<PAGE>   1
================================================================================
                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-K
================================================================================

(Mark One)

[X]             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1998

                                       OR

[ ]             TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                         Commission file number 0-28608

                               PETSEC ENERGY INC.*
             (Exact name of Registrant as specified in its charter)

                                     Nevada
         (State or other jurisdiction of incorporation or organization)

                         143 Ridgeway Drive, Suite 113
                           Lafayette, Louisiana 70503
                    (Address of principal executive offices)

                                 (318) 989-1942
              (Registrant's Telephone Number, including Area Code)

                                   84-1157209
                        (IRS Employer Identification No.)

           Securities registered pursuant to Section 12(b) of the Act.

<TABLE>
<CAPTION>
        Title of each                                 Name of each exchange
            class                                      on which registered
<S>                                                   <C>
             None                                             None
</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 Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
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]

All of the registrant's voting stock is held by affiliates of the registrant. As
of March 31, 1999, there was outstanding 1 share of Common Stock, par value
$1.00 per share, of the registrant.

*Petsec Energy Inc. is a wholly owned operating subsidiary of Petsec Energy Ltd,
a listed Australian public company registered with the Commission as a result of
its public offering of American Depositary Receipts ("ADRs") listed on the New
York Stock Exchange (symbol: PSJ). Shareholders and holders of American
Depositary Shares are advised to refer to the filings of Petsec Energy Ltd for
the consolidated results.
<PAGE>   2
                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                     Page
                                                                                     ----
<S>                                                                                  <C>
Glossary of Certain Industry Terms..................................................   3

                                     PART I

Item 1.  Description of Business....................................................   5
Item 2.  Description of Properties..................................................  21
Item 3.  Legal Proceedings..........................................................  22
Item 4.  Submission of Matters to a Vote of Security Holders........................  22

                                     PART II

Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters......  22
Item 6.  Selected Financial Data....................................................  23
Item 7.  Management's Discussion and Analysis of Financial Condition and              
           Results of Operations....................................................  24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.................  32
Item 8.  Financial Statements and Supplementary Data................................  33
Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial   
           Disclosure ..............................................................  33

                                    PART III

Item 10. Directors and Executive Officers of the Registrant ........................  33
Item 11. Executive Compensation.....................................................  35
Item 12. Security Ownership of Certain Beneficial Owners and Management.............  38
Item 13. Certain Relationships and Related Transactions.............................  38

                                     PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...........  38
</TABLE>
<PAGE>   3
                       GLOSSARY OF CERTAIN INDUSTRY TERMS

         The definitions set forth below apply to the indicated terms as used in
this Form 10-K. All volumes of natural gas referred to herein are stated at the
legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and, in most instances, are rounded to the nearest major
multiple.

         Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.

         Bcf. Billion cubic feet.

         Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

         Btu. British thermal unit, which is the heat required to raise the
temperature of one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

         Completion. The installation of permanent equipment for the production
of oil or natural gas, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.

         Developed acreage. The number of acres that are allocated or assignable
to producing wells or wells capable of production.

         Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.

         Dry hole or well. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

         Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

         Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

         Gross acreage or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.

         Liquids. Crude oil, condensate and natural gas liquids.

         MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

         Mcf. One thousand cubic feet.

         Mcf/d. One thousand cubic feet per day.


                                                                               3
<PAGE>   4
         Mcfe. One thousand cubic feet of gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.

         MMS. Minerals Management Service of the United States Department of the
Interior.

         MMbtu. One million Btus.

         MMcf. One million cubic feet.

         MMcfe. One million cubic feet of gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.

         Net acres or net wells. The sum of the fractional working interests
owned in gross acres or gross wells.

         OCS. Outer Continental Shelf.

         Oil. Crude oil and condensate.

         Present value or PV10. When used with respect to oil and natural gas
reserves, the estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future development costs,
using prices and costs in effect as of the date indicated, without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.

         Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

         Proved developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.

         Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.

         Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

         Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

         Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.

         Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.


                                                                               4
<PAGE>   5

         Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

         Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of costs of
production.

         Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.

         Working interest or W.I. The operating interest which gives the owner
the right to drill, produce and conduct operating activities on the property and
a share of production.

                                     PART I

                                ITEM 1 - BUSINESS

GENERAL

     Petsec Energy Inc. (the "Company") is an independent oil and gas
exploration and production company with its operations in the offshore waters of
the Gulf of Mexico. The Company is the principal operating subsidiary of Petsec
Energy Ltd,("Parent Company"), an Australian public company with ADRs listed on
the New York Stock Exchange (symbol: PSJ). Since establishing its Gulf of Mexico
operations in 1990, the Company has employed a focused, integrated strategy of
exploration and development to generate increases in reserves, production and
cash flow.

     As of December 31, 1998, and after taking into account the sale of a 50%
working interest in certain of its oil and gas properties to Apache Corporation
("Apache") the Company's estimated net proved reserves were 90.3 Bcfe
(approximately 65% of which were attributable to natural gas), with a PV10 of
approximately $67.1 million.

     The Company owns 44 leases on the Outer Continental Shelf, of which,
effective January 1, 1999, 23 leases are held in a 50% joint venture with
Apache. The Company is currently negotiating to farm out a number of the 21
leases in which it owns a 100% interest.

     The Company has assembled a team of geologists, geophysicists and engineers
with an extensive base of knowledge regarding geophysical processing and
interpretation of data, as well as field operating practices in the Gulf of
Mexico. The Company believes that focusing its drilling activities on properties
in a relatively concentrated area in the Gulf of Mexico permits it to utilize
its base of geological, engineering, and production experience in the region to
enhance its drilling.

     Until recently, the Company held 100% working interests in its Gulf of
Mexico properties, unlike many other independent energy companies that conduct
business through fractional working interests and non-operated joint ventures.
Effective January 1, 1999, the Company sold a 50% working interest in a
substantial number of the properties to Apache, a third party independent E&P
company. It also transferred operations on the properties sold. Ownership of
large working interests enables the Company to effectively control expenses,
capital allocation, and the timing and method of exploration and development of
its properties. The geographic focus of the Company allows it to manage a large
asset base with a relatively small number of employees.


                                                                               5
<PAGE>   6

     The Company relies significantly on advanced exploration technologies, such
as 3-D seismic and time depth migration, in its lease acquisition assessment and
its exploration and development activities. The Company's geotechnical staff has
substantial experience in analyzing 3-D seismic data, which has enabled the
Company to identify multiple exploration and development prospects in both
mature producing fields where advanced technology has not been previously
applied and in unexplored areas.

     The Company intends to continue to expand its inventory of exploration and
development prospects through an active lease acquisition and exploitation
program. The Company actively participates in OCS and state lease sales to build
its inventory of lease blocks. While the Company intends that competitive lease
sales will continue to be its primary method of building its inventory of lease
blocks, it will also evaluate other opportunities to acquire properties that
will complement the Company's existing reserve base and meet its economic and
investment criteria.

OIL AND GAS RESERVES

     The following table sets forth estimated net proved oil and gas reserves of
the Company, the estimated future net revenues before income taxes and the
present value of estimated future net revenues before income taxes related to
such reserves as of December 31, 1996, 1997 and 1998. All information in this
Annual Report relating to estimated net proved oil and gas reserves and the
estimated future net cash flows before income tax attributable thereto is based
upon reports by Ryder Scott Company, Petroleum Engineers. All calculations of
estimated net proved reserves have been made in accordance with the rules and
regulations of the Securities and Exchange Commission, and, except as otherwise
indicated, give no effect to federal or state income taxes otherwise
attributable to estimated future net revenues from the sale of oil and gas. The
present value of estimated future net revenues has been calculated using a
discount factor of 10% per annum.

     December 31, 1998 reserves are shown net of the sale to Apache of a 50%
working interest in certain of the Company's oil and gas properties which was
effective January 1, 1999.

<TABLE>
<CAPTION>
                                                               AS OF DECEMBER 31,
                                                       ----------------------------------
                                                         1996         1997         1998
<S>                                                    <C>          <C>          <C>   
TOTAL NET PROVED:
   Gas (MMcf)                                            73,291      122,149       58,252
   Oil (MBbls)                                            8,318       10,641        5,337
   Total (MMcfe)                                        123,199      185,995       90,274
NET PROVED DEVELOPED:
   Gas (MMcf)                                            43,133       88,199       26,965
   Oil (MBbls)                                            6,670        8,430        3,054
   Total (MMcfe)                                         83,153      138,779       45,289
Estimated future net revenues before income taxes
   (in thousands)                                      $372,980     $316,855     $ 83,132
Present value of estimated future net revenues
   before income taxes (in thousands)(1)(2)            $308,226     $255,839     $ 67,053
Standardized measure of discounted future net cash
   flows (in thousands)(3)                             $223,381     $204,114     $ 67,053
</TABLE>

(1)  The present value of estimated future net revenues attributable to the
     Company's reserves was prepared using constant prices, including the
     effects of hedging, as of the calculation date, discounted at 10% per 
     annum on a pre-tax basis.


                                                                               6
<PAGE>   7

(2)  The December 31, 1998 amount was calculated using an average oil price of
     $11.98 per barrel and an average gas price of $2.04 per Mcf, which include
     adjustments to reflect the effect of hedging.

(3)  The standardized measure of discounted future net cash flows represents the
     present value of estimated future net revenues after income tax discounted
     at 10% per annum.

     There are numerous uncertainties inherent in estimating quantities of
proved reserves, future rates of production and the timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner, and the accuracy of any reserve estimate
is a function of the quality of available data, engineering and geological
interpretation and judgment and the existence of development plans. As a result,
estimates of reserves made by different engineers for the same property will
often vary. Results of drilling, testing and production subsequent to the date
of an estimate may justify a revision of such estimates. Accordingly, reserve
estimates generally differ from the quantities of oil and gas ultimately
produced. Further, the estimated future net revenues from proved reserves and
the present value thereof are based upon certain assumptions, including
geological success, prices, future production levels and costs that may not
prove to be correct. Predictions about prices and future production levels are
subject to great uncertainty, and the meaningfulness of such estimates depends
on the accuracy of the assumptions upon which they are based.

ACQUISITION, PRODUCTION AND DRILLING ACTIVITY

     Acquisition and Development Costs. The following table sets forth certain
information regarding the costs incurred by the Company in its acquisition,
exploration and development activities:

<TABLE>
<CAPTION>
                                             Years Ended December 31,
                                        ----------------------------------

                                          1996         1997         1998
                                        --------     --------     --------
                                                  (In thousands)
<S>                                     <C>          <C>          <C>     
               Acquisition costs        $  6,699     $  8,437     $  7,836
               Exploration costs          71,490      115,523      107,111
               Development costs          14,187       31,327       10,301
                                        --------     --------     --------

               Total costs incurred     $ 92,376     $155,287     $125,248
                                        ========     ========     ========
</TABLE>


                                                                               7
<PAGE>   8
     Productive Well and Acreage Data. The following table sets forth certain
statistics for the Company regarding the number of productive wells and
developed and undeveloped acreage in the Gulf of Mexico as of December 31, 1998:

<TABLE>
<CAPTION>
                                               Gross      Net(5)
                                              -------     -------
<S>                                           <C>         <C>
               Productive Wells(1):
                        Oil(2)                     16           8
                        Gas(3)                     36          19
                                              -------     -------
                                 Total             52          27
                                              -------     -------
               Developed Acreage(1)            51,786      28,393
               Undeveloped Acreage(1)(4)       89,252      78,201
                                              -------     -------
                                 Total        141,038     106,594
                                              -------     -------
</TABLE>


(1)  Productive wells consist of producing wells and wells capable of
     production, including gas wells awaiting pipeline connections. Wells that
     are completed in more than one producing horizon are counted as one well.
     Undeveloped acreage includes leased acres on which wells have not been
     drilled or completed to a point that would permit the production of
     commercial quantities of oil and gas, regardless of whether or not such
     acreage contains proved reserves. A gross acre is an acre in which an
     interest is owned. A net acre is deemed to exist when the sum of fractional
     ownership interests in gross acres equals one. The number of net acres is
     the sum of the fractional interests owned in gross acres expressed as whole
     numbers and fractions thereof.

(2)  Two gross wells each have dual completions.

(3)  Fourteen gross wells each have dual completions.

(4)  Leases covering 11% of the Company's undeveloped acreage will expire in
     1999, approximately 17% in 2000, 27% in 2001, 12% in 2002 and 33% in 2003.

(5)  Net wells and acreage are shown after giving effect to the sale to Apache 
     of a 50% working interest in certain properties effective January 1, 1999.

Drilling Activity. The following table sets forth the Company's drilling
activity for the periods indicated.

<TABLE>
<CAPTION>
                                            Years Ended December 31,
                             -------------------------------------------------------
                                  1996                1997                1998
                             ---------------     ---------------     ---------------
                             Gross      Net      Gross      Net      Gross      Net
                             -----     -----     -----     -----     -----     -----
<S>                          <C>       <C>       <C>       <C>       <C>       <C>
Gulf of Mexico
         Exploratory wells       1         1        13      13.0         4         4
         Development wells       7         7         4       4.0         1         1
         Dry holes               0         0         3       2.4         3         3
                             -----     -----     -----     -----     -----     -----

                  Total          8         8        20      19.4         8         8
                             =====     =====     =====     =====     =====     =====
</TABLE>


                                                                               8
<PAGE>   9

OIL AND GAS MARKETING

     All of the Company's natural gas, oil and condensate production was sold at
market prices under short-term contracts providing for variable or market
sensitive prices. The Company has not experienced any difficulties in marketing
its oil or gas.

     There are a variety of factors which affect the market for oil and gas,
including the extent of domestic production and imports of oil and gas, the
proximity and capacity of natural gas pipelines and other transportation
facilities, demand for oil and gas, the marketing of competitive fuels and the
effects of state and federal regulations of oil and gas production and sales.
The oil and gas industry also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual customers.

     From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve more predictable
cash flows, as well as to reduce its exposure to fluctuations in oil and gas
prices. The Company restricts the time and quantity of the aggregate oil and gas
production covered by such transactions. See "Item 7 - Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Hedging
Transactions."

     Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for oil and natural gas sold
in the spot market due primarily to seasonality of demand and other factors
beyond the Company's control. Domestic oil prices generally follow worldwide oil
prices, which are subject to price fluctuations resulting from changes in world
supply and demand. The Company continues to evaluate the potential for reducing
these risks, and expects to enter into additional hedge transactions in future
years. In addition, the Company also may close out any portion of the existing,
or yet to be entered into, hedges as determined to be appropriate by management.

PRODUCTION SALES CONTRACTS

     The Company markets all of the oil and gas production from its properties.
All of the Company's crude oil and gas production is sold to a variety of
purchasers under short-term (less than twelve months) contracts or thirty-day
spot purchase contracts. Natural gas and crude oil sales contracts are based
upon field posted prices plus negotiated bonuses. During 1998, Duke Energy
Trading & Marketing, L.L.C. and Columbia Energy Services each purchased in
excess of 10% of the gas sold by the Company, and Vision Resources, Inc.
purchased in excess of 10% of the oil sold by the Company. Based upon current
demand for oil and gas, the Company does not believe the loss of any of these
purchasers would have a material adverse effect on the Company.

