<PAGE>   1
 
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
 
                       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, 1995
 
[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934
 
                             COMMISSION FILE NO. 1-7792
 
                             POGO PRODUCING COMPANY
             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
 
<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 Stock Exchange

Preferred Stock Purchase Rights               New York Stock Exchange
8% Convertible Subordinated                   New York Stock Exchange
  Debentures due December 31, 2005

5 1/2% Convertible Subordinated               New York Stock Exchange
  Notes due March 15, 2004
</TABLE>
 
        SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
 
     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 $1,007,572,356 as of March 1, 1996 (based on $33.25 per share, the
last sale price of the Common Stock as reported on the New York Stock Exchange
Composite Tape on such date).
 
     33,073,045 shares of the registrant's Common Stock were outstanding as of
March 1, 1996.
 
                       DOCUMENT INCORPORATED BY REFERENCE
 
     Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 23, 1996 (to be filed not later than
120 days after December 31, 1995) are incorporated by reference in Part III of
this Form 10-K.
 
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>   2
 
                                     PART I
 
ITEM 1. BUSINESS.
 
     Pogo Producing Company (the "Company"), incorporated in 1970, is engaged in
oil and gas exploration, development and production activities on its properties
located offshore in the Gulf of Mexico and onshore in the United States. The
Company is also engaged in exploration of its license concession in the Gulf of
Thailand, and has commenced, with its joint venture partners, a development
program in connection with its oil and gas discoveries on that concession. As of
December 31, 1995, the Company had interests in 78 lease blocks offshore
Louisiana and Texas, approximately 151,000 gross acres onshore in the United
States and approximately 1,300,000 gross acres offshore in the Kingdom of
Thailand.
 
DOMESTIC OFFSHORE OPERATIONS
 
     Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 73% of the Company's domestic proved reserves and
43% of its total proved reserves are now located. During 1995, approximately 86%
of the Company's natural gas production and 67% of its oil and condensate
production was from its domestic offshore properties, contributing approximately
78% of consolidated oil and gas revenues. Five offshore producing areas, Eugene
Island, Main Pass, South Pass, East Cameron and South Marsh Island, account for
approximately 36% of the Company's net proved natural gas reserves and
approximately 37% of the Company's proved crude oil, condensate and natural gas
liquids reserves. Eugene Island is the Company's largest producing area with
1995 average net revenue production (net to the Company's interest and net of
royalty burdens) of approximately 51.5 million cubic feet ("MMcf") per day of
natural gas and 4,800 barrels ("Bbls") per day of oil, condensate and natural
gas liquids. The table in Item 2 of this Annual Report on Form 10-K for the year
ended December 31, 1995 (this "Annual Report") summarizes the Company's offshore
leasehold interests, drilling activity, and platforms set or announced as of
December 31, 1995.
 
  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 sales and subsequent
activities, as of December 31, 1995, the Company owned interests in 71 federal
leases and 7 state leases offshore Louisiana and Texas. Federal leases generally
have primary terms of five years and state leases generally have terms of three
years, 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 1995, the Company was successful in acquiring
interests in eleven lease blocks, Vermilion 346, Main Pass 207, 212 and 213,
South Timbalier 316 and 317, South Pass 73, Mississippi Canyon 64 and High
Island A-94, A-95 and A-377, through federal Outer Continental Shelf oil and gas
lease sales and one block, Main Pass 76, through the State of Louisiana's state
waters lease sale. The Department of the Interior has announced its intention to
hold two lease sales during 1996 covering federal acreage in the Central and
Western portions of the Gulf of Mexico; and it is anticipated that various
states will also hold sales covering offshore state acreage from time to time.
As in the case of prior sales, the extent to which the Company participates in
future bidding will depend on the availability of funds and its estimates of
hydrocarbon deposits, operating expenses and future revenues which reasonably
may be expected from available lease blocks. Such estimates typically take into
account, among other things, estimates of future hydrocarbon prices, federal
regulations, and taxation policies applicable to the petroleum industry.
 
     It is also the Company's objective to acquire certain producing leasehold
properties in areas where additional low-risk drilling or improved production
methods by the Company can provide attractive rates of return. During 1995, the
Company acquired additional working interests in portions of three federal lease
blocks in the South Pass, Main Pass and East Cameron areas of the Gulf of
Mexico.
 
                                        1
<PAGE>   3
 
  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 1995 were approximately $37,800,000 (excluding approximately $650,000 of net
property acquisitions), or 22% lower than the Company's domestic offshore
capital and exploration expenditures of approximately $48,400,000 (excluding
approximately $32,600,000 of net property acquisitions) for 1994 and 7% lower
than the Company's domestic offshore capital and exploration expenditures of
approximately $40,600,000 for 1993. The decline in the Company's domestic
offshore capital and exploration expenditures for 1995, compared to 1994 and
1993, resulted primarily from a decrease in planned drilling and workovers by
the operators of certain of the Company's domestic offshore non-operated
properties, together with adverse weather conditions offshore during the third
and fourth quarters of 1995 that resulted in the postponement of certain
scheduled drilling and workover operations until early 1996. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
 
     Leases acquired by the Company and other participants in its bidding groups
are customarily committed, on a block-by-block basis, to separate operating
agreements under which the appointed operator supervises exploration and
development operations for the account and at the expense of the group. These
agreements usually contain terms and conditions which have become relatively
standardized in the industry. Major decisions regarding development and
operations typically require the consent of at least a majority (in working
interest) of the participants. Because the Company generally has a meaningful
working interest position, the Company believes it can significantly influence
(but not always control) decisions regarding development and operations on most
of the leases in which it has a working interest even though it may not be the
operator of a particular lease. The Company is currently the operator on all or
a portion of 23 of the 78 offshore leases in which it has an interest.
 
     Platforms 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. Platforms are used to
accommodate both development drilling and additional exploratory drilling. Over
the last three years, the gross cost of production platforms to the joint
ventures in which the Company has varying net interests has averaged
approximately $7,205,000. Platform costs vary and more expensive platforms could
be required in the future depending on, among other factors, the number of
slots, water depth, currents, and sea floor conditions. During 1995, the Company
installed a platform on High Island A-451. See "Properties -- Principal
Properties."
 
     In 1989, the Company entered into a limited partnership agreement as
general partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ("Pogo
Gulf Coast"). As of December 31, 1995, Pogo Gulf Coast had interests in 12
federal offshore leases. The Company owns 40% of any interest in properties
acquired by the limited partnership. Unless otherwise noted, the statistical
data reported in this Annual Report reflect only the Company's share of Pogo
Gulf Coast's holdings.
 
DOMESTIC ONSHORE OPERATIONS
 
     The Company has onshore division staffs in Houston and Midland, Texas. Its
onshore activities are concentrated in known oil and gas provinces, principally
the Permian Basin area of southeastern New Mexico, West Texas and Northwest
Texas, and in the onshore Gulf Coast area. The Company's primary drilling
objective in southeastern New Mexico is the Brushy Canyon (Delaware) formation
which 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 the drilling of 259 wells through December 31, 1995, including
50 wells in 1995. During the month of December 1995, the Company's net revenue
interest portion of daily oil and condensate production from its Western
Division, principally from its Permian Basin New Mexico properties, averaged
approximately 4,072 Bbls which represented approximately 34% of the Company's
total average daily production of oil and condensate during such month.
 
                                        2
<PAGE>   4
 
     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 domestic onshore capital and exploration expenditures were
approximately $32,950,000 (excluding approximately $7,750,000 of net property
acquisitions) for 1995, or 3% higher than the Company's domestic onshore capital
and exploration expenditures of approximately $32,000,000 for 1994 and 11%
higher than the Company's domestic onshore capital and exploration expenditures
of approximately $29,800,000 for 1993. As of December 31, 1995, the Company held
leases on 95,286 net acres onshore in the United States. Onshore reserves as of
December 31, 1995, accounted for approximately 27% of the Company's domestic
proved reserves and approximately 16% of its total proved reserves. During 1995,
approximately 14% of the Company's natural gas production and 33% of its oil and
condensate production was from its domestic onshore properties, contributing
approximately 22% of consolidated oil and gas revenues.
 
INTERNATIONAL OPERATIONS
 
     The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas throughout the world. The Company
pursues a strategy of evaluating potentially high return prospects in areas of
the world with a stable political and financial climate such as certain European
and ASEAN ("Association of Southeast Asian Nations") countries. Currently, the
Company maintains an office in Bangkok, Thailand from which it directs a field
development project in the Gulf of Thailand on a portion of its Block B8/32
Concession discussed below.
 
     The Company's international capital and exploration expenditures were
approximately $34,950,000 for 1995 (excluding approximately $4,171,000 of net
property acquisitions), or 450% higher than the Company's international capital
and exploration expenditures of approximately $6,350,000 for 1994 and 483%
higher than the Company's international capital and exploration expenditures of
approximately $6,000,000 for 1993. Substantially all of the Company's
international capital and exploration expenditures for 1995 were related to the
Company's license in the Kingdom of Thailand. In addition, the Company continues
to evaluate other international opportunities that are consistent with the
Company's international exploration strategy.
 
  Tantawan Field
 
     In August 1995, at the request of Pogo's wholly owned subsidiary Thaipo
Limited ("Thaipo") and two of its joint venture partners, the government of
Thailand designated a portion of the Block B8/32 Concession (the "Concession")
comprising approximately 68,000 acres as the Tantawan production area. The
Tantawan production area, of which Thaipo is the operator and has a 46.34%
working interest, has been named the Tantawan Field. Through March 1, 1996, ten
exploration and nine development wells have been drilled in the Tantawan
production area, all but one of which encountered hydrocarbons. A tenth
development well is currently being drilled in the Tantawan production area and
additional wells are currently planned for 1996.
 
     Thaipo and its partners are currently engaged in further development
drilling and in the design and construction of offshore platforms and pipelines
for the Tantawan Field. Oil and gas production from the field will be gathered
through pipelines from the platforms into a Floating Production, Storage and
Offloading system (an "FPSO") to be named the "Tantawan Explorer." The FPSO
Tantawan Explorer will be a converted oil tanker with a capacity of slightly
less than 1,000,000 Bbls, that will be moored in the Tantawan Field, on which
hydrocarbon processing, separation, dehydration, compression, metering and other
production related equipment will be installed. Following processing on board
the FPSO, natural gas produced from the field will be delivered into the export
pipeline currently under construction by the Petroleum Authority of Thailand
("PTT"). Oil and condensate produced from the field will be stored on board the
FPSO and transferred to shore by oil tanker. The FPSO and its processing
equipment, which is currently under construction, will be leased from a third
party under a bareboat charter by Tantawan Services, LLC, an affiliate of
Thaipo. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources." Thaipo and its joint
venture partners will pay a daily processing fee to Tantawan Services, LLC, to
process the production from the Tantawan Field through the
 
                                        3
<PAGE>   5
 
FPSO. The FPSO has been designed with an initial processing capacity of 50,000
Bbls per day of oil and condensate, and 150 MMcf per day of natural gas,
expandable to 200 MMcf per day. An additional 100 MMcf per day of natural gas
can bypass the processing facilities, as necessary, and enter the export
pipeline manifold now being fabricated for use in the Tantawan Field. The
Company currently anticipates achieving first-production from the Tantawan Field
in the latter part of the fourth quarter of 1996, contingent upon various
factors including timely delivery of the FPSO by its lessor, the completion of
the new pipeline being constructed by PTT, and ongoing development drilling and
field facilities construction by the concessionaires and their contractors. See
"-- Miscellaneous; Sales."
 
     On November 7, 1995, Thaipo and its joint venture partners announced the
signing of a thirty-year gas sales agreement with PTT, initially governing gas
production from the Tantawan Field. Initial terms of the agreement include an
initial minimum daily contract quantity ("DCQ") during the first year after
production commences from the Tantawan Field (or 1997) of 75 MMcf per day with
the DCQ rising to 85 MMcf per day in the following year. The DCQ is the minimum
daily volume that PTT has agreed to take, or pay for if not taken under the
agreement. Mutual agreement on dedicated reserves would be renegotiated as and
when the DCQ exceeds 125 MMcf per day. Initial base gas prices start at
approximately $2.00 per thousand cubic feet ("Mcf"), subject to semi-annual
adjustments based upon a formula which takes into account changes in Thai
wholesale and fuel oil prices and the U.S./Thai currency exchange rate.
 
  Benchamas and Pakakrong Discoveries
 
     Exploration efforts also continue on those portions of the Concession
outside the Tantawan production area. Through March 1, 1996, six exploration
wells have been drilled on the Concession outside of the Tantawan Field
production area. This includes four wells, all of which have encountered
hydrocarbons, on the Benchamas prospect and one well, which also encountered
hydrocarbons, on the Pakakrong prospect. A second well is currently being
drilled on the Pakakrong structure. Thaipo, which does not act as the operator
on those portions of the Concession outside the Tantawan production area, owns a
31.67% working interest in the Benchamas and Pakakrong prospects and all other
portions of the Concession outside the Tantawan production area. In addition to
the Benchamas and Pakakrong prospects, Thaipo and its joint venture partners
have identified several other potentially promising seismic structures on the
approximately 1.3 million acres of Concession that are not part of the Tantawan
production area. In 1995, Thaipo and its joint venture partners shot, processed
and are currently evaluating 13,283 kilometers of new 3-D seismic data on parts
of the Concession outside of the Tantawan production area. This 3-D seismic data
is in addition to the 19,500 kilometers of 3-D seismic that have already been
acquired on the Concession since 1993. Thaipo and its joint venture partners
currently plan to acquire additional 3-D seismic data during 1996 on certain
other parts of the Concession outside of the Tantawan production area.
 
     As a result of this successful drilling program, the Company's net proved
reserves located on the Concession are currently estimated at 132 billion cubic
feet ("Bcf") of natural gas, or approximately 40% of the Company's total
estimated net proved reserves of natural gas, 19 million Bbls ("MMBbls") of
crude oil, condensate and natural gas liquids, or approximately 42% of the
Company's total estimated net proved reserves of oil, condensate and natural gas
liquids, which totals, on an equivalent basis, 246 Bcf equivalent ("Bcfe"), or
approximately 41% of the Company's total net proved oil and gas equivalent
reserves.
 
     Any production resulting from the Concession (including the Tantawan
production area) will be subject to a royalty ranging from 5% to 15% of oil and
gas sales, plus certain fixed dollar amounts payable at specified cumulative
production levels. Revenue from production in Thailand will also be subject to
income taxes and other similar governmental charges. As set forth in the August
1991 Concession agreement, the initial exploratory term of the Concession
agreement is for a period of up to six years expiring on July 31, 1997; subject
to further extension as described below. In addition, the Concession agreement
also required Thaipo and its joint venture partners on July 31, 1995, to release
back to the government approximately 1.3 million acres out of the original
approximately 2.6 million acres included in the Concession on July 31, 1995. The
area that was released was located primarily in the western half of the
Concession. At the end of the Concession agreement's initial exploration term on
July 31, 1997, Thai petroleum law permits the government to grant, upon
application by a concessionaire, an additional three year exploration term on up
to fifty percent of the
 
                                        4
<PAGE>   6
 
Concession acreage that has not been previously designated as a production area
or returned to the government, subject to certain terms and conditions including
the agreement to undertake a work program and the payment of substantial fees
and rentals. Following the commencement of production, the initial production
period term is 20 years, subject to extension, for those portions of the
Concession that are designated as production areas. See also "-- Miscellaneous;
Sales."
 
MISCELLANEOUS
 
  Other Assets
 
     The Company and a subsidiary, Pogo Offshore Pipeline Co., own minority
interests in four pipelines through which offshore oil production is
transported. In addition, the Company owns an approximately 19.3% 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 handle the Company's current and projected future
production.
 
     The Company's concession in Thailand is traversed by a major (34 inches in
diameter) natural gas pipeline that is owned and operated by PTT which comes
within approximately 25 miles of the Tantawan structure. This pipeline is
currently running at or near capacity. However, completion of a second,
parallel, 36 inch in diameter pipeline that is also owned, and will be operated,
by PTT is expected to occur during 1996. Thaipo and its joint venture partners
in the Tantawan field signed a long term gas sales contract with PTT in November
1995. See "-- International Operations; Tantawan Field." Development plans for
the Tantawan field currently contemplate that oil and condensate production from
the Tantawan field will initially be stored aboard the FPSO, sold to PTT and
transferred to shore by means of oil tankers.
 
     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 domestic oil and gas production is located in
areas where commercial production of economic discoveries can be rapidly
effectuated.
 
     Most of the Company's natural gas sales are currently made in the "spot
market" for no more than one month at a time at then currently available prices.
Prices on the spot market fluctuate with demand. Crude oil and condensate
production is also generally sold one month at a time at the currently available
prices. Other than any futures contracts which may exist from time to time, and
which are referred to in "-- Miscellaneous; Competition and Market Conditions,"
and the gas sales contract for production from the Tantawan field (see
"-- International Operations; Tantawan Field") 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. See also "Financial Statements and
Supplementary Data -- Note 4 to Notes to Consolidated Financial Statements
and -- Unaudited Supplementary Financial Data."
 
  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.
 
                                        5
<PAGE>   7
 
In general, prices of oil and gas are dependent upon numerous factors beyond the
control of the Company, including various weather, economic, political and
regulatory conditions. In the past, when natural gas prices in the United States
were lower than they are currently, the Company at times elected to curtail
certain quantities of its production. For example, in the fourth quarter of
1994, the Company curtailed a small portion of its daily natural gas production.
As of March 1, 1996, the Company was not curtailing any of its natural gas
production as a result of low natural gas prices. Should natural gas prices fall
again in the future, the Company may again elect to curtail certain quantities
of its natural gas production. Any significant decline in oil or gas prices
could have a material adverse effect on the Company's operations and financial
condition and could, under certain circumstances, result in a reduction in funds
available under the Company's bank credit facility.
 
     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 March 1, 1996, the
Company was not a party to any natural gas future contracts or crude oil swap
agreements. When the Company does engage in such hedging activities, it may
satisfy its obligations with its own production or by the purchase (or sale) of
third party production. The Company may also cancel all delivery obligations by
offsetting such obligations with equivalent agreements, thereby effecting a
purely cash transaction.
 
  Operating and Uninsured Risks
 
     The Company's operations are subject to risks inherent in the exploration
for and production of oil and natural gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
pollution and other environmental risks. Offshore oil and gas operations are
subject to the additional hazards of marine and helicopter operations, such as
capsizing, collision and adverse weather and sea conditions. These hazards could
result in substantial losses to the Company due to injury or loss of life,
severe damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations. The Company carries insurance
which it believes is in accordance with customary industry practices, but is not
fully insured against all risks incident to its business.
 
     Drilling activities are subject to numerous risks, including the risk that
no commercially productive hydrocarbon reserves will be encountered. The cost of
drilling, completing and operating wells and of installing production facilities
and pipelines is often uncertain. The Company's drilling operations may be
curtailed, delayed or canceled as a result of numerous factors, including
weather conditions, compliance with governmental requirements and shortages or
delays in the delivery of equipment. 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.
 
  Risks of Foreign Operations
 
     Ownership of property interests and production operations in Thailand and
in any other areas outside the United States that 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. 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
 
                                        6
<PAGE>   8
 
where the Company believes that the existing government is stable and favorably
disposed towards United States exploration and production companies. The Company
believes that the Kingdom of Thailand currently presents favorable conditions in
which to conduct international operations.
 
EXPLORATION AND PRODUCTION DATA
 
     In the following data "gross" refers to the total acres or wells in which
the Company has an interest and "net" refers to gross acres or wells multiplied
by the percentage working interest owned by the Company.
 
