasing amount
thereafter.

     As of August 24, 1998, 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 on November 17, 1999. 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 3, 2000, the Company's borrowing base
was set at $160,000,000. 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
$525,000,000), 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 3, 2000, there was
$11,000,000 outstanding under the Credit Facility.

     As of March 3, 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

                                       31
<PAGE>   33

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 3, 2000, there was $10,000,000 outstanding
under the line of credit at an interest rate of 6.65%.

     Banker's Acceptances. The Company has entered into a Master Banker's
Acceptance Agreement under which one of the Company's lenders has offered to
accept up to $20,000,000 in bank drafts from the Company. The banker's drafts
are available on an uncommitted basis and the bank has no obligation to accept
the Company's request for drafts. Drafts drawn under this agreement are
reflected as long-term debt on the Company's balance sheet because the Company
currently has the ability and intent to reborrow such amounts under the Credit
Facility. The Credit Facility limits senior debt, including amounts incurred
under this agreement and debt incurred under the line of credit discussed
previously, to a maximum of $20,000,000. Further, the 2007 Notes and the 2009
Notes offered also restrict the incurrence of additional senior indebtedness.
See "; 2007 Notes" and "; 2009 Notes." The Master Banker's Acceptance Agreement
permits either party to terminate the letter agreement at any time upon five
business days notice. As of December 31, 1999, 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, 1999. The 2006 Notes are convertible into Common Stock at
$42.185 per share, subject to adjustment upon the occurrence of certain events.
The 2006 Notes bear interest at a rate of 5 1/2% and are currently redeemable at
the option of the Company, in whole or in part, at any time, at a redemption
price of 103.85% of their principal. The redemption premium will decline over
the next several years.

     2004 Notes. The Company's 2004 Notes were called for redemption on March
16, 1998, at a price equal to 103.30% of their principal amount. Prior thereto,
holders of all but $95,000 principal amount of the 2004 Notes chose to convert
their 2004 Notes into Common Stock at a conversion price of $22.188 per common
share, rather than receive cash for their 2004 Notes resulting in the issuance
of 3,879,726 shares of Common Stock.

                                       32
<PAGE>   34

     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. The government of the Kingdom of
Thailand and other governments in the region are currently acting to address
these issues. However, the economic difficulties currently being experienced in
Thailand, together with the volatility of the Thai Baht against the U.S. dollar,
will continue to have a material impact on the Company's operations in the
Kingdom of Thailand, together with the prices that the company receives for its
oil and natural gas production there. See "-- Results of Operations; Oil and Gas
Revenues" and "-- Results of Operations; Foreign Currency Transaction Gain
(Loss)."

     All of the Company's current natural gas production from the Thailand
Concession is committed under a long-term Gas Sales Agreement to PTT at a price
denominated in Thai Baht which is determined in accordance with a formula that
is intended to ameliorate, at least in part, any decline in the purchasing power
of the Thai Baht against the U.S. dollar. See "Business -- International
Operations; Contractual Terms Governing the Thailand Concession" and
"Business -- Miscellaneous; Sales." Although the Company

                                       33
<PAGE>   35

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."

     Year 2000 Readiness Disclosure. Many computer software systems, as well as
certain hardware and equipment using date-sensitive data, were structured to use
a two-digit date field meaning that they may not be able to properly recognize
dates in the year 2000. The Company addressed this issue through a process that
entailed evaluation of the Company's critical software and, to the extent
possible, its hardware and equipment to identify and assess Year 2000 issues. It
then remediated, replaced or established alternative procedures addressing
non-Year 2000 compliant systems, hardware and equipment.

     The Year 2000 problem has caused no material disruption to the Company's
facilities or operations, and resulted in no material costs. However, Year
2000-related problems may yet occur due to hidden defects in the Company's or
other third parties' computer hardware or software. The Company currently
anticipates that the Year 2000 problem will not create material disruptions to
its facilities, equipment or operations, and will not create material costs,
however, there can be no assurance that this will in fact be the case.

     The disclosure set forth in this section is provided pursuant to the
Securities Act Release No. 33-7558. As such, it is protected as a
forward-looking statement under the Private Securities Litigation Reform Act of
1995. See "Forward-Looking Statements." This disclosure is also subject to
protection under the Year 2000 Information and Readiness Disclosure Act of 1998,
Public Law 105-271, as a "Year 2000 Statement" and "Year 2000 Readiness
Disclosure" as defined therein.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

     The Company is exposed to market risk, including adverse changes in
commodity prices, interest rates and foreign currency exchange rates as
discussed below.

COMMODITY PRICE RISK

     The Company produces, purchases and sells natural gas, crude oil,
condensate and NGLs. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response to
changing market forces. In the past, the Company has made limited use of a
variety of derivative financial instruments only for non-trading purposes as a
hedging strategy to manage commodity prices associated with oil and gas sales
and to reduce the impact of commodity price fluctuations. See "Business --
Competition and Market Conditions."

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 March 10, 2000, 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

                                       34
<PAGE>   36

by year of maturity for the Company's debt obligations and their indicated fair
market value at December 31, 1999:

<TABLE>
<CAPTION>
                                                                                                      FAIR
                            2000    2001     2002      2003      2004     THEREAFTER     TOTAL       VALUE
                            ----    ----    ------    ------    ------    ----------    --------    --------
<S>                         <C>     <C>     <C>       <C>       <C>       <C>           <C>         <C>
Liabilities -- Long-Term
  Debt:
  Variable Rate...........  $  0    $  0    $1,500    $5,500    $3,000     $      0     $ 10,000    $ 10,000
  Average Interest Rate...   7.3%    7.3%      6.8%      6.8%      6.8%          --          7.3%         --
    Fixed Rate............  $  0    $  0    $    0    $    0    $    0     $365,000     $365,000    $346,631
  Average Interest Rate...    --      --        --        --        --          8.4%         8.4%         --
</TABLE>

FOREIGN CURRENCY EXCHANGE RATE RISK

     The Company conducts business in Thai Baht and the Canadian dollar and is
therefore subject to foreign currency exchange rate risk on cash flows related
to sales, expenses, financing and investing transactions. The Company conducts a
substantial portion of its oil and gas production and sales in Southeast Asia.
Southeast Asia in general, and the Kingdom of Thailand in particular, have
experienced severe economic difficulties, including sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations-Results of Operations; Foreign Currency
Transaction Gain (Loss") and " -- Liquidity and Capital Resources; Other
Matters; Southeast Asia Economic Issues." However, the economic difficulties in
Thailand and the volatility of the Thai Baht against the U.S. dollar will
continue to have a material impact on the Company's Thailand operations and
prices that the Company receives for its oil and gas production there. Although
the Company's sales to PTT under the Gas Sales Agreement are denominated in
Baht, because predominantly all of the Company's crude oil sales and its capital
and most other expenditures in the Kingdom of Thailand are denominated in U.S.
dollars, the U.S. dollar is the functional currency for the Company's operations
in the Kingdom of Thailand. As of March 10, 2000, 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, 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 counterparties 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. The Company accounts for these transactions as hedging activities
and, accordingly, gains or losses are included in oil and gas revenues when the
hedged production is delivered. Neither the hedging contract nor the unrealized
gains and losses on these contracts are recognized in the financial statements.

     Subsequent to December 31, 1999, the Company entered into commodity price
swap transactions for natural gas and crude oil and, during 1999, approximately
7% of the Company's equivalent production was subject to hedge positions. No
significant amounts of hedge positions were held by the Company in prior years.

                                       35
<PAGE>   37

     Natural Gas.  As of December 31,1999, the Company had entered into
commodity price hedging contracts with respect to its natural gas production for
2000 as follows:

<TABLE>
<CAPTION>
                                                    NYMEX CONTRACT PRICE PER
                                                            MMBTU(A)
                                                    -------------------------
                                                                 COLLARS
                                       VOLUME IN            -----------------   FAIR MARKET
               PERIOD                  MMBTU(A)     SWAPS   FLOORS   CEILINGS    VALUE(B)
               ------                 -----------   -----   ------   --------   -----------
<S>                                   <C>           <C>     <C>      <C>        <C>
Price Swap Contracts:
  January 2000 -- March 2000........       910      $3.11      --        --     $  637,000
  January 2000 -- May 2000..........       760      $2.70      --        --     $  243,000
  January 2000 -- August 2000.......     3,660      $2.87      --        --     $1,805,000
Collar Contracts:
  April 2000 -- September 2000......     7,320         --   $2.25     $2.80             --
</TABLE>

---------------

(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, 1999.

     Subsequent to December 31, 1999, the Company entered into natural gas price
swap agreements for the period February 1 through August 31, 2000 for 4,260
MMBtu's at a weighted average fixed price of $2.53 per thousand British Thermal
Units ("MBtu").

     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. With
respect to any particular swap transaction, the counterparty is required to make
a payment to the Company in the event that the settlement price for any
settlement period is less than the swap price for such transaction, and the
Company is required to make payment to the counterparty in the event that the
settlement price for any settlement period is greater than the swap price for
such transaction. For any particular collar transaction, the counterparty 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, and the Company
is required to make payment to the counterparty if the settlement price for any
settlement period is above the ceiling price for such transaction. For any
particular floor transaction, the counterparty 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.

     The Company believes that it has no material basis risk with respect to gas
swaps because it only enters into them with respect to its domestic offshore
natural gas production, substantially all of which is sold under spot contracts
that have historically correlated with the swap price.

     Crude Oil.  As of December 31, 1999, the Company had entered into commodity
price hedging contracts with respect to its crude oil and condensate production
for 2000 as follows:

<TABLE>
<CAPTION>
                                                   NYMEX CONTRACT PRICE PER BBL
                                                   -----------------------------
                                                                   COLLARS
                                       VOLUME IN             -------------------   FAIR MARKET
               PERIOD                    BBLS       SWAPS    FLOORS    CEILINGS     VALUE(A)
               ------                  ---------   -------   -------   ---------   -----------
<S>                                    <C>         <C>       <C>       <C>         <C>
Price Swap Contracts:
  January 2000 -- March 2000.........   136,500    $21.12        --         --      $(544,000)
  January 2000 -- December 2000......   732,000    $21.15        --         --      $(748,000)
Collar Contracts:
  January 2000 -- March 2000.........    91,000        --    $21.15     $23.00      $(191,000)
  April 2000 -- September 2000.......   183,000        --    $21.00     $25.00      $(152,000)
</TABLE>

---------------
(a) Fair Market Value is calculated using prices derived from NYMEX futures
    contract prices existing at December 31, 1999.