     Most of the Company's oil and all of the Company's gas is transported
through gathering systems and pipelines that are not owned by the Company.
Transportation space on such gathering systems and pipelines is occasionally
limited, and at times unavailable, due to repairs or improvements being made to
such facilities or due to such space being utilized by other oil or gas shippers
with priority transportation agreements. While the Company has not experienced
any inability to market its natural gas and oil, if transportation space is
restricted or unavailable, the Company's cash flow could be adversely impacted.


                                                                               9
<PAGE>   10
COMPETITION

     The oil and gas industry is highly competitive. The Company competes for
the acquisition of oil and gas properties with numerous other entities,
including major oil companies, other independent oil and gas concerns and
individual producers and operators. Many of these competitors have financial,
technical and other resources substantially greater than those of the Company.
Such companies may be able to pay more for productive oil and gas properties and
exploratory prospects and to define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company's financial or human
resources permit. The Company's ability to acquire additional properties and to
discover reserves in the future will be dependent upon its ability to evaluate
and select suitable properties and to consummate transactions in a highly
competitive environment.

REGULATION

     The oil and gas industry is regulated extensively by federal, state and
local authorities. In particular, oil and gas production operations and
economics are affected by price controls, environmental protection statutes and
regulations, tax statutes and other laws relating to the petroleum industry, as
well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. In October
1992, comprehensive national energy legislation was enacted which focuses on
electric power, renewable energy sources and conservation. This legislation,
among other things, guarantees equal treatment of domestic and imported natural
gas supplies, mandates expanded use of natural gas and other alternative fuel
vehicles, funds natural gas research and development, permits continued offshore
drilling and use of natural gas for electric generation and adopts various
conservation measures designed to reduce consumption of imported oil. The
legislation may be viewed as generally intended to encourage the development and
use of natural gas. Oil and gas industry legislation and agency regulation is
under constant review for amendment and expansion for a variety of political,
economic and other reasons.

     Regulation of Natural Gas and Oil Exploration and Production. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in, and the unitization or pooling of oil and gas properties. In this
regard, some states (such as Oklahoma) allow the forced pooling or integration
of tracts to facilitate exploration while other states (such as Texas) rely on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units and, therefore, more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations may
limit the amount of oil and gas the Company can produce from its wells and may
limit the number of wells or the locations at which the Company can drill. The
regulatory burden on the oil and gas industry increases the Company's costs of
doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are frequently expanded, amended or reinterpreted, the


                                                                              10
<PAGE>   11
Company is unable to predict the future cost or impact of complying with such
regulations.

     The Company has operations located on federal oil and gas leases, which are
administered by the MMS. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps
of Engineers and the Environmental Protection Agency (the "EPA")), lessees must
obtain a permit from the MMS prior to the commencement of drilling. Lessees
must also comply with detailed MMS regulations governing, among other things,
engineering and construction specifications for offshore production facilities,
safety procedures, flaring of production, plugging and abandonment of OCS
wells, calculation of royalty payments and the valuation of production for this
purpose, and removal of facilities. To cover the various obligations of lessees
on the OCS, the MMS generally requires that lessees post substantial bonds or
other acceptable assurances that such obligations will be met. The cost of such
bonds or other surety can be substantial and there is no assurance that bonds
or other surety can be obtained in all cases. Under certain circumstances, the
MMS may require Company operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially and adversely
affect the Company's financial condition and operations.

     The MMS has under consideration proposals to change the method of
calculating royalties and the valuation of crude oil produced from federal 
leases. These changes, if adopted, would modify the valuation procedures for
crude oil to reduce use of posted prices and assign a value to crude oil
intended to better reflect market value. The Company cannot predict at this
stage how it might be affected if the MMS adopts such changes.

     Natural Gas and Oil Marketing and Transportation. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the
Federal Energy Regulatory Commission (the "FERC"). In the past, the federal
government has regulated the prices at which oil and gas could be sold.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. The Natural Gas Wellhead Decontrol Act amended the NGPA
to remove both price and non-price controls from natural gas sold in "first
sales" as of January 1, 1993. While sales by producers of natural gas and all
sales of crude oil, condensate and natural gas liquids can currently be made at
uncontrolled market prices, Congress could reenact price controls in the
future.

     Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain


                                                                              11
<PAGE>   12
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the gas industry. The ultimate
impact of these complex and overlapping rules and regulations, many of which are
repeatedly subjected to judicial challenge and interpretation, cannot be
predicted.

     Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (collectively, "Order No. 636"), which, among other things, required
interstate pipelines to "restructure" to provide transportation separate, or
"unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires
pipelines to provide open-access transportation on a basis that is equal for all
gas supplies. Order No. 636 has been implemented as a result of FERC orders in
individual pipeline service restructuring proceedings. In many instances, the
result of the Order No. 636 and related initiatives have been to substantially
reduce or bring to an end the interstate pipelines' traditional roles as
wholesalers of natural gas in favor of providing only storage and transportation
services. 

     Although Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts, although recent price declines for natural gas may, in part,
reflect increased competition and more efficient gas transportation resulting
from Order No. 636. The courts have largely affirmed the significant features of
Order No. 636 and numerous related orders pertaining to the individual
pipelines, although certain appeals remain pending and the FERC continues to
review and modify its open access regulations. In particular, the FERC has
recently begun a broad review of its transportation regulations, including how
they operate in conjunction with state proposals for retail gas marketing
restructuring, whether to eliminate cost-of-service rates for short-term
transportation, whether to allocate all short-term capacity on the basis of
competitive auctions, and whether changes to its long-term transportation
policies may also be appropriate to avoid a market bias toward short-term
contracts. The Company cannot predict what action the FERC will take on these 



                                                                              12
<PAGE>   13
matters, nor can it accurately predict whether the FERC's actions will, over the
long-term, achieve the goal of increasing competition in markets in which the
Company's natural gas is sold. However, the Company does not believe that it
will be affected by any action taken materially differently than other natural
gas producers and marketers with which it competes.

     The FERC has issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While the FERC's
policy statement on new construction cost recovery affects the Company only
indirectly, in its present form, the new policy should enhance competition in
natural gas markets and facilitate construction of gas supply laterals. The FERC
has denied requests for rehearing of this policy statement. The FERC has issued
numerous orders approving the spin-down or spin-off by interstate pipelines of
their gathering facilities. A "spin-off" is a FERC-approved sale of gathering
facilities to a non-affiliate. A "spin-down" is a transfer of gathering
facilities to an affiliate. These approvals were given despite the strong
protests of a number of producers concerned that any diminution in FERC's
oversight of interstate pipeline-related gathering services might result in a
denial of open access or otherwise enhance the pipeline's monopoly power. While
the FERC has stated that it will retain limited jurisdiction over such gathering
facilities and will hear complaints concerning any denial of access, it is
unclear what effect the FERC's gathering policy will have, in the long-term, on
producers such as the Company and the Company cannot predict what further action
the FERC will take on these matters.

     In Order Nos. 561 and 561-A, the FERC established an indexing system under
which oil pipelines will be able to change their transportation rates, subject
to prescribed ceiling levels. The indexing system, which allows or may require
pipelines to make rate changes to track changes in the Producer Price Index for
Finished Goods, minus one percent, became effective January 1, 1995. The FERC's
decision in this matter was affirmed by the courts. The Company does not believe
that these rules affect it any differently than other oil producers and
marketers with which it competes.

     Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company does not anticipate that compliance
with existing federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon the capital expenditures, earnings
or competitive position of the Company.

     Environmental Regulation. Activities of the Company with respect to the
exploration, development and production of oil and natural gas are subject to
stringent environmental regulation by state and federal authorities including
the EPA. Such regulation has increased the cost of planning, designing,
drilling, operating and in some instances, abandoning wells. In most instances,
the regulatory requirements relate to the handling and disposal of drilling and
production waste products and waste created by water and air pollution control
procedures. Although the Company believes that compliance with environmental
regulations will not have a material adverse effect on operations or earnings,
the risks of substantial costs and liabilities are inherent in oil and gas


                                                                              13
<PAGE>   14

operations, and there can be no assurance that significant costs and
liabilities, including criminal penalties, will not be incurred. Moreover, it is
possible that other developments, such as stricter environmental laws and
regulations, and claims for damages to property or person resulting from the
Company's operations could result in substantial costs and liabilities.

     The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner and operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
the hazardous substances found at such site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.

     The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the disposal
options for certain hazardous and nonhazardous wastes. Furthermore, certain
wastes generated by the Company's oil and natural gas operations that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes," and therefore be subject to more rigorous and
costly operating and disposal requirements.

     The Company currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and gas. Although the Company has utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other wastes may have been disposed of or released on or under the properties
owned or leased by the Company or on or under other locations where such wastes
have been taken for disposal. In addition, many of these properties have been
operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under the Company's control. These
properties and the wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.

     The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of an onshore
facility, vessel or pipeline, 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 


                                                                              14
<PAGE>   15

imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10 million depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. For offshore facilities that have a
worst case oil spill potential of more than 1,000 barrels (which includes many
of the Company's offshore producing facilities), certain amendments to the OPA
that were enacted in 1996 provide that the amount of financial responsibility
that must be demonstrated by most facilities range from $10 million in specified
state waters to $35 million in federal OCS waters, with higher amounts, up to
$150 million in certain limited circumstances where the MMS believes such a
level is justified by the risks posed by the quantity or quality of oil that is
handled by the facility. On March 25, 1997, the MMS promulgated a proposed rule
implementing these OPA financial responsibility requirements. Under the proposed
rule, the amount of financial responsibility required for a facility would
depend on the "worst case" oil spill discharge volume calculated for the
facility. For oil and gas producers such as the Company operating offshore
facilities in OCS waters, worst case discharge volumes of up to 35,000 barrels
will require a financial responsibility demonstration of $35 million, while
worst case discharge volumes in excess of 35,000 barrels will require
demonstrations ranging from $70 million to $150 million.

     The operator will provide evidence of financial responsibility on the 
properties in which the Company has a non-operating working interest. The
Company will satisfy OPA financial responsibility obligations with respect to
its other properties through insurance over the level of $200,000 which is the
Company's self-insurance amount. The Company believes that it currently has
established adequate proof of financial responsibility for its offshore
facilities at no significant increase in expense over recent prior years.
However, the Company cannot predict whether these financial responsibility
requirements under the OPA amendments or proposed rule will result in the
imposition of substantial additional annual costs to the Company in the future
or otherwise materially adversely affect the Company. The impact, however,
should not be any more adverse to the Company than it will be to other similarly
situated or less capitalized owners or operators in the Gulf of Mexico. OPA also
imposes other requirements on facility operators, such as the preparation of an
oil spill contingency plan. The Company has such plans in place. The failure to
comply with ongoing requirements or inadequate cooperation in a spill event may
subject a responsible party to civil or even criminal liability.

OPERATING HAZARDS AND INSURANCE

     Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled as a result
of title problems, weather conditions, compliance with governmental
requirements, mechanical difficulties or shortages or delays in the delivery of
equipment and that the availability or capacity of gathering systems, pipelines
or processing facilities may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs.

     In addition, the Company's properties may be susceptible to hydrocarbon
drainage from production by other operators on adjacent properties. Industry
operating risks include the risk of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which
could result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. Additionally, the
Company's oil and gas operations are located in an area that is subject to
tropical weather disturbances, some of which can be severe enough to cause
substantial damage to facilities and possibly interrupt production.


                                                                              15
<PAGE>   16

     The MMS requires lessees of OCS properties to post performance bonds in
connection with the plugging and abandonment of wells located offshore and the
removal of all production facilities. The Company has posted an area wide bond
meeting MMS requirements and has obtained additional supplemental bonding on its
offshore leases as required by the MMS.

     The Company maintains customary oil and gas related third party liability
coverage, which it must renew annually, that insures the Company against certain
sudden and accidental risks associated with drilling, completing and operating
its wells. There can be no assurance that this insurance will be adequate to
cover any losses or exposure to liability or that the Company will be able to
renew its coverage annually. The Company carries workers' compensation insurance
in all states in which it operates. While the Company believes this coverage is
customary in the industry, it does not provide complete coverage against all
operating risks.

EMPLOYEES

     The Company currently has 27 full-time employees, primarily professionals,
including geologists, geophysicists and engineers. The Company also relies on
the services of certain consultants for technical and operational guidance. The
Company believes that its relationships with its employees and consultants are
satisfactory and has entered into employment and consulting contracts with its
executives and agreements with certain technical personnel and consultants whom
it considers particularly important to the operations of the Company. There can
be no assurance that such individuals will remain with the Company for the
immediate or foreseeable future. None of the Company's employees are covered by
a collective bargaining agreement. From time to time, the Company also utilizes
the services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as maintenance, dispatching, inspection and
testing, are generally provided by independent contractors supervised by Company
employees.

FORWARD-LOOKING STATEMENTS

     This Annual Report includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act and Section 21E of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"). All statements other than
statements of historical facts included in this Annual Report, including without
limitation statements under "Item 7- Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Item 1- Business" regarding
the planned capital expenditures, oil and gas production, the Company's
financial position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to have been correct.
There are numerous risks and uncertainties that can affect the outcome of
certain events including many factors beyond the control of the Company. These
factors include but are not limited to the matters that are described below. All
subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.


                                                                              16
<PAGE>   17
SUBSTANTIAL LEVERAGE

     As of December 31, 1998, the Company's long-term debt was $210.4 million,
of which $99.7 million was senior subordinated notes, $74 million was borrowings
under the Company's bank credit facility and $36.8 million was a subordinated
shareholder loan. In February 1999, upon settlement of the $68.3 million sale to
Apache of certain of its oil and gas properties, the Company repaid $65 million
of bank debt, reducing long-term debt to $145.4 million.

     The Company's level of indebtedness will have several important effects on
its operations, including (i) a substantial portion of the Company's cash flow
from operations will be dedicated to the payment of interest on its indebtedness
and will not be available for other purposes, (ii) the covenants contained in
the indenture governing the senior subordinated notes limit its ability to
borrow additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in business conditions and
(iii) the Company's ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general corporate purposes
or other purposes may be impaired. Moreover, future acquisition or development
activities may require the Company to alter its capitalization significantly.
These changes in capitalization may significantly alter the leverage of the
Company. The Company's ability to meet its debt service obligations and to
reduce its total indebtedness will be dependent upon the Company's future
performance, which will be subject to general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors. See "Item 7- Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources."

VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION

     The Company's revenue, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
natural gas. Prices for oil and natural gas are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond the control of the Company. These factors include the level of consumer
product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of oil and gas imports and overall economic conditions. From time to time,
oil and gas prices have been depressed by excess domestic and imported supplies,
as experienced in 1998 when oil prices were significantly depressed. In the
first quarter of 1999 oil prices showed some improvement, however there can be
no assurance that current price levels will be sustained. It is impossible to
predict future oil and natural gas price movements with any certainty. Declines
in oil and natural gas prices may adversely affect the Company's financial
condition, liquidity and results of operations and may reduce the amount of the
Company's oil and natural gas that can be produced economically. Additionally,
substantially all of the Company's sales of oil and natural gas are made in the
spot market or pursuant to contracts based on spot market prices and not
pursuant to long-term fixed price contracts. With the objective of reducing
price risk, the Company enters into hedging transactions with respect to a
portion of its expected future production. There can be no assurance, however,
that such hedging transactions will reduce risk or mitigate the effect of any
substantial or extended decline in oil or natural gas prices. Any substantial or
extended decline in the prices of oil or natural gas would have a material
adverse effect on the Company's financial condition and results of operations.



                                                                              17
<PAGE>   18

     In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk. See "Item 7- Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Overview" and "Item 1- Business
-- Oil and Gas Marketing."

UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES

     This Annual Report contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based upon the reserve
report prepared by Ryder Scott Company that rely upon various assumptions,
including assumptions required by the Securities and Exchange Commission as to
oil and gas prices, drilling and operating expenses, capital expenditures, taxes
and availability of funds. The process of estimating oil and gas reserves is
complex, requiring significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and economic data for each
reservoir. As a result, such estimates are inherently imprecise. Actual future
production, oil and gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and gas reserves may vary
substantially from those estimated in the reserve report prepared by Ryder Scott
Company. Any significant variance in these assumptions could materially affect
the estimated quantity and value of reserves set forth in this Annual Report.
In addition, the Company's proved reserves may be subject to downward or upward
revision based upon production history, results of future exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond the Company's control. Actual production, revenues, taxes, development
expenditures and operating expenses with respect to the Company's reserves will
likely vary from the estimates used, and such variances may be material.

     Approximately 50% of the Company's total proved reserves at December 31,
1998 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. The reserve data set forth in the report prepared by Ryder Scott
Company assumes that substantial capital expenditures by the Company will be
required to develop such reserves. Although cost and reserve estimates
attributable to the Company's oil and gas reserves have been prepared in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated. See "Item 1- Business -- Oil and Gas Reserves."

     The present value of future net revenues referred to in this Annual Report
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Securities and Exchange Commission, the estimated discounted
future net cash flows from proved reserves are generally based on prices and
costs as of the date of the estimate, whereas actual future prices and costs may
be materially higher or lower. Actual future net cash flows also will be
affected by changes in consumption by gas purchasers and changes in governmental
regulations or taxation. The timing of actual future net cash flows from proved
reserves, and thus their actual present value, will be affected by the timing of
both the production and the incurrence of costs in connection with development
and production of oil and gas properties. In addition, the 10% discount factor,
which is required by the Securities and Exchange Commission to be used in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with the Company or the oil and
gas industry in general.



                                                                              18
<PAGE>   19

REPLACEMENT OF RESERVES

     As is customary in the oil and gas exploration and production industry, the
Company's future success depends upon its ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless the
Company replaces its estimated proved reserves (through development, exploration
or acquisition), the Company's proved reserves will generally decline as they
are produced.

     The Company's current strategy includes increasing its reserve base through
acquisitions of lease blocks with drilling potential and by continuing to
exploit its existing jointly and wholly-owned properties. There can be no
assurance, however, that the Company's exploration and development projects will
result in significant additional reserves or that the Company will have
continuing success drilling productive wells at economically viable costs.
Furthermore, while the Company's revenues may increase if prevailing oil and gas
prices increase significantly, the Company's finding costs for additional
reserves could also increase. For a discussion of the Company's reserves, see
"Item 1- Business -- Oil and Gas Reserves."

SUBSTANTIAL CAPITAL REQUIREMENTS

     The Company makes, and will continue to make, substantial expenditures for
the development, exploration, acquisition and production of oil and natural gas
reserves. The Company made capital expenditures, including exploration expense,
of $155 million during 1997 and $124 million during 1998. As a result of the
sale of a 50% working interest in certain properties to Apache, the Company's
1999 revenues and cash flows will be significantly reduced. Similarly its 1999
capital budget in respect of those properties will also be significantly
reduced. In addition, the Company is currently discussing farm-out proposals on
a number of its exploration properties to reduce its risk and financial exposure
in the testing of prospects on those properties. However, if revenues or cash
flows from operations further decrease as a result of lower oil and natural gas
prices or operating difficulties, the Company may be limited in its ability to
expend the capital necessary to undertake or complete its drilling program, or
it may be forced to raise additional debt or equity proceeds to fund such
expenditures. There can be no assurance that additional debt or equity financing
or cash generated by operations will be available to meet these requirements.
See "Item 7- Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources."

INDUSTRY RISKS

     Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled and that
title problems, weather conditions, compliance with governmental requirements,
mechanical difficulties or shortages or delays in the delivery of drilling rigs,
work boats and other equipment may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells but also from wells that are productive but do not
produce sufficient net revenues to return a profit after drilling, operating and
other costs. In addition, the Company's properties may be susceptible to
hydrocarbon drainage from production by other operators on adjacent properties.




                                                                              19
<PAGE>   20

     Industry operating risks include the risk of fire, explosions, blow-outs,
pipe failure, abnormally pressured formations and environmental hazards such as
oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of
any of which could result in substantial losses to the Company due to injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, the Company's oil and gas operations are located in an area that
is subject to tropical weather disturbances, some of which can be severe enough
to cause substantial damage to facilities and possibly interrupt production. In
accordance with customary industry practice, the Company maintains insurance
against some, but not all, of the risks described above. There can be no
assurance that any insurance will be adequate to cover losses or liabilities.
The Company cannot predict the continued availability of insurance at premium
levels that justify its purchase.

GOVERNMENTAL REGULATION

     Oil and gas operations are subject to various United States federal, state
and local governmental regulations that change from time to time in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling and abandonment bonds,
reports concerning operations, the spacing of wells, and unitization and pooling
of properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. In addition, the production, handling, storage, transportation
and disposal of oil and gas, by-products thereof and other substances and
materials produced or used in connection with oil and gas operations are subject
to regulation under federal, state and local laws and regulations primarily
relating to protection of human health and the environment. To date,
expenditures related to complying with these laws and for remediation of
existing environmental contamination have not been significant in relation to
the results of operations of the Company. Although the Company believes it is in
substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
See "Item 1- Business -- Regulation."

RELIANCE ON KEY PERSONNEL

     The Company's operations are dependent upon a relatively small group of key
management and technical personnel. There can be no assurance that such
individuals will remain with the Company for the immediate or foreseeable
future. The unexpected loss of the services of one or more of these individuals
could have a detrimental effect on the Company. See "Item 10- Directors and
Executive Officers of the Registrant."


                                                                              20
<PAGE>   21

COMPETITION

     The Company operates in a highly competitive environment. The Company
competes with major and independent oil and gas companies for the acquisition of
desirable oil and gas properties, as well as for the equipment and labor
required to develop and operate such properties. Many of these competitors have
financial and other resources substantially greater than those of the Company.
See "Item 1 - Business -- Competition."

RISKS OF HEDGING TRANSACTIONS

     In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company has in the past and expects to continue to enter
into oil and natural gas price hedging arrangements with respect to a portion of
its expected production. These arrangements may include futures contracts on the
New York Mercantile Exchange (NYMEX), fixed price delivery contracts and
financial swaps. While intended to reduce the effects of volatility of the price
of oil and natural gas, such transactions may limit potential gains by the
Company if oil and natural gas prices were to rise substantially over the price
established by the hedge. In addition, such transactions may expose the Company
to the risk of financial loss in certain circumstances, including instances in
which (i) production is less than expected, (ii) if there is a widening of price
differentials between delivery points for the Company's production and the
delivery point assumed in the hedge arrangement, (iii) the counterparties to the
Company's future contracts fail to perform the contract or (iv) a sudden,
unexpected event materially impacts oil or natural gas prices. See "Item 7-
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Transactions" and "Item 1- Business -- Oil and Gas
Marketing."

                       ITEM 2 - DESCRIPTION OF PROPERTIES

ITEM 2(a) - SIGNIFICANT PROPERTIES

     The Company has grown principally through the acquisition and development
of properties in the Gulf of Mexico offshore Louisiana. The first four leases
were acquired from the State of Louisiana, four leases were purchased from third
parties and the remaining leases have been acquired at Gulf of Mexico State and
Federal OCS lease sales. At December 31, 1998, the Company had 44 lease blocks
in the Gulf of Mexico. All of the Company's proved oil and gas reserves at
December 31, 1998 were in these blocks. Effective January 1, 1999 a 50% working
interest in 23 of the leases was sold to Apache.

ITEM 2(b) - RESERVES

     The information on the Company's oil and gas reserves is set out under Item
1 on page 6.

     The information on the Company's oil and gas production is set out under
Item 7 on page 25.


                                                                              21
<PAGE>   22

                           ITEM 3 - LEGAL PROCEEDINGS

LEGAL PROCEEDINGS

     The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot be
predicted with certainty, the Company does not expect these matters to have a
material adverse effect on the financial position, results of operations or
liquidity of the Company.

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

                                 Not Applicable

                                     PART II

 ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

      All the shares of common stock of the Company are held by the Parent
Company, Petsec Energy Ltd. See "Notes to Financial Statements - Note 1(a)
Description of Business" on page 44.


                                                                              22
<PAGE>   23

                        ITEM 6 - SELECTED FINANCIAL DATA


     The following table sets forth selected historical financial data for the
Company as of and for each of the periods indicated. The financial data, for the
years ended December 31, 1994, 1995, 1996, 1997 and 1998 are derived from the
financial statements of the Company audited by KPMG LLP, independent auditors.
The following information should be read in conjunction with "Item 7-
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements of the Company and the related notes
thereto included elsewhere in this Annual Report.

<TABLE>
<CAPTION>
                                                                       Years Ended December 31,
                                                 ---------------------------------------------------------------------
                                                    1994           1995           1996           1997           1998
                                                 ---------      ---------      ---------      ---------      ---------
                                                                             (in thousands)
<S>                                              <C>            <C>            <C>            <C>            <C>      
Statement of Operations data:
    Oil and gas sales                            $  15,098      $  30,462      $  67,027      $ 125,139      $  92,017

    Lease operating expenses                         3,855          4,757          6,161         11,527         14,989
    Depletion, depreciation and amortization         4,291          9,256         29,639         63,864         57,576
    Exploration expenditures                         3,020          3,396          7,061          7,328          7,427
    Dry hole costs                                    --             --             --           10,454         27,503
    Impairments                                       --             --             --             --           72,916
    General and administrative                       2,046          4,502          5,259          6,054          7,867
    Stock compensation                                --             --              481            905            592
                                                 ---------      ---------      ---------      ---------      ---------

          Total operating expenses                  13,212         21,911         48,601        100,132        188,870
                                                 ---------      ---------      ---------      ---------      ---------
      Income (loss) from operations                  1,886          8,551         18,426         25,007        (96,853)
    Other income (expense)                             (55)            35           --            1,418            517
    Gain (loss) on sale of property, plant
      and equipment                                    (16)         4,312              6           --             --
    Interest expense                                  (959)        (2,452)        (3,369)        (7,586)       (11,721)
    Interest income                                     14             64            172            871            302
                                                 ---------      ---------      ---------      ---------      ---------
      Income (loss) before income taxes                870         10,510         15,235         19,710       (107,755)
    Income tax (expense) benefit                       (25)        (3,537)        (6,311)        (6,610)        16,458
                                                 ---------      ---------      ---------      ---------      ---------
      Net income (loss)                          $     845      $   6,973      $   8,924      $  13,100      $ (91,297)
                                                 =========      =========      =========      =========      =========
</TABLE>


<TABLE>
<CAPTION>
                                                                        As of December 31,
                                                 ------------------------------------------------------------------
                                                    1994           1995          1996          1997          1998
                                                 ---------      ---------     ---------     ---------     ---------
                                                                            (in thousands)
<S>                                              <C>            <C>            <C>            <C>            <C>      
Balance Sheet Data:
  Total assets                                   $  36,969      $  89,110     $ 146,145     $ 234,104     $ 185,032
  Senior subordinated notes                           --             --            --          99,630        99,656
  Bank credit facility                              12,825         32,350        37,000          --          74,000
  Subordinated shareholder loan                     11,386         25,038        57,954        37,298        36,792
                                                 ---------      ---------     ---------     ---------     ---------
      Total long-term debt                          24,211         57,388        94,954       136,928       210,448
  Shareholder's equity (deficit)                 $  (1,342)     $   5,631     $  15,036     $  48,635     $ (42,071)
                                                 =========      =========     =========     =========     =========
</TABLE>


                                                                              23
<PAGE>   24

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


INTRODUCTION

     The following discussion is intended to assist in the understanding of the
Company's historical financial position and results of operations for each year
in the three years ended December 31, 1998. Financial Statements and notes
thereto included elsewhere in this Annual Report should be referred to in
conjunction with the following discussion.

OVERVIEW

     The Company is the principal operating subsidiary of Petsec Energy Ltd, an
Australian public company with ADRs listed on the New York Stock Exchange. The
Company was incorporated in March 1990 to evaluate oil and gas exploration
opportunities in the United States. In 1990, the Company participated in an oil
discovery in the Paradox Basin in Colorado. In addition, the Company acquired
oil and gas lease interests in northern California. The Company also established
an office in Lafayette, Louisiana, hired several former employees of Tenneco Oil
Company and acquired leases in the Gulf of Mexico, offshore Louisiana. The
Company subsequently made a strategic decision to focus its efforts entirely in
the Gulf of Mexico and disposed of its interests in the Paradox Basin in January
1995.

      The Company has acquired substantially all of its 44 leases in the Gulf of
Mexico at federal or state lease sales. A disappointing drilling program in 1998
compounded by low oil and gas prices caused the Company's outstanding debt to
reach unacceptable levels. In December 1998, the Company agreed to sell to
Apache a 50% working interest in 17 developed leases and 6 exploration leases.
In addition, Apache assumed operatorship of the assets. The US$68.3 million sale
was effective January 1, 1999 and completed on February 1, 1999, reducing bank
debt to $9 million and total debt, including the subordinated shareholder loan
to $145.4 million. The $100 million of interest-only subordinated notes are due
for repayment in 2007.

     The Company is currently producing from 18 of its lease blocks. Production
increased significantly from 24,622 MMcfe in 1996 to 46,408 MMcfe in 1997, but
through natural decline decreased in 1998 to 39,511 MMcfe. As of December 31,
1998, after giving effect to the Apache sale, the Company's net proved reserves
were 90.3 Bcfe, 65% of which were natural gas.