  Acreage
 
     The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1995:
 
<TABLE>
<CAPTION>
                                                      DEVELOPED
                                                     ACREAGE(a)         UNDEVELOPED ACREAGE(b)
                                                 -------------------    ----------------------
                                                  GROSS        NET        GROSS         NET
                                                 -------     -------    ----------    --------
    <S>                                          <C>         <C>        <C>           <C>
    DOMESTIC ONSHORE
      Louisiana................................      869         209         3,252       1,253
      New Mexico...............................   17,495       9,370        59,809      41,275
      Texas....................................   16,893       8,960        49,587      33,831
      Other....................................    3,200         333           238          55
                                                 -------     -------    ----------    --------
              Total Domestic Onshore...........   38,457      18,872       112,886      76,414
                                                 =======     =======    ==========    ========
    DOMESTIC OFFSHORE
      Louisiana (State)........................    7,804       3,120         1,169         584
      Louisiana (Federal)(c)...................  174,625      59,786        77,200      24,805
      Texas (Federal)..........................   46,080      11,820        23,040      15,552
                                                 -------     -------    ----------    --------
              Total Domestic Offshore..........  228,509      74,726       101,409      40,941
                                                 -------     -------    ----------    --------
    TOTAL DOMESTIC.............................  266,966      93,598       214,295     117,355
                                                 -------     -------    ----------    --------
    INTERNATIONAL
      Thailand (Offshore)......................       --          --     1,351,556     437,971
                                                 -------     -------    ----------    --------
    TOTAL COMPANY..............................  266,966      93,598     1,565,851     555,326
                                                 =======     =======    ==========    ========
</TABLE>
 
---------------
 
(a)  "Developed acreage" consists of lease acres spaced or assignable to
     production on which wells have been drilled or completed to a point that
     would permit production of commercial quantities of oil and natural gas.
 
(b)  Approximately 14% of the Company's total domestic offshore net undeveloped
     acreage is under leases that have terms expiring in 1996 (unless otherwise
     extended) and another approximately 4.5% of total domestic offshore net
     undeveloped acreage will expire in 1997 (unless otherwise extended).
     Approximately 15% of the Company's total domestic onshore net undeveloped
     acreage is under leases that have terms expiring in 1996 (unless otherwise
     extended) and another approximately 7% of total domestic onshore net
     undeveloped acreage will expire in 1997 (unless otherwise extended). None
     of the Company's total international net undeveloped acreage will need to
     be relinquished in 1996. However, approximately 93% of the Company's total
     international net undeveloped acreage must be relinquished to the Thai
     government in 1997 unless designated as a production area or unless the
     exploration term is extended as discussed hereinabove. See
     "Business -- International Operations; Benchamas Discovery."
 
(c)  The Company also owns overriding royalty interests in one federal lease
     offshore Louisiana.
 
                                        7
<PAGE>   9
 
  Productive Wells and Drilling Activity
 
     The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1995. Productive wells are producing wells
plus 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 production facilities).
 
<TABLE>
<CAPTION>
                                                                                 NATURAL GAS
                                                             OIL WELLS(A)          WELLS(A)
                                                            ---------------     --------------
                                                            GROSS      NET      GROSS     NET
                                                            -----     -----     -----     ----
    <S>                                                     <C>       <C>       <C>       <C>
    Offshore United States................................   193       47.4      168      53.7
    Onshore United States.................................   260      159.1       70      27.5
                                                             ---      -----      ---      ----
              Total.......................................   453      206.5      238      81.2
                                                             ===      =====      ===      ====
</TABLE>
 
---------------
 
(a)  One or more completions in the same bore hole are counted as one well. The
     data in the above table includes 31 gross (8.0 net) oil wells and 13 gross
     (5.4 net) natural gas wells with multiple completions.
 
     The following table shows the number of successful gross and net
exploratory and development wells in which the Company has participated and the
number of gross and net wells abandoned as dry holes during the periods
indicated. An onshore well is considered successful upon the installation of
permanent equipment for the production of hydrocarbons. Successful offshore
wells consist of exploratory or development wells that have been completed or
are "suspended" pending completion (which has been determined to be feasible and
economic) and exploratory test wells that were not intended to be completed and
that encountered commercially producible hydrocarbons. A well is considered a
dry hole upon reporting of permanent abandonment to the appropriate agency.
 
<TABLE>
<CAPTION>
                                                 1995                  1994                 1993
                                           -----------------    ------------------    -----------------
                                           SUCCESSFUL    DRY    SUCCESSFUL    DRY     SUCCESSFUL    DRY
                                           ----------    ---    ----------    ----    ----------    ---
    <S>                                    <C>           <C>    <C>           <C>     <C>           <C>
    GROSS WELLS:
    Offshore United States
      Exploratory........................      7.0       4.0        2.0         --        5.0       1.0
      Development........................      3.0       1.0       25.0        2.0       15.0       --
    Onshore United States
      Exploratory........................      8.0       1.0        3.0        6.0        3.0       4.0
      Development........................     47.0       1.0       51.0        3.0       61.0       1.0
    Offshore Kingdom of Thailand
      Exploratory........................      3.0       --         5.0         --        2.0       2.0
      Development........................      7.0       --          --         --         --       --
                                              ----       ---       ----       ----       ----       ---
              Total......................     75.0       7.0       86.0       11.0       86.0       8.0
                                              ====       ===       ====       ====       ====       ===
    NET WELLS:
    Offshore United States
      Exploratory........................      3.0       1.6        0.6         --        1.7       0.1
      Development........................      1.0       0.4        8.4        1.4        7.7       --
    Onshore United States
      Exploratory........................      4.6       1.0        2.8        3.6        2.0       3.2
      Development........................     31.3       0.1       29.9        0.9       33.1       0.4
    Offshore Kingdom of Thailand
      Exploratory........................      1.1       --         1.6         --        0.6       0.6
      Development........................      3.2       --          --         --         --       --
                                              ----       ---       ----       ----       ----       ---
              Total......................     44.2       3.1       43.3        5.9       45.1       4.3
                                              ====       ===       ====       ====       ====       ===
</TABLE>
 
                                        8
<PAGE>   10
 
     As of December 31, 1995, the Company was participating in the drilling of 2
gross (0.7 net) offshore domestic wells, 8 gross (4.2 net) onshore wells and 2
gross (0.8 net) wells offshore the Kingdom of Thailand.
 
  Production and Sales
 
     The following table summarizes the Company's average daily production, net
of all royalties, overriding royalties and other outstanding interests, for the
periods indicated. Natural gas production refers only to marketable production
of natural gas on an "as sold" basis.
 
<TABLE>
<CAPTION>
                                                               1995       1994       1993
                                                              -------    -------    -------
    <S>                                                       <C>        <C>        <C>
    Production Sales:
      Natural Gas (Mcf per day).............................  121,000    144,800     91,700
                                                              =======    =======    =======
      Liquid Hydrocarbons (Bbls per day)
         Crude Oil and Condensate...........................   11,786     11,100      9,851
         Natural Gas Liquids(a).............................    1,998      2,222      1,678
                                                              -------    -------    -------
              Total Liquid Hydrocarbons.....................   13,784     13,322     11,529
                                                              =======    =======    =======
</TABLE>
 
---------------
 
(a)  Natural Gas Liquids production sales includes sales attributable to both 
     the Company's leasehold and plant ownership.
 
     The following table shows the average sales prices received by the Company
for its production and the average production (lifting) costs per unit of
production during the periods indicated. See "-- Miscellaneous; Competition and
Market Conditions and Sales."
 
<TABLE>
<CAPTION>
                                                                  1995      1994      1993
                                                                 ------    ------    ------
    <S>                                                          <C>       <C>       <C>
    Sales Prices:
      Natural Gas (per Mcf)....................................  $ 1.63    $ 1.88    $ 1.98
      Crude Oil and Condensate (per Bbl).......................  $17.80    $16.08    $17.81
      Natural Gas Liquids (per Bbl)............................  $11.10    $11.33    $11.90
    Production (lifting) Costs(a)
      Natural Gas, Crude Oil, Condensate and Natural Gas
         Liquids (per equivalent Mcf of Natural Gas)...........  $ 0.47    $ 0.36    $ 0.45
</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.
 
                                        9
<PAGE>   11
 
  Reserves
 
     The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1995, 1994, and 1993, 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 Company Petroleum Engineers, Houston, Texas ("Ryder
Scott") in accordance with criteria prescribed by the Securities and Exchange
Commission (the "Commission"). The summary report of Ryder Scott on the reserve
estimates, which includes definitions and assumptions, is set forth as an
exhibit to this Annual Report and definitions, assumptions and descriptions of
methodology following the tables are based upon the Ryder Scott report.
 
<TABLE>
<CAPTION>
                                                                  AS OF DECEMBER 31,
                                                           --------------------------------
                                                             1995        1994        1993
                                                           --------    --------    --------
    <S>                                                    <C>         <C>         <C>
    Total Proved Reserves:
      Oil, condensate, and natural gas liquids (thousands
         of Bbls ("MBbls")) --
         Located in the United States....................    26,185      26,188      22,843
         Located in the Kingdom of Thailand..............    18,997       7,674       5,425
                                                           --------    --------    --------
              Total Company..............................    45,182      33,862      28,268
                                                           ========    ========    ========
      Natural Gas (MMcf)
         Located in the United States....................   196,454     186,151     199,392
         Located in the Kingdom of Thailand..............   131,607      56,739      33,474
                                                           --------    --------    --------
              Total Company..............................   328,061     242,890     232,866
                                                           ========    ========    ========
      Present value of estimated future net revenues,
         before income taxes (in thousands)
         Located in the United States....................  $400,845    $330,868    $386,674
         Located in the Kingdom of Thailand..............   131,630      52,112      17,166
                                                           --------    --------    --------
              Total Company..............................   532,475     382,980    $403,840
                                                           ========    ========    ========
    Proved Developed Reserves (all located in the United
      States):
      Oil, condensate, and natural gas liquids (thousands
         of Bbls)........................................    22,488      24,670      20,976
      Natural Gas (MMcf).................................   164,679     178,518     183,139
      Present value of estimated future net revenues,
         before income taxes (in thousands)..............  $359,984    $321,514    $375,287
</TABLE>
 
     Natural gas liquids comprise approximately 9% of the Company's total proved
liquids reserves and approximately 15% of the Company's proved developed liquids
reserves. 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.
 
     Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing conditions. Reservoirs are considered proved if
economic producibility is supported by actual production or formation tests. In
certain instances, proved reserves are assigned on the basis of a combination of
core analysis and electrical and other type logs which indicate the reservoirs
are analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a reservoir
considered proved includes (i) that portion delineated by drilling and defined
by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that
can be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as hydrocarbons are
produced and additional data becomes available. Proved natural gas reserves
 
                                       10
<PAGE>   12
 
are comprised of nonassociated, associated and dissolved gas. An appropriate
reduction in gas reserves has been made for the expected removal of liquids, for
lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in
significant quantities and are removed prior to sale. Reserves that can be
produced economically through the application of established improved recovery
techniques are included in the proved classification when these qualifications
are met: (i) successful testing by a pilot project or the operation of an
installed program in the reservoir provides support for the engineering analysis
on which the project or program was based, and (ii) it is reasonably certain the
project will proceed. Improved recovery includes all methods for supplementing
natural reservoir forces and energy, or otherwise increasing ultimate recovery
from a reservoir, including, (i) pressure maintenance, (ii) cycling, and (iii)
secondary recovery in its original sense. Improved recovery also includes the
enhanced recovery methods of thermal, chemical flooding, and the use of miscible
and immiscible displacement fluids. Estimates of proved reserves do not include
crude oil, condensate, natural gas, or natural gas liquids being held in
underground storage. Depending on the status of development, these proved
reserves are further subdivided into:
 
          (i) "developed reserves" which are those proved reserves reasonably
     expected to be recovered through existing wells with existing equipment and
     operating methods, including (a) "developed producing reserves" which are
     those proved developed reserves reasonably expected to be produced from
     existing completion intervals now open for production in existing wells,
     and (b) "developed non-producing reserves" which are those proved developed
     reserves which exist behind casing of existing wells which are reasonably
     expected to be produced through these wells in the predictable future where
     the cost of making such hydrocarbons available for production should be
     relatively small compared to the cost of new wells; and
 
          (ii) "undeveloped reserves" which are those proved reserves reasonably
     expected to be recovered from new wells on undrilled acreage, from existing
     wells where a relatively large expenditure is required and from acreage for
     which an application of fluid injection or other improved recovery
     technique is contemplated where the technique has been proved effective by
     actual tests in the area in the same reservoir. Reserves from undrilled
     acreage are limited to those drilling units offsetting productive units
     that are reasonably certain of production when drilled. Proved reserves for
     other undrilled units are included only where it can be demonstrated with
     reasonable certainty that there is continuity of production from the
     existing productive formation.
 
     The Company has interests in certain tracts which may have substantial
additional hydrocarbon quantities which cannot be classified as proved and are
not included herein. The Company has active exploratory and development drilling
programs which in all likelihood will result in the reclassification of
significant additional quantities to the proved category.
 
     In computing future revenues from gas reserves attributable to the
Company's interests, prices in effect at December 31, 1995 were used, including
current market prices, contract prices and fixed and determinable price
escalations where applicable. In accordance with Commission guidelines, the
future 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 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 interest, prices in effect at December 31, 1995
were used and these prices were held constant to depletion of the properties.
With respect to the Company's Thailand properties, production was assumed to
commence in the latter part of 1996, at the initial sales price provided for in
the long term gas sales contract between Thaipo, its joint venture partners in
the Tantawan production area, and PTT. See "-- International Operations."
 
     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
 
                                       11
<PAGE>   13
 
expenditure for the proposed work or actual costs for similar projects. The
current operating and development costs were held constant throughout the life
of the properties. For properties located onshore, the estimates of future net
revenues and the present value thereof do not consider the salvage value of the
lease equipment or the abandonment cost of the lease since both are relatively
insignificant and tend to offset each other. The estimated net cost of
abandonment after salvage was considered for offshore properties where such
costs net of salvage are significant.
 
     No deduction was made for indirect costs such as general and administrative
and overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments. Accumulated gas production imbalances, if any, have
been taken into account.
 
     Production data used to arrive at the estimates set forth above includes
estimated production for the last few months of 1995.
 
     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. 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 governmental regulatory authorities and agencies,
including the Federal Energy Regulatory Commission ("FERC") and the Federal
Trade Commission. 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 above because of the nature of the various
reports required. The major differences 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 1995,
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.
 
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 federal and state
conservation laws and regulations, and the petroleum industry has been subject
to governmental tax laws dealing specifically with it.
 
                                       12
<PAGE>   14
 
  Federal Income Tax
 
     The Company's operations are significantly affected by certain provisions
of the federal income tax laws applicable to the petroleum industry. The
principal provisions affecting the Company are those that permit the Company,
subject to certain limitations, to deduct as incurred, rather than to capitalize
and amortize, its domestic "intangible drilling and development costs" and to
claim depletion on a portion of its domestic oil and gas properties based on 15%
of its oil and gas gross income from such properties (up to an aggregate of
1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic
natural gas) even though the Company has little or no basis in such properties.
Under certain circumstances, however, a portion of such intangible drilling and
development costs and the percentage depletion allowed in excess of basis will
be tax preference items that will be taken into account in computing the
Company's alternative minimum tax.
 
  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. Regulations
of the Department of the Interior currently impose absolute liability upon the
lessee under a federal lease for the costs of clean-up of pollution resulting
from a lessee's operations, and such lessee may also be subject to possible
legal 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. See "Legal Proceedings" for a discussion of
other environmental matters.
 
     The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" (which include owners and
operators of offshore facilities) 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 regulation. If the party fails to
report a spill or cooperate fully in the cleanup, liability limits likewise do
not apply. Few defenses exist to the liability imposed by the OPA.
 
     The OPA also imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10,000,000 depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. On August 25, 1993, the Mineral
Management Service (the "MMS") published an advance notice of its intention to
adopt a rule under OPA that would require owners and operators of offshore oil
and gas facilities to establish $150,000,000 in financial responsibility to
cover costs that might be incurred by governmental entities in responding to an
oil spill. Under the proposed rule, financial responsibility could be
established through insurance, guaranty, indemnity, surety bond, letter of
credit, qualification as a self-insurer or a combination thereof. There is
substantial uncertainty as to whether insurance companies or underwriters will
be willing to provide coverage under OPA because the statute provides for direct
lawsuits against insurers who provide financial responsibility coverage, and
most insurers have strongly protested this requirement. The financial tests or
other criteria that will be
 
                                       13
<PAGE>   15
 
used to judge self-insurance are also uncertain. Both the Senate and the U.S.
House of Representatives recently adopted separate legislation that would lower
the financial responsibility requirement under the OPA to $35,000,000 in most
cases, but this legislation has not yet been reconciled in conference committee
for consideration by both chambers of Congress. The Company cannot predict the
result of any legislative action or the final form of the financial
responsibility rule that will be adopted, but such rule has the potential to
result in the imposition of substantial additional annual costs on the Company
or otherwise materially adversely affect the Company. The impact of the rule,
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
federal, state, 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 regulations, among other things, impose
absolute liability on the lessee under a lease for the cost of clean-up of
pollution resulting from a lessee's operations, subject the lessee to liability
for pollution damages, may require suspension or cessation of operations in
affected areas, and impose restrictions on the injection of liquids into
subsurface aquifers that may contaminate groundwater. Such laws, if enacted,
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. State initiatives to further regulate
the disposal of oil and gas wastes are also pending in certain states, 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 an gas operations, many of the costs
attributable to environmental control facilities would have been incurred absent
environmental regulations as prudent, safe oilfield practice. During 1995, the
Company incurred capital expenditures of approximately $1,497,000 for
environmental control facilities, primarily relating to the completion of two
salt water disposal facilities in New Mexico. The Company currently has budgeted
approximately $1,000,000 for environmental control facilities during 1996,
including, among other things, one salt water disposal facility.
 
  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 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
regulation 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. To date, the rulings of various courts have been
mixed. The Company was involved in several settlement agreements with pipelines
that could be subject to the MMS' new reinterpretation. The MMS is currently
reviewing the Company's and other producers' settlement agreements, to see if it
believes any additional royalty payments may be due. The Company does not
believe that it owes any additional royalties beyond what it has previously
paid. However, in the event additional royalty is assessed against 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 condition of the Company.
 
                                       14
<PAGE>   16
 
     Prior to January 1, 1993, various aspects of the Company's natural gas
operations were subject to regulations by the FERC under the Natural Gas Act of
1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA") with
respect to "first sales" of natural gas including price controls and certificate
and abandonment authority regulations. However, as a result of the enactment of
the Natural Gas Decontrol Act of 1989, the remaining "first sales" restrictions
imposed by the NGA and the NGPA terminated on January 1, 1993. The FERC
responded to the deregulation of first sales with an effort to increase
competition for pipeline services. FERC Order 636, issued in April 1992,
requires each pipeline company, among other things, to "unbundle" its
traditional wholesale services and create and make available on an open and
nondiscriminatory basis numerous constituent services (such as gathering
services, storage services, firm and interruptible transportation services, and
stand-by sales services) and to adopt a new rate making methodology to determine
appropriate rates for those services. In subsequent orders, the FERC largely
affirmed Order 636 and denied a stay of the implementation of the new rules
pending judicial review. The FERC has also recently embarked on regulatory
initiatives relating to its jurisdiction over rates for natural gas gathering
services provided by interstate pipelines and to the availability of
market-based and other alternative rate mechanisms to such pipelines for
transmission and storage services. 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
 
EMPLOYEES
 
     As of December 31, 1995, the Company had 115 employees. 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.
 
PRINCIPAL PRODUCING PROPERTIES
 
     As of January 1, 1996, six significant producing areas, of which five are
located in the Gulf of Mexico and the sixth is located in New Mexico, accounted
for approximately 42% of the estimated proved natural gas reserves and
approximately 56% of the estimated oil, condensate and natural gas liquids
reserves of the Company. These six producing areas also accounted for
approximately 77% of natural gas production and 97% of oil, condensate and
natural gas liquids production for 1995. Reserves, as estimated by Ryder Scott,
and production data, as estimated by the Company, for the six principal
producing areas are shown in the following table. No other major producing area
accounted for more than 2.5% of the estimated discounted future net revenues
attributable to the Company's estimated proved reserves as of January 1, 1996.
Because it is not yet a producing property, the Company's Thailand concession
does not appear on the following table even though it
 
                                       15
<PAGE>   17
 
accounts for approximately 41% of the Company's total net proved oil and gas
equivalent reserves. See "Business -- International Operations."
 