                                       36
<PAGE>   38

     Subsequent to December 31, 1999, the Company entered into a crude oil
collar contract is for the period July 1 through December 31, 2000 for 184,000
barrels at $21.00 -- $25.03 per barrel.

     Substantially all of the Company's domestic oil production is sold under
spot contracts that generally correlate to the NYMEX West Texas Intermediate
price. Therefore, the Company believes that it currently has no material basis
risk with respect to these transactions. The actual cash price that the Company
receives, however, varies from the NYMEX West Texas Intermediate price when
adjusted for location, quality and other differences. These differences could
give rise to basis risk in the future.

                                       37
<PAGE>   39

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

                    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,
1999 and 1998, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1999. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.

                                            ARTHUR ANDERSEN LLP

Houston, Texas
February 25, 2000

                                       38
<PAGE>   40

                     POGO PRODUCING COMPANY & SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                              ------------------------------
                                                                1999       1998       1997
                                                              --------   --------   --------
                                                                 (EXPRESSED IN THOUSANDS,
                                                                EXCEPT PER SHARE AMOUNTS)
<S>                                                           <C>        <C>        <C>
REVENUES:
  Oil and gas...............................................  $230,499   $200,154   $284,851
  Pipeline sales and other..................................     7,159      2,741        349
  Gains (losses) on sales...................................    37,458        (92)     1,100
                                                              --------   --------   --------
          Total.............................................   275,116    202,803    286,300
                                                              --------   --------   --------
OPERATING COSTS AND EXPENSES:
  Lease operating...........................................    69,936     69,071     63,501
  Pipeline operating and natural gas purchases..............     6,481      2,142         --
  General and administrative................................    29,865     26,356     21,412
  Exploration...............................................     5,982      9,802     10,530
  Dry hole and impairment...................................     4,594     41,736      9,631
  Depreciation, depletion and amortization..................   104,266    110,916    103,157
                                                              --------   --------   --------
          Total.............................................   221,124    260,023    208,231
                                                              --------   --------   --------
OPERATING INCOME (LOSS).....................................    53,992    (57,220)    78,069
INTEREST:
  Charges...................................................   (35,874)   (24,682)   (21,886)
  Income....................................................     1,208        719        453
  Capitalized...............................................    17,733      9,381      6,175
MINORITY INTEREST -- Dividends and costs associated with
  mandatorily redeemable convertible preferred securities of
  a subsidiary trust........................................    (5,914)        --         --
FOREIGN CURRENCY TRANSACTION GAINS (LOSS)...................       572        953     (7,604)
                                                              --------   --------   --------
INCOME (LOSS) BEFORE TAXES..................................    31,717    (70,849)    55,207
INCOME TAX BENEFIT (EXPENSE)................................    (9,583)    27,751    (18,091)
                                                              --------   --------   --------
NET INCOME (LOSS)...........................................  $ 22,134   $(43,098)  $ 37,116
                                                              ========   ========   ========
EARNINGS (LOSS) PER COMMON SHARE:
  Basic.....................................................  $   0.55   $  (1.14)  $   1.11
                                                              ========   ========   ========
  Diluted...................................................  $   0.55   $  (1.14)  $   1.06
                                                              ========   ========   ========
DIVIDENDS PER COMMON SHARE..................................  $   0.12   $   0.12   $   0.12
                                                              ========   ========   ========
</TABLE>

The accompanying notes to consolidated financial statements are an integral part
                                    hereof.

                                       39
<PAGE>   41

                     POGO PRODUCING COMPANY & SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                              ------------------------
                                                                 1999          1998
                                                              -----------   ----------
                                                              (EXPRESSED IN THOUSANDS)
<S>                                                           <C>           <C>
CURRENT ASSETS:
  Cash and cash equivalents.................................  $     6,267   $    7,959
  Accounts receivable.......................................       37,321       24,054
  Other receivables.........................................       35,870       38,977
  Inventory -- product......................................        7,209          969
  Inventories -- tubulars...................................       10,352       10,594
  Other.....................................................        2,370        2,814
                                                              -----------   ----------
         Total current assets...............................       99,389       85,367
                                                              -----------   ----------
PROPERTY AND EQUIPMENT:
  Oil and gas, on the basis of successful efforts accounting
    Proved properties being amortized.......................    1,638,321    1,485,125
    Unevaluated properties and properties under development,
     not being amortized....................................      144,357      215,244
  Pipelines, at cost........................................        6,984        6,793
  Other, at cost............................................       13,103       11,122
                                                              -----------   ----------
                                                                1,802,765    1,718,284
                                                              -----------   ----------
  Accumulated depreciation, depletion and amortization
    Oil and gas.............................................   (1,006,542)    (985,897)
    Pipelines...............................................       (1,534)      (1,963)
    Other...................................................       (7,329)      (4,899)
                                                              -----------   ----------
                                                               (1,015,405)    (992,759)
                                                              -----------   ----------
  Property and equipment, net...............................      787,360      725,525
                                                              -----------   ----------
OTHER ASSETS:
  Foreign tax net operating losses..........................       16,237       12,546
  Foreign value added taxes receivable......................       12,025       10,456
  Debt issue expenses.......................................       12,686        7,727
  Other.....................................................       20,496       20,775
                                                              -----------   ----------
                                                                   61,444       51,504
                                                              -----------   ----------
                                                              $   948,193   $  862,396
                                                              ===========   ==========
                         LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
  Accounts payable -- operating activities..................  $    21,724   $   12,197
  Accounts payable -- investing activities..................       62,878       90,102
  Accrued interest payable..................................        7,457        3,226
  Accrued dividends associated with preferred securities of
    a subsidiary trust......................................          813           --
  Accrued payroll and related benefits......................        2,149        1,952
  Other.....................................................          208            2
                                                              -----------   ----------
         Total current liabilities..........................       95,229      107,479
LONG-TERM DEBT..............................................      375,000      434,947
DEFERRED FEDERAL INCOME TAX.................................       51,177       53,869
DEFERRED CREDITS............................................       13,524       16,441
                                                              -----------   ----------
         Total liabilities..................................      534,930      612,736
                                                              -----------   ----------
MINORITY INTERESTS:
  Company-obligated mandatorily redeemable convertible
    preferred securities of a subsidiary trust, net of
    unamortized issue expenses..............................      144,751           --
                                                              -----------   ----------
SHAREHOLDERS' EQUITY:
  Preferred stock, $1 par; 2,000,000 shares authorized......           --           --
  Common stock, $1 par; 100,000,000 shares authorized, and
    40,279,661 and 40,136,254 shares issued, respectively...       40,279       40,136
  Additional capital........................................      291,909      290,655
  Retained earnings (deficit)...............................      (62,291)     (79,600)
  Treasury stock (15,575 shares) and other, at cost.........       (1,385)      (1,531)
                                                              -----------   ----------
         Total shareholders' equity.........................      268,512      249,660
                                                              -----------   ----------
                                                              $   948,193   $  862,396
                                                              ===========   ==========
</TABLE>

The accompanying notes to consolidated financial statements are an integral part
                                    hereof.

                                       40
<PAGE>   42

                     POGO PRODUCING COMPANY & SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31,
                                                              -----------------------------------
                                                                 1999         1998        1997
                                                              -----------   ---------   ---------
                                                                   (EXPRESSED IN THOUSANDS)
<S>                                                           <C>           <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Cash received from customers..............................  $   218,936   $ 222,433   $ 272,004
  Federal income taxes received.............................        6,446          --       7,037
  Operating, exploration and general and administrative
    expenses paid...........................................     (105,924)   (116,272)    (86,445)
  Interest paid.............................................      (29,606)    (26,221)    (20,713)
  Federal income taxes paid.................................      (21,000)         --     (19,500)
  Value added taxes received (paid).........................          101      (6,161)     (1,630)
  Other.....................................................         (196)     (2,850)        (21)
                                                              -----------   ---------   ---------
         Net cash provided by operating activities..........       68,757      70,929     150,732
                                                              -----------   ---------   ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures......................................     (202,281)   (201,946)   (197,326)
  Purchase of proved reserves...............................      (19,042)     (2,961)    (31,234)
  Proceeds from the sale of property and tubular stock......       81,944       7,164         387
                                                              -----------   ---------   ---------
         Net cash used in investing activities..............     (139,379)   (197,743)   (228,173)
                                                              -----------   ---------   ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from issuance of new debt........................      150,000          --     100,000
  Proceeds from issuance of new financing...................      150,000          --          --
  Borrowings under senior debt agreements...................      287,053     449,947     502,000
  Payments under senior debt agreements.....................     (497,000)   (313,500)   (500,000)
  Proceeds from exercise of stock options...................        1,115       1,034       3,874
  Payment of cash dividends on common stock.................       (4,825)     (4,531)     (4,012)
  Payment of preferred dividends of a subsidiary trust......       (4,999)         --          --
  Payment of financing issue expenses.......................      (12,347)     (2,635)     (3,165)
  Principal payment of production payment obligation........           --     (15,246)         --
  Other.....................................................           --        (621)         --
                                                              -----------   ---------   ---------
         Net cash provided by financing activities..........       68,997     114,448      98,697
                                                              -----------   ---------   ---------
Effect of exchange rate changes on cash.....................          (67)        679      (4,664)
                                                              -----------   ---------   ---------
Net increase (decrease) in cash and cash equivalents........       (1,692)    (11,687)     16,592
Cash and cash equivalents at the beginning of the year......        7,959      19,646       3,054
                                                              -----------   ---------   ---------
Cash and cash equivalents at the end of the year............  $     6,267   $   7,959   $  19,646
                                                              ===========   =========   =========
RECONCILIATION OF NET INCOME TO NET CASH PROVIDED BY
  OPERATING ACTIVITIES:
  Net income (loss).........................................  $    22,134   $ (43,098)  $  37,116
  Adjustments to reconcile net income to net cash provided
    by operating activities
    Minority interest.......................................        5,914          --          --
    Foreign currency transaction (gain) loss................         (572)       (953)      7,604
    (Gains) losses on sales.................................      (37,458)         92      (1,100)
    Depreciation, depletion and amortization................      104,266     110,916     103,157
    Dry hole and impairment.................................        4,594      41,736       9,631
    Interest capitalized....................................      (17,733)     (9,381)     (6,175)
    (Decrease) increase in deferred income taxes............       (2,410)    (24,250)     12,999
    Change in assets and liabilities:
      (Increase) decrease in accounts receivable............      (13,006)     15,307     (12,483)
      Increase in inventory -- product......................       (6,117)       (259)       (713)
      (Increase) decrease in other current assets...........          453       1,258      (6,470)
      Increase in other assets..............................       (2,886)    (20,551)     (7,418)
      Increase (decrease) in accounts payable...............        9,714      (1,122)      8,998
      Increase in accrued interest payable..................        4,314          95       1,173
      Increase in accrued payroll and related benefits......          201          14         448
      Increase (decrease) in other current liabilities......          210        (637)        469
      Increase (decrease) in deferred credits...............       (2,861)      1,762       3,496
                                                              -----------   ---------   ---------
Net cash provided by operating activities...................  $    68,757   $  70,929   $ 150,732
                                                              ===========   =========   =========
</TABLE>

The accompanying notes to consolidated financial statements are an integral part
                                    hereof.