     The Company markets its oil through spot price contracts and typically
receives a premium above the price posted. The Company's gas production is sold
under contracts which generally reflect spot market conditions in the central
Gulf of Mexico. The Company has historically entered into crude oil and natural
gas price swaps to reduce its exposure to price fluctuations. The results of
operations described herein reflect any hedging transactions undertaken by the
Company. See Note 11 to the Financial Statements.

     The Company follows the successful efforts method of accounting. Under this
method, the Company capitalizes lease acquisition costs, costs to drill and
complete exploration wells in which proved reserves are discovered and costs to
drill and complete development wells. Costs to drill exploratory wells that do
not find proved reserves are expensed. Seismic, geological and geophysical, and
delay rental expenditures are expensed as incurred.



                                                                              24
<PAGE>   25

     The Company is allocated stock compensation expense in respect to options
in Petsec Energy Ltd (the "Parent") which are granted to the Company's employees
and certain consultants. In 1996, the Parent adopted SFAS No. 123, Accounting
for Stock-Based Compensation under which it recognizes as expense over the
vesting period the fair value of all stock-based awards on the date of grant.
See Note 6 to the Financial Statements.

     The Company reimburses the Parent for direct expenses incurred in
connection with the Company's operations. In addition, the Company has received
subordinated loans from the Parent to finance its operations. See "-- Liquidity
and Capital Resources."

     The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and gas, which are in
turn dependent upon numerous factors that are beyond the Company's control, such
as economic, political and regulatory developments and competition from other
sources of energy. The energy markets have historically been volatile, and there
can be no assurance that oil and gas prices will not be subject to wide
fluctuations in the future. A substantial or extended decline in oil and gas
prices could have a material adverse effect on the Company's financial position,
results of operations and access to capital, as well as the quantities of oil
and gas reserves that the Company may economically produce.

     The following table sets forth certain operating information with respect
to the oil and gas operations of the Company.

<TABLE>
<CAPTION>
                                                             Years Ended December 31,
                                                        ----------------------------------
                                                          1996         1997         1998
                                                        --------     --------     --------
<S>                                                     <C>          <C>          <C>   
Net production:
         Gas (MMcf)                                       11,722       27,940       25,390
         Oil (MBbls)                                       2,150        3,078        2,353
         Total (MMcfe)                                    24,622       46,408       39,511
Net sales data (in thousands):
         Gas                                            $ 23,056     $ 64,770     $ 54,171
         Oil                                            $ 43,971     $ 60,369     $ 37,846
         Total                                          $ 67,027     $125,139     $ 92,017
Average sales price (1):
         Gas (per Mcf)                                  $   1.97     $   2.32     $   2.13
         Oil (per Bbl)                                  $  20.45     $  19.61     $  16.08
         Total (per Mcfe)                               $   2.72     $   2.70     $   2.33
Average costs (per Mcfe):
         Lease operating expenses                       $   0.25     $   0.25     $   0.38
         General, administrative and other expenses     $   0.21     $   0.13     $   0.20
</TABLE>

(1)  Includes effects of hedging activities.


                                                                              25
<PAGE>   26

RESULTS OF OPERATIONS

1998 COMPARED TO 1997

     General. The Company drilled and/or sidetracked eight wells during the year
ended December 31, 1998, of which three have been brought into production, two
encountered mechanical difficulties and are suspended pending further
evaluation, and three were plugged and abandoned. Production in 1998 of 39.5
Bcfe was 15% less than 1997 due to natural decline and disappointing drilling
results.

     Oil and Gas Revenues. Oil and gas revenues for 1998 were $92 million, a
decrease of $33.1 million, or 26% below 1997 revenues of $125.1 million. A 24%
decrease in oil production coupled with an 18% decrease in oil prices combined
to account for $22.5 million of the decrease. A 9% decrease in gas production
and an 8% decrease in the gas price accounted for the remaining $10.6 million of
the decrease.

     The average realized gas price in 1998 was $2.13 per Mcf, or 2% above the
$2.08 per Mcf average gas price that would have otherwise been received if no
hedging had been undertaken. In the same period, the average realized oil price
was $16.08 per Bbl, or 20% above the $13.36 per Bbl that would have otherwise
been received if no hedging had taken place. In 1997 the average realized gas
price was $2.32 per Mcf, or 8% below the $2.53 per Mcf price that would have
otherwise been received if no hedging had been undertaken. In the same period
the average realized oil price was $19.61 per Bbl, or 3% above the $19.10 per
Bbl that would have otherwise been received if no hedging had taken place.
Hedging activities resulted in a $7.7 million increase in revenues for 1998
compared to a $4.4 million decrease in 1997.

     Lease Operating Expenses. Lease operating expenses in 1998 were $15.0
million, an increase of $3.5 million, or 30%, from $11.5 million in 1997. The
increase was attributable to workovers and recompletions in wells with declining
production from zones that were first perforated. These costs coupled with lower
production resulted in the per unit rate increasing from $0.25 per Mcfe in 1997
to $0.38 per Mcfe in 1998.

     Depletion, Depreciation and Amortization ("DD&A"). DD&A expense decreased
$6.3 million, or 10%, from $63.9 million in 1997 to $57.6 million in 1998. Lower
production accounted for a decrease of $9.5 million partially offset by an
increase in the average rate per unit from $1.38 to $1.46 per Mcfe. The increase
in the unit rate was due to increased costs of drilling goods and services,
platform and facilities construction and transportation services in the
industry. Lower commodity prices caused Ryder Scott downward reserve revisions
in the fourth quarter and the unit DD&A rate increased to $1.80 per Mcfe in that
quarter compared to an average rate of $1.36 for the preceding three quarters.

     Exploration Expenditures and Dry Hole Costs. The Company uses the
successful efforts method to account for oil and gas exploration, evaluation and
development expenditures. Under this method $27.5 million was expensed for dry
hole costs and $7.4 million for seismic, geological and geophysical expenditures
was expensed as incurred in 1998. In 1997 expenses were $10.5 million for dry
hole costs and $7.3 million for seismic, geological and geophysical
expenditures.

     Impairments. A non-cash charge of $72.9 million reflecting the impact of
lower oil and gas prices on the carrying value of the Company's oil and gas
properties was expensed in 1998. There were no impairments recorded in 1997.


                                                                              26
<PAGE>   27

     General and Administrative Expense. General and administrative expense
increased $1.9 million, or 32%, to $7.9 million in 1998 from $6.0 million in
1997. Contributing to this increase are costs associated with increased 
activity and the sale of a 50% working interest in certain properties to Apache
which resulted in severance changes of $422,000 related to employee
terminations. On a per Mcfe basis the rate increased 54% from $0.13 to $0.20
due to the costs noted above and decreased production. As a result of the sale
to Apache, the Company significantly reduced its workforce which may result in
future general and administrative expense savings.

     Interest Expense. Interest expense in 1998 increased $4.1 million, or 54%,
to $11.7 million from $7.6 million in 1997 due to increased borrowings under the
bank credit facility.

     Net Loss. As a result of the conditions noted above, a net loss of $91.3
million was recorded for 1998, a decrease of $104.4 million from the earnings of
$13.1 million for 1997.

1997 COMPARED TO 1996

     General. The Company drilled twenty wells during the year ended December
31, 1997, of which 14 have subsequently been brought into production. In
addition, the Company completed the installation of facilities at West Cameron
461, South Marsh Island 7, Grand Isle 45, Main Pass 104 and Main Pass 84. This
resulted in an increase in production of 21.8 Bcfe to 46.4 Bcfe in 1997, an 88%
increase over the 24.6 Bcfe in 1996.

     Oil and Gas Revenues. Oil and gas revenues for 1997 were $125.1 million, an
increase of $58.1 million, or 87% above 1996 revenues of $67.0 million. A 43%
increase in oil production offset by a 4% decrease in oil prices combined to
account for $16.4 million of the increase. A 138% increase in gas production and
an 18% increase in the gas price accounted for the remaining $41.7 million of
the increase. Increased oil production followed the development of the Ship
Shoal 194 field, while the increased gas production stems from the drilling and
development of the West Cameron 461, South Marsh Island 7 and Grand Isle 45
fields.

     The average realized gas price in 1997 was $2.32 per Mcf, or 8% below the
$2.53 per Mcf average gas price that would have otherwise been received if no
hedging had been undertaken. In the same period, the average realized oil price
was $19.61 per Bbl, or 3% above the $19.10 per Bbl that would have otherwise
been received if no hedging had taken place. In 1996 the average realized gas
price was $1.97 per Mcf, or 24% below the $2.58 per Mcf price that would have
otherwise been received if no hedging had been undertaken. In the same period
the average realized oil price was $20.45 per Bbl, or 3% below the $21.04 per
Bbl that would have otherwise been received if no hedging had taken place.
Hedging activities resulted in a $4.4 million decrease in revenues for 1997
compared to an $8.4 million decrease in 1996.

     Lease Operating Expenses. Lease operating expenses in 1997 were $11.5
million, an increase of $5.3 million, or 85%, from $6.2 million in 1996. The
increase was attributable to increased production. Lease operating expenses per
Mcfe were $0.25 in both years.

     Depletion, Depreciation and Amortization. DD&A expense increased $34.3
million, or 116%, from $29.6 million in 1996 to $63.9 million in 1997.
Production increases accounted for $26.1 million of the increase while an
increase in the average rate per unit from $1.20 to $1.38 per Mcfe accounted for
the balance. The increase in the unit rate was due to increased capital
expenditures from the Company's exploration and development activities coupled
with increased costs of drilling goods and services, platform and facilities
construction and transportation services in the industry. As a result of Ryder
Scott reserve revisions in the fourth quarter, the unit DD&A rate was reduced to
$1.25 per Mcfe in the fourth quarter compared to an average rate of $1.41 for
the preceding three quarters.


                                                                              27
<PAGE>   28

     Exploration Expenditures and Dry Hole Costs. The Company uses the
successful efforts method to account for oil and gas exploration, evaluation and
development expenditure. Under this method $10.5 million for dry hole costs and
$7.3 million for seismic, geological and geophysical expenditures were expensed
as incurred in 1997. There were no dry hole costs in 1996 while seismic,
geological and geophysical expenditures totaled $7.1 million.

     General and Administrative Expense. General and administrative expense
increased $0.8 million, or 15%, to $6.1 million in 1997 from $5.3 million in
1996. On a per Mcfe basis the rate decreased 38% from $0.21 to $0.13 due to
increased production.

     Interest Expense. Interest expense in 1997 increased $4.2 million, or 124%,
to $7.6 million from $3.4 million in 1996 due to increased borrowings coupled
with an increased effective interest rate as a result of the Senior Subordinated
Notes.

     Net Income. As a result of the conditions noted above, net income for 1997
was $13.1 million, an increase of $4.2 million, or 47% over the earnings of $8.9
million for 1996.

LIQUIDITY AND CAPITAL RESOURCES

     The following table represents cash flow data for the Company for the
periods indicated.

<TABLE>
<CAPTION>
                                                            Years Ended December 31,
                                                       ----------------------------------
                                                         1996         1997         1998
                                                       --------     --------     --------
                                                                 (in thousands)
<S>                                                    <C>          <C>          <C>     
CASH FLOW DATA:
         Net cash provided by operating activities     $ 44,695     $ 92,401     $ 54,711
         Net cash used in investing activities           83,337      145,093      135,118
         Net cash provided by financing activities       37,566       59,781       74,000
</TABLE>

     The decrease in cash provided by operating activities from 1997 to 1998 was
due to lower oil and gas production coupled with lower prices. The increase in
cash provided by operating activities from 1996 to 1997 was primarily due to
increased oil and gas production. Before changes in operating assets and
liabilities, cash flow from operations was $51.4 million in 1998, $93.7 million
in 1997 and $45.4 million in 1996.

     In response to lower commodity prices and earlier disappointing drilling
results, the Company deferred certain of its exploration program in 1998. As a
result, cash used in investing activities in 1998 was below that of 1997. In
1997 the Company drilled 20 wells, compared to 8 in 1996, which resulted in an
increase in cash used in investing activities in 1997.

     In 1998, cash provided by financing activities consisted entirely of
borrowings under the bank credit facility. The cash provided by financing
activities in 1997 consisted of proceeds from a June 1997 Senior Subordinated
Note issue (described below) a portion of which was used to repay outstanding
borrowings under the bank credit facility. The cash provided by financing
activities in 1996 consisted of advances from the Parent and borrowings under
the bank credit facility.


                                                                              28
<PAGE>   29

     Since 1990 the Company has financed its working capital needs, operations
and growth primarily with advances from the Parent, cash flow from operations,
long term debt and bank borrowings under a revolving credit facility.

     Petsec Energy Ltd made an initial cash investment of $11.4 million in the
Company and, subsequently, increased this investment with advances of $18.5
million from an Australian offering of Ordinary Shares in September 1995 and
$31.0 million out of net proceeds from a U.S. offering of ADRs in July 1996.

     Funds advanced by the Parent have historically been provided in the form of
subordinated loans. These loans are subordinated to the payment of all senior
indebtedness and have been subordinated to the Notes (defined below). The US
dollar loans bear interest at 6.83% and, in the case of Australian dollar
borrowings, 7.25%. The loans from the Parent do not have mandatory principal
payments due until December 31, 2008. No interest was paid or accrued on these
loans prior to June 1, 1997. Any payments or distributions made by the Company
to its Parent have been principally for reimbursement of direct expenses
incurred in connection with the Company's operations.

     In April 1996, the Company entered into a $75 million bank credit facility,
under which the borrowing base at December 31, 1998 was $75 million. In
addition, a sublimit of $15 million exists for letter of credit purposes to
support the bonding requirements of the MMS and commodity swap transactions. At
December 31, 1998, borrowings outstanding under the bank credit facility were
$74 million with letters of credit outstanding of $1.0 million. Upon settlement
of the sale of a 50% working interest in certain properties to Apache on
February 1, 1999, $65 million in borrowings under the bank credit facility were
repaid and the borrowing base was reduced to $10 million. The bank credit
facility is a two-year revolving credit facility followed by a two-year term
period with equal quarterly amortization payments. The facility matures in April
2001. The bank credit facility is secured by the Company's Gulf of Mexico
producing properties and contains financial covenants that require the Company
to maintain a ratio of senior debt to earnings before interest, taxes,
depletion, depreciation and amortization of not more than 4.0 to 1.0 and a
coverage ratio of earnings before interest, taxes and depletion, depreciation
and amortization to total interest of not less than 3.0 to 1.0. The Company is
currently in compliance with all financial covenants under the bank credit
facility. Outstanding borrowings accrue interest at the rate of LIBOR plus a
margin of 1.25% to 1.75% per annum, depending upon the total amount borrowed.
The Company is obligated to pay a fee equal to .30% to .375% per annum based on
the unused portion of the borrowing base under the facility.