                          SIGNIFICANT PRODUCING AREAS
 
<TABLE>
<CAPTION>
                                                                      1995 AVERAGE NET
                                   NET PROVED RESERVES                DAILY PRODUCTION
                                  AS OF JANUARY 1, 1996         -----------------------------   DISCOUNTED
                              ------------------------------                                      FUTURE
                               NATURAL GAS      LIQUIDS(A)       NATURAL GAS     LIQUIDS(A)         NET
                              -------------   --------------    -------------   -------------   REVENUES(B)
                              (MMcf)    %     (MBbls)    %      (Mcf)     %     (Bbls)    %          %
                              ------   ----   -------   ----    ------   ----   ------   ----   -----------
<S>                           <C>      <C>    <C>       <C>     <C>      <C>    <C>      <C>    <C>
OFFSHORE
Eugene Island...............  46,799   14.3%   7,932    17.6%   51,532   42.6%  4,835    35.1%      22.4%
Main Pass...................  15,947    4.9    5,226    11.6     6,268    5.2   1,721    12.5       10.4
South Pass..................  23,480    7.2    1,251     2.8     6,312    5.2     712     5.2        7.8
East Cameron................  25,260    7.7      306      .7    15,660   12.9     175     1.3        4.6
South Marsh Island..........   6,909    2.1    1,954     4.3     2,710    2.2   1,301     9.4        3.9
ONSHORE
New Mexico Lea/Eddy
  Counties..................  18,172    5.5    8,440    18.7    10,482    8.7   4,593    33.3       14.4
</TABLE>
 
---------------
 
(a)  "Liquids," includes oil, condensate and natural gas liquids.
 
(b)  Before income taxes, discounted at 10%.
 
     Set forth below are descriptions of certain of the Company's significant
producing areas. Unless otherwise specifically identified, the information set
forth in such descriptions, including production rates and the number of wells,
platforms and blocks, is presented on a gross basis, rather than net to the
Company.
 
  Eugene Island
 
     A significant portion of the Company's reserves and a substantial part of
its production are located in the Eugene Island area off the Louisiana coast in
the Gulf of Mexico. The Eugene Island area has been an important part of the
Company's operations since the first lease in that area was purchased in 1970
and production began in 1973. The Company currently holds interests in 13 blocks
in the Eugene Island area. These blocks comprise eight fields containing 86 oil
and gas wells producing from multiple reservoirs and horizons.
 
     The Eugene Island Block 330 field is the Company's most significant
producing asset, with 28 productive Pleistocene horizons between 4,000 and 8,000
feet, containing multiple reservoirs. The field, located in 245 feet of water,
contains three drilling and production platforms in which the Company holds a
35% working interest, as well as an additional platform in which the Company
holds a 30% working interest. There are currently 13 wells producing primarily
natural gas and 35 wells producing primarily oil on the block. In 1995, a
successful well workover program was completed and more workover and development
drilling is currently planned for 1996. Since initial production in 1973, the
Eugene Island Block 330 field has produced approximately 660 Bcf of natural gas
and 131 MMBbls of oil and condensate (178 Bcf and 38 MMBbls attributable to the
Company's net revenue interest). Reserves have been added to this field
consistently since production commenced. These increases have been derived from
new exploratory horizons, infill drilling, field expansions and higher than
anticipated recovery efficiencies.
 
     Another significant field to the Company is the Eugene Island Block 295
field. In production since 1973, this block has recorded gross production of
over 429 Bcf of natural gas and over 3.0 MMBbls of oil and condensate during its
twenty-three year life. During the fourth quarter of 1993, the Company
successfully drilled and completed five horizontal wells to exploit the natural
gas potential located in certain shallow reservoirs on this block in an area
where it has a 100% working interest. A platform was set and production
commenced from these wells in late February 1994. For the 22 months ending in
December 1995, the Company had produced approximately 37 Bcf (26 Bcf
attributable to the Company's net revenue interest)
 
                                       16
<PAGE>   18
 
from these shallow reservoirs. During December 1995, natural gas production from
these reservoirs averaged approximately 24.2 MMcf per day.
 
     The Eugene Island Block 212 field consists of Eugene Island Blocks 211 and
212 and Ship Shoal Block 175. The field contains eight productive horizons which
have four oil wells and one natural gas well producing from a platform set in
1985. During 1995, the Company acquired a 3-D survey over this field that it is
currently evaluating in anticipation of additional development drilling.
 
  Main Pass
 
     The Company's lease blocks in the Main Pass area are located near the mouth
of the Mississippi River in the Gulf of Mexico and include leases in which it
has held an interest since 1974. The Company acquired four new leases in the
Main Pass area during 1995, bringing the Company's total lease interest in this
area to twelve blocks as of the end of 1995. The primary drilling objectives in
these fields are Pliocene and Miocene sandstone reservoirs with productive
formation depths from 5,000 to 12,000 feet. The Company's interests in the Main
Pass area include 42 producing oil and gas wells producing from seven platforms.
The Company currently plans an active exploratory drilling program during 1996
to evaluate the new blocks that it acquired in the Main Pass Area during 1995.
 
     A field including Main Pass Blocks 72, 73 and 72/74 was unitized in 1982.
The Company's working interest in this field is currently 35%. This field
contains 22 producing oil wells and 9 producing natural gas wells from three
platforms operated by one of the Company's joint venture partners. The field is
located in 125 feet of water with 38 mapped horizons adjacent to and surrounding
a salt dome. These horizons contain over 150 separate reservoirs between 5,000
and 12,000 feet. A successful workover and three well development drilling
program was completed in 1995. The Company currently plans to continue its
workover program and to drill additional wells in this field during 1996 based
in part on the analysis of a recent 3-D seismic survey over the field.
 
     Main Pass Block 123 was acquired in the federal lease sale of 1990. Pogo
Gulf Coast, for which the Company is the general partner, has a 75% working
interest and is the operator on the block. Along with its non-operating joint
venture partner, Pogo Gulf Coast drilled two discovery wells on the block in
1993 and two additional wells in 1994. Installation of a platform and
construction of a pipeline from the platform to an existing main pipeline was
completed in January 1995. Platform start-up was completed and full production
from this field commenced in February 1995. During December 1995, production
from this field averaged approximately 1,200 Bbls of oil and 3.2 MMcf of natural
gas per day.
 
  South Pass
 
     The Company acquired its first leasehold interest in the South Pass area
off of the mouth of the Mississippi River in September 1972. The Company
currently owns interests in portions of seven blocks in this area on which four
production platforms have been set that produce oil and gas from 27 wells which
have been completed principally in Pleistocene, Pliocene and Miocene reservoirs
at depths ranging from approximately 4,000 to 14,800 feet.
 
     One of the Company's fields in the South Pass area is located on South Pass
Blocks 49 and 50. The Company currently holds a 50% working interest in South
Pass Block 50 and a 20% interest in South Pass Block 49. The Company currently
plans to drill an additional three wells in this field during 1996.
 
     Another field in which the Company has an interest in the South Pass area
is the South Pass Block 78 field. The South Pass Block 78 field, which commenced
production in 1981, had ceased production. Following analysis of a recently
acquired 3-D seismic survey, the Company increased its working interest in the
field from 9% to 35% and assumed the operatorship of the field in June 1995.
Operating from an existing platform, the Company drilled and completed three
highly deviated wells into previously unexplored reservoirs which, as of March
1, 1996, had a combined flow rate in excess of 35 MMcf per day. A fourth well is
currently being drilled from the same platform, with additional wells currently
planned for 1996.
 
                                       17
<PAGE>   19
 
  East Cameron
 
     The first leasehold interest acquired by the Company in the East Cameron
area off the Texas/Louisiana border in the Gulf of Mexico commenced production
in February 1973. Presently, the Company has interests in three offshore blocks
in this area which contain two fields and 16 producing gas wells.
 
     During 1992, the Company and its partners conducted a 3-D seismic survey of
the East Cameron Block 334/335 field area where the Company has a 42% working
interest. Analysis of this 3-D seismic survey resulted in the drilling of four
successful development wells. In 1995, an exploratory well, in which the Company
held a 70% working interest, was drilled on East Cameron Block 334 which
resulted in the discovery of significant new reserves. The Company currently
plans to set a platform over this new well and commence production during the
third quarter of 1996. In addition, the Company currently plans to drill another
exploratory well from the platform in late 1996 after it is installed.
 
  South Marsh Island
 
     The Company currently owns interests in portions of seven blocks in the
South Marsh Island area, located offshore Louisiana. Three of the leases were
acquired in 1974, a fourth in 1980, a fifth in 1992 and portions of two more
leases were acquired in 1994 through farmins. Three blocks contain a total of
five drilling and production platforms. These platforms currently have 47 oil
and gas wells producing from Pleistocene age sandstone reservoirs located at
depths from 5,000 to 10,000 feet.
 
     The South Marsh Island Block 128 field, in which the Company owns a 16%
working interest, is comprised of South Marsh Island Blocks 125, 127, 128 and
141. This field primarily produces oil, with 36 oil wells and eight natural gas
wells producing from 20 separate reservoirs. In 1995, the Company commenced a
workover program designed to increase oil and gas deliverability from the field,
with additional workover work currently planned for 1996 based, in part, on a
recently completed detailed reservoir study of the field. In addition, the
Company currently plans a multi-well drilling program for this field in 1996.
 
  New Mexico
 
     The Company considers southeastern New Mexico to be an area of significant
growth in both production and reserves as a result of recent exploration and
development activities. The Company believes that during the past four 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 77,000 gross acres. The Company's
primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in
the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of
the Permian Basin are generally characterized by production from relatively
shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and
relatively high initial rates of production (frequently equaling the top field
allowables which range from of 142 Bbls to 230 Bbls per day, depending on the
depth of production from the field). The Company has achieved rapid cost
recovery with respect to its New Mexico wells drilled to date because of
relatively low capital costs and high initial rates of production.
 
     Since the Company began exploring in the Brushy Canyon (Delaware) formation
in October 1989, it has participated in the drilling of 259 wells through
December 31, 1995, including, among others, 91 wells in the Sand Dunes field
where the Company's working interest ranges from 4% to 100%, 27 wells in the
East Loving field where the Company's working interest ranges from 33% to 98%,
52 wells in the Livingston Ridge field where the Company's working interest
ranges from 25% to 100%; and 47 wells in the Red Tank field where the Company's
working interest ranges from 89% to 100%. The oil fields in this area are
generally developed on a 40 acre spacing pattern. The Company anticipates
drilling many additional locations in these and other fields in southeastern New
Mexico during 1996 and in future years.
 
                                       18
<PAGE>   20
 
DOMESTIC OFFSHORE PROPERTIES
 
     The following is a listing of the Company's domestic offshore properties
and contains information as of December 31, 1995.
 
<TABLE>
<CAPTION>
               POGO        EXPLORATORY                               DEVELOPMENT                                  DATE OR
              WORKING         WELLS              PLATFORMS              WELLS                       LEASE       ANTICIPATED
             INTEREST      DRILLED OR             SET OR             DRILLED OR        DATE       EFFECTIVE       DATE OF
 BLOCK           %          DRILLING             ANNOUNCED            DRILLING       ACQUIRED       DATE        PRODUCTION
---------------------------------------------------------------------------------------------------------------------------
<S>          <C>           <C>           <C>                         <C>             <C>          <C>           <C>
OFFSHORE TEXAS -- FEDERAL
Matagorda Island
   A-4            27.0           3                   1                     2          8-83         10-1-83        9-89
---------------------------------------------------------------------------------------------------------------------------
   670            30.7[A]        1                   1                     2          8-83         10-1-83       10-89
---------------------------------------------------------------------------------------------------------------------------
Brazos
 A-104            10.8           1                   1                                8-89         10-1-89        6-90
---------------------------------------------------------------------------------------------------------------------------
Galveston
   325            20.0                                                                8-91         11-1-91
---------------------------------------------------------------------------------------------------------------------------
High Island/South Addition
 A-515            25.0           2                   1                                11-79        1-1-80        11-84
---------------------------------------------------------------------------------------------------------------------------
High Island/East Addition/South Extension
  A-94           100.0                                                                9-95         1-1-96
---------------------------------------------------------------------------------------------------------------------------
  A-95           100.0                                                                9-95         1-1-96
---------------------------------------------------------------------------------------------------------------------------
 A-323             1.8           4                   1                    17          6-73         8-1-73         6-78
---------------------------------------------------------------------------------------------------------------------------
 A-325             9.9[A]        8[B]              3[C]                    9          6-73         8-1-73         8-81
---------------------------------------------------------------------------------------------------------------------------
 A-356            50.0           1                   1                     4          5-74         7-1-74         7-80
---------------------------------------------------------------------------------------------------------------------------
 A-377            50.0                                                                9-95         11-1-95
---------------------------------------------------------------------------------------------------------------------------
 A-451            50.0           2                   1                     1          8-94         12-1-94       12-95
---------------------------------------------------------------------------------------------------------------------------
     TOTAL TEXAS                22                  10                    35
---------------------------------------------------------------------------------------------------------------------------
OFFSHORE LOUISIANA -- FEDERAL
West Cameron
   63             20.0                                                                3-91         5-1-91
---------------------------------------------------------------------------------------------------------------------------
  196              [D]           3                   1                     2          5-83         7-1-83        12-90
---------------------------------------------------------------------------------------------------------------------------
  202             39.3           3                   1                     2          11-82        1-1-83         8-85
---------------------------------------------------------------------------------------------------------------------------
  252             80.0           1          Share 253 Platform             2          11-82        1-1-83         8-84
---------------------------------------------------------------------------------------------------------------------------
  253             80.0           1                   1                     6          6-77         8-1-77         7-84
---------------------------------------------------------------------------------------------------------------------------
  310             20.0                                                                3-91         7-1-91
---------------------------------------------------------------------------------------------------------------------------
  352             15.0           1                   1                     9          10-74        12-1-74        8-79
---------------------------------------------------------------------------------------------------------------------------
  532              4.0           5          Share 533 Platform             3          12-72        2-1-73         9-76
---------------------------------------------------------------------------------------------------------------------------
  533              4.0           2[E]                2                     7          12-72        2-1-73         9-76
---------------------------------------------------------------------------------------------------------------------------
  609             16.0           1                   1                     7          10-74        12-1-74        7-78
---------------------------------------------------------------------------------------------------------------------------
East Cameron
  270             30.0           3                   1                    30          12-70        1-1-71         1-73
---------------------------------------------------------------------------------------------------------------------------
  334*       42.0/70.0           6[E]                2                    11          12-70        2-1-71         8-77
---------------------------------------------------------------------------------------------------------------------------
  335             42.0           3                   2                    27          6-73         8-1-73         8-77
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
 
                                                     (footnotes at end of table)
 
                                       19
<PAGE>   21
 
<TABLE>
<CAPTION>
               POGO        EXPLORATORY                               DEVELOPMENT                                  DATE OR
              WORKING         WELLS              PLATFORMS              WELLS                       LEASE       ANTICIPATED
             INTEREST      DRILLED OR             SET OR             DRILLED OR        DATE       EFFECTIVE       DATE OF
 BLOCK           %          DRILLING             ANNOUNCED            DRILLING       ACQUIRED       DATE        PRODUCTION
---------------------------------------------------------------------------------------------------------------------------
<S>          <C>           <C>           <C>                         <C>             <C>          <C>           <C>
Vermilion
  175             70.0           1                   1                                5-91         9-1-85         12-91
---------------------------------------------------------------------------------------------------------------------------
  335             37.5                                                                3-94         5-1-94
---------------------------------------------------------------------------------------------------------------------------
  346             33.3                                                                5-95         9-1-95
---------------------------------------------------------------------------------------------------------------------------
South March Island
  125             16.0           3                   1                     8          10-74        12-1-74        7-77
---------------------------------------------------------------------------------------------------------------------------
  127             16.0                      Share 128 Platform             3          10-74        12-1-74        7-77
---------------------------------------------------------------------------------------------------------------------------
  128             16.0           6                   3                    62          3-74         5-1-74         7-77
---------------------------------------------------------------------------------------------------------------------------
 +141             16.0[F]                   Share 128 Platform             2          3-94         12-1-74        3-94
---------------------------------------------------------------------------------------------------------------------------
  160             25.0           2                   1                     5          9-80         11-1-80        2-84
---------------------------------------------------------------------------------------------------------------------------
 +161             25.0[F]                   Share 160 Platform             1          5-94         9-1-81        12-94
---------------------------------------------------------------------------------------------------------------------------
  188             25.0                                                                5-92         9-1-92
---------------------------------------------------------------------------------------------------------------------------
Eugene Island
  101             20.0                                                                3-91         5-1-91
---------------------------------------------------------------------------------------------------------------------------
  102             20.0                                                                3-91         5-1-91
---------------------------------------------------------------------------------------------------------------------------
  211             33.3                      Share 212 Platform             3          5-83         7-1-83         1-87
---------------------------------------------------------------------------------------------------------------------------
  212             33.3           1                   1                     3          5-83         7-1-83         1-87
---------------------------------------------------------------------------------------------------------------------------
  256             69.2           5                   1                     7          12-70        2-1-71        10-79
---------------------------------------------------------------------------------------------------------------------------
  261             66.7           2                   1                    17          10-74        12-1-74       10-79
---------------------------------------------------------------------------------------------------------------------------
  295**     20.0/100.0           7[E]                2                    30          12-70        2-1-71         2-73
---------------------------------------------------------------------------------------------------------------------------
  312              4.0           5        1 + Share 333 Platform           8          3-74         5-1-74         7-77
---------------------------------------------------------------------------------------------------------------------------
  318             20.0           1                                                    3-91         6-1-91
---------------------------------------------------------------------------------------------------------------------------
  330             35.0[G]       10[E]                4                    94          12-70        1-1-71         4-73
---------------------------------------------------------------------------------------------------------------------------
  333              4.0           3                   2                    22          12-72        2-1-73         7-77
---------------------------------------------------------------------------------------------------------------------------
  337             37.5           3                   1                     8          2-76         3-1-76         6-85
---------------------------------------------------------------------------------------------------------------------------
Ship Shoal
  175             33.3                     Share EI 212 Platform           2          5-83         7-1-83         7-88
---------------------------------------------------------------------------------------------------------------------------
  240             30.0           2                   2                                3-89         6-1-89        12-94
---------------------------------------------------------------------------------------------------------------------------
  256             30.0           1                   1                                3-90         5-1-90        12-94
---------------------------------------------------------------------------------------------------------------------------
South Timbalier
  198             25.0           2                   1                     4          5-85         9-1-85         8-90
---------------------------------------------------------------------------------------------------------------------------
  316             50.0                                                                5-95         9-1-95
---------------------------------------------------------------------------------------------------------------------------
  317             50.0                                                                5-95         9-1-95
---------------------------------------------------------------------------------------------------------------------------
South Pass
  +33             15.9[F]                    Share 49 Platform             2          10-74        12-1-74        2-83
---------------------------------------------------------------------------------------------------------------------------
   49             15.9[H]        5[E]                1                    19          9-72         11-1-72       10-80
---------------------------------------------------------------------------------------------------------------------------
   50             50.0           1           Share 49 Platform                        7-93         8-1-88        12-93
---------------------------------------------------------------------------------------------------------------------------
  +57             12.0                     Share 57/58 Platform            3          11-76        1-1-77        11-82
---------------------------------------------------------------------------------------------------------------------------
   73             35.0                                                                5-95         7-1-95
---------------------------------------------------------------------------------------------------------------------------
  +78             35.0           7                   1                    13          9-72         10-1-72        4-81
---------------------------------------------------------------------------------------------------------------------------
Mississippi Canyon
   63             20.0           2                   1                     5          5-75         7-1-75         6-84
---------------------------------------------------------------------------------------------------------------------------
   64             33.3                                                                5-95         7-1-95
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
 
                                                     (footnotes at end of table)
 