                                       41
<PAGE>   43

                     POGO PRODUCING COMPANY & SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                                                 TREASURY
                                                                     RETAINED     STOCK      SHARE-
                                  SHARES      COMMON    ADDITIONAL   EARNINGS      AND      HOLDERS'
                                OUTSTANDING    STOCK     CAPITAL     (DEFICIT)    OTHER      EQUITY
                                -----------   -------   ----------   ---------   --------   --------
                                                  (DOLLARS EXPRESSED IN THOUSANDS)
<S>                             <C>           <C>       <C>          <C>         <C>        <C>
BALANCE AT DECEMBER 31,
  1996........................  33,305,806    $33,321    $139,337    $(65,075)   $  (301)   $107,282
Net income....................          --         --          --      37,116         --      37,116
Exercise of stock options.....     229,024        230       5,461          --         --       5,691
Shares issued in connection
  with the conversion of 2004
  Notes.......................       2,297          2          50          --         --          52
Dividends ($0.12 per common
  share)......................          --         --          --      (4,012)                (4,012)
Other.........................          --         --          --          --        (23)        (23)
                                ----------    -------    --------    --------    -------    --------
BALANCE AT DECEMBER 31,
  1997........................  33,537,127     33,553     144,848     (31,971)      (324)    146,106
Net loss......................          --         --          --     (43,098)        --     (43,098)
Exercise of stock options.....     147,240        147       1,835          --         --       1,982
Shares issued in connection
  with the conversion of 2004
  Notes.......................   3,879,726      3,880      80,712          --         --      84,592
Shares issued for stock and
  debt of acquired company....   2,539,582      2,539      62,944          --         --      65,483
Shares issued as
  compensation................      17,004         17         316          --         --         333
Dividends ($0.12 per common
  share)......................          --         --          --      (4,531)                (4,531)
Other.........................          --         --          --          --     (1,207)     (1,207)
                                ----------    -------    --------    --------    -------    --------
BALANCE AT DECEMBER 31,
  1998........................  40,120,679     40,136     290,655     (79,600)    (1,531)    249,660
Net income....................          --         --          --      22,134         --      22,134
Exercise of stock options.....     130,275        130       1,267          --         --       1,397
Adjustment for fractional
  shares and other............      13,132         13         (13)         --         --          --
Dividends ($0.12 per common
  share)......................          --         --          --      (4,825)        --      (4,825)
Other.........................          --         --          --          --        146         146
                                ----------    -------    --------    --------    -------    --------
BALANCE AT DECEMBER 31,
  1999........................  40,264,086    $40,279    $291,909    $(62,291)   $(1,385)   $268,512
                                ==========    =======    ========    ========    =======    ========
</TABLE>

The accompanying notes to consolidated financial statements are an integral part
                                    hereof.

                                       42
<PAGE>   44

                     POGO PRODUCING COMPANY & SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Nature of Operations --

     Pogo Producing Company was incorporated in 1970. Pogo Producing Company and
its subsidiaries (the "Company") are engaged in oil and gas exploration,
development and production activities 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 require 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 and the
resulting gains or losses on Canadian currency transactions are included in the
consolidated statement of shareholders' equity for the period.

  Inventory -- Product

     Crude oil and condensate from the Company's producing fields located in the
Kingdom of Thailand are produced into storage vessels and sold periodically as
economic quantities are accumulated. The product

                                       43
<PAGE>   45
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

inventory at December 31, 1999 and 1998, consists of approximately 287,000 and
90,000 barrels, respectively of crude oil and condensate, net to the Company's
interest, and is carried at its estimated net realizable value of $25.09 and
$10.76 per barrel, respectively.

  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.

  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.

<TABLE>
<CAPTION>
                                                                    FOR THE YEAR ENDED
                                                                    DECEMBER 31, 1999
                                                              ------------------------------
                                                              INCOME     SHARES    PER SHARE
                                                              -------    ------    ---------
<S>                                                           <C>        <C>       <C>
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
</TABLE>

                                       44
<PAGE>   46
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
                                                                    FOR THE YEAR ENDED
                                                                     DECEMBER 31, 1998
                                                              -------------------------------
                                                               INCOME     SHARES    PER SHARE
                                                              --------    ------    ---------
<S>                                                           <C>         <C>       <C>
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE.................  $(43,098)   37,902     $(1.14)
                                                              ========    ======     ======
Antidilutive securities:
  Shares assumed not issued from options to purchase common
     shares as the exercise prices are above the average
     market price for the period or the effect of the
     assumed exercise would be antidilutive.................  $     --     2,464     $19.37
  Interest expense incurred, net of taxes, and shares not
     issued related to the assumed non-conversion at $42.185
     per share of the 2006 Notes............................  $  4,111     2,726     $ 1.51
  Interest expense avoided, net of taxes, and shares issued
     from the assumed conversion at $22.188 per share of the
     2004 Notes.............................................  $    478       594     $ 0.80
</TABLE>

<TABLE>
<CAPTION>
                                                                    FOR THE YEAR ENDED
                                                                    DECEMBER 31, 1997
                                                              ------------------------------
                                                              INCOME     SHARES    PER SHARE
                                                              -------    ------    ---------
<S>                                                           <C>        <C>       <C>
BASIC EARNINGS PER SHARE....................................  $37,116    33,421     $ 1.11
Effect of potential dilutive securities:
  Shares assumed issued from the exercise of options to
     purchase common shares, net of treasury shares assumed
     purchased from the proceeds, at the average market
     price for the period...................................       --       758         --
  Interest expense avoided, net of taxes, and shares issued
     from the assumed conversion at $22.188 per share of the
     2004 Notes.............................................    3,082     3,885         --
                                                              -------    ------     ------
DILUTED EARNINGS PER SHARE..................................  $40,198    38,064     $ 1.06
                                                              =======    ======     ======
Antidilutive securities:
  Shares assumed not issued from options to purchase common
     shares as the exercise prices are above the average
     market price for the period............................  $    --       471     $40.82
  Interest expense incurred, net of taxes, and shares not
     issued related to the assumed non-conversion at $42.185
     per share of the 2006 Notes............................  $ 4,111     2,726     $ 1.51
</TABLE>

  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 "take" (cash) method of accounting for production
imbalances. Under this method, the Company recognizes revenues on production as
it is taken and delivered to its purchasers. The Company's crude oil imbalances
are not significant. At December 31, 1999, the Company had taken approximately
2,289 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 1,853 MMcf more than its entitlement on
other properties placing the Company at year-end in a net under-delivered
position of approximately 436 MMcf of natural gas based on its working interest
ownership in the properties.

  Oil and Gas Activities and Depreciation, Depletion and Amortization --

     The Company follows the successful efforts method of accounting for its oil
and gas activities. Under the successful efforts method, lease acquisition costs
and all development costs are capitalized. Proved properties

                                       45
<PAGE>   47
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

are reviewed whenever events or changes in circumstances indicate that the value
of such property on the Company's books may not be recoverable. Unproved
properties are reviewed quarterly to determine if there has been impairment of
the carrying value, with any such impairment charged to expense in the period.
Proved oil and gas properties are reviewed when circumstances suggest the need
for such a review and, if required, the proved properties are written down to
their estimated fair value. Estimated fair value includes the estimated present
value of all reasonably expected future production, prices, and costs. As a
result of poor reservoir performance and persistent low oil and gas prices, the
Company performed such a review in 1998 and expensed $30,813,000 related to its
domestic oil and gas properties which is included in the Consolidated Statements
of Incomes 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
costs to abandon offshore wells and platforms, and is on a cost center by cost
center basis using the units of production method. The Company generally creates
cost centers on a field by field basis for oil and gas activities in the Gulf of
Mexico and the Gulf of Thailand. Generally, the Company establishes cost centers
on the basis of an oil or gas trend or play for its onshore oil and gas
activities.

     In connection with an ongoing asset rationalization 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 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 following acquisition
section of this note and the Consolidated Statements of Shareholders' Equity
relating to shares issued in connection with the conversion of notes into common
stock in 1997 and 1998, shares issued for stock and debt of an acquired company
in 1998 and shares issued as compensation in 1998.

  Acquisition --

     In August 1998, a wholly owned subsidiary of the Company merged with Arch
Petroleum Inc. ("Arch") in a tax-free, stock for stock transaction accounted for
as a purchase through which Arch became a wholly owned subsidiary of the
Company. 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 following summary presents unaudited pro forma
consolidated results of operations as if the acquisition had occurred at the
beginning of each period presented. The pro forma results are for illustrative
purposes only and are not

                                       46
<PAGE>   48
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31,
                                                              (IN THOUSANDS, EXCEPT PER
                                                                   SHARE AMOUNTS)
                                                              -------------------------
                                                                 1998           1997
                                                              ----------     ----------
                                                                     (UNAUDITED)
<S>                                                           <C>            <C>
Revenues....................................................   $217,915       $366,803
Net income (loss)...........................................   $(48,369)      $ 36,691
Earnings (loss) per share
  Basic.....................................................   $  (1.22)      $   1.02
  Diluted...................................................   $  (1.22)      $   0.98
</TABLE>

  Commitments and Contingencies --

     The Company has commitments for operating leases (primarily for office
space) in Houston, Midland, 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 $1,855,000 in 1999, $1,545,000 in 1998, and $1,440,000 in 1997.
Expenses for the FPSO lease were $11,122,000 in each of the years 1999, 1998 and
1997. Expenses for the floating storage and offloading system ("FSO") (which
commenced in May 1999) were $2,497,000 in 1999 and are expected to be
approximately $3,950,000 in the year 2000 and each year thereafter. Future
minimum office, FPSO and FSO lease expenses (in thousands of dollars) at
December 31, 1999 are as follows:

<TABLE>
<S>                                                          <C>
2000......................................................   $17,100
2001......................................................   $17,000
2002......................................................   $15,400
2003......................................................   $15,200
2004......................................................   $15,300
Thereafter................................................   $52,300
</TABLE>

  Price Risk Management --

     The Company enters into various commodity price hedging contracts with
respect to its oil and gas production. 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 counterparties will be unable to
meet the financial terms of such transactions. Such contracts are accounted for
as hedges, in accordance with Statement of Financial Accounting Standards 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 1999, the Company
recorded hedge gains of $933,000 in connection with its natural gas contracts
and hedge losses of $1,947,000 in connection with its crude oil contracts. 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.