     The Company's ability to borrow under the bank credit facility is dependent
upon the reserve value of its oil and gas properties, as determined by The Chase
Manhattan Bank ("Chase"). If the reserve value of the Company's borrowing base
declines, the amount available to the Company under the bank credit facility
will be reduced and, to the extent that the borrowing base is less than the
amount then outstanding (including letters of credit) under the bank credit
facility, the Company will be obligated to repay such excess amount upon ninety
days' notice from Chase or to provide additional collateral. Borrowing base
repayments, if required, are expected to be met from estimated future net
operating cash flow.

     In June 1997, the Company issued $100 million of 9 1/2% Senior Subordinated
Notes due 2007 (the "Notes"). The Notes were issued at a discount with a yield
to maturity of 9.56% per annum. The net proceeds from the offering of the Notes
were approximately $96.4 million. The Company used a portion of the net proceeds
to repay borrowings under the bank credit facility. The remainder


                                                                              29
<PAGE>   30


of the net proceeds was used to provide working capital for the Company and to
fund further exploration and development of its oil and gas properties, the
acquisition of lease blocks and other general corporate purposes.

     In response to changing market conditions and restricted capital
availability, the Company will take a more risk diverse approach to its
exploration and development program. This will result in a much lower capital
budget than previous years. The Company was recently the high bidder on two
leases at the March 18, 1999 lease sale. If awarded by the MMS the cost to the
Company is $1.9 million, which currently can be met from net operating cash
flows. The Company intends to finance its 1999 drilling program with cash on
hand, cash flow from operations and proceeds from farm-outs of certain oil and
gas properties. The success of the drilling program will determine the amount of
funds required for development expenditures and, accordingly, additional capital
may have to be raised at that time. The capital expenditure budget is
continually re-evaluated based on drilling results, commodity prices, cash flow
from operations and opportunities for property acquisitions.

HEDGING TRANSACTIONS

     From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more predictable
cash flow and to reduce its exposure to oil and gas price fluctuations. While
these hedging arrangements limit the downside risk of adverse price movements,
they may also limit future revenues from favorable price movements. The use of
hedging transactions also involves the risk that the counterparties will be
unable to meet the financial terms of such transactions. The credit worthiness
of counterparties is subject to continuing review and full performance is
anticipated. The Company limits the duration of the transactions and the
percentage of the Company's expected aggregate oil and gas production that may
be hedged. The Company accounts for these transactions as hedging activities
and, accordingly, gains or losses are included in oil and gas revenues when the
hedged production is delivered.

     The Company enters into forward swap contracts with major financial
institutions to reduce the price volatility on the sale of oil and gas
production. In swap agreements, the Company receives the difference between a
fixed price per unit of production and a floating price issued by a third party.
If the floating price is higher than the fixed price, the Company pays the
difference.

     The Company also enters into collar agreements with third parties. A collar
agreement is similar to a swap agreement except that the Company receives the
difference between the floor price and the floating price if the floating price
is below the floor. The Company pays the difference between the ceiling price
and the floating price if the floating price is above the ceiling. The Company
has proved reserves sufficient to cover all of these contracts and does not
trade in derivatives without underlying forecasted production and proved
reserves.

     For the year ended December 31, 1998 hedging activities increased revenues
by $7.7 million. For the years ended December 31, 1996 and 1997, hedging
activities reduced revenues by $8.4 million and $4.4 million, respectively.


                                                                              30
<PAGE>   31

YEAR 2000

     The Company has a plan in place to address Year 2000 ("Y2K") issues. The
plan requires the Company to assess its information technology ("IT") systems
and non-information technology ("non-IT") systems (primarily embedded technology
in process control equipment containing microprocessors or other similar
circuitry) and those of its principal suppliers, customers and business
associates whose Y2K readiness could reasonably be expected to have a material
effect on the Company's business, results of operations or financial condition.

     On February 1, 1999 the Company completed the sale of a 50% working
interest in most of the Company's producing oil and gas properties to Apache
including the responsibilities associated with the operation of these assets. As
a result, Apache is primarily responsible for Y2K compliance issues concerning
these oil and gas operating assets. The Company will assist Apache in assessing
the Y2K exposure and has made available to Apache all data and testing
accumulated to date that is relevant to the oil and gas assets that are now
jointly owned. With Apache now among the Company's principal business partners,
the Company will undertake to assess Apache's Y2K readiness.

     Prior to the Apache transaction, the Company had identified all material IT
and non-IT systems it uses directly in its operations that could be affected by
Y2K issues. Of these identified systems, the Company has assessed the Y2K
readiness of 95% of the systems, with 10% having been found to have Y2K
compliance problems. All identified compliance problems can be remedied without
the expenditure of any material sums. In addition, the licensor of the Company's
primary financial software has certified that this software is Y2K compliant.
Surveys have been received from a substantial number of the Company's principal
suppliers, customers and business associates. The Company's management expects
to identify all principal suppliers, customers and business associates with
respect to which the Company does not have verification of Y2K compliance before
April 30, 1999. The Company will continue to seek Y2K compliance assurances from
its principal suppliers, customers and business associates who have not already
done so. There can be no guarantee, however, that the systems of other companies
on which the Company's operations rely will be timely converted, or that a
failure to convert by another company, or a conversion that is incompatible with
the Company's systems would not have a material adverse effect on the Company.

     The Company has begun to formulate contingency plans to address Y2K risks.
These contingency plans presently consist of identifying suppliers, hydrocarbon
purchasers and other business associates that have developed systems that are
Y2K compliant. In addition, the Company is working on plans to conduct its
operations manually in the event an unexpected Y2K problem would shut down
significant systems. There can be no assurance that the Company's contingency
plans will be effective to mitigate an anticipated Y2K compliance problem or
that the Company has anticipated all Y2K compliance problems that could arise.

     The Company has and will utilize both internal and external resources to
complete tasks and perform testing necessary to address the Y2K issue. The
Company expects to continue to assess its Y2K risks and develop contingency
plans to minimize those risks during the year. To date, the Company has not
incurred any significant costs on its Y2K project and estimates a total cost of
less than $80,000 related to the assessment and remediation of Year 2000 issues.


                                                                              31
<PAGE>   32

      ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The Company is exposed to market risk from adverse changes in commodity 
prices and interest rates as discussed below.

     Commodity Price Risk. The Company produces and sells natural gas and 
crude oil. As a result, the Company's financial results can be significantly
affected as these commodity prices fluctuate widely in response to changing
market forces. The Company has made use of derivative financial instruments
such as forward swap contracts and collars as a hedging strategy to manage
commodity prices associated with oil and gas sales and to reduce the impact of
commodity price fluctuations. The Company used the hedge or deferral method of
accounting for these instruments and, as a result, gains and losses on
commodity derivative financial instruments were generally offset by similar
changes in the realized prices of the commodities. See "Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Hedging Transactions" for discussion of hedged position at December 31, 1998.

     The Company uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of crude oil and natural
gas may have on the fair value of the Company's derivative instruments. At
December 31, 1998, the potential change in the fair value of commodity
derivative instruments assuming a 10 percent adverse movement in the underlying
commodity price is a $3.3 million decrease in the deferred benefit at December
31, 1998.

     For purposes of calculating the hypothetical change in fair value, the
relevant variables are the type of commodity (crude oil or natural gas), the
commodities futures prices and volatility of commodity prices. The hypothetical
fair value is calculated by multiplying the difference between the hypothetical
price and the contractual price by the contractual volumes.

     Interest Rate Risk. Currently, The Company has no open interest rate
swap or interest rate lock agreements.

     Therefore, the Company's exposure to changes in interest rates primarily
results from its short-term and long-term debt with both fixed and floating
interest rates. The following table presents principal amounts (stated in 
thousands) and related average interest rates by year of maturity for the 
Company's debt obligations at December 31, 1998:

<TABLE>
<CAPTION>
                                  1999        2000        2001        2002        2003     THEREAFTER     TOTAL       FAIR VALUE
                                ---------   ---------   ---------   ---------   ---------  ----------    ---------    ----------
<S>                             <C>         <C>         <C>         <C>         <C>        <C>           <C>          <C>        
Long-term debt, including
 current maturities
    Variable rates-bank            67,250       4,500       2,250        --          --          --         74,000        74,000
    Average interest  rates           7.3%        7.3%        7.3%       --          --          --            7.3%
  
    Variable rates-shareholder 
     loan                            --          --          --          --          --        36,792       36,792           N/A
    Average interest rates            6.9%        6.9%        6.9%        6.9%        6.9%        6.9%         6.9% 

    Fixed  rates                     --          --          --          --          --       100,000      100,000        57,000
    Average interest  rates           9.5%        9.5%        9.5%        9.5%        9.5%        9.5%         9.5%
</TABLE>


     If market interest rates average 1% higher or lower in 1999 than in 1998,
interest expense would increase (decrease), and loss before income taxes would
increase (decrease) by approximately $0.5 million.




                                                                              32
<PAGE>   33

              ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The financial information in this form 10-K refers to Petsec Energy Inc., a
wholly owned subsidiary of Petsec Energy Ltd. The publicly listed Petsec Energy
Ltd files its annual consolidated financial statements separately under form
20-F and a summary of its quarterly consolidated financial statements under form
6-K. The response to this item begins on page 38.

            ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                      ACCOUNTING AND FINANCIAL DISCLOSURE

                                      None

                                    PART III

          ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

                                   MANAGEMENT

DIRECTORS AND EXECUTIVES

     The following table sets forth the name, age and position of each person
who is a director, executive officer, key employee, or who provides services to
the Company.

<TABLE>
<CAPTION>
Name                               Age      Position
----                               ---      --------
<S>                                <C>      <C>
Terrence N. Fern                   51       Chairman and Chief Executive Officer

Maynard V. Smith                   48       General Manager-- Exploration and Production

Ross A. Keogh                      39       Director, Chief Financial Officer and Treasurer

Howard H. Wilson, Jr.              40       Vice President of Operations

John T. Bellatti                   41       Geophysical Manager

William R. Sack                    37       Geological Manager

James E. Slatten  III              40       Director, Secretary and Manager -- Land and Legal
</TABLE>


                                                                              33
<PAGE>   34

     Mr. Smith provides services to the Company through an arrangement with the
Company's parent.

     The following biographies describe the business experience of the
directors, executive officers and those who provide services to the Company.
Directors serve annual terms.

     TERRENCE N. FERN has served as Chairman and Chief Executive Officer of the
Company since 1990. Mr. Fern has over 25 years of extensive international
experience in petroleum and minerals exploration, development and financing. Mr.
Fern holds a Bachelor of Science degree from The University of Sydney and has
followed careers in both exploration geophysics and natural resource investment.


     MAYNARD V. SMITH has served as General Manager -- Exploration and
Production since 1990. Mr. Smith has over 20 years of oil and gas exploration
experience and has served in various technical and executive positions with Gulf
Oil Corporation, Tenneco Oil Company, Natomas Oil Company, and Barcoo Petroleum
Company in the United States, Australia and Southeast Asia. Mr. Smith holds a
Bachelor of Science degree in Geology from the California State University at
San Diego.

     ROSS A. KEOGH has served as Treasurer of the Company since 1990 and has
over 15 years experience in the oil and gas industry. Between 1979 and 1989, Mr.
Keogh worked in the financial accounting and budgeting divisions of Total Oil
Company and as Joint Venture Administrator for Bridge Oil Limited in Australia.
Mr. Keogh holds a Bachelor of Economics degree, with a major in Accounting, from
Macquarie University in Sydney. Mr. Keogh was appointed a Director in March 1998
and Chief Financial Officer in November 1998. Mr. Keogh is also Chief Financial
Officer of the Parent.

     HOWARD H. WILSON, JR. has served as Vice President of Operations of the
Company since 1993. Between 1981 and 1993, Mr. Wilson held various technical and
managerial positions with Placid Oil Company and Nerco Oil and Gas, Inc.
involving onshore and offshore oil and gas fields in Louisiana, Mississippi and
Texas. Mr. Wilson holds a Bachelor of Science degree in Petroleum Engineering
from the Louisiana Polytechnic Institute.

     JOHN T. BELLATTI is the Geophysical Manager of the Company. He joined the
Company in January 1996. Mr. Bellatti worked for Shell Oil Co. between 1981 and
1995 in various technical and supervisory positions in the Michigan Basin and
the shallow water Gulf of Mexico. He holds a Bachelor of Arts degree in Physics
from Hanover College, a Master of Science degree in Geophysics from the Colorado
School of Mines and a Master of Business Administration in Finance from the
University of Houston.

     WILLIAM R. SACK is the Geological Manager of the Company. Mr. Sack joined
the Company in January 1996. Between 1988 and 1996 Mr. Sack held various
technical and supervisory positions with Shell Offshore Inc., involving
exploration, development and business activities. Mr. Sack holds a Bachelor of
Science degree in Earth Science and Physics from St. Cloud State University
(MN), a Master of Science degree in Geology from Michigan State University, and
a Master's degree in Business Administration from Tulane University.

     JAMES E. SLATTEN III was appointed Manager--Land and Legal in January 1998.
He has over 15 years experience in corporate and energy law. Prior to joining
the Company, he was a partner in the Louisiana law firm of Gordon, Arata,
McCollam & Duplantis. Mr. Slatten holds a Bachelor of Arts degree in political
science and economics from the University of Southwestern Louisiana and
post-graduate degrees in law (J.D.) and business management (M.H.A.) from Tulane
University. Mr. Slatten was appointed Director and Secretary in March 1998.



                                                                              34
<PAGE>   35

                        ITEM 11 - EXECUTIVE COMPENSATION

COMPENSATION OF EXECUTIVE OFFICERS

     The following table sets forth certain information for the three years
ended December 31, 1998 with respect to the compensation paid to the Chief
Executive Officer of the Company and the four other most highly compensated
Executive Officers (collectively, the "Named Executive Officers"). The Company
has entered into employment agreements with certain management and technical
personnel.

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                                LONG TERM
                                                                               COMPENSATION
                                                 ANNUAL COMPENSATION              AWARDS
                                          ---------------------------------    ------------
                                                                                SECURITIES
            NAME                                               OTHER ANNUAL     UNDERLYING        ALL OTHER
       AND PRINCIPAL                      SALARY      BONUS    COMPENSATION      OPTIONS/       COMPENSATION
          POSITION              YEAR        ($)        ($)        ($) (2)         SARS (3)           ($)
------------------------------  ----      -------     -----    ------------    ------------     ------------
<S>                             <C>       <C>         <C>      <C>             <C>              <C>
Terrence N. Fern (1)..........  1998            0         0             0               0             0
  Chairman of the Board,        1997            0         0             0               0             0
  Chief Executive Officer       1996            0         0             0               0             0
  and President

Ross A. Keogh.................  1998      154,066         0             0               0             0
  Director, Chief Financial     1997      134,500         0             0               0             0
  Officer and Treasurer         1996      118,333    10,548             0         110,000             0

Howard H. Wilson, Jr..........  1998      165,078         0             0               0             0
  Vice President--Operations    1997      150,000    32,007             0               0             0
                                1996      140,000    45,561             0         125,000             0

John T. Bellatti..............  1998      151,865         0             0               0             0
  Geophysical Manager           1997      131,150    23,847             0               0             0
                                1996      122,400     5,753        41,871         150,000             0

William R. Sack...............  1998      151,593         0             0               0             0
  Geological Manager            1997      131,150    23,717        28,334               0             0
                                1996      122,400     5,753        25,068         150,000             0
</TABLE>

(1)  Mr. Fern receives no compensation from the Company. A company controlled by
     Mr. Fern's family provides management services to the Parent. The cost of 
     the services provided was $437,000, $290,000 and $292,334 in 1998, 1997 and
     1996, respectively.

