<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, 1999

                                       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)

                                 (337) 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.
                                      None

           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 30, 2000, 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") traded on
the OTC Bulletin Board (symbol: PSJEY). 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.           Business .........................................................................................       5
Item 2.           Description of Properties ........................................................................      19
Item 3.           Legal Proceedings ................................................................................      20
Item 4.           Submission of Matters to a Vote of Security Holders ..............................................      20

                                                            PART II
Item 5.           Market for Registrant's Common Equity and Related Stockholder Matters ............................      20
Item 6.           Selected Financial Data ..........................................................................      21
Item 7.           Management's Discussion and Analysis of Financial Condition and
                   Results of Operations............................................................................      22

Item 7A.          Quantitative and Qualitative Disclosures About Market Risk .......................................      30
Item 8.           Financial Statements and Supplementary Data ......................................................      32
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 ...........................................................................      34
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>


                                                                               2

<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.

         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.

                                                                               3

<PAGE>   4

         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.

         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.


                                                                               4

<PAGE>   5


         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


     The Company is the wholly owned principal operating subsidiary of Petsec
Energy Ltd (the "Parent"). The Parent is an Australian public company with
ordinary shares listed on the Australian Stock Exchange (symbol: PSA) and
American Depositary Receipts ("ADRs") traded on the OTC Bulletin Board (symbol:
PSJEY). The results discussed in this report refer only to the Company. The
Parent's results are filed with the Securities and Exchange Commission
separately under Forms 6-K (quarterly) and 20-F (annually). Shareholders and ADR
holders are advised to refer to these filings.

     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 48 leases on the Outer
Continental Shelf at federal or state lease sales, of which 18 are held by
production. Until December 31, 1998, 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. A disappointing drilling program in 1998 compounded by low oil
and gas prices caused the Company's outstanding debt to reach unacceptable
levels. Effective January 1, 1999, the Company sold a 50% working interest in a
substantial number of its properties to Apache Corporation, an unrelated
independent exploration and production company. It also transferred operations
on the properties sold. Proceeds from the sale were used to reduce debt.

     The Company engaged a financial advisor in October 1999 to assist with the
restructure of its $100 million 9 1/2% Senior Subordinated Notes due 2007 (the
"9 1/2% Notes"). The Company did not make the interest payment due on the 9 1/2%
Notes at December 15, 1999, and is in default under the indenture governing the
9 1/2% Notes (the "Indenture"). The Company began discussions with a
subcommittee of holders of the 9 1/2% Notes on January 18, 2000 regarding
alternative solutions to its financial situation. While the Company is hopeful
that a solution acceptable to both the holders of the 9 1/2% Notes and the
Company can be reached, there can be no assurance that the Company will be able
to reach agreement on these proposals. Whether or not a consensual resolution
can be reached, it is likely that the Company will need to seek protection under
the United States Bankruptcy Code. The Company does not intend to make any
further public comments about the restructuring process until either agreement
on a solution is reached with the holders of the 9 1/2% Notes or it becomes
apparent that no such agreement can be reached. See "Item 7-- Management's
Discussion and Analysis of Financial Condition and Results of Operations;" "Risk
Factors -- Liquidity Problems."


                                                                               5

<PAGE>   6
     The Company completed a refinancing of its senior secured credit facility
with Foothill Capital Corporation on January 18, 2000. For a discussion of
certain events affecting the current liquidity of the Company, see "Risk Factors
-- Liquidity Problems" and see "Item 7-- Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

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, 1997, 1998 and 1999. 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, L.P., 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,
                                                                -------------------------------------------------

                                                                     1997               1998             1999

<S>                                                             <C>                <C>                 <C>
TOTAL NET PROVED:
   Gas (MMcf)                                                       122,149             58,252             56,783
   Oil (MBbls)                                                       10,641              5,337              4,469
   Total (MMcfe)                                                    185,995             90,274             83,597

NET PROVED DEVELOPED:
   Gas (MMcf)                                                        88,199             26,965             21,950
   Oil (MBbls)                                                        8,430              3,054              2,090
   Total (MMcfe)                                                    138,779             45,289             34,490

Estimated future net revenues before income  taxes              $   316,855        $    83,132         $  150,828
   (in thousands)

Present value of estimated future net revenues                  $   255,839        $    67,053         $  113,139
   before income taxes (in thousands) (1)(2)

Standardized measure of discounted future net cash              $   204,114        $    67,053         $  113,139
   flows (in thousands) (3)(4)
</TABLE>


                                                                               6

<PAGE>   7


(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.

(2)  The present value as of December 31, 1999 was calculated using an average
     oil price of $25.61 per barrel before hedging and an average gas price of
     $2.43 per Mcf before 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.

(4)  Income taxes have not been provided in 1999 and 1998 due to the Company's
     current availability of net operating loss carryforwards.