                                       47
<PAGE>   49
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(2) INCOME TAXES

     The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1999, are as follows (expressed in
thousands):

<TABLE>
<CAPTION>
                                                          1999       1998      1997
                                                         -------   --------   -------
<S>                                                      <C>       <C>        <C>
United States..........................................  $40,472   $(57,112)  $62,953
Foreign................................................   (8,755)   (13,737)   (7,746)
                                                         -------   --------   -------
  Income (loss) before income taxes....................  $31,717   $(70,849)  $55,207
                                                         =======   ========   =======
</TABLE>

     The components of federal income tax expense (benefit) for each of the
three years in the period ended December 31, 1999, are as follows (expressed in
thousands):

<TABLE>
<CAPTION>
                                                          1999       1998      1997
                                                         -------   --------   -------
<S>                                                      <C>       <C>        <C>
United States, current.................................  $21,000   $     --   $16,000
United States, deferred................................   (6,978)   (20,750)    5,964
Foreign, deferred......................................   (4,439)    (7,001)   (3,873)
                                                         -------   --------   -------
  Federal income tax expense (benefit).................  $ 9,583   $(27,751)  $18,091
                                                         =======   ========   =======
</TABLE>

     Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1999, 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):

<TABLE>
<CAPTION>
                                                              1999    1998    1997
                                                              ----   ------   ----
<S>                                                           <C>    <C>      <C>
Federal statutory income tax rate...........................  35.0%   (35.0)% 35.0%
Increases (reductions) resulting from:
  Statutory depletion in excess of tax basis................  (0.8)    (0.4)  (0.2)
  Foreign taxes.............................................  (4.1)    (3.8)  (2.1)
  Other.....................................................   0.1       --    0.1
                                                              ----   ------   ----
                                                              30.2%   (39.2)% 32.8%
                                                              ====   ======   ====
</TABLE>

     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

                                       48
<PAGE>   50
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

components of the Company's deferred income tax assets and liabilities at
December 31, 1999 and 1998 (expressed in thousands) are as follows:

<TABLE>
<CAPTION>
                                                                  DECEMBER 31,
                                                              ---------------------
                                                                1999        1998
                                                              ---------   ---------
<S>                                                           <C>         <C>
Deferred federal income tax liability.......................  $  51,177   $  53,869
Other assets -- foreign tax net operating losses............    (16,237)    (12,546)
                                                              ---------   ---------
Net deferred tax liability..................................  $  34,940   $  41,323
                                                              =========   =========
Deferred tax liabilities:
  Intangible drilling costs, capitalized and amortized for
     financial statement purposes and deducted for income
     tax purposes...........................................  $ 162,526   $ 182,760
  Charges to property and equipment, expensed for financial
     statement purposes, and capitalized and amortized for
     income tax purposes....................................     24,254      27,192
  Interest charges, capitalized and amortized for financial
     statement purposes and deducted for income tax
     purposes...............................................     15,037      16,231
                                                              ---------   ---------
                                                                201,817     226,183
                                                              ---------   ---------
Deferred tax asset:
  Differences in depletion and depreciation rates used for
     tangible assets for financial and income tax
     purposes...............................................   (145,630)   (162,017)
  Foreign net operating loss carryforwards..................    (16,237)    (12,546)
  Domestic net operating loss carryforwards.................     (3,979)    (10,116)
  Tax credits and other.....................................     (1,031)       (181)
                                                              ---------   ---------
                                                               (166,877)   (184,860)
                                                              ---------   ---------
Net deferred tax liability..................................  $  34,940   $  41,323
                                                              =========   =========
</TABLE>

     The Company has a federal consolidated net operating loss carryforward for
tax purposes of approximately $11,400,000, which will begin to expire in 2009.
The Company also has a net operating loss carryforward applicable to non-U.S.
subsidiaries of approximately $32,500,000, which will begin to expire in 2007.
The domestic and foreign net operating loss carryforwards are projected to be
utilized before their expiration periods. The benefits of the domestic and
foreign net operating losses have been recognized as deferred tax assets.

                                       49
<PAGE>   51
                     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, 1999 and
1998, consists of the following (dollars expressed in thousands):

<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                              -------------------
                                                                1999       1998
                                                              --------   --------
<S>                                                           <C>        <C>
Senior debt --
  Bank revolving credit agreement:
     LIBO Rate based loans, borrowings at December 31, 1999
       and 1998 at average interest rates of 7.8% and 7.4%,
       respectively.........................................  $  5,000   $205,000
  Uncommitted credit lines with banks, borrowings at
     December 31, 1999 and 1998 at average interest rates of
     5.9% and 6.1%, respectively............................     5,000      4,000
  Banker's acceptance loans, borrowing at December 31, 1998
     at an average interest rate of 5.9%....................        --     10,947
                                                              --------   --------
Total senior debt...........................................    10,000    219,947
                                                              --------   --------
Subordinated debt --
  8 3/4% Senior subordinated notes, due 2007................   100,000    100,000
  10 3/8% Senior subordinated notes, due 2009...............   150,000         --
  5 1/2% Convertible subordinated notes, due 2006...........   115,000    115,000
                                                              --------   --------
Total subordinated debt.....................................   365,000    215,000
                                                              --------   --------
Total debt..................................................   375,000    434,947
                                                              --------   --------
Amount due within one year --...............................        --         --
                                                              --------   --------
Long-term debt..............................................  $375,000   $434,947
                                                              ========   ========
</TABLE>

     The Company entered into a reserve-based credit facility (the "Credit
Facility"), which was amended most recently on November 17, 1999. 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, 1999, the Company's borrowing base was set at $160,000,000. 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 $525,000,000), 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.

     As of December 31, 1999, 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,

                                       50
<PAGE>   52
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

     The Company entered into a Master Banker's Acceptance Agreement under which
one of the Company's lenders has offered to accept up to $20,000,000 in bank
drafts from the Company. The banker's drafts are available on an uncommitted
basis and the bank has no obligation to accept the Company's request for drafts.
Drafts drawn under this agreement are reflected as long-term debt on the
Company's balance sheet because the Company currently has the ability and intent
to reborrow such amounts under the Credit Facility. The Credit Facility limits
senior debt, including amounts incurred under this agreement and debt incurred
under the line of credit discussed previously, to a maximum of $20,000,000.
Further, the 2007 Notes and the 2009 Notes offered also restrict the incurrence
of additional senior debt. The Master Banker's Acceptance Agreement permits
either party to terminate the letter agreement at any time upon five business
days notice.

     On 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 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 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, 1999, $16,516,000 was
available for dividends under this limitation, which is currently the Company's
most restrictive covenant.

     The outstanding principal amount of 2006 Notes was $115,000,000 as of
December 31, 1999. The 2006 Notes are convertible into Common Stock at $42.185
per share subject to adjustment upon the occurrence of certain events. The 2006
Notes bear interest at a rate of 5 1/2% and are currently redeemable at the
option of the Company, in whole or in part, at any time, at a redemption price
of 103.85% of their principal. The redemption premium will decline over the next
several years.

     Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are none in 2000 and 2001,
$1,500,000 in 2002, $5,500,000 in 2003 and $3,000,000 in 2004. All of the
current maturities reflected above are related to the retirement of the
Company's bank debt. The Company has established a history of refinancing its
senior debt before scheduled maturity payments commence and expects to do so
again before the amortization of senior debt commences in 2002.

                                       51
<PAGE>   53
                     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
guarantee 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 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.

(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

                                       52
<PAGE>   54
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and income taxes. The Company's reportable segments are managed separately
because of their geographical locations. Financial information by operating
segment is presented below:

<TABLE>
<CAPTION>
                                                                                          GAINS
                                                        TOTAL       OIL                  (LOSSES)
                                                       COMPANY    AND GAS    PIPELINES   & OTHER
                                                       --------   --------   ---------   --------
                                                                (EXPRESSED IN THOUSANDS)
<S>                                                    <C>        <C>        <C>         <C>
LONG-LIVED ASSETS:
  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
                                                       ========   ========    ======     =======
  As of December 31, 1998:
     United States...................................  $502,787   $493,633    $4,992     $ 4,162
     Kingdom of Thailand.............................   209,552    207,756        --       1,796
     Canada..........................................    13,186     13,083        --         103
                                                       --------   --------    ------     -------
     Total...........................................  $725,525   $714,472    $4,992     $ 6,061
                                                       ========   ========    ======     =======
REVENUES:
  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
                                                       ========   ========    ======     =======
  For the year ended December 31, 1997
     United States...................................  $246,965   $245,458    $   --     $ 1,507
     Kingdom of Thailand.............................    39,335     39,393        --         (58)
                                                       --------   --------    ------     -------
     Total...........................................  $286,300   $284,851    $   --     $ 1,449
                                                       ========   ========    ======     =======
OPERATING INCOME (LOSS):
  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
                                                       ========   ========    ======     =======
  For the year ended December 31, 1997
     United States...................................  $ 83,865   $ 82,358    $   --     $ 1,507
     Kingdom of Thailand.............................    (5,796)    (5,738)       --         (58)
                                                       --------   --------    ------     -------
     Total...........................................  $ 78,069   $ 76,620    $   --     $ 1,449
                                                       ========   ========    ======     =======
</TABLE>

(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.
No customer accounted for more than 10% of the

                                       53
<PAGE>   55
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's sales during 1999. For purposes of comparison, 1999 sales have been
presented for those customers who have in either of the previous two years
exceeded 10% of revenues (expressed in thousands):

<TABLE>
<CAPTION>
                                                           1999      1998      1997
                                                          -------   -------   -------
<S>                                                       <C>       <C>       <C>
Petroleum Authority of Thailand(PTT)....................  $24,315   $23,137   $30,108
Enron Corp. and affiliates..............................  $10,911   $29,539   $57,965
</TABLE>

(7) CREDIT RISK

     Substantially all of the Company's accounts receivable at December 31, 1999
and 1998, 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 1999 or 1998.