                                       20
<PAGE>   22
 
<TABLE>
<CAPTION>
               POGO        EXPLORATORY                               DEVELOPMENT                                  DATE OR
              WORKING         WELLS              PLATFORMS              WELLS                       LEASE       ANTICIPATED
             INTEREST      DRILLED OR             SET OR             DRILLED OR        DATE       EFFECTIVE       DATE OF
 BLOCK           %          DRILLING             ANNOUNCED            DRILLING       ACQUIRED       DATE        PRODUCTION
---------------------------------------------------------------------------------------------------------------------------
<S>          <C>           <C>           <C>                         <C>             <C>          <C>           <C>
Main Pass
   +30            25.0[A]        2                   1                     8[B]      10-81        12-1-81        12-87
---------------------------------------------------------------------------------------------------------------------------
   37             25.0           4                   1                     5          7-79         10-1-79        7-82
---------------------------------------------------------------------------------------------------------------------------
  +72             35.3           1           Share 73 Platform             2          5-75         7-1-75         8-79
---------------------------------------------------------------------------------------------------------------------------
  +72/74          35.3           5                   2                    48          11-76        1-1-77         8-79
---------------------------------------------------------------------------------------------------------------------------
   73             35.3           4                   1                    17          10-74        12-1-74        8-79
---------------------------------------------------------------------------------------------------------------------------
  123             30.0           4                   1                                3-90         5-1-90         1-95
---------------------------------------------------------------------------------------------------------------------------
  131             50.0           1                                                    5-92         9-1-92
---------------------------------------------------------------------------------------------------------------------------
  207             50.0           1                                                    5-95         9-1-95
---------------------------------------------------------------------------------------------------------------------------
  212             25.0                                                                5-95         9-1-95
---------------------------------------------------------------------------------------------------------------------------
  213             25.0                                                                5-95         9-1-95
---------------------------------------------------------------------------------------------------------------------------
TOTAL LOUISIANA                120                  44                   507
---------------------------------------------------------------------------------------------------------------------------
STATE LEASES
Offshore Louisiana
South Pass
  +57/58          12.0           3                   1                    13          5-74         5-13-74        7-82
---------------------------------------------------------------------------------------------------------------------------
Main Pass
   31             50.0           1                   1                     1          3-85         3-18-85        2-90
---------------------------------------------------------------------------------------------------------------------------
   76             50.0                                                                9-95         9-18-95
---------------------------------------------------------------------------------------------------------------------------
Breton Sound
    2         100.0[A]           2[B]                1                     1          4-80         9-15-80        8-87
---------------------------------------------------------------------------------------------------------------------------
   23             82.5           1                   1                                9-78         9-18-78        7-84
---------------------------------------------------------------------------------------------------------------------------
   24             22.5           1                   1                     1          9-78         9-18-78        7-84
---------------------------------------------------------------------------------------------------------------------------
North Lighthouse Point
S/L 340           50.0           1                                         3          5-84         5-1-84        10-84
---------------------------------------------------------------------------------------------------------------------------
TOTAL STATE LEASES               9                   5                    19
---------------------------------------------------------------------------------------------------------------------------
TOTAL DOMESTIC OFFSHORE        151                  59                   561
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
 
[A] Portion of block farmed out
 
[B] Includes one farmout well
 
[C] Includes one farmout platform
 
[D] Block farmed out - Overriding Royalty Interest only
 
[E] Includes offset contribution well
 
[F] Block farmed in
 
[G] Pogo owns 35% in "A", "B", and "C" platform area and 30% in platform "D"
     area
 
[H] Pogo owns 20% in a non-unit area
 
[+] Represents portion of block
 
 *  Pogo owns 70% interest in certain portions of this block
 
 ** Pogo owns 20% in rights below 3,000 feet and 100% in rights above 3,000 feet
    in certain portions of the block
 
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."
 
                                       21
<PAGE>   23
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
 
     Not Applicable.
 
ITEM S-K 401(B). EXECUTIVE OFFICERS OF REGISTRANT.
 
     Executive officers of the Company are appointed annually to serve for the
ensuing year or until their successors have been elected or appointed. The
executive officers of the Company, their age as of March 1, 1996, and the year
each was elected to his present position are as follows:
 
<TABLE>
<CAPTION>
                                                                                       YEAR
              EXECUTIVE OFFICER                   EXECUTIVE OFFICE            AGE     ELECTED
    -------------------------------------  -------------------------------    ---     -------
    <S>                                    <C>                                <C>     <C>
    Paul G. Van Wagenen..................  Chairman of the Board,
                                           President and Chief Executive
                                             Officer                          50        1991
    Kenneth R. Good......................  Senior Vice President --
                                             Land and Budgets                 58        1991
    Stuart P. Burbach....................  Vice President and
                                             Offshore Division Manager        43        1991
    Jerry A. Cooper......................  Vice President and
                                             Western Division Manager         47        1990
    John W. Elsenhans....................  Vice President and Treasurer       43        1995
    Harvey L. Gold.......................  Vice President -- Engineering      60        1988
    Thomas E. Hart.......................  Vice President and Controller      53        1988
    R. Phillip Laney.....................  Vice President and
                                             International Division
                                             Manager                          55        1991
    John O. McCoy, Jr....................  Vice President and
                                             Chief Administrative Officer     44        1989
    J. D. McGregor.......................  Vice President -- Sales            51        1988
    Ronald B. Manning....................  Vice President and
                                             General Counsel                  42        1995
    Sammie M. Shaw.......................  Vice President -- Operations       64        1992
    Gerald A. Morton.....................  Corporate Secretary and
                                             Associate General Counsel        37        1995
</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. Good, who joined the
Company in 1977, served as Vice President -- Land of the Company since 1988; Mr.
Burbach was Vice President of Norfolk Holding Inc. since 1986; Mr. Cooper served
in various positions since joining the Company in 1979; Mr. Elsenhans was
Director, Corporate Finance for the Company since 1991 and prior thereto held
various positions with Chemical Bank and its affiliates since 1984; Mr. Gold was
Manager of Reservoir Engineering for the Company since joining the Company in
1977; Mr. Hart was Controller for the Company since joining the Company in 1977;
Mr. Laney, who joined the Company in 1977, served as International Exploration
Manager for the Company since 1983; Mr. McCoy served as Director of Personnel
and Administration for the Company since joining the Company in 1978; Mr.
McGregor was Manager of Hydrocarbon Sales and Contracts for the Company since
joining the Company in 1981; Mr. Manning, who joined the Company in 1987, was
Corporate Secretary and an Associate General Counsel for the Company since 1990;
Mr. Shaw was Operations Manager for the Company since joining the Company in
1981; Mr. Morton was an Associate General Counsel for the Company since 1993 and
prior thereto was an attorney with the law firm of Weil, Gotshal & Manges since
1988.
 
                                       22
<PAGE>   24
 
                                    PART II
 
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
        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 Company's common stock trades under the symbol PPP. The
Company's common stock is also listed on the Pacific Stock Exchange.
 
<TABLE>
<CAPTION>
                                                                  LOW           HIGH
                                                                  ---           ----
    <S>                                                           <C>           <C>
    1994
      1st Quarter...............................................  15 5/8        21 1/2
      2nd Quarter...............................................  15 5/8        24 1/4
      3rd Quarter...............................................  19 5/8        23 5/8
      4th Quarter...............................................  16 1/8        23 1/8
    1995
      1st Quarter...............................................  16            20 1/2
      2nd Quarter...............................................  19 1/2        25 3/8
      3rd Quarter...............................................  21 1/8        25
      4th Quarter...............................................  19 3/8        29
</TABLE>
 
     As of March 1, 1996, there were 3,431 holders of record of the Company's
Common Stock.
 
     In 1995, the Company paid four quarterly dividends of $0.03 per share on
its Common Stock. In this regard, the Company reinstated the practice of
declaring a quarterly cash dividend commencing in the third quarter of 1994.
However, the declaration and payment of future dividends will depend upon, among
other things, the Company's future earnings and financial condition, liquidity
and capital requirements, the general economic and regulatory climate and other
factors deemed relevant by the Company's Board of Directors.
 
     Pursuant to the Company's revolving credit agreement with its banks under
which the Company has borrowed funds, 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 from and
after a specified date plus the proceeds of the issuance of capital stock after
the same specified date or if the net worth of the Company is negative. As of
December 31, 1995, $71,708,000 was available for dividends under this
limitation.
 
                                       23
<PAGE>   25
 
ITEM 6. SELECTED FINANCIAL DATA.
 
<TABLE>
<CAPTION>
                                                                FOR THE YEAR ENDED DECEMBER 31,
                                                    --------------------------------------------------------
                                                      1995        1994        1993        1992        1991
                                                    --------    --------    --------    --------    --------
<S>                                                 <C>         <C>         <C>         <C>         <C>
FINANCIAL DATA
(Expressed in thousands, except per share data)
Revenues:
  Crude oil and condensate........................  $ 76,557    $ 65,141    $ 64,042    $ 64,224    $ 54,420
  Natural gas.....................................    72,032      99,093      66,173      67,366      63,225
  Natural gas liquids.............................     8,097       9,189       7,288       5,833       3,442
  Other, net......................................       773         133        (950)      1,705       3,338
                                                    --------    --------    --------    --------    --------
  Oil and gas revenues............................   157,459     173,556     136,553     139,128     124,425
  Interest on tax refunds.........................        --          --       2,322          --          --
  Gains on sales..................................       100          52         679       1,702          44
                                                    --------    --------    --------    --------    --------
         Total....................................  $157,559    $173,608    $139,554    $140,830    $124,469
                                                    ========    ========    ========    ========    ========
Income before extraordinary item..................  $  9,230    $ 27,374    $ 25,061    $ 18,495    $ 10,322
Extraordinary gains (losses)......................        --        (307)         --          --       1,336
                                                    --------    --------    --------    --------    --------
Net income........................................  $  9,230    $ 27,067    $ 25,061    $ 18,495    $ 11,658
                                                    ========    ========    ========    ========    ========
Per share data:
  Primary and fully diluted earnings:
    Before extraordinary item.....................  $   0.28    $   0.82    $   0.76    $   0.66    $   0.37
    Extraordinary item............................        --       (0.01)         --          --        0.05
                                                    --------    --------    --------    --------    --------
    Net income....................................  $   0.28    $   0.81    $   0.76    $   0.66    $   0.42
                                                    ========    ========    ========    ========    ========
  Price range of common stock:
    High..........................................  $  29.00    $  24.25    $  21.00    $  13.88    $   8.25
    Low...........................................  $  16.00    $  15.63    $   9.75    $   5.13    $   4.63
Weighted average number of common and common
  equivalent shares outstanding...................    33,490      33,352      32,860      27,929      27,611
Long-term debt at year-end........................  $163,249    $149,249    $130,539    $129,260    $184,260
Production payment obligation at year-end.........  $     --    $     --    $     --    $ 24,854    $ 45,475
Shareholders' equity (deficit) at year-end........  $ 71,708    $ 64,037    $ 33,803    $  5,648    $(56,636)
Total assets at year-end..........................  $338,177    $298,826    $239,774    $206,347    $213,772
PRODUCTION (SALES) DATA
Net daily average production and weighted average
  price:
    Natural gas (Mcf per day).....................   121,000     144,800      91,700     105,200     104,200
      Price (per Mcf).............................  $   1.63    $   1.88    $   1.98    $   1.75    $   1.66
    Crude oil-condensate (Bbl. per day)...........    11,786      11,100       9,851       8,699       7,108
      Price (per Bbl.)............................  $  17.80    $  16.08    $  17.81    $  20.17    $  20.98
    Natural gas liquids (Bbl. per day)............     1,998       2,222       1,678       1,181         663
      Price (per Bbl.)............................  $  11.10    $  11.33    $  11.90    $  13.50    $  14.21
CAPITAL EXPENDITURES (Expressed in thousands)
Oil and gas:
  Domestic Offshore --
    Exploration...................................  $ 13,300    $  2,800    $  4,600    $  1,700    $  1,600
    Development...................................    17,800      44,100      33,700       5,500      23,600
    Purchase of reserves..........................        --      32,600          --       8,900       5,100
  Domestic Onshore--
    Exploration...................................     8,800       6,800       5,200       4,900       4,700
    Development...................................    22,400      23,700      24,300      15,600      13,900
    Purchase of reserves..........................     7,900          --          --          --          --
  International --
    Exploration...................................     5,500       5,100       4,600       1,400          --
    Development...................................    24,400          --          --          --          --
    Purchase of reserves..........................     4,200          --          --          --          --
                                                    --------    --------    --------    --------    --------
         Total oil and gas........................   104,300     115,100      72,400      38,000      48,900
Other.............................................       500       1,200         200         600       2,400
                                                    --------    --------    --------    --------    --------
         Total....................................  $104,800    $116,300    $ 72,600    $ 38,600    $ 51,300
                                                    ========    ========    ========    ========    ========
</TABLE>
 
                                       24
<PAGE>   26
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS.
 
RESULTS OF OPERATIONS
 
     The Company reported net income for 1995 of $9,230,000 or $0.28 per share
compared to net income for 1994 of $27,067,000 or $0.81 per share and net income
for 1993 of $25,061,000 or $0.76 per share. The Company recorded an
extraordinary loss of $307,000 during the second quarter of 1994 related to the
early retirement of the Company's 10.25% Convertible Subordinated Notes, due
1999 (the "10.25% Notes") with the proceeds from the Company's issuance on March
16, 1994, of its 5 1/2% Convertible Subordinated Notes, due 2004 (the "5 1/2%
Notes"). Earnings per common share are based on the weighted average number of
common and common equivalent shares outstanding for 1995 of 33,490,000 compared
to 33,352,000 for 1994 and 32,860,000 for 1993. The yearly increases in the
weighted average number of common and common equivalent shares outstanding
resulted primarily from the issuance of shares of common stock upon the exercise
of stock options pursuant to the Company's stock option plans. Earnings per
common share computations on a fully diluted basis primarily reflect additional
common shares issuable upon the assumed conversion of the Company's 5 1/2% Notes
in 1994 (the only convertible securities of the Company that were dilutive
during the applicable periods) and the elimination of related interest
requirements, as adjusted for applicable federal income taxes. However, the
dilution resulting from the assumed conversion of the 5 1/2% Notes in 1994 was
not sufficient to change reported earnings per share.
 
     The Company's total revenues for 1995 were $157,559,000, a decrease of
approximately 9% from total revenues of $173,608,000 for 1994, and an increase
of approximately 13% from total revenues of $139,554,000 for 1993. The decrease
in the Company's total revenues for 1995, compared to 1994, resulted primarily
from decreases in the Company's natural gas production volumes and the
substantial decrease in prices that the Company received for such natural gas
production volumes, which were not entirely offset by increases in the Company's
liquid hydrocarbon (including crude oil, condensate and natural gas liquid
("NGL")) production volumes and increased prices that the Company received for
its liquid hydrocarbon production volumes. The increase in the Company's total
revenues for 1995, compared to 1993, resulted primarily from increases in the
Company's natural gas and total liquid hydrocarbon production volumes, which
were only partially offset by the decreased prices that the Company received for
such natural gas and total liquid hydrocarbon production volumes. In addition,
the Company's total revenues in 1993 were positively affected by revenues from
the settlement of an issue with the Internal Revenue Service for which there
were no comparable offsets in 1995.
 
     The Company's oil and gas revenues for 1995 were $157,459,000, a decrease
of approximately 9% from oil and gas revenues of $173,556,000 for 1994, and an
increase of approximately 15% from oil and gas revenues of $136,553,000 for
1993. The following table reflects an analysis of variances in the Company's oil
and gas revenues between 1995 and the previous two years:
 
<TABLE>
<CAPTION>
                                                                       1995 COMPARED TO
                                                                     ---------------------
                                                                       1994         1993
                                                                     --------     --------
                                                                        (IN THOUSANDS)
    <S>                                                              <C>          <C>
    Increase (decrease) in oil and gas revenues resulting from
      variances in:
      Natural Gas
         Price.....................................................  $(12,891)    $(11,547)
         Production................................................   (14,170)      17,406
                                                                     --------     --------
                                                                      (27,061)       5,859
                                                                     --------     --------
      Crude oil and condensate
         Price.....................................................     6,956          (54)
         Production................................................     4,460       12,569
                                                                     --------     --------
                                                                       11,416       12,515
                                                                     --------     --------
      Natural gas liquids ("NGL") and other, net...................      (452)       2,532
                                                                     --------     --------
    Increase (decrease) in oil and gas revenues....................  $(16,097)    $ 20,906
                                                                     ========     ========
</TABLE>
 
     Average natural gas prices received by the Company during 1995 were marked
by extreme volatility, ranging from a low of $1.43 for the month of August 1995,
to a high of $2.10 for the month of December 1995,
 
                                       25
<PAGE>   27
 
with an average price for the year of $1.63 per Mcf. The average price that the
Company received for its natural gas production in 1995 compared unfavorably
with the average price that the Company had received during the preceding two
years of $1.88 per Mcf for 1994 (a decrease of approximately 13%) and $1.98 per
Mcf for 1993 (a decrease of approximately 18%), and constituted a fifteen year
low. See "Business -- Miscellaneous; Competition and Market Conditions." The
Company's natural gas production for 1995 averaged 121 MMcf per day, a decrease
of approximately 16% from average production of 144.8 MMcf per day in 1994, and
an increase of approximately 32% from average production of 91.7 MMcf per day
for 1993. The decrease in the Company's average natural gas production for 1995,
compared to 1994, resulted primarily from the difference between the high
initial natural gas production rates from horizontal wells drilled from the
Company's Eugene Island 295 "B" platform which commenced in late February 1994
and the subsequent natural production decline from those reservoirs, the
slowdown of development drilling, workover and recompletion work on certain of
the Company's non-operated properties in the Gulf of Mexico, largely due to a
decrease in planned drilling by the operators of such properties and production
curtailments due to adverse weather conditions (and drilling and workover
operations on certain of the Company's properties), along with the natural
decline in deliverability from certain of the Company's more mature properties.
Those decreases were only partially offset by new and increased production from
the Company's continued offshore drilling and workover program. As of March 1,
1996, the Company was not a party to any natural gas futures contracts.
 
     Crude oil and condensate prices received by the Company averaged $17.80 per
barrel in 1995, an increase of approximately 11% compared to an average of
$16.08 per barrel in 1994, but essentially unchanged from an average price of
$17.81 per barrel that the Company received in 1993. Crude oil and condensate
production for 1995 averaged 11,786 Bbls per day, an increase of approximately
6% from 11,100 Bbls per day for 1994, and an increase of approximately 20% from
9,851 Bbls per day for 1993. The increase in the Company's crude oil and
condensate production for 1995, compared to 1994 and 1993, resulted primarily
from ongoing development drilling and workover programs in the Gulf of Mexico
and in Lea and Eddy Counties of southeastern New Mexico, which was only
partially offset by the slowdown of development drilling, workover and
recompletion work on certain of the Company's non-operated properties in the
Gulf of Mexico, largely due to a decrease in planned drilling by the operators
of such properties and production curtailments due to adverse weather conditions
(and drilling and workover operations on certain of the Company's properties),
along with the natural decline in deliverability from certain of the Company's
more mature properties. See "Properties -- Principal Properties" and
"Business -- Domestic Offshore Operations; Lease Acquisitions." As of March 1,
1996, the Company was not a party to any crude oil swap agreements.
 
     Liquid products are often extracted from natural gas streams and sold
separately as NGL. In addition, the Company's oil and gas revenues for 1995,
1994 and 1993 also reflect adjustments for various miscellaneous items. The
Company's NGL and other, net revenues for 1995 decreased $452,000 from those
reported in 1994, but increased $2,532,000 from those reported in 1993. The
decrease in NGL and other, net revenues in 1995, compared with 1994, primarily
related to a decrease in the Company's NGL production volumes, together with a
decline in the prices received for such production, which was only partially
offset by other items, primarily the net proceeds resulting from the settlement
of a gas balancing dispute. The increase in NGL and other, net revenues for
1995, compared with 1993, primarily related to an increase in the Company's NGL
production volumes and the net proceeds from the gas balancing dispute referred
to above, which were only partially offset by decreases in the prices that the
Company received for its NGL production volumes and the settlement of other
disputes in 1993, including certain litigation with the State of Louisiana
relating to alleged royalties due on certain of the Company's Louisiana state
leases.
 
     The Company's average liquid hydrocarbon (including crude oil, condensate
and NGL) production during 1995 was 13,784 Bbls per day, an increase of
approximately 3% from an average total liquids production of 13,322 Bbls per day
for 1994, and an increase of approximately 20% from an average total liquids
production of 11,529 Bbls per day for 1993. The increase in the Company's
average liquid hydrocarbon production during 1995, compared to 1994, was
adversely affected by the decline in the Company's NGL production, which more
closely parallels the Company's natural gas production than it does its crude
oil and condensate production.
 