(2)  "Other Annual Compensation" includes payments to Messrs. Sack and Bellatti
     of $53,402 and $41,871, respectively, for relocation costs.

(3)  Options issued are in respect of ordinary shares in the Parent.


                                                                              35
<PAGE>   36

SHARE AND OPTION PLANS

     The Parent maintains an Employee Share Plan (the "Share Plan") and an
Employee Share Option Plan (the "Option Plan"). Both plans were approved by the
Parent's shareholders at the Parent's 1994 Annual General Meeting and are
administered by a committee (the "Remuneration Committee") appointed by the
Board of Directors of the Parent. The total number of Ordinary Shares issued or
subject to option under all share and option plans during any five-year period
may not exceed 6.5% of the total number of issued Ordinary Shares at the 
relevant date.

     The Share Plan provides for the issue of Ordinary Shares to employees and
directors at prevailing market prices. Purchases pursuant to the Share Plan are
financed by interest-free loans from the Parent, subject to certain conditions
set by the Remuneration Committee. Grants are subject to a minimum six-month
vesting term and the vesting may also be contingent upon the market price of the
Ordinary Shares on the Australian Stock Exchange ("ASX") achieving certain
benchmarks. After the vesting of such shares, the grantee may either repay the
Parent loan or sell such shares and retain the difference. As of December 31,
1998, all employees and directors of the Company, in the aggregate, owned
1,525,000 Ordinary Shares subject to the terms of this Plan.

     The Option Plan provides for the issue of options to purchase Ordinary
Shares to employees and directors at prevailing market prices and subject to
certain conditions set by the Remuneration Committee. Grants are subject to a
minimum six-month vesting term and the vesting may also be contingent upon the
market price on the ASX of the Ordinary Shares achieving certain benchmarks.
Options granted under the Option Plan expire five years from the date of grant.
As of December 31, 1998, all directors and employees of the Company, in the
aggregate, held options to purchase an aggregate of 873,000 Ordinary Shares
pursuant to the Option Plan.

STOCK OPTION GRANTS AND EXERCISES

     The Parent did not grant any stock options or stock appreciation rights
("SARs") to the Named Executive Officers of the Company in 1998.

     The following table sets forth the aggregated option exercises by each of
the Named Executive Officers during the year ended December 31, 1998.


                                                                              36
<PAGE>   37

               AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND
                          FISCAL YEAR-END OPTIONS VALUE


<TABLE>
<CAPTION>
                                                               NUMBER OF SECURITIES        VALUE OF UNEXERCISED
                                                                    UNDERLYING                 IN-THE-MONEY
                                                                    UNEXERCISED                 OPTIONS AT
                                                                    OPTIONS AT                FISCAL YEAR-END
                               SHARES           VALUE             FISCAL YEAR-END                   ($)
                             ACQUIRED ON       REALIZED             EXERCISABLE/                EXERCISABLE/
      Name                   EXERCISE (#)        ($)               UNEXERCISABLE              UNEXERCISABLE
      ----                   ------------      --------        --------------------        --------------------
<S>                                             <C>                                                    
Terrence N. Fern                  --            $  --                --/--                         --/--

Ross A. Keogh                     --            $  --                --/110,000                    --/--
                                                                     
Howard H. Wilson, Jr.             --            $  --                --/125,000                    --/--
                                                                     
John T. Bellatti                  --            $  --                --/150,000                    --/--
                                                                     
William R. Sack                   --            $  --                --/150,000                    --/--
                                                                     
</TABLE>

COMPENSATION OF DIRECTORS

     Anthony J. Walton resigned as a director of the Company on December 15,
1998. Mr. Walton was not paid any director's fees in 1998. In 1997, Mr. Walton
was paid $20,000 for services as a director pursuant to an arrangement whereby
Mr. Walton provided financial advice to the Company. There were no other
arrangements pursuant to which directors of the Company received compensation
for their services as directors in 1998 or 1997.

EMPLOYMENT AGREEMENTS, TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS

     Effective July 1, 1996, John T. Bellatti, Ross A. Keogh and William R.
Sack entered into three-year extensions of their employment agreements with the
Company. The agreements provide that they receive a base salary which is
reviewed annually, and are entitled to participate in any incentive
compensation programs established by the Parent for the Company's executive
officers.

     Effective May 1, 1998 Howard H. Wilson, Jr. entered into a three-year 
extension of his employment agreement with the Company. The agreement provides
that Mr. Wilson receive a base salary which is reviewed annually, and is
entitled to participate in any incentive compensation program established by
the Parent for the Company's executive officers. In addition should a change of
control of the Parent occur and Mr. Wilson is terminated without cause or his
employment conditions are materially changed, he is entitled to receive the
balance of salary due under his contract.

     In 1998, the Parent established the Petsec Energy Inc. Change in Control
Bonus and Severance Plan whereby the named executive officers and all other 
employees of the Company may receive compensation in the event of a change in
control. The compensation benefit is composed of a bonus equal to nine months
salary for employees who have been continuously employed by the Company from
June 17, 1998 through two months after a change in control occurs. In addition,
the plan provides for a severance benefit in an amount equal to compensation
for three months plus three weeks per year of service in the event the employee
is relocated more than 30 miles, responsibilities are significantly changed,
salary is reduced by 10% or employment is terminated.


                                                                              37
<PAGE>   38

    ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The Common Stock of the Company is owned by Petsec USA Inc. which is a
wholly owned subsidiary of the ultimate Parent Company, Petsec Energy Ltd. See
"Notes to Financial Statements Note 1(a) Description of Business" on page 44.

            ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The Company has historically been financed in part with borrowings from its
immediate parent company, Petsec (U.S.A.), Inc., which is an indirect
wholly-owned subsidiary of Petsec Energy Ltd. Outstanding borrowings (the
"Subordinated Shareholder Loan") are made by the Company under a subordinated
note (the "Subordinated Shareholder Note") in either or both U.S. or Australian
dollars, which effective as of June 1, 1997 bears interest at market rates,
currently LIBOR plus 1.5% or, in the case of Australian dollar borrowings, the
Australian bank bill rate plus 1.5%. The Subordinated Shareholder Note provides
that the Subordinated Shareholder Loan (i) is subordinated in right of payment
to all present and future Indebtedness of the Company for borrowed money and
(ii) not subject to any mandatory principal or sinking fund payment, or
mandatory repurchase obligation, until 91 days following the final Stated
Maturity of the Senior Subordinated Notes due 2007. The Company has agreed not
to modify these two terms of the Subordinated Shareholder Loan until all
outstanding Notes have been paid in full, retired or acquired in their entirety
by Affiliates of the Company. As of December 31 1998, the amount of
Subordinated Shareholder Loan outstanding was $36.8 million.

     One executive, Maynard Smith, and two former executives Mark Gannaway and
Prent Kallenberger own overriding royalty interests on certain leases held by
the Company, which were issued prior to July 1994 as incentives. As of July
1994, the granting of overriding royalty interests as an incentive was replaced
by grants under the Parent's Option Plan. Mr. Gannaway and Mr. Kallenberger
resigned from the Company effective September 1, 1998.

                                     PART IV

         ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON 
FORM 8-K 

(a). FINANCIAL STATEMENTS


                                                                              38
<PAGE>   39

                          INDEX TO FINANCIAL STATEMENTS


<TABLE>
<S>                                                                               <C>
Independent Auditors' Report .................................................... 40
Balance Sheets as of December 31, 1997, and 1998 ................................ 41
Statements of Operations and Retained Earnings (Deficit) for the years ended
  December 31, 1996, 1997 and 1998 .............................................. 42
Statements of Cash Flows for the years ended December 31, 1996, 1997 and 1998 ... 43
Notes to Financial Statements ................................................... 44
</TABLE>


                                                                              39
<PAGE>   40

                          INDEPENDENT AUDITORS' REPORT


The Board of Directors
Petsec Energy Inc.:

     We have audited the accompanying balance sheets of Petsec Energy Inc. as of
December 31, 1997 and 1998 and the related statements of operations and retained
earnings (deficit) and cash flows for each of the years in the three-year period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Petsec Energy Inc. as of
December 31, 1997 and 1998, and the results of its operations and its cash flows
for each of the years in the three-year period ended December 31, 1998 in
conformity with generally accepted accounting principles.



                                                KPMG LLP

New Orleans, Louisiana
February 5, 1999


                                                                              40
<PAGE>   41

                               PETSEC ENERGY INC.
                 A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
                                 BALANCE SHEETS
                  (DOLLARS IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                                               December 31,

                                                                             1997        1998
                                                                           ---------   ---------
<S>                                                                        <C>         <C>      
                                  ASSETS

Current Assets:
         Cash                                                              $   7,431   $   1,024
         Accounts receivable                                                  13,978       8,279
         Other receivables                                                        80       4,626
         Inventories of crude oil                                                 43          45
         Prepaid expenses                                                        258         274
         Assets held for sale                                                   --        68,300
                                                                           ---------   ---------
                  Total Current Assets                                        21,790      82,548
Net property, plant and equipment, at cost, under the                       
         successful efforts method of accounting
         for oil and gas properties                                          209,314      99,802
Other assets                                                                   3,000       2,682
                                                                           ---------   ---------
                                                                           $ 234,104   $ 185,032
                                                                           =========   =========

              LIABILITIES AND SHAREHOLDER'S EQUITY (DEFICIT)

Current Liabilities:
         Trade accounts payable                                               15,107       8,572
         Interest payable                                                      1,720       2,214
         Other accrued liabilities                                            11,967       3,381
         Bank credit facility                                                   --        67,250
                                                                           ---------   ---------
                  Total Current Liabilities                                   28,794      81,417
Senior Subordinated Notes                                                     99,630      99,656
Bank credit facility                                                            --         6,750
Subordinated shareholder loan                                                 37,298      36,792
Provision for dismantlement                                                    3,289       2,488
Deferred income taxes                                                         16,458        --
                                                                           ---------   ---------
                  Total Liabilities                                        $ 185,469   $ 227,103
                                                                           ---------   ---------

Shareholder's Equity (Deficit):
         Common stock, $1 par value; authorized 1,000,000 shares; 
         issued and outstanding 1 share                                         --          --
         Additional paid-in-capital                                           20,981      21,572
         Retained earnings (deficit)                                          27,654     (63,643)
                                                                           ---------   ---------
                  Total Shareholder's Equity (Deficit)                        48,635     (42,071)
                                                                           ---------   ---------
                                                                           $ 234,104   $ 185,032
                                                                           =========   =========
</TABLE>


                 See accompanying notes to financial statements.


                                                                              41
<PAGE>   42

                               PETSEC ENERGY INC.
                 A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD

            STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT)
                             (DOLLARS IN THOUSANDS)


<TABLE>
<CAPTION>
                                                     Years Ended December 31,

                                                  1996         1997         1998
                                                ---------    ---------    ---------
<S>                                             <C>          <C>          <C>      
Revenue:
     Oil and gas sales                          $  67,027    $ 125,139    $  92,017
                                                ---------    ---------    ---------

Operating expenses:
     Lease operating expenses                       5,561       10,825       14,379
     Production taxes                                 600          702          610
     Exploration expenditures                       7,061        7,328        7,427
     Dry hole costs                                  --         10,454       27,503
     Impairments                                     --           --         72,916
     General and administrative                     5,259        6,054        7,867
     Stock compensation                               481          905          592
     Depletion, depreciation and amortization      29,639       63,864       57,576
                                                ---------    ---------    ---------
Total operating expenses                           48,601      100,132      188,870
                                                ---------    ---------    ---------

Income (loss) from operations                      18,426       25,007      (96,853)

Other income (expenses):
     Interest expense                              (3,369)      (7,586)     (11,721)
     Interest income                                  172          871          302
     Other, principally foreign exchange gain           6        1,418          517
                                                ---------     --------    ---------
                                                   (3,191)      (5,297)     (10,902)

Income (loss) before income taxes                  15,235       19,710     (107,755)
Income tax (expense) benefit                       (6,311)      (6,610)      16,458
                                                ---------    ---------    ---------
Net income (loss)                                   8,924       13,100      (91,297)
Retained earnings at beginning of year              5,630       14,554       27,654
                                                ---------    ---------    ---------
Retained earnings (deficit) at end of year      $  14,554    $  27,654    $ (63,643)
                                                =========    =========    =========
</TABLE>


                 See accompanying notes to financial statements.


                                                                              42
<PAGE>   43

                               PETSEC ENERGY INC.
                 A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
                            STATEMENTS OF CASH FLOWS
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                           Years Ended December 31,

                                                                        1996         1997         1998
                                                                     ---------    ---------    ---------
<S>                                                                  <C>          <C>          <C>       
Cash flows from operating activities:
Net income (loss)                                                    $   8,924    $  13,100    $ (91,297)
Adjustments to reconcile net income (loss) to net cash provided by
     operating activities:
     Depletion, depreciation and amortization                           29,639       63,864       57,576
     Deferred income taxes                                               6,311        6,610      (16,458)
     Dry hole costs                                                       --         10,454       27,503
     Impairments                                                          --           --         72,916
     Other                                                                 483         (323)       1,112
     Changes in operating assets and liabilities:
        Decrease (increase)  in receivables                             (3,523)      (2,123)       5,699
        Decrease (increase) in inventories                                  43            2           (2)
        Decrease (increase) in prepayments                                  23          (90)         (16)
        Decrease (increase) in other receivables                           301           21       (4,546)
        Decrease in other assets                                         1,937         --           --
        Increase (decrease) in trade accounts payable                      309       (1,494)         755
        Increase in other accrued liabilities                              233          862          975
        Increase in interest payable                                        15        1,518          494
                                                                     ---------    ---------    ---------
                  Net cash provided by operating  activities            44,695       92,401       54,711
                                                                     ---------    ---------    ---------

Cash flows from investing activities:
     Lease acquisitions                                                 (6,367)      (8,074)      (8,771)
     Exploration and development expenditures                          (76,296)    (136,561)    (125,871)
     Other asset additions                                                (674)        (458)        (476)
                                                                     ---------    ---------    ---------
                  Net cash used in investing activities                (83,337)    (145,093)    (135,118)
                                                                     ---------    ---------    ---------

Cash flows from financing activities:
     Proceeds from senior subordinated notes                              --         96,446         --
     Proceeds from bank credit facility                                 63,540       21,000       74,000
     Repayment of bank credit facility                                 (58,890)     (58,000)        --
     Proceeds from shareholder loans                                    36,000        1,500         --
     Repayment of shareholder loans                                     (3,084)      (1,165)        --
                                                                     ---------    ---------    ---------
                  Net cash provided by financing  activities            37,566       59,781       74,000
                                                                     ---------    ---------    ---------
Net increase (decrease) in cash                                         (1,076)       7,089       (6,407)
Cash at beginning of year                                                1,418          342        7,431
                                                                     ---------    ---------    ---------
Cash at end of year                                                  $     342    $   7,431    $   1,024
                                                                     =========    =========    =========
</TABLE>


                 See accompanying notes to financial statements.