     A substantial portion of the Company's oil and gas operations are conducted
in Southeast Asia, and a substantial portion of its natural gas and liquids
hydrocarbon production are sold there. In the last two years, Southeast Asia in
general, and the Kingdom of Thailand in particular, have experienced severe
economic difficulties which have been characterized by sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. The government of the Kingdom of Thailand and other
governments in the region are currently acting to address these issues. However,
the economic difficulties currently being experienced in Thailand, together with
the volatility of the Thai Baht against the U.S. dollar, will continue to have a
material impact on the Company's operations in the Kingdom of Thailand together
with the prices that the Company receives for its oil and natural gas production
there.

     All of the Company's current natural gas production from its Thailand
operations are committed under a long-term Gas Sales Agreement to PTT at a price
denominated in Thai Baht. The Company's crude oil and condensate production from
its Thailand operations is currently sold on a tanker load by tanker load basis.
Prices that the Company receives for such crude oil production are based on
world benchmark prices, which are denominated in U.S. dollars and are generally
expected on future crude oil sales to be paid in U.S. dollars.

(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
2000), and the Company will then match the employee's contribution on a dollar
for dollar basis up to 6% of the employee's salary. Funds contributed by the
employee and the matching funds contributed by the Company are held in trust by
a bank trustee in six separate funds. Amounts contributed by the employee and
earnings and accretions thereon may be used to purchase shares of Common Stock,
invest in a money market fund or invest in four stock, bond, or blended stock
and bond mutual funds according to instructions from the employee. Matching
funds contributed to the savings plan by the Company are invested only in Common
Stock. The Company contributed $963,000 to the savings plan in 1999, $701,000 in
1998, and $588,000 in 1997.

     A trusteed retirement plan has been adopted by the Company for its U.S.
salaried employees. The benefits are based on years of service and the
employee's average compensation for five consecutive years within the final ten
years of service which produce the highest average compensation. The Company
makes annual contributions to the plan in the amount of retirement plan cost
accrued or the maximum amount which can be deducted for federal income tax
purposes. Although the Company has no obligation to do so, the Company currently
provides full medical benefits to its retired U.S. employees and dependents. For
current

                                       54
<PAGE>   56
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1999 and 1998.

<TABLE>
<CAPTION>
                                                                              POST-RETIREMENT
                                                         RETIREMENT PLAN       MEDICAL PLAN
                                                       -------------------   -----------------
                                                         1999       1998      1999      1998
                                                       --------   --------   -------   -------
<S>                                                    <C>        <C>        <C>       <C>
CHANGE IN BENEFIT OBLIGATION
  Benefit obligation at beginning of year............  $ 13,849   $ 11,220   $ 6,284   $ 6,906
     Service cost....................................     1,177        938       489       418
     Interest cost...................................       840        843       418       374
     Participant contributions.......................        --         --         5         4
     Benefits paid...................................      (903)    (2,099)     (213)     (191)
     Actuarial (gain) or loss........................    (3,494)     2,947       104    (1,227)
                                                       --------   --------   -------   -------
  Benefit obligation at end of year..................  $ 11,469   $ 13,849   $ 7,087   $ 6,284
                                                       ========   ========   =======   =======
CHANGE IN PLAN ASSETS
  Fair value of plan assets at beginning of year.....  $ 37,404   $ 31,312   $    --   $    --
     Actual return on plan assets....................     1,075      8,439        --        --
     Employer contributions..........................        --         --       208       187
     Participant contributions.......................        --         --         5         4
     Benefits paid...................................      (903)    (2,099)     (213)     (191)
     Administrative expenses.........................      (277)      (248)       --        --
                                                       --------   --------   -------   -------
  Fair value of plan assets at end of year...........  $ 37,299   $ 37,404   $    --   $    --
                                                       ========   ========   =======   =======
RECONCILIATION OF FUNDED STATUS
  Funded status......................................  $ 25,830   $ 23,555   $(7,087)  $(6,284)
  Unrecognized actuarial gain........................   (14,307)   (14,670)   (1,544)   (1,742)
  Unrecognized transition (asset) or obligation......      (129)      (233)    1,826     2,132
  Unrecognized past service cost.....................      (214)      (257)       --        --
                                                       --------   --------   -------   -------
  Prepaid (accrued) benefit cost at year-end.........  $ 11,180   $  8,395   $(6,805)  $(5,894)
                                                       ========   ========   =======   =======
  Discount rate......................................      7.75%      6.75%     7.75%     6.75%
  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.......................................  $  1,177   $    938   $   489   $   418
  Interest cost......................................       840        843       418       374
  Expected return on plan assets.....................    (3,544)    (2,926)       --        --
  Amortization of prior service cost.................       (43)       (43)       --        --
  Amortization of transition (asset) obligation......      (103)      (104)      305       305
  Recognized actuarial gain..........................    (1,112)      (781)      (93)     (127)
                                                       --------   --------   -------   -------
                                                       $ (2,785)  $ (2,073)  $ 1,119   $   970
                                                       ========   ========   =======   =======
</TABLE>

     For measurement purposes, a 12% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2000. The rate is assumed
to decrease gradually to 5% for 2005 and remain at that level thereafter.

                                       55
<PAGE>   57
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The accumulated post-retirement benefit obligation (in thousands) at
December 31 is attributable to the following groups:

<TABLE>
<CAPTION>
                                                              POST-RETIREMENT
                                                               MEDICAL PLAN
                                                              ---------------
                                                               1999     1998
                                                              ------   ------
<S>                                                           <C>      <C>
Retirees and beneficiaries..................................  $2,703   $2,603
Fully eligible active employees.............................     626      578
Active employees, not fully eligible........................   3,758    3,103
                                                              ------   ------
                                                              $7,087   $6,284
                                                              ======   ======
</TABLE>

     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):

<TABLE>
<CAPTION>
                                                                ONE PERCENTAGE
                                                                     POINT
                                                              -------------------
                                                              INCREASE   DECREASE
                                                              --------   --------
<S>                                                           <C>        <C>
Effect on total of service and interest cost components for
  1999......................................................   $  188     $(148)
Effect on year-end 1999 postretirement benefit obligation...   $1,156     $(946)
</TABLE>

(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 1999, 1998, 1997 and 1996, 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):

<TABLE>
<CAPTION>
                                                          1999       1998      1997
                                                         -------   --------   -------
<S>                                                      <C>       <C>        <C>
Net income (loss):
  As reported..........................................  $22,134   $(43,098)  $37,116
  Pro forma............................................  $20,118   $(44,602)  $34,220
Earnings (loss) per share:
  As reported -- Basic.................................  $  0.55   $  (1.14)  $  1.11
  As reported -- Diluted...............................  $  0.55   $  (1.14)  $  1.06
  Pro forma -- Basic...................................  $  0.51   $  (1.19)  $  1.04
  Pro forma -- Diluted.................................  $  0.51   $  (1.20)  $  0.98
</TABLE>

     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 1999, 1998 and 1997, respectively: risk free interest rates of 5.92%,
5.31% and 6.10%, expected volatility of 42.73%, 35.58% and 34.63%, dividend
yields of 0.63%, 0.64% and 0.29%, and an expected life of the options of 5 years
in 1999, 4 years in 1998 and 1997.

                                       56
<PAGE>   58
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     A summary of the status of the Company's plans as of December 31, 1999,
1998 and 1997, and changes during the years ended on those dates is presented
below:

<TABLE>
<CAPTION>
                                                                           WEIGHTED
                                                                           AVERAGE
                                                              NUMBER OF    EXERCISE
                                                               OPTIONS      PRICE
                                                              ---------    --------
<S>                                                           <C>          <C>
Outstanding, December 31, 1996..............................  1,707,187     $19.70
     Granted in 1997........................................    480,400     $40.49
     Exercised in 1997......................................   (229,024)    $16.83
                                                              ---------
  Outstanding, December 31, 1997............................  1,958,563     $25.13
                                                              =========
  Exercisable, December 31, 1997............................  1,196,803     $18.15
                                                              =========
  Available for grant, December 31, 1997....................    832,993
                                                              =========
  Weighted-average fair value of options granted during
     1997...................................................                $14.63
  Outstanding, December 31, 1997............................  1,958,563     $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............................  1,607,695     $20.11
                                                              =========
  Available for grant, December 31, 1999....................    205,182
                                                              =========
  Weighted-average fair value of options granted during
     1999...................................................                $ 8.31
</TABLE>

                                       57
<PAGE>   59
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following table summarizes information about stock options outstanding
at December 31, 1999:

<TABLE>
<CAPTION>
                                                  OPTIONS OUTSTANDING             OPTIONS EXERCISABLE
                                          ------------------------------------   ----------------------
                                                         WEIGHTED
                                                          AVERAGE
                                                         REMAINING    WEIGHTED                 WEIGHTED
                                                        CONTRACTUAL   AVERAGE                  AVERAGE
                RANGE OF                    NUMBER         LIFE       EXERCISE     NUMBER      EXERCISE
             OPTION PRICES                OUTSTANDING     (DAYS)       PRICE     EXERCISABLE    PRICE
             -------------                -----------   -----------   --------   -----------   --------
<S>                                       <C>           <C>           <C>        <C>           <C>
$ 5.63 to $ 7.81........................     197,085         992       $ 6.53       197,085     $ 6.53
$12.31 to $12.72........................       9,000       3,609       $12.54         1,333     $12.31
$15.13 to $19.56........................   1,697,859       3,347       $18.55       595,494     $17.75
$20.28 to $24.81........................     885,138       2,673       $21.40       609,207     $21.80
$25.38 to $29.06........................      49,962       3,386       $25.72        46,974     $25.52
$30.23 to $33.94........................      30,962       2,709       $33.75        30,641     $33.79
$35.13 to $36.00........................      53,109       2,656       $35.97        52,628     $35.97
$40.62 to $44.00........................      82,500       3,084       $41.00        74,333     $41.04
                                           ---------                              ---------
          Total.........................   3,005,615       2,970       $19.78     1,607,695     $20.11
                                           =========                              =========
</TABLE>

(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. There are no cash equivalents included in the
balances as of December 31, 1999 and 1998.