                                       26
<PAGE>   28
 
     Lease operating expenses for 1995 were $35,071,000, an increase of
approximately 18% from lease operating expenses of $29,768,000 for 1994, and an
increase of approximately 32% from lease operating expenses of $26,633,000 for
1993. The increase in lease operating expenses for 1995, compared to 1994 and
1993, resulted primarily from increased costs to the Company (and the entire
offshore oil industry) because of an increasing shortage of qualified offshore
service contractors, which has permitted such contractors to increase the costs
of their services significantly in the last year, a year to year increase in the
level of the Company's operating activities, including increased operating costs
related to additional properties brought on production and an increased
ownership interest in certain properties as a result of the acquisition of such
interests. To a lesser extent, lease operating expenses for 1995, compared to
1994 and 1993, also increased as a result of a general maintenance and repair
program that was undertaken on many of the Company's operated properties, for
which no corresponding offsets of such magnitude existed in the comparable prior
periods.
 
     General and administrative expenses for 1995 were $16,400,000, an increase
of approximately 3% from general and administrative expenses of $15,984,000 for
1994, and an increase of approximately 13% from general and administrative
expenses of $14,550,000 for 1993. The increase in general and administrative
expenses for 1995, compared to 1994 and 1993, was related to, among other
things, the costs associated with the establishment of a Company office in
Bangkok, Thailand in connection with the Company's development project and other
activities in the Gulf of Thailand, an increase in the number of Company
employees resulting from the Company's increased exploration and production
related activities and to normal salary and concomitant benefit expense
adjustments.
 
     Exploration expenses consist primarily of delay rentals and geological and
geophysical costs which are expensed as incurred. Exploration expenses for 1995
were $7,468,000, an increase of approximately 42% from exploration expenses of
$5,257,000 for 1994, and an increase of approximately 204% from exploration
expenses of $2,455,000 for 1993. The increase in exploration expenses for 1995,
compared to 1994 and 1993, resulted primarily from increased geophysical
activity by the Company, including the costs of conducting and processing
certain proprietary 3-D seismic surveys on its domestic onshore and offshore
properties, as well as in the Gulf of Thailand, together with the cost of
acquiring several non-proprietary 3-D seismic surveys in the Gulf of Mexico. In
addition, a portion of the increase in exploration expenses was attributable to
increased delay rental expense resulting from the Company's acquisition of
additional prospective oil and gas acreage.
 
     Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled along with impairments due to decreases in expected reserves from
producing wells. The Company's dry hole and impairment expenses for 1995 were
$6,703,000, a decrease of approximately 5% from dry hole and impairment costs of
$7,088,000 for 1994, but an increase of approximately 43% from dry hole and
impairment costs of $4,690,000 for 1993.
 
     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. 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. 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 ("DD&A") is
based on 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's DD&A expense for 1995 was $68,489,000, an increase of approximately 8%
from DD&A expenses of $63,308,000 for 1994, and an increase of approximately 68%
from DD&A expenses of $40,693,000 for 1993. The increases in the Company's DD&A
expenses for 1995, compared to 1994 and 1993, resulted primarily from increased
volumes produced (largely related to the increased natural gas production
discussed above) and, to a lesser extent, an increase in the composite DD&A
rate. The composite DD&A rate for all of the Company's producing fields for 1995
was $0.91 per equivalent Mcf ($5.47 per equivalent barrel), an increase of
approximately 18% from a composite DD&A rate of $0.77 per equivalent Mcf ($4.59
per equivalent barrel) for 1994, and an increase of 32% from a composite DD&A
rate of $0.69 per equivalent Mcf ($4.11 per equivalent barrel) for 1993. The
Company produced 74,337,000 equivalent Mcf (12,389,000 equivalent Bbls)
 
                                       27
<PAGE>   29
 
in 1995, a decrease of approximately 9% from the 82,008,000 equivalent Mcf
(13,668,000 equivalent Bbls) produced in 1994, and an increase of approximately
27% from the 58,718,000 equivalent Mcf (9,786,000 equivalent Bbls) produced in
1993. See "Financial Statements and Supplementary Data -- Note 1 of Notes to
Consolidated Financial Statements."
 
     Interest charges for 1995 were $11,167,000, an increase of approximately
11% from interest charges of $10,104,000 for 1994, and an increase of
approximately 2% from interest charges of $10,956,000 for 1993. The increase in
the Company's interest charges for 1995, compared to 1994 and 1993, resulted
primarily from an increase in the amount of debt outstanding that, with respect
to 1995 compared primarily to 1993, was partially offset by a decrease in debt
issue amortization expenses, a lower average interest rate level on the debt
outstanding (as a result of refinancing of the 10.25% Debentures in 1994). The
increases in interest charges for 1995, compared to 1994, were also partially
offset by decreased commitment fees resulting from decreased availability under
the Company's bank revolving credit facility, as well as a decreased fee
structure on the Company's revolving credit facility that was negotiated in
1995. See "Financial Statements and Supplementary Data -- Note 3 of Notes to
Consolidated Financial Statements," and "-- Liquidity and Capital Resources."
Capitalized interest for 1995 was $1,834,000 an increase of approximately 148%
from capitalized interest of $739,000 for 1994, and an increase of approximately
307% from capitalized interest of $451,000 for 1993. The increase in the amount
of interest capitalized by the Company in 1995, compared to 1994 and 1993,
related primarily to the capitalization of interest expenses resulting from the
engineering, acquisition and construction of facilities and equipment for the
Company's Tantawan Field that commenced in 1995 and for which no comparable
activity of such magnitude existed in the prior periods.
 
     As of March 1, 1996, the Company was a party to an interest rate swap
agreement. The swap agreement, which terminates on March 10, 1998, effectively
changes the interest rate paid by the Company on $5,000,000 of debt from a
market based variable rate to a fixed rate of 7.2%.
 
     Income tax expense for 1995 was $4,891,000, a decrease of approximately 68%
from income tax expense of $15,517,000 for 1994, and a decrease of approximately
67% from income tax expense of $14,981,000 for 1993. The decrease in income tax
expense for 1995, compared to 1994 and 1993, resulted primarily from decreased
pretax income.
 
LIQUIDITY AND CAPITAL RESOURCES
 
     The Company's Consolidated Statement of Cash Flows for the year ended
December 31, 1995, reflects net cash provided by operating activities of
$96,333,000. In addition to the net cash provided by operating activities, the
Company also received $1,717,000 from the exercise of stock options, $100,000
from the sale of certain non-strategic properties, and had net borrowings of
$17,000,000 under its revolving credit agreement and uncommitted money market
credit lines with certain banks. The Company invested $96,403,000 of such cash
flow in capital projects during 1995, purchased certain proved reserves for
$11,921,000, paid $3,946,000 ($0.03 per share for four quarters) in cash
dividends to holders of the Company's common stock and, in satisfaction of its
sinking fund obligations under its 8% Convertible Subordinated Debentures, due
2005 (the "8% Debentures"), repaid $871,000 principal amount of the 8%
Debentures and purchased 8% Debentures in the open market for $450,000. Of the
$96,403,000 invested in capital projects, $26,497,000 was applicable to 1994
projects and $69,906,000 was applicable to 1995 capital projects. The Company's
total debt at December 31, 1995, was $166,249,000, an increase of approximately
10% from total debt of $150,531,000 at December 31, 1994. The increase in the
Company's total debt at the end of 1995, compared with year end 1994, resulted
primarily from increased capital expenditures and decreased revenues during 1995
as compared to 1994, which were not entirely offset by the purchase of fewer
proved reserves in 1995, compared to 1994. As of December 31, 1995, the Company
had $4,481,000 in cash and cash investments.
 
     The Company's capital and exploration budget for 1996, which does not
include any amounts which may be expended for the purchase of proved reserves or
any interest which may be capitalized resulting from projects in progress, has
been established by the Company's Board of Directors at $165,000,000, an
increase of approximately 67% from the Company's capital and exploration
expenditures (excluding purchased reserves and interest capitalized) of
$98,560,000 for 1995, an increase of approximately 88% over capital and
 
                                       28
<PAGE>   30
 
exploration expenditures (excluding purchased reserves and interest capitalized)
of $88,300,000 for 1994, and an increase of approximately 115% over capital and
exploration expenditures (excluding purchased reserves and interest capitalized)
of approximately $74,600,000 for 1993.
 
     In addition to anticipated capital and exploration expenses, other material
1996 cash requirements that the Company currently anticipates include ongoing
operating, general and administrative, income tax, and interest expense, sinking
fund payments and the payment of dividends on its common stock, including a
$0.03 per share dividend on its common stock paid on February 24, 1996, to
stockholders of record on February 5, 1996. The Company currently anticipates
that cash provided by operating activities and funds available under its Credit
Agreement and uncommitted money market credit lines will be sufficient to fund
the Company's ongoing expenses, its 1996 capital and exploration budget and
anticipated future cash dividend payments. In this regard, the Company
reinstated the practice of declaring a quarterly cash dividend commencing in the
third quarter of 1994. 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.
 
     Effective June 1, 1995, the Company entered into an amended and restated
credit agreement (the "Credit Agreement") with the same banks that were parties
to the credit agreement that it superseded. The Credit Agreement provides for an
unsecured $150,000,000 revolving/term credit facility which will be fully
revolving until January 1, 1998, after which the balance will be due in eight
quarterly term loan installments, commencing April 30, 1998. Effective November
1, 1995, the Company voluntarily reduced, on a temporary basis, the lenders'
commitment under the Credit Agreement to $125,000,000. The amount that may be
borrowed under the Credit Agreement may not exceed a borrowing base, determined
semiannually by the lenders in accordance with the Credit Agreement, based on
the discounted present value of future net revenues from certain of the
Company's oil and gas reserves and the provisions of the Credit Agreement. As of
March 1, 1996, the borrowing base exceeded $125,000,000. The Credit Agreement is
governed by various financial and other covenants, including requirements to
maintain positive working capital (excluding current maturities of debt) and a
fixed charge coverage ratio, and limitations on indebtedness, creation of liens,
the prepayment of subordinated debt, the payment of dividends, mergers and
consolidations, investments and asset dispositions. See "Market for the
Registrant's Common Stock and Related Security Holder Matters." In addition, the
Company is prohibited from pledging borrowing base properties as security for
other debt. Borrowings under the Credit Agreement currently bear interest at a
Base (Prime) rate, a certificate of deposit rate plus 1 1/8%, or LIBOR plus 1%,
at the Company's option. A commitment fee on the unborrowed amount under the
Credit Agreement is also charged. The commitment fee is 5/16 of 1% per annum on
the unborrowed amount under the Credit Agreement that is designated as "active"
and 1/8 of 1% per annum on the unborrowed amount under the Credit Agreement that
is designated as "inactive." Of the $125,000,000 that is currently available
under the Credit Agreement, $100,000,000 is designated as "active" and
$25,000,000 is designated as "inactive."
 
     The Company has also entered into separate letter agreements with two banks
under which each bank may provide a $10,000,000 uncommitted money market line of
credit. The two lines of credit are on an as available or offered basis and
neither bank has an obligation to make any advances under its respective line of
credit. Although loans made under these letter agreements are for a maximum term
of 30 days, they are reflected as long-term debt on the Company's balance sheet
because the Company currently has the ability and intent to reborrow such
amounts under its Credit Agreement. Both letter agreements permit either party
to terminate such letter agreement at any time. Under its Credit Agreement, the
Company is currently limited to incurring a maximum of $10,000,000 of additional
senior debt, which would include debt incurred under these lines of credit. As
of December 31, 1995, indebtedness in the principal amount of $38,000,000 was
outstanding under the Credit Agreement and the two letter agreements.
 
     The outstanding principal amount of 5 1/2% Notes was $86,250,000 as of
December 31, 1995. The 5 1/2% Notes are convertible into Common Stock at $22.188
per share, subject to adjustment upon the occurrence of certain events. The
5 1/2% Notes will be redeemable at the option of the Company, in whole or in
part, at any time on or after March 15, 1998, at a redemption price of 103.3% of
their principal amount and decreasing
 
                                       29
<PAGE>   31
 
percentages thereafter. No sinking fund payments are required on the 5 1/2%
Notes. The 5 1/2% Notes are redeemable at the option of the holder, upon the
occurrence of a repurchase event (a change of control as defined in the
indenture governing the 5 1/2% Notes), at 100% of the principal amount.
 
     The outstanding principal amount of the 8% Debentures was $41,999,000 as of
December 31, 1995. The 8% Debentures are convertible into Common Stock at $39.50
per share, subject to adjustment in certain circumstances, including stock
splits. The 8% Debentures are redeemable at the option of the Company at 102% of
their principal amount through December 30, 1996, and decreasing percentages
thereafter, and are subject to mandatory annual sinking fund requirements of
$3,000,000, due each December, with a final maturity of December 31, 2005. The
sinking fund requirements for the 8% Debentures will be sufficient to retire all
but $15,000,000 of the issue prior to maturity. See "Financial Statements and
Supplementary Data -- Note 3 to Notes to Consolidated Financial Statements."
 
     As of February 9, 1996, Tantawan Services, LLC ("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 a FPSO for use in the Tantawan Field. See "Business -- International
Operations." The initial term of the Charter is for ten years, subject to
extension, with an anticipated commencement date in mid-December 1996. In
addition, TS has a purchase option on the FPSO throughout the term of the
Charter. The Charter currently provides for an estimated charter hire commitment
of $20,075,000 per year ($9,303,050 net to Thaipo), commencing upon its
installation in the field. TS has also contracted with another company, SBM
Marine Services Thailand Ltd., to operate the FPSO on a reimbursable basis
throughout the initial term of the Charter. Performance of both the Charter and
the agreement to operate the FPSO are non-recourse to TS and the Company.
However, performance is secured by a lien on any hydrocarbons stored on the FPSO
and is guaranteed by each of the working interest holders in the Tantawan Field,
including Thaipo. Thaipo's guarantee is limited to its percentage interest in
the Tantawan Field (currently 46.34%).
 
OTHER MATTERS
 
     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 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 dollar, such effect is not currently considered significant.
 
                                       30
<PAGE>   32
 
                                     ITEM 8
 
                  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 


                           ANNUAL REPORT ON FORM 10-K
 
                      FOR THE YEAR ENDED DECEMBER 31, 1995
 


                    POGO PRODUCING COMPANY AND SUBSIDIARIES
 
                                 HOUSTON, TEXAS
 
                                       31
<PAGE>   33
 
                    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,
1995 and 1994, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1995. These financial statements are the responsibility of Pogo's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
 
     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
 
     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Pogo Producing Company and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
 


                                            ARTHUR ANDERSEN LLP
 
Houston, Texas
February 1, 1996
 
                                       32
<PAGE>   34
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
                       CONSOLIDATED STATEMENTS OF INCOME
 
<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                               --------------------------------
                                                                 1995        1994        1993
                                                               --------    --------    --------
                                                                   (EXPRESSED IN THOUSANDS,
                                                                  EXCEPT PER SHARE AMOUNTS)
<S>                                                            <C>         <C>         <C>
Revenues:
  Oil and gas................................................  $157,459    $173,556    $136,553
  Interest on tax refund.....................................        --          --       2,322
  Gains on sales.............................................       100          52         679
                                                               --------    --------    --------
          Total..............................................   157,559     173,608     139,554
                                                               --------    --------    --------
Operating Costs and Expenses:
  Lease operating............................................    35,071      29,768      26,633
  General and administrative.................................    16,400      15,984      14,550
  Exploration................................................     7,468       5,257       2,455
  Dry hole and impairment....................................     6,703       7,088       4,690
  Depreciation, depletion and amortization...................    68,489      63,308      40,693
                                                               --------    --------    --------
          Total..............................................   134,131     121,405      89,021
                                                               --------    --------    --------
Operating Income.............................................    23,428      52,203      50,533
Interest:
  Charges....................................................   (11,167)    (10,104)    (10,956)
  Income.....................................................        26          53          14
  Capitalized................................................     1,834         739         451
                                                               --------    --------    --------
Income Before Taxes and Extraordinary Item...................    14,121      42,891      40,042
                                                               --------    --------    --------
Income Tax Expense...........................................    (4,891)    (15,517)    (14,981)
                                                               --------    --------    --------
Income Before Extraordinary Item.............................     9,230      27,374      25,061
Extraordinary Loss on Early Extinguishment of Debt, net of
  tax........................................................        --        (307)         --
                                                               --------    --------    --------
Net Income...................................................  $  9,230    $ 27,067    $ 25,061
                                                               ========    ========    ========
Primary and Fully Diluted
  Earnings per Common Share:
          Before extraordinary item..........................  $   0.28    $   0.82    $   0.76
          Extraordinary item.................................        --       (0.01)         --
                                                               --------    --------    --------
          Net income.........................................  $   0.28    $   0.81    $   0.76
                                                               ========    ========    ========
Dividends per Common Share...................................  $   0.12    $   0.06    $     --
                                                               ========    ========    ========
</TABLE>
 
     The accompanying notes to consolidated financial statements are an integral
part hereof.
 
                                       33
<PAGE>   35
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
                          CONSOLIDATED BALANCE SHEETS
 
                                     ASSETS
 
<TABLE>
<CAPTION>
                                                                            DECEMBER 31,
                                                                       ----------------------
                                                                         1995          1994
                                                                       ---------     --------
                                                                           (EXPRESSED IN
                                                                             THOUSANDS)
<S>                                                                    <C>           <C>
Current Assets:
  Cash and cash investments..........................................  $   4,481     $  2,922
  Accounts receivable................................................     21,820       28,915
  Other receivables..................................................     30,504       14,717
  Inventories........................................................      6,438        2,422
  Other..............................................................        722          745
                                                                       ---------     --------
          Total current assets.......................................     63,965       49,721
                                                                       ---------     --------
Property and Equipment:
  Oil and gas, on the basis of successful efforts accounting
     Proved properties being amortized...............................    963,330      913,865
     Unevaluated properties and properties under development, not
      being amortized................................................     47,431        6,890
  Other, at cost.....................................................      8,811        8,268
                                                                       ---------     --------
                                                                       1,019,572      929,023
  Less -- accumulated depreciation, depletion, and amortization,
     including $5,603 and $5,040 respectively, applicable to other
     property........................................................    757,739      691,110
                                                                       ---------     --------
                                                                         261,833      237,913
                                                                       ---------     --------
Other................................................................     12,379       11,192
                                                                       ---------     --------
                                                                       $ 338,177     $298,826
                                                                       =========     ========
                            LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
  Accounts payable...................................................  $  10,007     $  8,065
  Other payables.....................................................     35,254       26,497
  Current portion of long-term debt..................................      3,000        1,282
  Accrued interest payable...........................................      1,714        1,583
  Accrued payroll and related benefits...............................      1,239        1,237
  Other..............................................................        103           40
                                                                       ---------     --------
          Total current liabilities..................................     51,317       38,704
Long-Term Debt.......................................................    163,249      149,249
Deferred Federal Income Tax..........................................     41,409       36,487
Deferred Credits.....................................................     10,494       10,349
                                                                       ---------     --------
          Total liabilities..........................................    266,469      234,789
                                                                       ---------     --------
Shareholders' Equity:
  Preferred stock, $1 par; 2,000,000 shares authorized...............         --           --
  Common stock, $1 par; 100,000,000 and 43,333,333 shares authorized
     respectively, and 33,006,972 and 32,825,836 shares issued,
     respectively....................................................     33,007       32,826
  Additional capital.................................................    132,881      130,675
  Retained earnings (deficit)........................................    (93,856)     (99,140)
  Treasury stock, at cost............................................       (324)        (324)
                                                                       ---------     --------
          Total shareholders' equity.................................     71,708       64,037
                                                                       ---------     --------
                                                                       $ 338,177     $298,826
                                                                       =========     ========
</TABLE>
 
The accompanying notes to consolidated financial statements are an integral part
                                    hereof.
 