                                                                              43
<PAGE>   44

                               PETSEC ENERGY INC.
                         NOTES TO FINANCIAL STATEMENTS

1.    DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

      (a) Description of Business

      Petsec Energy Inc. (the Company), located in Lafayette, Louisiana, is a
wholly-owned subsidiary of Petsec (U.S.A.) Inc., which is a wholly-owned
subsidiary of Petsec Energy Ltd (the Parent Company), incorporated in Australia.

      The Company's business is comprised of one operating segment which is the
exploration, development and production of oil and gas; therefore, the Company
is directly affected by fluctuating economic conditions of the oil and gas
industry. The Company's activities are focused in the shallow waters of the Gulf
of Mexico, primarily offshore Louisiana and Texas.

      (b) Income Taxes

      The Company is included in the consolidated federal and state income tax
returns of Petsec (U.S.A.) Inc. The income tax provision has been prepared as if
the Company was a separate taxpayer.

      The Company accounts for income taxes under the asset and liability method
which requires that deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date.

      (c) Oil and Gas Properties

      The Company uses the successful efforts method of accounting for oil and
gas producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves, and
to drill and equip development wells are capitalized. Costs to drill exploratory
wells that do not find proved reserves, and geological and geophysical costs are
expensed.

      Unproved oil and gas properties are periodically assessed on a
property-by-property basis, and a loss is recognized to the extent, if any, that
the cost of the property has been impaired. Capitalized costs of producing oil
and gas properties are depreciated and depleted by the units-of-production
method.

      The Company assesses the impairment of capitalized costs of proved oil and
gas properties on a field-by-field basis, utilizing its current estimate of
future revenues and operating expenses. In the event net undiscounted cash flow
is less than the carrying value, an impairment loss is recorded based on
estimated fair value, which would consider discounted future net cash flows.

      The estimated costs of dismantling and abandoning offshore oil and gas
properties are provided currently using the units-of-production method. Such
provision is included in depletion, depreciation and amortization in the
accompanying statement of operations.


                                                                              44
<PAGE>   45
                               PETSEC ENERGY INC.
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)



      On the sale or retirement of a complete unit of a proved property, the
cost and related accumulated depletion, depreciation and amortization are
eliminated from the property accounts, and the resultant gain or loss is
recognized.

      (d) Other Property, Plant and Equipment

      Depreciation is calculated using the straight-line method over the
estimated useful lives of the assets.

      (e) Inventories

      Inventories are stated at the lower of cost or market. Cost is determined
principally on the average cost method.

      (f) Hedging Activities

      The Company uses derivative commodity instruments to manage commodity
price risks associated with future natural gas and crude oil production but does
not use them for speculative purposes. The Company's commodity price hedging
program utilizes swap contracts and collars. To qualify as a hedge, these
contracts must correlate to anticipated future production such that the
Company's exposure to the effects of commodity price changes is reduced. The
gains and losses related to these hedging transactions are recognized as
adjustments to the revenue recorded for the related production. The Company uses
the accrual method of accounting for derivative commodity instruments. At
inception, any contract premiums paid are recorded as prepaid expenses and, upon
settlement of the hedged production month, are included with the gains and
losses on the contracts in oil and gas revenues.

      (g) Use of Estimates

      The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

      (h) Reclassifications

      Certain amounts in prior years' financial statements have been
reclassified to conform to the 1998 financial statement presentation.


2. PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                                           1997         1998
                                                                         ---------    ---------
                                                                         (dollars in thousands)
<S>                                                                      <C>          <C>      
Oil and gas properties:

         Proved                                                          $ 227,049    $ 156,265
         Unproved                                                           20,759       31,984
         Production facilities                                              66,956       43,321
                                                                         ---------    ---------
                                                                           314,764      231,570
         Other                                                               1,527        1,970
                                                                         ---------    ---------
                                                                           316,291      233,540
         Less accumulated depletion, depreciation and amortization        (106,977)    (133,738)
                                                                         ---------    ---------
                                                                         $ 209,314    $  99,802
                                                                         =========    =========
</TABLE>

      The Company capitalized interest of $0.9 million and $3.5 million in 1997
and 1998, respectively, which is included in Property, Plant and Equipment.


                                                                              45
<PAGE>   46
                               PETSEC ENERGY INC.
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

      The non-cash impairment charge of approximately $72.9 million was recorded
in accordance with the Statement of Financial Accounting Standards No. 121,
which requires that long-lived assets held and used by the Company be reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of the asset may not be recoverable. The continued low prices
received for the sales of oil and natural gas along with the sale of certain
assets (further discussed in Note 14) are such events. As a result of these
events, after related income tax benefits, this write-down increased the net
loss by $69.0 million. The carrying values for assets determined to be impaired
were adjusted to estimated fair values based on projected future discounted net
cash flows for such assets and the proceeds from the sale of certain assets sold
in February 1999. The Company has exposure to future impairments if oil and gas
prices deteriorate from December 1998 levels, which could have a material
adverse effect on financial condition, results of operations and liquidity in
the near term.


3. BANK CREDIT FACILITY AND SENIOR SUBORDINATED NOTES

      In April 1996, the Company entered into a $75 million revolving credit
facility (the facility) with a syndicate of banks. Beginning July 1999 the
Company is required to make eight equal quarterly payments. The facility matures
in the year 2001 and is secured by the Company's Gulf of Mexico producing
properties. Outstanding borrowings accrue interest at LIBOR plus a margin of
1.25% to 1.75% per annum, depending on the balance drawn. The Company is
obligated to pay a fee of .30% to .375% per annum of the unused portion of the
borrowing base.

      At December 31, 1998, borrowings outstanding totaled $74 million at a
weighted average annual interest rate of 7.3% and letters of credit outstanding
totaled $1.0 million. The fair value of the facility's outstanding borrowings
approximated the carrying value. The facility is subject to certain restrictive
covenants. In February 1999, the borrowing base was reduced to $10 million as a
result of the sale of certain assets more fully described in Note 14. Concurrent
with the sale of assets, the Company repaid $65 million of the facility, which
is classified as current in the accompanying balance sheet.

      In June 1997, the Company issued $100 million 9 1/2% Senior Subordinated
Notes due in 2007. The notes were issued at a discount with an annual yield to
maturity of 9.56%. A portion of the proceeds was used to pay the outstanding
balance on the bank credit facility. At December 31, 1997 and 1998, the fair
value of the notes was $102.6 million and $57 million, respectively, based on
quoted market prices. These notes are subject to certain restrictive covenants.


4. SUBORDINATED SHAREHOLDER LOAN

      Petsec (U.S.A.) Inc. had advances outstanding to the Company of $37.3
million and $36.8 million at December 31, 1997 and 1998, respectively. A summary
of activity is as follows (in thousands):

<TABLE>
<CAPTION>
                     Beginning                                      Ending 
                      Balance      Additions    Reductions          Balance
<S>                  <C>           <C>          <C>                 <C>
           1996        25,038       36,000       (3,084)            57,954
           1997        57,954        1,500      (22,156)            37,298
           1998        37,298           --         (506)            36,792
</TABLE>

      The average balance outstanding for the years ended 1996, 1997 and 1998
was $33.6 million, $47.0 million, and $37.0 million, respectively.


                                                                              46
<PAGE>   47
                               PETSEC ENERGY INC.
                  NOTES TO FINANCIAL STATEMENTS (CONTINUED)



      Prior to June 1, 1997, the advances were without interest charges or fixed
repayment terms. Effective June 1, 1997, Petsec (U.S.A.) Inc. began charging the
Company interest on the subordinated shareholder loan. At December 31, 1997, the
rates were 7.18% for the $29 million U.S. dollar loan and 6.83% for the
equivalent US$8.3 million Australian dollar denominated loan. In addition,
effective June 1, 1997, $20 million of the outstanding subordinated shareholder
loan was recapitalized as equity. At December 31, 1998, the interest rates were
6.83% for the $29 million U.S. dollar loan and 7.25% for the equivalent US$7.8
million Australian dollar denominated loan. The Company is unable to determine
the fair value of these loans because they are with a related party. Petsec
(U.S.A.) Inc. has confirmed that no repayments will be required prior to
December 31, 2007.

5. SIGNIFICANT CUSTOMERS

      Customers which account for 10% or more of revenue for the years ended
December 31, 1996, 1997 and 1998 follow:

<TABLE>
<CAPTION>
                                                        1996     1997     1998
                                                        ----     ----     ----
<S>                                                     <C>      <C>      <C>
         Vision Resources, Inc.                          60%      46%      30%
         Aquila Energy Marketing Corporation             12%       *        *
         Duke Energy Trading & Marketing, L.L.C          19%      22%      19%
         P G & E Energy Trading Corporation              --       16%       *
         Natural Gas Clearinghouse                        *       12%      --
         Columbia Energy Services                        --        *       36%
</TABLE>

*  less than 10%

      Based upon the current demand for oil and gas, the Company does not
believe the loss of any current purchasers would have a material adverse effect
on the Company. The Company continually evaluates the financial strength of its
customers but does not require collateral to support trade receivables.


6. STOCK COMPENSATION EXPENSE

      The Parent Company has an Employee Option Plan and issues options to
employees and certain consultants of the Company to purchase stock in the Parent
Company. The Parent Company's equity securities are traded on both the
Australian Stock Exchange and the New York Stock Exchange.

      The Company is allocated stock compensation expense in respect to the
options in the Parent Company which are granted to the Company's employees and
certain consultants. The Parent Company accounts for its expense related to the
stock option plan in accordance with Statement of Financial Accounting Standards
No. 123 (Statement 123), Accounting for Stock-Based Compensation, under which it
recognizes as expense over the vesting period the fair value of all stock-based
awards on the date of grant. The amount is recorded as an increase to additional
paid-in-capital. The fair value was determined using the Black-Scholes valuation
method. The calculation takes into account the exercise price, expected life,
current price of underlying stock, expected volatility of the underlying stock,
expected dividend yield and the risk-free interest rate. The expected life,
volatility, dividend yield and risk-free interest rates used in determining the
fair value of options granted in 1996 were 2.1 to 3.5 years (weighted average
3.0 years); 30%; 0; and 7.1% to 8.4% per annum (weighted average 8% per annum),
respectively, 1.5 to 2.5 years (weighted average 2.1 years); 30%; 0; and 5.8% to
6.5% per annum (weighted average 6.1% per annum), respectively, in 1997, and 2.4
to 4.5 years (weighted average 3.4 years); 37%; 0; and 5.3%, respectively, in
1998.


                                                                              47
<PAGE>   48
                               PETSEC ENERGY INC.
                  NOTES TO FINANCIAL STATEMENTS (CONTINUED)


7. INCOME TAXES

      Although the Company is included in the consolidated federal and state
income tax returns of Petsec (U.S.A.) Inc., the income tax provision has been
prepared as if the Company was a separate taxpayer. Income tax attributable to
income or loss before income taxes was $6.3 million expense, $6.6 million
expense and $16.5 million benefit for the years ended December 31, 1996, 1997
and 1998 respectively, and differed from the amounts computed by applying the
U.S. federal income tax rate of 34% to income before income taxes as a result of
the following:

<TABLE>
<CAPTION>
                                                                  1996       1997        1998
                                                                --------   --------    --------
                                                                     (dollars in thousands)
<S>                                                             <C>        <C>         <C>      
Computed "expected" tax expense (benefit)                       $  5,180   $  6,701    $(36,637)
Increase (reduction) in income taxes resulting from:
         Items not deductible for tax                                550         30         481
         State income tax expense (benefit)                          322        368      (1,934)
         Other                                                       259       (489)       --
         Change in the balance of the valuation allowance for                                  
         deferred tax assets allocated to income tax expense        --         --        21,632
                                                                --------   --------    --------
                                                                $  6,311   $  6,610    $(16,458)
                                                                ========   ========    ========
</TABLE>

      The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at December 31,
1997 and 1998 are presented below.

<TABLE>
<CAPTION>
                                                                              1997        1998
                                                                            --------    --------
                                                                           (dollars in thousands)
<S>                                                                         <C>         <C>     
Deferred tax assets:
          Financial provisions not currently deductible for tax purposes    $  1,091    $    851
          Net operating loss carryforwards                                    16,823      32,045
                                                                            --------    --------
             Total gross deferred tax assets                                  17,914      32,896
          Less valuation allowance                                              --       (21,632)
                                                                            --------    --------
             Net deferred tax assets                                        $ 17,914    $ 11,264
Deferred tax liabilities:
          Differences in depreciation and depletion of oil and gas assets    (34,372)    (11,264)
                                                                            --------    --------
             Net deferred tax liabilities                                   $(16,458)   $   --
                                                                            ========    ========
</TABLE>

      The net change in the valuation allowance for the year ended December 31,
1998 was an increase of $21.6 million. This change was made to provide for
uncertainties surrounding the realization of net operating loss carryforwards.
The remaining balance of deferred tax assets are expected to be realized through
the reversal of taxable temporary differences.

      At December 31, 1998, the Company has net operating loss carryforwards for
federal and state income tax purposes of $89 million which are available to
offset future federal taxable income, if any, from 2005 through 2018.

8. RELATED PARTY TRANSACTIONS

      The Parent Company has advanced funds to Petsec Energy Inc. through Petsec
(U.S.A.) Inc. (Note 4). The funds were used to finance exploration and
development expenditures.


                                                                              48
<PAGE>   49
                               PETSEC ENERGY INC.
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

      For the years ended December 31, 1996, 1997 and 1998, Petsec Energy Inc.
paid amounts of $1.0 million, $540,000 and $325,000 to the Parent Company
principally for reimbursement of direct expenses incurred in connection with the
Company's operations.

9. COMMITMENTS

      Future minimum lease commitments at December 31, 1998, applicable to
noncancelable operating leases with terms of one year or more are summarized as
follows (in thousands):

<TABLE>
<CAPTION>
                        Year              Amount
                        ----              ------
                        <S>               <C>  
                        1999              $ 268
                        2000                 89
                                          -----
                                          $ 357
                                          =====
</TABLE>

      Rent expense for the years ended December 31, 1996, 1997 and 1998 was
$281,000, $264,000, and $281,000 respectively.