  Debt

<TABLE>
<CAPTION>
                 INSTRUMENT                             BASIS OF FAIR VALUE ESTIMATE
                 ----------                             ----------------------------
<S>                                             <C>
Bank revolving credit agreement                 Fair value is carrying value as of December
                                                31, 1999 and 1998 based on the market value
                                                interest rates.
Uncommitted credit lines with banks and         Fair value is carrying value as of December
  banker's acceptance loans                     31, 1999 and 1998 based on the market value
                                                interest rates.
2007 Notes                                      Fair value is 97.5% and 94%, of carrying
                                                value as of December 31, 1999 and 1998,
                                                respectively, based on quoted market values.
2009 Notes                                      Fair value is 106% of carrying value as of
                                                December 31, 1999 based on quoted market
                                                value.
2006 Notes                                      Fair value is 78.375% and 68.375%, of
                                                carrying value as of December 31, 1999 and
                                                1998, respectively, based on quoted market
                                                values.
Minority interest in company obligated          Fair value is 101.25% of carrying value as
  preferred securities of a subsidiary trust    of December 31, 1999 based on quoted market
                                                value.
</TABLE>

                                       58
<PAGE>   60
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1999 and 1998 (in thousands of dollars) are as
follows:

<TABLE>
<CAPTION>
                                                         1999                    1998
                                                 ---------------------   ---------------------
                                                 CARRYING      FAIR      CARRYING      FAIR
                                                   VALUE       VALUE       VALUE       VALUE
                                                 ---------   ---------   ---------   ---------
<S>                                              <C>         <C>         <C>         <C>
Cash and cash investments......................  $   6,267   $   6,267   $   7,959   $   7,959
Debt:
  Bank revolving credit agreement..............  $  (5,000)  $  (5,000)  $(205,000)  $(205,000)
  Uncommitted credit lines with banks..........  $  (5,000)  $  (5,000)  $  (4,000)  $  (4,000)
  Banker's acceptance loans....................         --          --   $ (10,947)  $ (10,947)
  2007 Notes...................................  $(100,000)  $ (97,500)  $(100,000)  $ (94,000)
  2009 Notes...................................  $(150,000)  $(159,000)         --          --
  2006 Notes...................................  $(115,000)  $ (90,131)  $(115,000)  $ (78,637)
Minority interest in company obligated
  mandatorily redeemable preferred securities
  of a subsidiary trust,.......................  $(150,000)  $(151,875)         --          --
  net of unamortized issue expenses of.........  $   5,249   $   5,249          --          --
</TABLE>

     The Company occasionally enters into forward and futures contracts to
minimize the impact of oil and gas price fluctuations. However, the Company does
not consider its forward and futures contracts to be financial instruments since
these contracts require or permit settlement by the delivery of the underlying
commodity.

(11) COMPREHENSIVE INCOME

     During 1998, the Company adopted the Financial Accounting Standards Board's
(FASB) Reporting Comprehensive Income ("SFAS 130"). Currently there are no
significant amounts to be included in the computation of comprehensive income of
the Company, as defined, that are required to be disclosed under the provisions
of SFAS 130.

(12) IMPACT OF SFAS 133

     In June 1998, the FASB issued SFAS 133, Accounting for Derivative
Investments and Hedging Activities. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair market value.
The statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge 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.

     In June 1999, the FASB issued SFAS No. 137 which deferred the effective
date of SFAS 133 to fiscal years beginning after June 15, 2000. A company may
implement SFAS 133 as of the beginning of any fiscal quarter after issuance,
however, the statement cannot be applied retroactively. The Company does not
plan to early adopt SFAS No. 133. The Company has not yet quantified the impact
the adoption of SFAS 133 or determined the timing or methods of adoption.

(13) PRICE HEDGE TRANSACTIONS

     During 1999, approximately 7% of the Company's equivalent production was
subject to hedge positions. No significant amounts of hedge positions were held
by the Company in 1998 and 1997.

                                       59
<PAGE>   61
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     As of December 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its natural gas production for 2000 as
follows:

<TABLE>
<CAPTION>
                                                            NYMEX CONTRACT PRICE PER
                                                                    MMBTU(A)
                                                            -------------------------
                                                                         COLLARS
                                                VOLUME IN           -----------------   FAIR MARKET
                    PERIOD                      MMBTU(A)    SWAPS   FLOORS   CEILINGS    VALUE(B)
                    ------                      ---------   -----   ------   --------   -----------
<S>                                             <C>         <C>     <C>      <C>        <C>
Price Swap Contracts
  January 2000 -- March 2000..................      910     $3.11      --        --     $  637,000
  January 2000 -- May 2000....................      760     $2.70      --        --     $  243,000
  January 2000 -- August 2000.................    3,660     $2.87      --        --     $1,805,000
Collar Contracts
  April 2000 -- September 2000................    7,320        --   $2.25     $2.80             --
</TABLE>

     As of December 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its crude oil and condensate production for
2000 as follows:

<TABLE>
<CAPTION>
                                                              NYMEX CONTRACT PRICE
                                                                    PER BBL
                                                           --------------------------
                                                                         COLLARS
                                               VOLUME IN            -----------------   FAIR MARKET
                   PERIOD                        BBLS      SWAPS    FLOORS   CEILINGS    VALUE(B)
                   ------                      ---------   ------   ------   --------   -----------
<S>                                            <C>         <C>      <C>      <C>        <C>
Price Swap Contracts
  January 2000 -- March 2000.................   136,500    $21.12       --        --     $(544,000)
  January 2000 -- December 2000..............   732,000    $21.15       --        --     $(748,000)
Collar Contracts
  January 2000 -- March 2000.................    91,000        --   $21.15    $23.00     $(191,000)
  April 2000 -- September 2000...............   183,000        --   $21.00    $25.00     $(152,000)
</TABLE>

---------------

(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, 1999

     Subsequent to December 31, 1999, the Company entered into additional
commodity price swap transactions for natural gas and crude oil. The natural gas
contracts are for the period February 1 through August 31, 2000 for 4,260
MMBtu's at a weighted average fixed price of $2.53 per MBtu. The crude oil
collar contract is for the period July 1 through December 31, 2000 for 184,000
barrels at $21.00 -- $25.03 per barrel.

     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 (the
"settlement price"). With respect to any particular swap transaction, the
counterparty is required to make a payment to the Company in the event that the
settlement price for any settlement period is less than the swap price for such
transaction, and the Company is required to make payment to the counterparty in
the event that the settlement price for any settlement period is greater than
the swap price for such transaction. For any particular collar transaction, the
counterparty 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,
and the Company is required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price of such
transaction.

                                       60
<PAGE>   62
                     POGO PRODUCING COMPANY & SUBSIDIARIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Except as indicated in the foregoing table, the Company did not have any
basis swaps associated with the indicated hedging contracts. Because
substantially all of the Company's natural gas production is sold under spot
contracts that have historically correlated with the swap price, the Company
believes that it has no material basis risk with respect to gas swaps that are
not coupled with basis swaps. Substantially all of the Company's crude oil and
condensate production is sold under spot contracts that generally correlate to
the NYMEX West Texas Intermediate price. Therefore, the Company believes that it
currently has no material basis risk with respect to these transactions. The
actual cash price the Company receives, however, varies from the NYMEX West
Texas Intermediate price when adjusted for location, quality and other
differences. These differences could give rise to basis risk in the future.

                                       61
<PAGE>   63

                     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.

<TABLE>
<CAPTION>
                                                      TOTAL      UNITED    KINGDOM OF
                                                     COMPANY     STATES     THAILAND    CANADA
                                                    ---------   --------   ----------   -------
                                                             (EXPRESSED IN THOUSANDS)
<S>                                                 <C>         <C>        <C>          <C>
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)    (3,766)     (1,673)      (543)
  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     44,431       3,818       (407)
  Income tax (expense) benefit....................    (16,315)   (16,794)        291        188
                                                    ---------   --------    --------    -------
  Operating results...............................  $  31,527   $ 27,637    $  4,109    $  (219)
                                                    =========   ========    ========    =======
1998:
  Revenues........................................  $ 200,154   $163,438    $ 35,445    $ 1,271
  Lease operating expense.........................    (68,883)   (47,294)    (20,913)      (676)
  Exploration expense.............................     (9,802)    (8,835)       (289)      (678)
  Dry hole and impairment expense.................    (41,736)   (41,736)         --         --
  Depreciation, depletion and amortization
     expense......................................   (109,288)   (85,969)    (22,753)      (566)
                                                    ---------   --------    --------    -------
  Pretax operating results........................    (29,555)   (20,396)     (8,510)      (649)
  Income tax benefit..............................     11,916      7,401       4,255        260
                                                    ---------   --------    --------    -------
  Operating results...............................  $ (17,639)  $(12,995)   $ (4,255)   $  (389)
                                                    =========   ========    ========    =======
1997:
  Revenues........................................  $ 284,851   $245,458    $ 39,393    $    --
  Lease operating expense.........................    (63,501)   (43,934)    (19,567)        --
  Exploration expense.............................    (10,530)    (6,242)     (4,288)        --
  Dry hole and impairment expense.................     (9,631)    (9,631)         --         --
  Depreciation, depletion and amortization
     expense......................................   (101,273)   (84,443)    (16,830)        --
                                                    ---------   --------    --------    -------
  Pretax operating results........................     99,916    101,208      (1,292)        --
  Income tax (expense) benefit....................    (30,353)   (32,390)      2,037         --
                                                    ---------   --------    --------    -------
  Operating results...............................  $  69,563   $ 68,818    $    745    $    --
                                                    =========   ========    ========    =======
</TABLE>

                                       62
<PAGE>   64
                     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.

<TABLE>
<CAPTION>
                                                      TOTAL      UNITED    KINGDOM OF
                                                     COMPANY     STATES     THAILAND    CANADA
                                                     --------   --------   ----------   -------
<S>                                                  <C>        <C>        <C>          <C>
Costs incurred
  (capitalized unless otherwise indicated):
  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
                                                     ========   ========    ========    =======
  1997:
     Property acquisition
       Proved......................................  $ 31,234   $  2,617    $ 28,617    $    --
       Unproved....................................    11,875     11,875          --         --
     Exploration
       Capitalized.................................    45,203     24,016      21,187         --
       Expensed....................................    10,530      6,242       4,288         --
     Development...................................   156,764     95,768      60,996         --
     Interest......................................     6,175      3,427       2,748         --
                                                     --------   --------    --------    -------
     Total oil and gas costs incurred..............  $261,781   $143,945    $117,836    $    --
                                                     ========   ========    ========    =======
  Provision for depreciation, depletion and
     amortization..................................  $101,273   $ 84,443    $ 16,830    $    --
                                                     ========   ========    ========    =======
</TABLE>

     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

                                       63
<PAGE>   65
                     POGO PRODUCING COMPANY & SUBSIDIARIES

             UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)

"Item 1. Business -- Exploration and Production Data -- Reserves" should be
referred to in connection with the following information.