                                       34
<PAGE>   36
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                                           YEAR ENDED DECEMBER 31,
                                                                     ------------------------------------
                                                                       1995          1994          1993
                                                                     ---------     ---------     --------
                                                                           (EXPRESSED IN THOUSANDS)
<S>                                                                  <C>           <C>           <C>
Cash flows from operating activities:
  Cash received from customers.....................................  $ 164,065     $ 165,549     $141,012
  Federal income taxes and interest received.......................      6,000         3,364           --
  Operating, exploration, and general and administrative expenses
    paid...........................................................    (56,997)      (50,894)     (45,051)
  Interest paid....................................................    (11,036)       (9,620)     (10,912)
  Federal income taxes paid........................................     (6,000)       (7,500)      (2,800)
  Settlement of natural gas transportation and exchange
    imbalance......................................................         --        (2,168)          --
  Other............................................................        301           542          895
                                                                     ---------     ---------     --------
         Net cash provided by operating activities.................     96,333        99,273       83,144
                                                                     ---------     ---------     --------
Cash flows from investing activities:
  Capital expenditures.............................................    (96,403)      (85,375)     (62,353)
  Purchase of proved reserves......................................    (11,921)      (32,578)          --
  Proceeds from the sale of property and tubular stock.............        100            52        2,713
                                                                     ---------     ---------     --------
         Net cash used in investing activities.....................   (108,224)     (117,901)     (59,640)
                                                                     ---------     ---------     --------
Cash flows from financing activities:
  Net borrowings (payments) under revolving credit agreements......     15,000       (53,000)       8,000
  Net borrowings under uncommitted lines of credit with banks......      2,000         7,000           --
  Proceeds from issuance of new debt...............................         --        86,250           --
  Proceeds from exercise of stock options..........................      1,717         3,687        2,026
  Principal payments of other long-term debt obligations...........       (871)      (24,472)      (7,000)
  Principal payments of production payment obligation..............         --            --      (24,854)
  Debt issue expenses paid.........................................         --        (2,446)          --
  Payment of cash dividends on common stock........................     (3,946)       (1,966)          --
  Purchase of 8% debentures due 2005...............................       (450)         (216)          --
                                                                     ---------     ---------     --------
         Net cash provided by (used in) financing activities.......     13,450        14,837      (21,828)
                                                                     ---------     ---------     --------
Net increase (decrease) in cash and cash investments...............      1,559        (3,791)       1,676
Cash and cash investments at the beginning of the year.............      2,922         6,713        5,037
                                                                     ---------     ---------     --------
Cash and cash investments at the end of the year...................  $   4,481     $   2,922     $  6,713
                                                                     =========     =========     ========
Reconciliation of net income to net cash provided by operating
  activities:
  Net income.......................................................  $   9,230     $  27,067     $ 25,061
  Adjustments to reconcile net income to net cash provided by
    operating activities
    Extraordinary loss on early extinguishment of debt, net of
      tax..........................................................         --           307           --
    Gains on sales.................................................       (100)          (52)        (679)
    Depreciation, depletion and amortization.......................     68,489        63,308       40,693
    Dry hole and impairment........................................      6,703         7,088        4,690
    Interest capitalized...........................................     (1,834)         (739)        (451)
    Increase in deferred federal income taxes......................      5,592         8,374       13,356
    Change in assets and liabilities:
      (Increase) decrease in accounts receivable...................      7,095       (10,435)       4,172
      (Increase) decrease in federal income taxes and interest
         receivable................................................         --         3,320       (3,320)
      (Increase) decrease in other current assets..................         23           (18)        (360)
      (Increase) decrease in other assets..........................     (1,187)       (1,426)         838
      Increase (decrease) in accounts payable......................      1,942          (242)      (1,592)
      Increase in accrued interest payable.........................        131           381           80
      Increase in accrued payroll and related benefits.............          2           232           63
      Increase (decrease) in other current liabilities.............         63          (124)         (20)
      Increase in deferred credits.................................        184         2,232          613
                                                                     ---------     ---------     --------
Net cash provided by operating activities..........................  $  96,333     $  99,273     $ 83,144
                                                                     =========     =========     ========
</TABLE>
 
The accompanying notes to consolidated financial statements are an integral part
                                    hereof.
 
                                       35
<PAGE>   37
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
 
<TABLE>
<CAPTION>
                                                                        RETAINED
                                     SHARES      COMMON    ADDITIONAL   EARNINGS    TREASURY   SHAREHOLDERS'
                                   OUTSTANDING    STOCK     CAPITAL     (DEFICIT)    STOCK        EQUITY
                                   -----------   -------   ----------   ---------   --------   -------------
                                                       (DOLLARS EXPRESSED IN THOUSANDS)
<S>                                <C>           <C>       <C>          <C>         <C>        <C>
BALANCE AT DECEMBER 31, 1992.....   32,103,864   $32,104    $ 122,846   $(149,302)   $   --       $ 5,648
Net income.......................           --        --           --      25,061        --        25,061
Exercise of stock options........      345,308       345        3,072          --        --         3,417
Acquisition of treasury stock,
  at cost........................      (15,575)       --           --          --      (324)         (324)
Conversion of debenture..........           25        --            1          --        --             1
                                    ----------   -------    ---------   ---------    ------       -------
BALANCE AT DECEMBER 31, 1993.....   32,433,622    32,449      125,919    (124,241)     (324)       33,803
Net income.......................           --        --           --      27,067        --        27,067
Exercise of stock options........      376,639       377        4,756          --        --         5,133
Dividends ($0.06 per common
  share).........................           --        --           --      (1,966)       --        (1,966)
                                    ----------   -------    ---------   ---------    ------       -------
BALANCE AT DECEMBER 31, 1994.....   32,810,261    32,826      130,675     (99,140)     (324)       64,037
Net income.......................           --        --           --       9,230        --         9,230
Exercise of stock options........      181,136       181        2,206          --        --         2,387
Dividends ($0.12 per common
  share).........................           --        --           --      (3,946)       --        (3,946)
                                    ----------   -------    ---------   ---------    ------       -------
BALANCE AT DECEMBER 31, 1995.....   32,991,397   $33,007    $ 132,881   $ (93,856)   $ (324)      $71,708
                                    ==========   =======    =========   =========    ======       =======
</TABLE>
 
The accompanying notes to consolidated financial statements are an integral part
                                    hereof.
 
                                       36
<PAGE>   38
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
  Nature of Operations --
 
     Pogo Producing Company was incorporated in 1970. Pogo Producing Company and
its subsidiaries (the "Company") are engaged in oil and gas exploration,
development and production activities on its properties located offshore in the
Gulf of Mexico and onshore in the United States. The Company is also engaged in
exploration of its license concession in the Gulf of Thailand, and has
commenced, with its joint venture partners, a development program in connection
with its oil and gas discoveries on that concession. The Company has interest in
78 lease blocks offshore Louisiana and Texas, approximately 151,000 gross acres
onshore in the United States and approximately 1,300,000 gross acres offshore in
the Kingdom of Thailand.
 
  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 wholly-owned subsidiaries, after elimination of all
significant intercompany transactions.
 
  Inventories --
 
     Inventories consist primarily of tubular 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 per common and common equivalent share (primary earnings per
share) are based on the weighted average number of shares of Common Stock and
common equivalent shares outstanding during the periods. The dilutive effect of
stock options was considered in the earnings per share reported for the periods.
The 8% Debentures are common stock equivalents and were anti-dilutive in all
periods. Earnings per common and common equivalent share assuming full dilution
(fully diluted earnings per share) considered the 10.25% Notes (retired on April
18, 1994) which were anti-dilutive in all periods in which they were outstanding
and the 5 1/2% Notes (issued on March 16, 1994) which were dilutive for the
portion of 1994 in which they were
 
                                       37
<PAGE>   39
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
outstanding (such dilution was not sufficient to change reported earnings per
share) and anti-dilutive in 1995. Earnings per share are based on the following:
 
<TABLE>
<CAPTION>
                                                                1995      1994       1993
                                                               ------    -------    -------
                                                                 (EXPRESSED IN THOUSANDS)
    <S>                                                        <C>       <C>        <C>
    Earnings applicable to Common Stock:
      Primary --
         Income before extraordinary loss....................  $9,230    $27,374    $25,061
         Extraordinary loss..................................      --       (307)        --
                                                               ------    -------    -------
         Net income..........................................  $9,230    $27,067    $25,061
                                                               ======    =======    =======
      Fully diluted --
         Income before extraordinary loss....................  $9,230    $29,755    $25,061
         Extraordinary loss..................................      --       (307)        --
                                                               ------    -------    -------
         Net income..........................................  $9,230    $29,448    $25,061
                                                               ======    =======    =======
    Weighted average number of Common Stock and common
      equivalent shares outstanding:
         Primary.............................................  33,490     33,352     32,860
         Fully diluted.......................................  33,490     36,451     32,894
</TABLE>
 
  Production Imbalances --
 
     Owners of an oil and gas property often take more or less production from a
property than entitled to based on their ownership percentages in the property.
This results in a condition known in the industry as a production imbalance. The
Company follows the "take" (cash) method of accounting for production
imbalances. Under this method, the Company recognizes revenues on production as
it is taken and delivered to its purchasers. The Company's crude oil imbalances
are not significant. At December 31, 1995, the Company had taken approximately
1,872 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 1,675 MMcf more than its entitlement on
other properties placing the Company at year-end in a net under-delivered
position of approximately 197 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. 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. 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 capitalized costs, as determined above, 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.
 
     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.
 
     Effective January 1, 1995, the Company adopted Financial Accounting
Standard No. 121 (Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of ("SFAS 121")). SFAS 121 requires the Company
to review its oil and gas properties whenever events or changes in the
circumstances indicate that the carrying amount of such assets may not be
recoverable. If the carrying amount of any of the Company's oil and gas
properties (determined on a cost center by cost center basis) is greater
 
                                       38
<PAGE>   40
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
than its fair market value, an impairment loss is recognized. Adoption of SFAS
121 did not have a material effect on the Company's financial statements for the
year ended December 31, 1995.
 
  Consolidated Statements of Cash Flows --
 
     For the purpose of cash flows, the Company considers all highly liquid
investments with a maturity date of three months or less to be cash equivalents.
Significant transactions may occur which do not directly affect cash balances
and as such will not be disclosed in the Consolidated Statements of Cash Flows.
Certain such noncash transactions are disclosed in the Consolidated Statements
of Shareholders' Equity relating to the acquisition of treasury stock in 1993 in
exchange for stock options exercised and the conversion in 1993 of a debenture
into Common Stock. In addition, the Company in 1993, exchanged its working
interest in thirteen Gulf of Mexico oil and gas properties for an increased
working interest in five other Gulf of Mexico oil and gas properties in a
noncash "like kind" exchange. The oil and gas property and accumulated
depreciation, depletion and amortization accounts as reflected in the
Consolidated Balance Sheets have been adjusted to reflect the appropriate
amounts to record the working interests acquired and disposed of. The oil and
gas reserves acquired and disposed of are reflected as purchases and sales in
the "Estimates of Proved Reserves" roll forward included in the "Unaudited
Supplementary Financial Data" included elsewhere herein.
 
  Commitments and Contingencies --
 
     The Company's office rent expense was $861,000, $819,000, and $868,000 in
1995, 1994, and 1993, respectively. The Company has lease commitments for office
space of $1,067,000 in 1996, $1,056,000 in 1997, $1,007,000 in 1998, and
$962,000 in 1999 and 2000.
 
     The Company's subsidiary in Thailand, along with the other working interest
owners in the Tantawan Field, have guaranteed performance under a 10-year
charter agreement for a floating production, storage and offloading system. The
Company currently estimates its subsidiary's share of the commitment made under
this agreement will be $9,303,000 per year commencing in December 1996.
 
(2) INCOME TAXES
 
     The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1995, are as follows (expressed in
thousands):
 
<TABLE>
<CAPTION>
                                                               1995       1994       1993
                                                              -------    -------    -------
    <S>                                                       <C>        <C>        <C>
    United States...........................................  $16,899    $44,931    $43,749
    Foreign.................................................   (2,778)    (2,040)    (3,707)
                                                              -------    -------    -------
              Total.........................................  $14,121    $42,891    $40,042
                                                              =======    =======    =======
</TABLE>
 
     The components of federal income tax expense (benefit) for each of the
three years in the period ended December 31, 1995, are as follows (expressed in
thousands):
 
<TABLE>
<CAPTION>
                                                                1995      1994       1993
                                                               ------    -------    -------
    <S>                                                        <C>       <C>        <C>
    United States, current...................................  $   --    $ 7,500    $ 2,800
    United States, deferred(a)...............................   5,602      8,374     12,360
    Foreign, current.........................................    (711)      (357)      (179)
                                                               ------    -------    -------
              Total..........................................  $4,891    $15,517    $14,981
                                                               ======    =======    =======
</TABLE>
 
---------------
 
(a) Excludes $165,000 of deferred tax benefits on a $472,000 extraordinary loss
    in 1994.
 
                                       39
<PAGE>   41
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1995, 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>
                                                                   1995      1994      1993
                                                                   ----      ----      ----
    <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.................  (2.2)     (0.1)     (0.4)
      Foreign taxes..............................................   1.6       0.9       2.9
      Other......................................................   0.2       0.4        --
                                                                   ----      ----      ----
                                                                   34.6%     36.2%     37.5%
                                                                   ====      ====      ====
</TABLE>
 
     The deferred federal income tax provision is the result of the difference
between deferred tax liabilities determined at each balance sheet date. The
deferred tax liabilities are determined by applying current tax laws to
temporary differences in the recognition of revenue and expense for tax and
financial purposes. The principal components of the Company's deferred income
tax liability include the following at December 31, 1995 and 1994 (expressed in
thousands):
 
<TABLE>
<CAPTION>
                                                                         DECEMBER 31,
                                                                    ----------------------
                                                                      1995          1994
                                                                    ---------     --------
    <S>                                                             <C>           <C>
    Temporary differences arise primarily from the following --
      Intangible drilling costs, capitalized and amortized for
         financial statement purposes and deducted for income tax
         purposes.................................................  $ 168,753     $132,500
      Differences in depletion and depreciation rates used for
         tangible assets for financial and income tax purposes....   (100,491)     (78,457)
      Charges to property and equipment, expensed for financial
         statement purposes, and capitalized and amortized for
         income tax purposes......................................    (47,915)     (35,266)
      Interest charges, capitalized and amortized for financial
         statement purposes and deducted for income tax
         purposes.................................................     21,062       17,710
                                                                    ---------     --------
      Deferred tax liability......................................  $  41,409     $ 36,487
                                                                    =========     ========
</TABLE>
 
                                       40
<PAGE>   42
 
                     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, 1995 and
1994, consists of the following (dollars expressed in thousands):
 
<TABLE>
<CAPTION>
                                                                         DECEMBER 31,
                                                                     ---------------------
                                                                       1995         1994
                                                                     --------     --------
    <S>                                                              <C>          <C>
    Senior debt --
      Bank revolving credit agreement debt:
         Prime rate based loans, borrowings at December 31, 1995 at
           an interest rate of 8.5%................................  $  2,000     $     --
         LIBO Rate based loans, borrowings at December 31, 1995 and
           1994 at average interest rates of 6.81% and 7.63%,
           respectively............................................    27,000       14,000
                                                                     --------     --------
              Total bank revolving credit agreement debt...........    29,000       14,000
      Uncommitted credit lines with banks, borrowings at December
         31, 1995 and 1994 at average interest rates of 6.8% and
         7.21%, respectively.......................................     9,000        7,000
                                                                     --------     --------
    Total senior debt..............................................    38,000       21,000
                                                                     --------     --------
    Subordinated debt --
      5 1/2% Convertible subordinated notes, due 2004..............    86,250       86,250
      8% Convertible subordinated debentures, due 2005, and a
         $3,000 annual sinking fund requirement....................    41,999       43,281
                                                                     --------     --------
    Total subordinated debt........................................   128,249      129,531
                                                                     --------     --------
    Total debt.....................................................   166,249      150,531
                                                                     --------     --------
    Amount due within one year --
      Current portion of long-term debt, consisting of sinking fund
         requirements on 8% Debentures.............................    (3,000)      (1,282)
                                                                     --------     --------
    Long-term debt.................................................  $163,249     $149,249
                                                                     ========     ========
</TABLE>
 
     Effective June 1, 1995, the Company entered into an amended and restated
bank revolving credit agreement which extends to the Company an unsecured
$150,000,000 revolving/term credit facility. The facility will be fully
revolving until January 1, 1998, and will convert to a term loan with eight
quarterly installments commencing April 30, 1998. Effective November 1, 1995,
the Company voluntarily reduced, on a temporary basis, the commitment under the
facility to $125,000,000. The amount that may be borrowed under the facility may
not exceed a borrowing base, determined semiannually by the lenders based on the
discounted present value of future net revenues from certain of the Company's
oil and gas reserves and the provisions of the agreement. The borrowing base
currently exceeds $125,000,000. The facility is governed by various financial
covenants including the maintenance of positive working capital (excluding
current maturities of debt), a fixed charge ratio, as defined, of 2.0 or
greater, a limit of $300,000,000 on total debt, as defined, a $10,000,000 limit
on other senior debt, and a $10,000,000 limit on prepayment (without
refinancing) of subordinated debt in any one year and $20,000,000 in total
through February 1, 1998. The Company is prohibited from pledging borrowing base
properties as security for other debt. Borrowings under the facility bear
interest at a Base (Prime) rate, certificate of deposit rate plus 1 1/8%, or
LIBOR plus 1%, at the Company's option. A commitment fee on the unborrowed
amount under the facility is also charged. The Commitment fee is 5/16 of 1% per
annum on the unborrowed amount under the "active" portion of the facility and
 1/8 of 1% per annum on the unborrowed amount of the "inactive" portion of the
facility. Of the $125,000,000 that is currently available under the facility,
$100,000,000 is designated as "active" and
 
                                       41
<PAGE>   43
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
$25,000,000 is designated as "inactive". The Company incurred commitments fees
of $352,000 in 1995, $409,000 in 1994, and $149,000 in 1993 under this and a
prior revolving credit agreement.
 
     The Company has also entered into separate letter agreements with two banks
under which each bank may provide a $10,000,000 uncommitted money market line of
credit. The two lines of credit are on an as available or offered basis and the
banks have no obligations to make any advances under the lines. Loans made under
the agreements are for a maximum term of 30 days and are reflected as long-term
debt as the Company has the intent and ability to reborrow such amounts under
its bank revolving credit agreement discussed above. The agreements may be
terminated at any time by the Company or either bank.
 
     The 5 1/2% convertible subordinated notes, due 2004 (the "5 1/2% Notes")
are convertible into Common Stock at $22.188 per share subject to adjustment
upon the occurrence of certain events. The 5 1/2% Notes will be redeemable at
the option of the Company, in whole or in part, at any time on or after March
15, 1998, at a redemption price of 103.3% and decreasing percentages thereafter.
No sinking fund is provided. The 5 1/2% Notes are redeemable at the option of
the holder, upon the occurrence of a repurchase event (a change in control, as
defined), at 100% of the principal amount.
 
     The 8% convertible subordinated debentures, due 2005 (the "8% Debentures")
are convertible into Common Stock at $39.50 per share subject to adjustments
under certain circumstances, including stock splits. The 8% Debentures are
redeemable at the option of the Company at 102% through December 30, 1996, and
decreasing percentages thereafter, and are subject to mandatory annual sinking
fund requirements of $3,000,000 which commenced December 31, 1990. Such
requirements will be sufficient to retire 75% of the issue prior to maturity. As
of December 31, 1995, the Company has purchased $14,409,000 principal amount of
the bonds at less than face value resulting in both ordinary and extraordinary
gains. The Company has applied the entire principal amount of these bonds
towards the sinking fund requirements.
 
     Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are $3,000,000 in 1996, $3,000,000
in 1997, $20,100,000 in 1998, $20,100,000 in 1999 and $6,800,000 in 2000.
Included in the current maturities reflected above are $17,100,000 in 1998,
$17,100,000 in 1999, and $3,800,000 in 2000 relative to bank debt. The Company
has established a history of refinancing its bank debt before scheduled
maturities and expects to do so again before the amortization of bank debt
commences in 1998.
 