     Approximately 59% of the Company's total proved reserves at December 31,
1999 were undeveloped. Recovery of such reserves will require significant
capital expenditures and successful drilling operations. The Company's financial
resources are limited, and there can be no assurance that additional debt or
equity financing or cash generated by operations will be available to meet these
requirements. The Company's credit facility has a borrowing base that is
determined by the value of its oil and gas properties reviewed monthly by the
creditor. The creditor has substantial discretion to place reserves against the
borrowing base. See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Liquidity and Capital Resources" for
additional explanation regarding the Company's liquidity problems.

     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,
                            ------------------------------------------

                                1997           1998           1999
                            ------------   ------------   ------------
                                         (In thousands)

<S>                         <C>            <C>            <C>
Acquisition costs           $      8,437   $      7,836   $      2,610
Exploration costs                115,523        107,111         14,745
Development costs                 31,327         10,301          1,216
                            ------------   ------------   ------------

Total costs incurred        $    155,287   $    125,248   $     18,571
                            ============   ============   ============
</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, 1999:

<TABLE>
<CAPTION>
                                          Gross           Net
                                      ------------   ------------
<S>                                   <C>            <C>
Productive Wells(1):
         Oil(2)                                 17            8.5
         Gas(3)                                 37           19.5
                                      ------------   ------------

                  Total                         54           28.0
                                      ------------   ------------

Developed Acreage(1)                        51,823         28,412
Undeveloped Acreage(1)(4)                  103,971         71,926
                                      ------------   ------------

                  Total                    155,794        100,338
                                      ============   ============
</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 7% of the Company's undeveloped acreage will expire in
     2000, approximately 30% in 2001, 12% in 2002, 32% in 2003 and 19% in 2004.

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

<TABLE>
<CAPTION>
                                                               Years Ended December 31,
                                      ---------------------------------------------------------------------------
                                                1997                      1998                     1999
                                                ----                      ----                     ----
                                         Gross         Net        Gross         Net         Gross         Net
                                      ----------   ----------   ----------   ----------   ----------   ----------

<S>                                   <C>          <C>          <C>          <C>          <C>          <C>
Gulf of Mexico
         Exploratory wells                    13         13.0            4            4            6          2.6
         Development wells                     4          4.0            1            1            2          0.8
         Dry holes                             3          2.4            3            3            1          0.5
         Abandoned wells                      --           --           --           --            1          0.2
                                      ----------   ----------   ----------   ----------   ----------   ----------

                  Total                       20         19.4            8            8           10          4.1
                                      ==========   ==========   ==========   ==========   ==========   ==========
</TABLE>

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


                                                                               8

<PAGE>   9

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 gas production from its properties. All of
the Company's gas production is sold to a variety of purchasers under short-term
(one year or less) contracts or thirty-day spot purchase contracts. Natural gas
sales contracts are based upon field posted prices plus negotiated bonuses.
Apache Corporation markets all of the Company's oil production through marketing
arrangements it has with other companies, which accounted for 36% of the
Company's revenue in 1999. During 1999, Enron North America Corp. (formerly
Columbia Energy Services Corporation) ("Enron") purchased 49% of the gas sold by
the Company. Enron purchased all of the Company's gas after April 1, 1999
pursuant to a twelve-month contract that provided for monthly market pricing
adjustments. Based upon current demand for oil and gas in the Gulf of Mexico
region, the Company believes that there is sufficient competition for the
purchase of its hydrocarbons to ensure that the Company will continue to receive
market pricing.

     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.


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, to access adequate financing, and to consummate
transactions in a highly competitive environment.

                                                                               9

<PAGE>   10

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 Louisiana) 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. In as much as such
laws and regulations are frequently expanded, amended or reinterpreted, the
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.


                                                                              10

<PAGE>   11

     The MMS has proposed changes to 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
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 price declines for natural gas following the
implementation of order No. 636 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 issued Order No. 637, which, among other
things, (i) lifts the cost-based cap on pipeline transportation rates in the
capacity release market until September 30, 2002, for releases of pipeline
capacity of less than one year, (ii) permits pipelines to charge different
maximum cost-based rates for peak and off-peak times, (iii) encourages auctions
for pipeline capacity, (iv) requires pipelines to implement imbalance management
services, and (v) restricts the ability of pipelines to impose penalties for
imbalances, overruns, and non-compliance with operational flow orders. Order No.
637 also requires the FERC Staff to analyze whether the FERC should implement
additional fundamental policy changes, including, among other things, whether to
pursue performance-based ratemaking or other non-cost based ratemaking
techniques and whether the FERC should mandate greater standardization in terms
and conditions of service across the interstate pipeline grid. In addition, the
FERC recently implemented new regulations governing the procedure for obtaining
authorization to construct new pipeline facilities and has issued a policy
statement, which it largely affirmed in a recent order on rehearing,
establishing a presumption in favor of requiring owners of new pipeline
facilities to charge rates based solely on the costs associated with such new
pipeline facilities. The Company cannot predict what additional action the FERC
will take on


                                                                              11

<PAGE>   12

these 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 numerous orders approving the spindown 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.