                          ESTIMATES OF PROVED RESERVES

<TABLE>
<CAPTION>
                                                OIL, CONDENSATE AND NATURAL GAS LIQUIDS (BBLS.)
                                                -----------------------------------------------
                                                  TOTAL        UNITED     KINGDOM OF
                                                 COMPANY       STATES      THAILAND     CANADA
                                                ----------   ----------   ----------   --------
<S>                                             <C>          <C>          <C>          <C>
Proved Reserves as of December 31, 1996.......  49,602,182   28,270,402   21,331,780         --
  Revisions of previous estimates.............   1,033,664    2,194,936   (1,161,272)        --
  Extensions, discoveries and other
     additions................................   9,316,407    4,649,856    4,666,551         --
  Purchase of properties......................   5,175,501      409,428    4,766,073         --
  Sale of properties..........................      (6,155)      (6,155)          --         --
  Estimated 1997 production...................  (6,957,246)  (6,136,957)    (820,289)        --
                                                ----------   ----------   ----------   --------
Proved Reserves as of December 31, 1997.......  58,164,353   29,381,510   28,782,843         --
  Revisions of previous estimates.............    (263,410)   1,316,467   (1,417,472)  (162,405)
  Extensions, discoveries and other
     additions................................  10,111,879    2,767,537    7,341,791      2,551
  Purchase of properties......................   6,226,804    5,496,985           --    729,819
  Sale of properties..........................     (28,024)     (28,024)          --         --
  Estimated 1998 production...................  (6,702,038)  (5,724,933)    (896,200)   (80,905)
                                                ----------   ----------   ----------   --------
Proved Reserves as of December 31, 1998.......  67,509,564   33,209,542   33,810,962    489,060
  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
                                                ==========   ==========   ==========   ========
Proved Developed Reserves as of:
  December 31, 1996...........................  31,090,407   25,898,414    5,191,993         --
  December 31, 1997...........................  33,149,612   26,167,519    6,982,093         --
  December 31, 1998...........................  33,368,347   28,581,175    4,298,112    489,060
  December 31, 1999...........................  53,894,653   35,136,156   18,407,852    350,645
</TABLE>

                                       64
<PAGE>   66
                     POGO PRODUCING COMPANY & SUBSIDIARIES

             UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)

<TABLE>
<CAPTION>
                                                                  NATURAL GAS (MMCF)
                                                        ---------------------------------------
                                                         TOTAL    UNITED    KINGDOM OF
                                                        COMPANY   STATES     THAILAND    CANADA
                                                        -------   -------   ----------   ------
<S>                                                     <C>       <C>       <C>          <C>
Proved Reserves as of December 31, 1996...............  360,944   215,946    144,998         --
  Revisions of previous estimates.....................  (16,860)   (5,582)   (11,278)        --
  Extensions, discoveries and other additions.........   92,063    49,651     42,412         --
  Purchase of properties..............................   30,319     8,919     21,400         --
  Sale of properties..................................   (1,864)   (1,864)        --         --
  Estimated 1997 production...........................  (63,114)  (50,350)   (12,764)        --
                                                        -------   -------    -------     ------
Proved Reserves as of December 31, 1997...............  401,488   216,720    184,768         --
  Revisions of previous estimates.....................  (13,376)    7,391    (17,943)    (2,824)
  Extensions, discoveries and other additions.........   70,649    55,859     14,418        372
  Purchase of properties..............................   38,689    32,259         --      6,430
  Sale of properties..................................   (2,738)   (2,738)        --         --
  Estimated 1998 production...........................  (54,543)  (41,136)   (12,854)      (553)
                                                        -------   -------    -------     ------
Proved Reserves as of December 31, 1998...............  440,169   268,355    168,389      3,425
  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
                                                        =======   =======    =======     ======
Proved Developed Reserves as of:
  December 31, 1996...................................  238,032   192,034     45,998         --
  December 31, 1997...................................  239,732   179,972     59,760         --
  December 31, 1998...................................  225,054   181,205     40,424      3,425
  December 31, 1999...................................  245,257   156,398     88,041        818
</TABLE>

                                       65
<PAGE>   67

                     POGO PRODUCING COMPANY & SUBSIDIARIES

                   STANDARDIZED MEASURE OF DISCOUNTED FUTURE
       NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED

<TABLE>
<CAPTION>
                                                                      1999
                                                 ----------------------------------------------
                                                   TOTAL        UNITED     KINGDOM OF
                                                  COMPANY       STATES      THAILAND    CANADA
                                                 ----------   ----------   ----------   -------
                                                            (EXPRESSED IN THOUSANDS)
<S>                                              <C>          <C>          <C>          <C>
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
                                                 ==========   ==========   ==========   =======
</TABLE>

<TABLE>
<CAPTION>
                                                                      1998
                                                 ----------------------------------------------
<S>                                              <C>          <C>          <C>          <C>
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
                                                 ==========   ==========   ==========   =======
</TABLE>

<TABLE>
<CAPTION>
                                                                      1997
                                                 ----------------------------------------------
<S>                                              <C>          <C>          <C>          <C>
Future gross revenues..........................  $1,801,254   $1,002,609   $  798,645   $    --
Future production costs:
  Lease operating expense......................    (604,665)    (269,505)    (335,160)       --
Future development and abandonment costs.......    (401,970)    (155,179)    (246,791)       --
                                                 ----------   ----------   ----------   -------
Future net cash flows before income taxes......     794,619      577,925      216,694        --
Discount at 10% per annum......................    (331,838)    (171,764)    (160,074)       --
                                                 ----------   ----------   ----------   -------
Discounted future net cash flow before income
  taxes........................................     462,781      406,161       56,620        --
Future income taxes, net of discount at 10% per
  annum........................................    (113,316)     (93,386)     (19,930)       --
                                                 ----------   ----------   ----------   -------
Standardized measure of discounted future net
  cash flows relating to proved oil and gas
  reserves.....................................  $  349,465   $  312,775   $   36,690   $    --
                                                 ==========   ==========   ==========   =======
</TABLE>

     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.

                                       66
<PAGE>   68
                     POGO PRODUCING COMPANY & SUBSIDIARIES

                   STANDARDIZED MEASURE OF DISCOUNTED FUTURE
                  NET CASH FLOWS RELATED TO PROVED OIL AND GAS
                      RESERVES -- UNAUDITED -- (CONTINUED)

          2. The estimated future gross revenues from proved reserves are priced
     on the basis of year end prices, except in those instances where fixed and
     determinable natural gas price escalations are covered by contracts.

          3. The future gross revenue streams are reduced by estimated future
     costs to develop and to produce the proved reserves, as well as certain
     abandonment costs based on year end cost estimates, and the estimated
     effect of future income taxes. These cost estimates are subject to some
     uncertainty, particularly those estimates relating to the Company's
     properties located in the Kingdom of Thailand.

     The standardized measure of discounted future net cash flows does not
purport to present the fair market value of the Company's oil and gas reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.

     The following are the principal sources of change in the standardized
measure of discounted future net cash flows. All amounts are related to changes
in reserves located in the United States, the Kingdom of Thailand, and Canada,
as noted.

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31, 1999
                                                   --------------------------------------------
                                                     TOTAL      UNITED     KINGDOM OF
                                                    COMPANY     STATES      THAILAND    CANADA
                                                   ---------   ---------   ----------   -------
                                                             (EXPRESSED IN THOUSANDS)
<S>                                                <C>         <C>         <C>          <C>
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
                                                   =========   =========   =========    =======
</TABLE>

                                       67
<PAGE>   69
                     POGO PRODUCING COMPANY & SUBSIDIARIES

                   STANDARDIZED MEASURE OF DISCOUNTED FUTURE
                  NET CASH FLOWS RELATED TO PROVED OIL AND GAS
                      RESERVES -- UNAUDITED -- (CONTINUED)

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31, 1998
                                                    -------------------------------------------
                                                      TOTAL      UNITED     KINGDOM OF
                                                     COMPANY     STATES      THAILAND    CANADA
                                                    ---------   ---------   ----------   ------
                                                             (EXPRESSED IN THOUSANDS)
<S>                                                 <C>         <C>         <C>          <C>
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
                                                    =========   =========   =========    ======
</TABLE>

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31, 1997
                                                    -------------------------------------------
                                                      TOTAL      UNITED     KINGDOM OF
                                                     COMPANY     STATES      THAILAND    CANADA
                                                    ---------   ---------   ----------   ------
                                                             (EXPRESSED IN THOUSANDS)
<S>                                                 <C>         <C>         <C>          <C>
Beginning balance.................................  $ 686,040   $ 560,221   $ 125,819    $   --
Revisions to prior years' proved reserves:
  Net changes in prices and production costs......   (473,086)   (344,493)   (128,593)       --
  Net changes due to revisions in quantity
     estimates....................................    (18,624)      9,619     (28,243)       --
  Net changes in estimates of future development
     costs........................................    (83,170)    (75,649)     (7,521)       --
  Accretion of discount...........................     95,455      77,313      18,142        --
  Changes in production rate and other............    (31,132)     (4,518)    (26,614)       --
                                                    ---------   ---------   ---------    ------
     Total revisions..............................   (510,557)   (337,728)   (172,829)       --
New field discoveries and extensions, net of
  future production and development costs.........     79,258      76,687       2,571        --
Purchases of properties...........................     10,189       5,899       4,290        --
Sales of properties...............................     (6,069)     (6,069)         --        --
Sales of oil and gas produced, net of production
  costs...........................................   (221,350)   (201,524)    (19,826)       --
Previously estimated development costs incurred...    156,764      95,768      60,996        --
Net change in income taxes........................    155,190     119,521      35,669        --
                                                    ---------   ---------   ---------    ------
       Net change in standardized measure of
          discounted future net cash flows........   (336,575)   (247,446)    (89,129)       --
                                                    ---------   ---------   ---------    ------
Ending balance....................................  $ 349,465   $ 312,775   $  36,690    $   --
                                                    =========   =========   =========    ======
</TABLE>

                                       68
<PAGE>   70

QUARTERLY RESULTS -- UNAUDITED

     Summaries of the Company's results of operations by quarter for the years
1999 and 1998 are as follows:

<TABLE>
<CAPTION>
                                                                    QUARTER ENDED
                                                 ---------------------------------------------------
                                                 MARCH 31    JUNE 30    SEPTEMBER 30    DECEMBER 31
                                                 ---------   --------   -------------   ------------
                                                 (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                              <C>         <C>        <C>             <C>
1999
Revenues.......................................   $76,046(c) $44,828       $69,138        $ 85,104
Gross profit (a)...............................   $33,987    $ 5,116       $18,912        $ 25,842
Net income (loss)..............................   $14,313    $(3,006)      $ 2,737        $  8,090
Earnings (loss) per share (b):
  Basic........................................   $  0.36    $ (0.07)      $  0.07        $   0.20
  Diluted......................................   $  0.36    $ (0.07)      $  0.07        $   0.20
1998
Revenues.......................................   $60,730    $52,663       $46,179        $ 43,231
Gross profit (loss)(a).........................   $ 8,621    $ 4,758       $(3,908)       $(40,335)
Net income (loss)..............................   $   184    $(2,668)      $(8,322)       $(32,292)(d)
Earnings (loss) per share (b):
  Basic........................................   $  0.01    $ (0.07)      $ (0.22)       $  (0.80)
  Diluted......................................   $  0.01    $ (0.07)      $ (0.22)       $  (0.80)
</TABLE>

---------------

(a) Represents revenues less lease operating, pipeline operating and natural gas
    purchases, exploration, dry hole, and impairment, and depreciation,
    depletion and amortization expenses.