(4) SALES TO MAJOR CUSTOMERS
 
     The Company is an oil and gas exploration and production company that
generally sells its oil and gas to numerous customers on a month-to-month basis.
Sales to the following customers exceeded 10 percent of revenues during the
years indicated (expressed in thousands):
 
<TABLE>
<CAPTION>
                                                               1995       1994       1993
                                                              -------    -------    -------
    <S>                                                       <C>        <C>        <C>
    Enron Corp. and affiliates..............................  $42,895    $27,630    $16,437
    Coastal Gas Marketing Company...........................  $18,117    $27,609    $ 4,682
    Scurlock Oil Company....................................  $ 1,757    $21,134    $38,510
</TABLE>
 
(5) CREDIT RISK
 
     Substantially all of the Company's accounts receivable at December 31, 1995
and 1994, 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
 
                                       42
<PAGE>   44
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
Company on receivables generally have not been material. No known material
credit losses were experienced during 1995 or 1994.
 
(6) EMPLOYEE BENEFITS
 
     A total of 3,295,294 shares of Common Stock are reserved for issuance to
key employees and non-employee directors under the Company's stock option plans.
The stock option plans authorize the granting of options 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 granted and, if not
exercised, expire 10 years from the date of grant. At January 1, 1995, 1,387,537
shares were issuable under stock options outstanding. Options for 379,000 shares
were granted during 1995 at prices ranging from $22.00 to $23.88 per share.
During 1995, 181,136 options were exercised at prices ranging from $4.38 to
$23.88 per share and options to purchase 20,000 shares at a price of $14.88 were
cancelled. At December 31, 1995, options to purchase 1,565,401 shares were
outstanding (982,380 were exercisable) at prices ranging from $4.38 to $23.88.
 
     In October 1995, the Financial Accounting Standards Board issued Statement
No. 123 ("SFAS No. 123") a new standard on accounting for stock based
compensation. This standard establishes a fair value based method of accounting
for stock compensation plans awarded after December 31, 1995 and encourages
companies to adopt SFAS No. 123 in place of the existing accounting method which
requires expense recognition only in situations where stock compensation plans
award intrinsic value to recipients at the date of grant. Companies that do not
follow SFAS No. 123 for accounting purposes must make annual proforma
disclosures of its effects. Adoption of the standard by the Company is required
in 1996, although earlier implementation is permitted. The Company is currently
evaluating what effect, if any, SFAS No. 123 will have on its financial position
and results of operations.
 
     The Company has a tax-advantaged savings plan in which all salaried
employees may participate. Under such plan, a participating employee may
allocate up to 10% of his salary, and the Company makes matching contributions
of up to 6% thereof. 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
$277,000 to the savings plan in 1995, $375,000 in 1994, and $125,000 in 1993.
 
                                       43
<PAGE>   45
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     A trusteed retirement plan has been adopted by the Company for its 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. The
following table sets forth the plan's funded status (in thousands of dollars) as
of December 31, 1995, 1994, and 1993.
 
<TABLE>
<CAPTION>
                                                               1995       1994       1993
                                                              -------    -------    -------
    <S>                                                       <C>        <C>        <C>
    Actuarial present value (discounted at 7 1/4, 8 1/2, and
      7 1/2%, respectively) of benefit obligations:
      Accumulated benefit obligations --
         Vested.............................................  $ 5,488    $ 3,940    $ 4,019
         Non-vested.........................................    1,173        820        717
                                                              -------    -------    -------
         Total accumulated benefit obligations..............    6,661      4,760      4,736
      Projected salary increases (escalated at 5%, 6% and
         6%, respectively) and other changes................    1,734      1,434      1,500
                                                              -------    -------    -------
      Projected benefit obligations for service rendered to
         date...............................................    8,395      6,194      6,236
    Plan assets at fair value, primarily listed securities
      with an expected long-term rate of return of 8 1/2%...   19,089     13,988     13,481
                                                              -------    -------    -------
    Plan assets in excess of projected benefit
      obligations...........................................   10,694      7,794      7,245
    Unrecognized:
      Net overfunding being recognized over 15 years........     (543)      (646)      (750)
      Net gain arising from the difference between actual
         experience and that assumed........................   (5,989)    (3,443)    (3,209)
      Prior service cost....................................     (387)      (430)      (473)
                                                              -------    -------    -------
    Accrued retirement plan asset...........................  $ 3,775    $ 3,275    $ 2,813
                                                              =======    =======    =======
    Retirement plan cost (benefit) for 1995, 1994, and 1993
      included the following components:
      Service cost, benefits accruing each year with
         proration for future salary increases..............  $   480    $   499    $   611
      Interest cost on projected benefit obligations........      535        476        524
      Actual return on plan assets..........................   (1,182)    (1,139)    (1,164)
      Net amortization and deferral.........................     (333)      (298)      (278)
                                                              -------    -------    -------
      Accrued retirement plan cost (benefit)................  $  (500)   $  (462)   $  (307)
                                                              =======    =======    =======
</TABLE>
 
     Effective January 1, 1992, the Company adopted the provisions of the
Statement of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." The Company currently provides
full medical benefits to its retired employees and dependents. For current
employees, the company assumes all or a portion of post retirement medical and
term life insurance costs based on the employee's age and length of service with
the Company. The postretirement medical plan has no assets and is currently
funded by the Company on a pay-as-you-go basis.
 
                                       44
<PAGE>   46
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The following is an analysis (in thousands of dollars) of the annual
expense and activity in the deferred cost and benefits obligation accounts for
1993, 1994 and 1995. The computation assumes that future increases in medical
costs will trend down from 8.8% to 5% per year over the next 9 years for
purposes of estimating future costs. The medical cost trend rate assumption has
a significant effect on the amounts reported. Increasing the assumed medical
cost trend rate by one percent in each year would increase the aggregate of
service and interest cost components of net periodic postretirement benefit cost
for 1995 by $115,000 and the accumulated post retirement benefit obligation as
of December 31, 1995 by $850,000.
 
<TABLE>
<CAPTION>
                                                                 ANNUAL    DEFERRED    BENEFIT
                                                                 EXPENSE    COSTS     OBLIGATION
                                                                 -------   --------   ----------
    <S>                                                          <C>       <C>        <C>
    Balance at January 1, 1993.................................             $3,958     $ (4,758)
    Amortization of transition costs over 14 years representing
      the average remaining service period of eligible
      employees................................................  $  305       (305)         305
    Service cost, including interest...........................     368
    Interest cost on transition obligation.....................     407
                                                                 ------
    1993 expense...............................................  $1,080                  (1,080)
                                                                 ======
    Current benefits paid......................................                             246
    Unrecognized net loss......................................                          (1,400)
                                                                            ------     --------
    Balance at December 31, 1993...............................              3,653       (6,687)
    Amortization of transition costs over 14 years.............  $  304       (304)         304
    Amortization of net loss from earlier periods..............      57                      57
    Service cost, including interest...........................     395
    Interest cost on transition obligation.....................     494
                                                                 ------
    1994 expense...............................................  $1,250                  (1,250)
                                                                 ======
    Current benefits paid......................................                             126
    Unrecognized net gain......................................                           1,963
                                                                            ------     --------
    Balance at December 31, 1994...............................              3,349       (5,487)
    Amortization of transition costs over 14 years.............  $  304       (304)         304
    Amortization of net gain from earlier periods..............     (69)                    (69)
    Service cost, including interest...........................     241
    Interest cost on transition obligation.....................     399
                                                                 ------
    1995 expense...............................................  $  875                    (875)
                                                                 ======
    Current benefits paid......................................                             145
    Unrecognized net gain......................................                             541
                                                                            ------
    Balance at December 31, 1995...............................             $3,045
                                                                            ======
    Plan assets at fair value..................................                              --
                                                                                       --------
    Funded status at December 31, 1995 (discounted at
      7 1/4%)..................................................                        $ (5,441)
                                                                                       ========
</TABLE>
 
     The accumulated postretirement benefit obligation (in thousands of dollars)
at December 31, 1995 is attributable to the following groups:
 
<TABLE>
    <S>                                                                          <C>
    Retirees and beneficiaries.................................................  $ 1,890
    Dependents of retirees.....................................................      947
    Fully eligible active employees............................................      481
    Active employees, not fully eligible.......................................    2,123
                                                                                 -------
                                                                                 $ 5,441
                                                                                 =======
</TABLE>
 
                                       45
<PAGE>   47
 
                     POGO PRODUCING COMPANY & SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(7) FAIR VALUE OF FINANCIAL INSTRUMENTS
 
     The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
 
  Cash and Cash Investments
 
     Fair value is carrying value as no cash equivalents or cash investments are
included in the balances as of December 31, 1995 and 1994.
 
  Debt
 
<TABLE>
<CAPTION>
             INSTRUMENT                          BASIS OF FAIR VALUE ESTIMATE
------------------------------------  --------------------------------------------------
<S>                                   <C>
Bank revolving credit agreement       Fair value is carrying value as of December 31,
                                      1995 and 1994, based on 1995 negotiations with the
                                      lenders and the market value interest rates.

Uncommitted credit lines with banks   Fair value is carrying value as of December 31,
                                      1995 and 1994 based on the market value interest
                                      rates.

5 1/2% Notes                          Fair value is 118% and 94%, of carrying value as
                                      of December 31, 1995 and 1994, respectively, based
                                      on the quoted market prices for this publicly
                                      traded debt.

8% Debentures                         Fair value is 102.5% and 98.75%, of carrying value
                                      as of December 31, 1995 and 1994, respectively,
                                      based on the quoted market prices for this
                                      publicly traded debt.
</TABLE>
 
     The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1995 and 1994 (in thousands of dollars) are as
follows:
 
<TABLE>
<CAPTION>
                                                        1995                     1994
                                                ---------------------    --------------------
                                                CARRYING      FAIR       CARRYING      FAIR
                                                 VALUE        VALUE       VALUE       VALUE
                                                --------    ---------    --------    --------
    <S>                                         <C>         <C>          <C>         <C>
    Cash and cash investments.................  $  4,481    $   4,481    $  2,922    $  2,922
    Debt:
      Bank revolving credit agreement.........   (29,000)     (29,000)    (14,000)    (14,000)
      Uncommitted credit lines with banks.....    (9,000)      (9,000)     (7,000)     (7,000)
      5 1/2% Notes............................   (86,250)    (101,775)    (86,250)    (81,075)
      8% Debentures...........................   (41,999)     (43,049)    (43,281)    (42,740)
</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. Gains and losses on these activities are recognized in revenues when
the hedged production occurs.
 
                                       46
<PAGE>   48
 
                     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. United States income tax expense was
determined by applying the statutory rates to pretax operating results with
adjustments for permanent differences. Kingdom of Thailand tax expense was
determined by applying the statutory tax rate to Thailand taxable income.
 
<TABLE>
<CAPTION>
                                                                        UNITED     KINGDOM OF
                                                           TOTAL        STATES      THAILAND
                                                          --------     --------    ----------
                                                                (EXPRESSED IN THOUSANDS)
    <S>                                                   <C>          <C>         <C>
                                                                         1995
                                                          -----------------------------------
    Oil and gas revenues................................  $157,459     $157,536     $    (77)
    Lease operating expense.............................   (35,071)     (35,071)          --
    Exploration expense.................................    (7,468)      (6,111)      (1,357)
    Dry hole and impairment expense.....................    (6,703)      (6,703)          --
    Depreciation, depletion and amortization expense....   (67,831)     (67,798)         (33)
                                                          --------     --------     --------
    Pretax operating results............................    40,386       41,853       (1,467)
    Income tax (expense) benefit........................   (13,623)     (14,334)         711
                                                          --------     --------     --------
    Operating results...................................  $ 26,763     $ 27,519     $   (756)
                                                          ========     ========     ========

                                                                         1994
                                                          -----------------------------------
    Oil and gas revenues................................  $173,556     $173,518     $     38
    Lease operating expense.............................   (29,768)     (29,768)          --
    Exploration expense.................................    (5,257)      (3,931)      (1,326)
    Dry hole and impairment expense.....................    (7,088)      (7,088)          --
    Depreciation, depletion and amortization expense....   (62,723)     (62,690)         (33)
                                                          --------     --------     --------
    Pretax operating results............................    68,720       70,041       (1,321)
    Income tax (expense) benefit........................   (24,262)     (24,619)         357
                                                          --------     --------     --------
    Operating results...................................  $ 44,458     $ 45,422     $   (964)
                                                          ========     ========     ========

                                                                         1993
                                                          -----------------------------------
    Oil and gas revenues................................  $136,553     $136,525     $     28
    Lease operating expense.............................   (26,633)     (26,633)          --
    Exploration expense.................................    (2,455)      (1,060)      (1,395)
    Dry hole and impairment expense.....................    (4,690)      (2,737)      (1,953)
    Depreciation, depletion and amortization expense....   (40,224)     (40,193)         (31)
                                                          --------     --------     --------
    Pretax operating results............................    62,551       65,902       (3,351)
    Income tax expense..................................   (22,712)     (22,891)         179
                                                          --------     --------     --------
    Operating results...................................  $ 39,839     $ 43,011     $ (3,172)
                                                          ========     ========     ========
</TABLE>
 
                                       47
<PAGE>   49
 
             UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
 
     The following table sets forth the Company's capitalized costs (expressed
in thousands) incurred for oil and gas producing activities during the years
indicated.
 
<TABLE>
<CAPTION>
                                                            1995         1994        1993
                                                          --------     --------     -------
    <S>                                                   <C>          <C>          <C>
    Capitalized costs incurred:
      Property acquisition -- United States.............  $ 14,864     $ 36,354     $ 1,520
      Property acquisition -- Kingdom of Thailand.......     4,171           --          --
      Exploration -- United States......................    14,562        5,803       8,267
      Exploration -- Kingdom of Thailand................     5,418        5,022       4,583
      Development -- United States......................    39,461       67,143      57,648
      Development -- Kingdom of Thailand................    23,994           --          --
      Interest capitalized..............................     1,834          739         451
                                                          --------     --------     -------
                                                          $104,304     $115,061     $72,469
                                                          ========     ========     =======
    Provision for depreciation, depletion and
      amortization:
      United States.....................................  $ 67,798     $ 62,690     $40,193
      Kingdom of Thailand...............................        33           33          31
                                                          --------     --------     -------
                                                          $ 67,831     $ 62,723     $40,224
                                                          ========     ========     =======
</TABLE>
 
                                       48
<PAGE>   50
 
             UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
 
     The following information regarding estimates of the Company's proved oil
and gas reserves, which are located offshore in United States waters of the Gulf
of Mexico, onshore in the United States and offshore in the Kingdom of Thailand
is based on reports prepared by Ryder Scott Company Petroleum Engineers. Their
summary report dated February 5, 1996 is set forth as an exhibit to this Form
10-K and includes definitions and assumptions that served as the basis for the
discussions under the caption "Item 1, Business -- Exploration and Production
Data -- Reserves." Such definitions and assumptions should be referred to in
connection with the following information.
 
                          ESTIMATES OF PROVED RESERVES
 
<TABLE>
<CAPTION>
                                       TOTAL COMPANY              UNITED STATES           KINGDOM OF THAILAND
                                 -------------------------  -------------------------  -------------------------
                                     OIL                        OIL                        OIL
                                 CONDENSATE &               CONDENSATE &               CONDENSATE &
                                 NATURAL GAS                NATURAL GAS                NATURAL GAS
                                   LIQUIDS     NATURAL GAS    LIQUIDS     NATURAL GAS    LIQUIDS     NATURAL GAS
                                    (BBLS)       (MMCF)        (BBLS)       (MMCF)        (BBLS)       (MMCF)
                                 ------------  -----------  ------------  -----------  ------------  -----------
<S>                              <C>           <C>          <C>           <C>          <C>           <C>
Proved reserves as of
  December 31, 1992...........    22,555,788     207,068     19,978,881     196,400      2,576,907      10,668
  Revisions of previous
     estimates................       342,022       1,148        342,022       1,148             --          --
  Extensions, discoveries and
     other additions..........     9,764,408      55,626      6,916,502      32,820      2,847,906      22,806
  Purchase of properties......       182,610      13,192        182,610      13,192             --          --
  Sale of properties..........      (356,514)    (11,849)      (356,514)    (11,849)            --          --
  Estimated 1993 production...    (4,219,873)    (32,319)    (4,219,873)    (32,319)            --          --
                                  ----------     -------     ----------     -------     ----------     -------
Proved reserves as of
  December 31, 1993...........    28,268,441     232,866     22,843,628     199,392      5,424,813      33,474
  Revisions of previous
     estimates................     1,286,984      (2,558)     1,286,984      (2,558)            --          --
  Extensions, discoveries and
     other additions..........     6,565,442      49,517      4,315,883      26,252      2,249,559      23,265
  Purchase of properties......     2,686,919      15,792      2,686,919      15,792             --          --
  Sale of properties..........          (497)       (109)          (497)       (109)            --          --
  Estimated 1994 production...    (4,945,677)    (52,618)    (4,945,677)    (52,618)            --          --
                                  ----------     -------     ----------     -------     ----------     -------
Proved reserves as of
  December 31, 1994...........    33,861,612     242,890     26,187,240     186,151      7,674,372      56,739
  Revisions of previous
     estimates................       496,849      21,800        363,213      16,592        133,636       5,208
  Extensions, discoveries and
     other additions..........    11,901,880      78,434      4,267,871      35,058      7,634,009      43,376
  Purchase of properties......     4,015,131      30,054        460,156       3,770      3,554,975      26,284
  Sale of properties..........       (15,144)       (748)       (15,144)       (748)            --          --
  Estimated 1995 production...    (5,078,326)    (44,369)    (5,078,326)    (44,369)            --          --
                                  ----------     -------     ----------     -------     ----------     -------
Proved reserves as of
  December 31, 1995...........    45,182,002     328,061     26,185,010     196,454     18,996,992     131,607
                                  ==========     =======     ==========     =======     ==========     =======
Proved developed reserves as
  of:
  December 31, 1992...........    18,798,149     175,523     18,798,149     175,523             --          --
  December 31, 1993...........    20,976,194     183,139     20,976,194     183,139             --          --
  December 31, 1994...........    24,669,755     178,518     24,669,755     178,518             --          --
  December 31, 1995...........    22,487,608     164,679     22,487,608     164,679             --          --
</TABLE>
 
                                       49
<PAGE>   51
 
                   STANDARDIZED MEASURE OF DISCOUNTED FUTURE
 
       NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED
 
<TABLE>
<CAPTION>
                                                              TOTAL       UNITED      KINGDOM OF
                                                             COMPANY      STATES       THAILAND
                                                            ---------    ---------    ----------
                                                                  (EXPRESSED IN THOUSANDS)
<S>                                                         <C>          <C>          <C>
                                                                           1995
                                                            ------------------------------------
Future gross revenues.....................................  $1,495,320   $ 873,578    $  621,742
Future production costs:
  Lease operating expense.................................    (415,829)   (208,477)     (207,352)
Future development and abandonment costs..................    (247,019)   (119,821)     (127,198)
                                                            ----------   ---------    ----------
Future net cash flows before income taxes.................     832,472     545,280       287,192
Discount at 10% per annum.................................    (299,997)   (144,435)     (155,562)
                                                            ----------   ---------    ----------
Discounted future net cash flow before income taxes.......     532,475     400,845       131,630
Future income taxes, net of discount at 10% per annum.....    (155,330)   (104,864)      (50,466)
                                                            ----------   ---------    ----------
Standardized measure of discounted future net cash flows               
  relating to proved oil and gas reserves.................  $  377,145   $ 295,981    $   81,164
                                                            ==========   =========    ==========

                                                                           1994
                                                            ------------------------------------
Future gross revenues.....................................  $  985,888   $ 720,086    $  265,802
Future production costs:                                                
  Lease operating expense.................................    (253,140)   (192,834)      (60,306)
Future development and abandonment costs..................    (180,839)    (86,684)      (94,155)
                                                            ----------   ---------    ----------
Future net cash flows before income taxes.................     551,909     440,568       111,341
Discount at 10% per annum.................................    (168,929)   (109,700)      (59,229)
                                                            ----------   ---------    ----------
Discounted future net cash flow before income taxes.......     382,980     330,868        52,112
Future income taxes, net of discount at 10% per annum.....     (92,911)    (73,602)      (19,309)
                                                            ----------   ---------    ----------
Standardized measure of discounted future net cash flows                
  relating to proved oil and gas reserves.................  $  290,069   $ 257,266    $   32,803
                                                            ==========   =========    ==========

                                                                           1993
                                                            ------------------------------------
Future gross revenues.....................................  $  869,783   $ 744,201    $  125,582
Future production costs:                                                
  Lease operating expense.................................    (186,464)   (158,934)      (27,530)
Future development and abandonment costs..................    (133,258)    (79,735)      (53,523)
                                                            ----------   ---------    ----------
Future net cash flows before income taxes.................     550,061     505,532        44,529
Discount at 10% per annum.................................    (146,221)   (118,858)      (27,363)
                                                            ----------   ---------    ----------
Discounted future net cash flow before income taxes.......     403,840     386,674        17,166
Future income taxes, net of discount at 10% per annum.....    (103,580)    (98,788)       (4,792)
                                                            ----------   ---------    ----------
Standardized measure of discounted future net cash flows                
  relating to proved oil and gas reserves.................  $  300,260   $ 287,886    $   12,374
                                                            ==========   =========    ==========
</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.
 