10. ADDITIONAL PAID-IN-CAPITAL

The following is a reconciliation of additional paid-in-capital (in thousands):

<TABLE>
<S>                                               <C>    
           Balance at December 31, 1996           $   482

           Recapitalization of loan                19,594

           Stock Options (Note 6)                     905
                                                  -------

           Balance at December 31, 1997           $20,981

           Stock Options (Note 6)                     592
                                                  -------

           Balance at December 31, 1998           $21,572
                                                  =======
</TABLE>

11. HEDGING ACTIVITIES

      The Company enters into forward swap contracts with major financial
institutions to reduce the price volatility on the sale of oil and gas
production. In swap agreements, the Company receives the difference between a
fixed price per unit of production and a floating price issued by a third party.
If the floating price is higher than the fixed price, the Company pays the
difference. At December 31, 1998, giving effect to the contracts terminated as a
result of the sale of certain properties discussed in Note 14, the Company had
contracts maturing monthly through May 2000 on the net sale of 517,000 barrels
of oil at an average price of $19.70 per barrel and on the net sale of 14.3
million MMbtu of gas at an average price of $2.311 per MMbtu. The effect to the
Company to terminate these contracts at December 31, 1998 is estimated to be a
gain of $3.2 million for oil and $4.2 million for gas.

      For the years ended December 31, 1996, 1997 and 1998, hedging activities
reduced revenues by $8.4 million and $4.4 million, and increased revenues by
$7.7 million, respectively.


                                                                              49
<PAGE>   50
                               PETSEC ENERGY INC.
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

12. SUPPLEMENTAL CASH FLOW INFORMATION

      Cash paid for interest was $3.4 million, $6.8 million and $10.9 million
for the years ended December 31, 1996, 1997 and 1998, respectively. The Company
has not paid any cash for income taxes in these years.

13. LITIGATION

      The Company is involved in certain lawsuits arising in the ordinary course
of business. While the outcome of any of these lawsuits cannot be predicted with
certainty, management expects these matters to have no material adverse effect
on the financial position, results of operations or liquidity of the Company.

14. SUBSEQUENT EVENT

     On February 1, 1999, the Company completed the sale of a 50% working
interest in certain of its oil and gas properties to an unrelated party for
$68.3 million. The transaction was effective January 1, 1999. As a result of the
sale, a non-cash impairment of approximately $27 million was recognized at
December 31, 1998, to properly value the assets at their fair value. This charge
is included in the $72.9 million impairment shown in the accompanying financial
statements. The proceeds from the sale were used to repay $65 million of the
Bank Credit Facility, reducing outstandings under the credit facility to $9
million. The credit facility was reduced to $10 million as a result of the sale.
Revenues in 1998 attributed to the 50% working interest that was sold were $41
million.

                               PETSEC ENERGY INC.
               SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED

15. SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED

      Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.

      Proved reserves are estimated quantities of natural gas, crude oil and
condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
existing economic and operating conditions.

      Proved developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.

      Estimates of proved and proved developed reserves at December 31, 1996,
1997 and 1998 were based on studies performed by Ryder Scott Company.

      No major discovery or other favorable or adverse event subsequent to
December 31, 1998 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date. 


                                                                              50
<PAGE>   51

                               PETSEC ENERGY INC.
         SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED (CONTINUED)

      For the purposes of the disclosure below, the effect of the sale of
interests in certain oil and gas properties (see Note 14) effective January 1,
1999 are reflected as if sold on December 31, 1998.

ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES

      The following table sets forth the Company's net proved reserves,
including the changes therein, and proved developed reserves (all within the
United States) as estimated by Ryder Scott Company:

<TABLE>
<CAPTION>
                                                                      Crude Oil     Natural Gas
                                                                       (MBbl)          (MMcf)
<S>                                                                   <C>           <C>   
Proved developed and undeveloped reserves:
         December 31, 1995                                              7,172         49,747
                  Revisions of previous estimates                         211          2,297
                  Extensions, discoveries and other additions           3,085         32,969
                  Production                                           (2,150)       (11,722)
                                                                       ------        -------
         December 31, 1996                                              8,318         73,291
                  Revisions of previous estimates                       2,220         12,194
                  Extensions, discoveries and other additions           3,181         64,604
                  Production                                           (3,078)       (27,940)
                                                                       ------        -------
         December 31, 1997                                             10,641        122,149
                  Revisions of previous estimates                         (66)       (18,985)
                  Extensions, discoveries and other additions           1,168          4,738
                  Sales of reserves in place*                          (4,053)       (25,700)
                  Purchase of reserves in place                            --          1,440
                  Production                                           (2,353)       (25,390)
                                                                       ------        -------
         December 31, 1998                                              5,337         58,252
                                                                       ======        =======
</TABLE>

*Relates to sale to Apache Corporation of a 50% working interest in certain
 properties effective January 1, 1999.

<TABLE>
<CAPTION>
                                                                      Crude Oil     Natural Gas
                                                                       (MBbl)          (MMcf)
<S>                                                                   <C>           <C>   
Proved developed reserves:
         December 31, 1996                                              6,670         43,133
         December 31, 1997                                              8,430         88,199
         December 31, 1998                                              3,054         26,965
</TABLE>


                                                                              51
<PAGE>   52

                               PETSEC ENERGY INC.
         SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED (CONTINUED)

      Capitalized costs for oil and gas producing activities consist of the
following:

<TABLE>
<CAPTION>
                                                                As of December 31,

                                                         1996         1997         1998

                                                                 (in thousands)
<S>                                                    <C>          <C>          <C>      
Proved properties                                      $ 169,982    $ 294,005    $ 199,586
Unproved properties                                        7,276       20,759       31,984
                                                       ---------    ---------    ---------
                                                         177,258      314,764      231,570
Accumulated depreciation, depletion and amortization     (44,349)    (106,392)    (132,739)
                                                       ---------    ---------    ---------
         Net capitalized costs                         $ 132,909    $ 208,372    $  98,831
                                                       =========    =========    =========
</TABLE>

      Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:

<TABLE>
<CAPTION>
                                                           Years Ended December 31,

                                                         1996       1997       1998

                                                               (in thousands)        
                                                                                     
<S>                                                    <C>        <C>        <C>     
Lease acquisition                                      $  6,699   $  8,437   $  7,836
Exploration                                              71,490    115,523    107,111
Development                                              14,187     31,327     10,301
                                                       --------   --------   --------
      Total costs incurred                             $ 92,376   $155,287   $125,248
                                                       ========   ========   ========
</TABLE>

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES

      The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures
about Oil and Gas Producing Activities" (SFAS No. 69) and based on natural gas
and crude oil reserve and production volumes estimated by Ryder Scott Company.
It may be useful for certain comparative purposes, but should not be solely
relied upon in evaluating the Company or its performance. Further, information
contained in the following table should not be considered as representative of
realistic assessments of future cash flows, nor should the Standardized Measure
of Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.

      The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (4)
future net revenues may be subject to different rates of income taxation.

      Under the Standardized Measure, future cash inflows were estimated by
applying period end oil and gas prices adjusted for fixed and determinable
escalations including hedged prices to the estimated future production of
period-end proved reserves. As of December 31, 1998, approximately 14.3 million
MMbtu of the Company's future gas production and 517,000 barrels of oil were
subject to such positions. Future cash inflows were reduced by estimated future
development, abandonment and production costs based on period-end costs in order
to arrive at net cash flow before tax. Future income tax expense has been


                                                                              52
<PAGE>   53


                               PETSEC ENERGY INC.
         SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)

computed by applying period-end statutory tax rates to aggregate future pretax
net cash flows, reduced by the tax basis of the properties involved and tax
carryforwards. Use of a 10% discount rate is required by SFAS No. 69.

      Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.

      The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows. For the purpose of the disclosure
below, the effect of the sale of interests in certain oil and gas properties
(see Note 14) effective January 1, 1999 are reflected as if sold on December 31,
1998.

<TABLE>
<CAPTION>
                                                                    As of December 31,

                                                              1996         1997         1998

                                                                      (in thousands)
<S>                                                        <C>          <C>          <C>      
Future cash inflows                                        $ 479,220    $ 472,470    $ 183,371
      Future production costs                                (58,367)    (101,765)     (55,456)
      Future development and abandonment costs               (47,873)     (53,851)     (44,783)
      Future income tax expense                             (102,669)     (64,064)          --
                                                           ---------    ---------    ---------
Future net cash flows after income taxes                     270,311      252,790       83,132
10% annual discount for estimated timing of cash flows       (46,930)     (48,676)     (16,079)
                                                           ---------    ---------    ---------
Standardized measure of discounted future net cash flows   $ 223,381    $ 204,114    $  67,053
                                                           =========    =========    =========
</TABLE>

      A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves is as follows:

<TABLE>
<CAPTION>
                                                                 Year Ended December 31,
                                                          -----------------------------------
                                                             1996         1997         1998

                                                                     (in thousands)
<S>                                                       <C>          <C>          <C>      
Beginning of the period                                   $ 131,488    $ 223,381    $ 204,114
                                                          ---------    ---------    ---------
Sales and transfers of oil and gas produced, net of
   production costs                                         (60,764)    (113,462)     (77,028)
Net changes in prices and production costs                   61,394     (142,243)     (86,433)
Extensions, discoveries and improved recoveries, net of     
   future production costs                                  145,494      134,467       13,422
Net changes due to revisions in quantity estimates           10,070       40,994      (21,677)
Development costs incurred during the period                  8,945        1,050        2,251
Sales of reserves in place*                                    --           --        (57,164)
Purchase of reserves in place                                  --           --          1,646
Change in estimated future development costs                (26,208)      (5,674)       5,499
Accretion of discount                                        12,079       32,481       30,749
Net change in income taxes                                  (59,117)      33,120       51,674
                                                          ---------    ---------    ---------
Net increase (decrease)                                      91,893      (19,267)    (137,061)
                                                          ---------    ---------    ---------
End of period                                             $ 223,381    $ 204,114    $  67,053
                                                          =========    =========    =========
</TABLE>

* Relates to sale to Apache Corporation of a 50% working interest in certain
  properties effective January 1, 1999.


                                                                              53
<PAGE>   54

                               PETSEC ENERGY INC.
         SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED (CONTINUED)

      The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1998 was based on
average natural gas prices of approximately $2.04 per mcf and on average liquids
of approximately $11.98 per barrel.

(b).   REPORTS ON FORM 8-K

       No current reports on Form 8-K were filed during the Company's fourth
quarter 1998.


(c).   EXHIBITS

<TABLE>
<CAPTION>
  Exhibit No.        Description
  -----------        -----------
<S>                  <C>
     4.1             Articles of Incorporation of the Company (filed with
                     Registration Statement on Form S-4 (No. 333-31625) and
                     incorporated herein by reference)

     4.2             By-Laws of the Company (filed with Registration Statement
                     on Form S-4 (File No. 333-31625) and incorporated herein by
                     reference)

     4.3             Indenture dated as of June 13, 1997 among the Company, as
                     issuer, and the Bank of New York, as trustee (filed with
                     Registration Statement on Form S-4. (File No 333-31625) and
                     is incorporated herein by reference)

     4.4             Registration Rights Agreement dated June 13, 1997 by and
                     among the Company and Merrill Lynch & Co., Merrill, Lynch,
                     Pierce, Fenner & Smith Incorporated, Donaldson, Lufkin &
                     Jenrette Securities Corporation and Salomon Brothers Inc.
                     (filed with Registration Statement on Form S-4 (File No.
                     333-31625) and incorporated herein by reference)

     10.1            Credit Agreement by and among Petsec Energy Inc. and Chase
                     Manhattan Bank and certain financial institutions named
                     therein as Lenders (filed with Registration Statement on
                     Form S-4 filed (File No. 333-31625) and incorporated herein
                     by reference)

     23.1*           Consent of Ryder Scott Company

     27*             Financial Data Schedule
</TABLE>

* Filed herewith


                                                                              54
<PAGE>   55
                                   SIGNATURES


      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 and on the dates indicated.

                                       Petsec Energy Inc.




Date:                                  By: /s/ Ross A. Keogh
     ---------------                       -------------------------------------
                                           Name:  Ross A. Keogh
                                           Title: Chief Financial Officer

      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 and on the dates indicated.

      KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Ross A. Keogh, his true and lawful
attorney-in-fact and agent, with full power of substitution and resubstitution,
for him and in his name, place and stead, in any and all capacities, to sign on
his behalf individually and in each capacity stated below any and all amendments
to this annual report, and to file the same, with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission,
granting unto said attorney-in-fact and agent, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said
attorney-in-fact and agent, or his substitutes, may lawfully do or cause to be
done by virtue hereof.

<TABLE>
<CAPTION>
         Name                                 Title                        Date
         ----                                 -----                        ----
<S>                            <C>                                         <C>
/s/ Terrence N. Fern           Chairman and Chief Executive Officer
-------------------------      (Principal Executive Officer)               
Terrence N. Fern                                          


/s/ Ross A. Keogh
-------------------------
Ross A. Keogh                  Director and Treasurer                   
                               (Principal Financial and Accounting 
                               Officer)


/s/ James E. Slatten III
-------------------------
James E. Slatten III           Director and Secretary                   
                               
</TABLE>



                                                                              55
<PAGE>   56
                                 EXHIBIT INDEX


<TABLE>
<CAPTION>
  Exhibit No.        Description
  -----------        -----------
<S>                  <C>
     4.1             Articles of Incorporation of the Company (filed with
                     Registration Statement on Form S-4 (No. 333-31625) and
                     incorporated herein by reference)

     4.2             By-Laws of the Company (filed with Registration Statement
                     on Form S-4 (File No. 333-31625) and incorporated herein by
                     reference)

     4.3             Indenture dated as of June 13, 1997 among the Company, as
                     issuer, and the Bank of New York, as trustee (filed with
                     Registration Statement on Form S-4. (File No 333-31625) and
                     is incorporated herein by reference)

     4.4             Registration Rights Agreement dated June 13, 1997 by and
                     among the Company and Merrill Lynch & Co., Merrill, Lynch,
                     Pierce, Fenner & Smith Incorporated, Donaldson, Lufkin &
                     Jenrette Securities Corporation and Salomon Brothers Inc.
                     (filed with Registration Statement on Form S-4 (File No.
                     333-31625) and incorporated herein by reference)

     10.1            Credit Agreement by and among Petsec Energy Inc. and Chase
                     Manhattan Bank and certain financial institutions named
                     therein as Lenders (filed with Registration Statement on
                     Form S-4 filed (File No. 333-31625) and incorporated herein
                     by reference)

     23.1*           Consent of Ryder Scott Company

     27*             Financial Data Schedule
</TABLE>

* Filed herewith