(b) The sum of the individual quarterly earnings (loss) per share may not agree
    with year-to-date earnings (loss) per share as each quarterly computation is
    based on the weighted average number of common shares outstanding during
    that period.

(c) Revenues for the first quarter of 1999 include $37,344,000 related to gains
    on the sales of properties.

(d) The net loss for the fourth quarter of 1998 includes an impairment charge of
    approximately $24,500,000 resulting from poor reservoir performance and
    persistent low oil and gas prices.

ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

     Not applicable.

                                    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
25, 2000, to be filed within 120 days of December 31, 1999 pursuant to
Regulation 14A under the Securities Exchange Act of 1934, as amended (the
Company's "2000 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 2000
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 2000 Proxy Statement is
incorporated herein by reference.

                                       69
<PAGE>   71

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     The information regarding certain relationships and related transactions
with management in the Company's 2000 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

<TABLE>
<CAPTION>
                                                                     PAGE
                                                                     ----
<S>  <C>                                                             <C>
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.......................     41
     Consolidated statements of shareholders' equity.............     42
     Notes to consolidated financial statements..................     43
     Unaudited supplementary financial data......................     62
</TABLE>

     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.

     3. EXHIBITS:

<TABLE>
<C>                      <S>
          *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).
</TABLE>

                                       70
<PAGE>   72

<TABLE>
<S>                        <C>
            *4.4           -- 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).
            *4.5           -- 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).
            *4.6           -- 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).
            *4.7           -- 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).
            *4.8           -- 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).
            *4.9           -- 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).
            *4.10          -- 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).
            *4.11          -- 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, 1999. Pogo Producing Company hereby agrees to furnish to the Commission a copy of any such
        debt instrument upon request.

                EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (COMPRISING EXHIBITS 10.1 THROUGH 10.37, 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).
</TABLE>

                                       71
<PAGE>   73
<TABLE>
<C>                      <S>
         *10.6           -- Executive Employment Agreement by and between Pogo
                            Producing Company and Stuart P. Burbach, dated February
                            1, 1996 (Exhibit 10(f)(1), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.7           -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Stuart P. Burbach, dated effective February 1, 1999
                            (Exhibit 10.7, Annual Report on Form 10-K for the year
                            ended December 31, 1999, 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, 2000.
         *10.9           -- 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).
         *10.10          -- 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).
          10.11          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Jerry
                            A. Cooper, dated effective February 1, 2000.
         *10.12          -- Executive Employment Agreement by and between Pogo
                            Producing Company and Kenneth R. Good, dated February 1,
                            1996 (Exhibit 10(f)(3), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.13          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Kenneth R. Good, dated effective February 1, 1999
                            (Exhibit 10.11, Annual Report on Form 10-K for the year
                            ended December 31, 1999, File No. 001-7792).
          10.14          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Kenneth R. Good, dated effective February 1, 2000.
         *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.
         *10.18          -- 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).
         *10.19          -- 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).
</TABLE>

                                       72
<PAGE>   74
<TABLE>
<C>                      <S>
          10.20          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and John
                            O. McCoy, dated effective February 1, 2000.
         *10.21          -- Executive Employment Agreement by and between Pogo
                            Producing Company and Paul G. Van Wagenen, dated February
                            1, 1996 (Exhibit 10(f)(6), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.22          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Paul
                            G. Van Wagenen, dated effective February 1, 1999 (Exhibit
                            10.17, Annual Report on Form 10-K for the year ended
                            December 31, 1999, File No. 001-7792).
          10.23          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Paul
                            G. Van Wagenen, dated effective February 1, 2000.
         *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.
         *10.27          -- 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).
          10.28          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and David
                            R. Beathard, dated effective February 1, 2000.
         *10.29          -- 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).
          10.30          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Stephen R. Brunner, dated effective February 1, 2000.
         *10.31          -- 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).
          10.32          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and J. D.
                            McGregor, dated effective February 1, 2000.
         *10.33          -- 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).
          10.34          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Gerald A. Morton, dated effective February 1, 2000.
          10.35          -- Executive Employment Agreement by and between Pogo
                            Producing Company and James P. Ulm, II, dated as of
                            February 1, 2000.
</TABLE>

                                       73
<PAGE>   75
<TABLE>
<C>                      <S>
         *10.36          -- Excess Benefits Letter Agreement by and between Pogo
                            Producing Company and Kenneth R. Good, dated March 2,
                            1995 (Exhibit 10(g)(1), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.37          -- 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).
         *10.38          -- 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).
         *10.39          -- 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).
         *10.40          -- 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).
         *10.41          -- 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, 1999.
          27             -- Financial Data Schedule.
</TABLE>

---------------

* Asterisk indicates exhibits incorporated by reference as shown.

     (b) Reports on Form 8-K

        None

                                       74
<PAGE>   76

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                            POGO PRODUCING COMPANY
                                            (REGISTRANT)

                                            By:   /s/ PAUL G. VAN WAGENEN
                                              ----------------------------------
                                                     Paul G. Van Wagenen
                                               Chairman of the Board, President
                                                              and
                                                   Chief Executive Officer

Date: March 17, 2000

     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 17, 2000.

<TABLE>
<CAPTION>
                     SIGNATURES                                              TITLE
                     ----------                                              -----
<C>                                                      <S>
               /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
-----------------------------------------------------
                   Tobin Armstrong

                          *                              Director
-----------------------------------------------------
                   Jack S. Blanton

                          *                              Director
-----------------------------------------------------
                 W. M. Brumley, Jr.

                          *                              Director
-----------------------------------------------------
                 Robert H. Campbell

                          *                              Director
-----------------------------------------------------
                  William L. Fisher

                          *                              Director
-----------------------------------------------------
                   Gerrit W. Gong
</TABLE>

                                       75
<PAGE>   77

<TABLE>
<CAPTION>
                     SIGNATURES                                              TITLE
                     ----------                                              -----
<C>                                                      <S>
                          *                              Director
-----------------------------------------------------
                   J. Stuart Hunt

                          *                              Director
-----------------------------------------------------
              Frederick A. Klingenstein

                          *                              Director
-----------------------------------------------------
                   Jack A. Vickers

                          *                              Director
-----------------------------------------------------
                  Stephen A. Wells
</TABLE>

*By:      /s/ THOMAS E. HART
     -------------------------------
             Thomas E. Hart
            Attorney-in-Fact

                                       76
<PAGE>   78

         INDEX TO EXHIBITS

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          *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           -- 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).
          *4.5           -- 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).
          *4.6           -- 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).
          *4.7           -- 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).
          *4.8           -- 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).
          *4.9           -- 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).
          *4.10          -- 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).
</TABLE>
<PAGE>   79

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          *4.11          -- 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, 1999. Pogo Producing Company hereby
        agrees to furnish to the Commission a copy of any such debt instrument upon
                                                                 request.
                EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (COMPRISING EXHIBITS
                                          10.1 THROUGH 10.37, 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           -- Executive Employment Agreement by and between Pogo
                            Producing Company and Stuart P. Burbach, dated February
                            1, 1996 (Exhibit 10(f)(1), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.7           -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Stuart P. Burbach, dated effective February 1, 1999
                            (Exhibit 10.7, Annual Report on Form 10-K for the year
                            ended December 31, 1999, 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, 2000.
         *10.9           -- 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).
         *10.10          -- 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).
          10.11          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Jerry
                            A. Cooper, dated effective February 1, 2000.
</TABLE>
<PAGE>   80

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         *10.12          -- Executive Employment Agreement by and between Pogo
                            Producing Company and Kenneth R. Good, dated February 1,
                            1996 (Exhibit 10(f)(3), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.13          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Kenneth R. Good, dated effective February 1, 1999
                            (Exhibit 10.11, Annual Report on Form 10-K for the year
                            ended December 31, 1999, File No. 001-7792).
          10.14          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Kenneth R. Good, dated effective February 1, 2000.
         *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.
         *10.18          -- 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).
         *10.19          -- 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).
          10.20          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and John
                            O. McCoy, dated effective February 1, 2000.
         *10.21          -- Executive Employment Agreement by and between Pogo
                            Producing Company and Paul G. Van Wagenen, dated February
                            1, 1996 (Exhibit 10(f)(6), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.22          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Paul
                            G. Van Wagenen, dated effective February 1, 1999 (Exhibit
                            10.17, Annual Report on Form 10-K for the year ended
                            December 31, 1999, File No. 001-7792).
          10.23          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Paul
                            G. Van Wagenen, dated effective February 1, 2000.
         *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).
</TABLE>
<PAGE>   81

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          10.26          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and Bruce
                            E. Archinal, dated effective February 1, 2000.
         *10.27          -- 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).
          10.28          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and David
                            R. Beathard, dated effective February 1, 2000.
         *10.29          -- 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).
          10.30          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Stephen R. Brunner, dated effective February 1, 2000.
         *10.31          -- 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).
          10.32          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and J. D.
                            McGregor, dated effective February 1, 2000.
         *10.33          -- 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).
          10.34          -- Extension Agreement to Continue Executive Employment
                            Agreement by and between Pogo Producing Company and
                            Gerald A. Morton, dated effective February 1, 2000.
          10.35          -- Executive Employment Agreement by and between Pogo
                            Producing Company and James P. Ulm, II, dated as of
                            February 1, 2000.
         *10.36          -- Excess Benefits Letter Agreement by and between Pogo
                            Producing Company and Kenneth R. Good, dated March 2,
                            1995 (Exhibit 10(g)(1), Annual Report on Form 10-K for
                            the year ended December 31, 1995, File No. 001-7792).
         *10.37          -- 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).
         *10.38          -- 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).
         *10.39          -- 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).
         *10.40          -- 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).
</TABLE>
<PAGE>   82

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         *10.41          -- 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, 1999.
          27             -- Financial Data Schedule.
</TABLE>

---------------

* Asterisk indicates exhibits incorporated by reference as shown.