                                       50
<PAGE>   52
 
                   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 and the Kingdom of Thailand, as noted.
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31, 1995
                                                             ------------------------------------
                                                               TOTAL       UNITED      KINGDOM OF
                                                              COMPANY      STATES       THAILAND
                                                             ---------    ---------    ----------
                                                                   (EXPRESSED IN THOUSANDS)
<S>                                                          <C>          <C>          <C>
Beginning balance..........................................  $ 290,069    $ 257,266     $ 32,803
Revisions to prior years' proved reserves:
  Net changes in prices and production costs...............     34,004       69,988      (35,984)
  Net changes due to revisions in quantity estimates.......     29,630       26,109        3,521
  Net changes in estimates of future development costs.....     (8,632)     (36,721)      28,089
  Accretion of discount....................................     38,298       33,087        5,211
  Changes in production rate...............................    (14,754)     (15,792)       1,038
  Other....................................................     (4,393)        (432)      (3,961)
                                                             ---------    ---------     --------
          Total revisions..................................     74,153       76,239       (2,086)
New field discoveries and extensions, net of future
  production and development costs.........................    105,172       71,701       33,471
Purchases of properties....................................     29,299        5,160       24,139
Sales of properties........................................       (969)        (969)          --
Sales of oil and gas produced, net of production costs.....   (121,615)    (121,615)          --
Previously estimated development costs incurred............     63,455       39,461       23,994
Net change in income taxes.................................    (62,419)     (31,262)     (31,157)
                                                             ---------    ---------     --------
          Net change in standardized measure of discounted
            future net cash flows..........................     87,076       38,715       48,361
                                                             ---------    ---------     --------
Ending balance.............................................  $ 377,145    $ 295,981     $ 81,164
                                                             =========    =========     ========
</TABLE>
 
                                       51
<PAGE>   53
 
                   STANDARDIZED MEASURE OF DISCOUNTED FUTURE
 
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - UNAUDITED - (CONTINUED)
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31, 1994
                                                             ------------------------------------
                                                               TOTAL       UNITED      KINGDOM OF
                                                              COMPANY      STATES       THAILAND
                                                             ---------    ---------    ----------
                                                                   (EXPRESSED IN THOUSANDS)
<S>                                                          <C>          <C>          <C>
Beginning balance..........................................  $ 300,260    $ 287,886     $ 12,374
Revisions to prior years' proved reserves:
  Net changes in prices and production costs...............    (30,813)     (44,948)      14,135
  Net changes due to revisions in quantity estimates.......      5,947        5,947           --
  Net changes in estimates of future development costs.....    (45,370)     (47,880)       2,510
  Accretion of discount....................................     40,384       38,667        1,717
  Changes in production rate...............................      1,162       (9,574)      10,736
  Other....................................................      5,326        5,421          (95)
                                                             ---------    ---------     --------
          Total revisions..................................    (23,364)     (52,367)      29,003
New field discoveries and extensions, net of future
  production and development costs.........................     59,047       53,104        5,943
Purchases of properties....................................     22,973       22,973           --
Sales of properties........................................     (4,114)      (4,114)          --
Sales of oil and gas produced, net of production costs.....   (143,655)    (143,655)          --
Previously estimated development costs incurred............     68,252       68,252           --
Net change in income taxes.................................     10,670       25,187      (14,517)
                                                             ---------    ---------     --------
          Net change in standardized measure of discounted
            future net cash flows..........................    (10,191)     (30,620)      20,429
                                                             ---------    ---------     --------
Ending balance.............................................  $ 290,069    $ 257,266     $ 32,803
                                                             =========    =========     ========
</TABLE>
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31, 1993
                                                             ------------------------------------
                                                               TOTAL       UNITED      KINGDOM OF
                                                              COMPANY      STATES       THAILAND
                                                             ---------    ---------    ----------
                                                                   (EXPRESSED IN THOUSANDS)
<S>                                                          <C>          <C>          <C>
Beginning balance..........................................  $ 307,657    $ 299,045     $  8,612
Revisions to prior years' proved reserves:
  Net changes in prices and production costs...............    (41,775)     (34,842)      (6,933)
  Net changes due to revisions in quantity estimates.......      4,066        4,066           --
  Net changes in estimates of future development costs.....        662         (871)       1,533
  Accretion of discount....................................     40,510       39,089        1,421
  Changes in production rate...............................      5,134        6,728       (1,594)
  Other....................................................      2,278        3,935       (1,657)
                                                             ---------    ---------     --------
          Total revisions..................................     10,875       18,105       (7,230)
New field discoveries and extensions, net of future
  production and development costs.........................     39,247       29,059       10,188
Purchases of properties....................................     22,516       22,516           --
Sales of properties........................................    (19,633)     (19,633)          --
Sales of oil and gas produced, net of production costs.....   (110,870)    (110,870)          --
Previously estimated development costs incurred............     56,604       56,604           --
Net change in income taxes.................................     (6,136)      (6,940)         804
                                                             ---------    ---------     --------
          Net change in standardized measure of discounted
            future net cash flows..........................     (7,397)     (11,159)       3,762
                                                             ---------    ---------     --------
Ending balance.............................................  $ 300,260    $ 287,886     $ 12,374
                                                             =========    =========     ========
</TABLE>
 
                                       52
<PAGE>   54
 
QUARTERLY RESULTS - UNAUDITED
 
     Summaries of the Company's results of operations by quarter for the years
1995 and 1994 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>
1995
Revenues......................................  $41,810      $41,738       $ 36,967         $37,044
Gross profit(a)...............................  $12,063      $13,562       $  6,849         $ 7,354
Net income....................................  $ 3,431      $ 4,353       $    722         $   724
Earnings per share
  (primary and fully diluted).................  $  0.10      $  0.13       $   0.02         $  0.02
1994
Revenues......................................  $37,892      $49,734       $ 46,452         $39,530
Gross profit(a)...............................  $17,355      $21,782       $ 17,762         $11,288
Income before extraordinary loss..............  $ 7,278      $ 9,903       $  7,433         $ 2,760
Extraordinary loss on early extinguishment of
  debt........................................       --      $  (307)            --              --
Net income....................................  $ 7,278      $ 9,596       $  7,433         $ 2,760
Earnings per share:
  Primary --
     Income before extraordinary loss.........  $  0.22      $  0.30       $   0.22         $  0.08
     Extraordinary loss.......................       --      $ (0.01)            --              --
     Net income...............................  $  0.22      $  0.29       $   0.22         $  0.08
  Fully diluted --
     Income before extraordinary loss.........  $  0.22      $  0.29       $   0.22         $  0.08
     Extraordinary loss.......................       --      $ (0.01)            --              --
     Net income...............................  $  0.22      $  0.28       $   0.22         $  0.08
</TABLE>
 
---------------
 
(a) Represents revenues less lease operating, exploration, dry hole and
    impairment, and depreciation depletion and amortization expenses.
 
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
 
     Not applicable.
 
                                       53
<PAGE>   55
 
                                    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
23, 1996, to be filed within 120 days of December 31, 1995 pursuant to
Regulation 14A under the Securities Exchange Act of 1934, as amended (the
Company's "1996 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 1996
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 1996 Proxy Statement is
incorporated herein by reference.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
 
     The information regarding certain relationships and related transactions
with management in the Company's 1996 Proxy Statement is incorporated herein by
reference.
 
                                       54
<PAGE>   56
 
                                    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
 
        1. Financial Statements and Supplementary Data:
 
<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
            <S>                                                             <C>
            Report of Independent Public Accountants......................   32
            Consolidated statements of income.............................   33
            Consolidated balance sheets...................................   34
            Consolidated statements of cash flows.........................   35
            Consolidated statements of shareholders' equity...............   36
            Notes to consolidated financial statements....................   37
            Unaudited supplementary financial data........................   47
</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>
        <S>          <C>  <C>
        * 3(a)       --   Restated Certificate of Incorporation of Pogo Producing Company.
                          (Exhibit 3(a), Annual Report on Form 10-K for the year ended December
                          31, 1987, File No. 0-5468).
        * 3(a)(i)    --   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(b)       --   Bylaws of Pogo Producing Company, as amended and restated through
                          July 24, 1990. (Exhibit 3(a), Quarterly Report on Form 10-Q for the
                          quarter ended June 30, 1990, File No. 0-5468).
        * 4(a)       --   Amended and Restated Credit Agreement dated as of June 1, 1995 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 September
                          30, 1995, File No. 1-7792).
        * 4(b)       --   Indenture dated as of October 15, 1980 to Chemical Bank, as Trustee.
                          (Exhibit 4, File No. 2-69428).
        * 4(c)       --   Indenture dated as of March 23, 1994 to Shawmut Bank Connecticut,
                          National Association, as Trustee. (Exhibit 4(c), Annual Report on
                          Form 10-K for the year ended December 31, 1994, File No. 1-7792)
        * 4(d)       --   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(e)       --   Certificate of Designations of Series A Junior Participating
                          Preferred Stock of Pogo Producing Company dated April 26, 1994.
                          (Exhibit 4(d), Registration Statement on Form S-8 filed August 9,
                          1994, File No. 33-54969).
                          Pogo Producing Company agrees to furnish to the Commission upon
                          request a copy of any agreement defining the rights of holders of
                          long-term debt of Pogo Producing Company and all its subsidiaries for
                          which consolidated or unconsolidated financial statements are
                          required to be filed under which the total amount of securities
                          authorized does not exceed 10% of the total assets of Pogo Producing
                          Company and its subsidiaries on a consolidated basis.
</TABLE>
 
                                       55
<PAGE>   57
 
<TABLE>
        <S>          <C>  <C>
                          EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhibits
                          10(a) through 10(g)(2), inclusive)
        *10(a)       --   1977 Stock Option Plan of Pogo Producing Company, as amended as of
                          September 28, 1981 and July 24, 1984. (Exhibit 10(a), Annual Report
                          on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
        *10(a)(1)    --   Form of Amended Nonqualified Stock Option Agreement under 1977 Stock
                          Option Plan (with stock appreciation rights and without employment
                          restrictions). (Exhibit 10(a)(1), Annual Report on From 10-K for the
                          year ended December 31, 1981, File No. 0-5468).
        *10(a)(2)    --   Form of Amended Incentive Stock Option Agreement under 1977 Stock
                          Option Plan (with stock option appreciation rights and without
                          employment restrictions), (Exhibit 10(a)(2), Annual Report on Form
                          10-K for the year ended December 31, 1981, File No. 0-5468).
        *10(a)(3)    --   Form of Amended Nonqualified Stock Option Agreement under 1977 Stock
                          Option Plan (without stock appreciation rights and with employment
                          restrictions). (Exhibit 10(a)(3), Annual Report on Form 10-K for the
                          year ended December 31, 1981, File No. 0-5468).
        *10(a)(4)    --   Form of Amended Incentive Stock Option Agreement under 1977 Stock
                          Option Plan (without stock option appreciation rights and with
                          employment restrictions). (Exhibit 10(a)(4), Annual Report on Form
                          10-K for the year ended December 31, 1981, File No. 0-5468).
        *10(a)(5)    --   Form of Amended Nonqualified Stock Option Agreement under 1977 Stock
                          Option Plan (with stock appreciation rights and with employment
                          restrictions). (Exhibit 10(a)(5), Annual Report on Form 10-K for the
                          year ended December 31, 1981, File No. 0-5468).
        *10(a)(6)    --   Form of Amended Incentive Stock Option Agreement under 1977 Stock
                          Option Plan (with stock option appreciation rights and with
                          employment restrictions). (Exhibit 10(a)(6), Annual Report on Form
                          10-K for the year ended December 31, 1981, File No. 0-5468).
        *10(a)(7)    --   Form of Amended Nonqualified Stock Option Agreement under 1977 Stock
                          Option Plan (without stock appreciation rights and without employment
                          restrictions). (Exhibit 10(a)(7), Annual Report on Form 10-K for the
                          year ended December 31, 1981, File No. 0-5468).
        *10(a)(8)    --   Form of Amended Incentive Stock Option Agreement under 1977 Stock
                          Option Plan (without stock option appreciation rights and without
                          employment restrictions). (Exhibit 10(a)(8), Annual Report on Form
                          10-K for the year ended December 31, 1981, File No. 0-5468).
        *10(b)       --   1981 Stock Option Plan of Pogo Producing Company, as amended as of
                          July 24, 1984. (Exhibit 10(b), Annual Report on Form 10-K for the
                          year ended December 31, 1984, File No. 0-5468).
        *10(b)(1)    --   Form of Stock Option Agreement under 1981 Nonqualified Stock Option
                          Plan (with stock appreciation rights). Exhibit 10(b)(1), Annual
                          Report on Form 10-K for the year ended December 31, 1981, File No.
                          0-5468).
        *10(b)(2)    --   Form of Stock Option Agreement under 1981 Nonqualified Stock Option
                          Plan (without stock appreciation rights). Exhibit 10(b)(2), Annual
                          Report on Form 10-K for the year ended December 31, 1981, File No.
                          0-5468).
        *10(c)       --   1981 Incentive and Nonqualified Stock Option Plan of Pogo Producing
                          Company, as amended as of July 24, 1984. (Exhibit 10(c), Annual
                          Report on Form 10-K for the year ended December 31, 1984, File No.
                          0-5468).
</TABLE>
 
                                       56
<PAGE>   58
 
<TABLE>
        <S>          <C>  <C>
        *10(c)(1)    --   Form of Stock Option Agreement under 1981 Incentive Stock Option
                          Plan. (Exhibit 10(c)(1), Annual Report of Form 10-K for the year
                          ended December 31, 1981, File No. 0-5468).
        *10(d)       --   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(d)(1)    --   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(d)(2)    --   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(e)       --   Form of Letter Agreement respecting treatment of options upon change
                          in control. (Exhibit 19(f), Quarterly Report on Form 10-Q for the
                          quarter ended June 30, 1982. File No. 0-5468).
         10(f)(1)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Stuart P. Burbach, dated February 1, 1996.
         10(f)(2)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Jerry A. Cooper, dated February 1, 1996.
         10(f)(3)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Kenneth R. Good, dated February 1, 1996.
         10(f)(4)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and R. Phillip Laney, dated February 1, 1996.
         10(f)(5)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and John O. McCoy, Jr., dated February 1, 1996.
         10(f)(6)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Paul G. Van Wagenen, dated February 1, 1996.
         10(g)(1)    --   Excess Benefits Letter Agreement by and between Pogo Producing
                          Company and Kenneth R. Good, dated March 2, 1995.
         10(g)(2)    --   Excess Benefits Letter Agreement by and between Pogo Producing
                          Company and Paul G. Van Wagenen, dated March 2, 1995.
        *10(h)       --   Undertaking by Pogo Producing Company dated as of August 8, 1977.
                          (Exhibit 10(e), Annual Report on Form 10-K for the year ended
                          December 31, 1980, File No. 0-5468).
        *10(i)       --   Limited partnership agreement of Pogo Gulf Coast, Ltd. (Exhibit 19,
                          Quarterly Report on Form 10-Q for the quarter ended June 30, 1989,
                          File No. 0-5468).
         10(j)       --   Bareboat Charter Agreement by and between Tantawan Services, LLC and
                          Tantawan Production B.V., dated as of February 9, 1996.
         21          --   List of Subsidiaries of Pogo Producing Company.
         23(a)       --   Consent of Independent Public Accountants.
         23(b)       --   Consent of Independent Petroleum Engineers.
</TABLE>
 
                                       57
<PAGE>   59
 
<TABLE>
        <S>          <C>  <C>
         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, 1995.
         27          --   Financial Data Schedule.
         28          --   Summary of Reserve Report of Ryder Scott Company Petroleum Engineers
                          dated February 5, 1996 relating to oil and gas reserves of Pogo
                          Producing Company.
</TABLE>
 
---------------
* Asterisk indicates exhibits incorporated by reference as shown.
 
     (B) REPORTS ON FORM 8-K
 
        None
 
                                       58
<PAGE>   60
 
                                   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 4, 1996
 
     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 4, 1996.
 
<TABLE>
<CAPTION>
                SIGNATURES                                TITLE
------------------------------------------    ------------------------------
<S>                                           <C>
         /s/  PAUL G. VAN WAGENEN             Principal Executive
------------------------------------------    Officer and Director
           Paul G. Van Wagenen
     Chairman of the Board, President
       and Chief Executive Officer

          /s/  JOHN W. ELSENHANS              Principal Financial
------------------------------------------    Officer
            John W. Elsenhans
            Vice President and
                Treasurer

           /s/  THOMAS E. HART                Principal Accounting Officer
------------------------------------------
              Thomas E. Hart
            Vice President and
                Controller

             TOBIN ARMSTRONG*                 Director
------------------------------------------
             Tobin Armstrong

             JACK S. BLANTON*                 Director
------------------------------------------
             Jack S. Blanton

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

           JOHN B. CARTER, JR.*               Director
------------------------------------------
           John B. Carter, Jr.

            WILLIAM L. FISHER*                Director
------------------------------------------
            William L. Fisher
</TABLE>
 
                                       59
<PAGE>   61
 
<TABLE>
<CAPTION>
                SIGNATURES                                TITLE
------------------------------------------    -----------------------------
<S>                                           <C>
            WILLIAM E. GIPSON*                Director
------------------------------------------
            William E. Gipson

              GERRIT W. GONG*                 Director
------------------------------------------
              Gerrit W. Gong

              J. STUART HUNT*                 Director
------------------------------------------
              J. Stuart Hunt

        FREDERICK A. KLINGENSTEIN*            Director
------------------------------------------
        Frederick A. Klingenstein

            NICHOLAS R. PETRY*                Director
------------------------------------------
            Nicholas R. Petry

             JACK A. VICKERS*                 Director
------------------------------------------
             Jack A. Vickers

      *By:  /s/  THOMAS E. HART
------------------------------------------
              Thomas E. Hart
             Attorney-in-Fact
</TABLE>
 
                                       60
<PAGE>   62
                                      EXHIBIT  INDEX

<TABLE>
        <S>          <C>  <C>
         10(f)(1)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Stuart P. Burbach, dated February 1, 1996.
         10(f)(2)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Jerry A. Cooper, dated February 1, 1996.
         10(f)(3)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Kenneth R. Good, dated February 1, 1996.
         10(f)(4)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and R. Phillip Laney, dated February 1, 1996.
         10(f)(5)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and John O. McCoy, Jr., dated February 1, 1996.
         10(f)(6)    --   Executive Employment Agreement by and between Pogo Producing Company
                          and Paul G. Van Wagenen, dated February 1, 1996.
         10(g)(1)    --   Excess Benefits Letter Agreement by and between Pogo Producing
                          Company and Kenneth R. Good, dated March 2, 1995.
         10(g)(2)    --   Excess Benefits Letter Agreement by and between Pogo Producing
                          Company and Paul G. Van Wagenen, dated March 2, 1995.
         10(j)       --   Bareboat Charter Agreement by and between Tantawan Services, LLC and
                          Tantawan Production B.V., dated as of February 9, 1996.
         21          --   List of Subsidiaries of Pogo Producing Company.
         23(a)       --   Consent of Independent Public Accountants.
         23(b)       --   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, 1995.
         27          --   Financial Data Schedule.
         28          --   Summary of Reserve Report of Ryder Scott Company Petroleum Engineers
                          dated February 5, 1996 relating to oil and gas reserves of Pogo
                          Producing Company.


</TABLE>