     The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines
operating on or across the Outer Continental Shelf (the OCS) provide
open-access, non-discriminatory service. Pursuant to one of the FERC's recent
initiatives regarding its regulatory treatment of pipelines and services on the
OCS, the FERC has proposed to adopt certain reporting requirements concerning
OCS rates and terms and conditions of service, which requirements are
applicable, with certain limited exceptions, to both gas pipelines and gatherers
operating on the OCS. The purpose of the proposed requirements is to provide
regulators and other interested parties with sufficient information to detect
and then seek to remedy discriminatory conduct in such operations. The Company
cannot predict what, if any, affect this matter may have on the Company.

     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 federal, state and local laws and regulations pertaining to the
discharge of materials into the environment or otherwise relating to protection
of the environment. Such laws and regulations have 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. Some laws and regulations relating to
protection of the environment may, in certain circumstances, impose "strict
liability" for environmental contamination, rendering a person liable for
environmental and natural resource damages and cleanup costs without regard to
negligence or fault on the part of such person. Although the Company believes
that compliance with environmental laws and 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 operations, and there can be no
assurance that significant costs and liabilities, including administrative,
civil, and 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.



                                                                              12

<PAGE>   13

     The Comprehensive Environmental Response, Compensation and Liability Act,
as amended, ("CERCLA"), also known as the "Superfund" law, and comparable state
laws impose 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, as amended, ("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, as amended, (the "OPA"), and regulations
thereunder impose a variety of regulations on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in United States waters. A "responsible party" includes the owner or
operator of a vessel, pipeline, or onshore facility 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. Certain amendments to OPA that were enacted in 1996 and a final rule
adopted by the MMS in 1998 require responsible parties of covered 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), to
demonstrate financial responsibility in amounts ranging 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 operations or if
the worst-case spill discharge volume possible at the facility may exceed the
applicable threshold volumes specified under the MMS's final rule.

     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


                                                                              13

<PAGE>   14

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 final 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 administrative, civil or
criminal liability.

     The Federal Water Pollution Control Act, as amended ("FWPCA"), imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas wastes in navigable waters. Permits must be obtained to
discharge pollutants to waters and to conduct construction activities in waters
and wetlands. The FWPCA and analogous state laws provide for administrative,
civil, and criminal penalties for any unauthorized discharges of pollutants and
reportable quantities of oil and other hazardous substances. Many state
discharge regulations and the National Pollutant Discharge Elimination system
generally prohibit the discharge of produced water and sand, drilling fluids,
drill cuttings, and certain other substances related to the oil and gas industry
into coastal waters. Although the costs to comply with these zero discharge
mandates under federal or state law may be significant, the entire industry is
expected to experience similar costs in the western Gulf of Mexico, and the
Company believes that these costs will not have a material adverse impact on the
Company's financial condition and operations.


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, blowouts, 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.

     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.


                                                                              14

<PAGE>   15

     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 23 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.


RISK FACTORS

LIQUIDITY PROBLEMS

     The Company is experiencing a liquidity problem. As of December 31, 1999,
the Company's long-term debt including current maturities was $144.9 million, of
which $99.7 million was senior subordinated notes, $7.9 million was borrowings
under the Company's bank credit facility and $37.3 million was a subordinated
shareholder loan.

     On October 29, 1999, in order to preserve available cash, the Company
elected not to pay $3.2 million due to the syndicate of banks under its
revolving credit facility (the "Chase Credit Facility") in which the Chase
Manhattan Bank, N.A., Bank of America, N.A. (formerly NationsBank N.A.) and
Credit Lyonnais (collectively, the "Banks") were participants. This caused a
default of its secured debt and a cross default under the Indenture.
Subsequently, the Company refinanced the Chase Credit Facility with Foothill
Capital Corporation ("Foothill"), completing a $30 million revolving credit
facility on January 18, 2000 (the "Foothill Credit Facility"). At March 22,
2000, the Company's borrowing base was $29.3 million. After subtracting
borrowings and letters of credit issued under the Foothill Credit Facility to
secure hedging obligations, the Company had $15.3 million available for
additional borrowing at March 22, 2000. The Company's ability to borrow under
the Foothill Credit Facility is dependent upon the reserve value of its oil and
gas properties, as determined monthly by Foothill. If the reserve value of the
Company's borrowing base declines, the amount available to the Company under the
Foothill 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 facility, the Company will be obligated to repay such excess amount
immediately upon notice from Foothill. Moreover, Foothill has broad discretion
under the Foothill Credit Facility to set reserves against the borrowing base.

     As a consequence of the October 29, 1999 default on the Chase Credit
Facility, a cross default occurred under the Indenture. The Indenture trustee or
the holders of $25 million or more of the 9 1/2% Notes can elect to accelerate
the entire debt that is due to them, which is $100 million, and to commence
collection proceedings. The semi-annual interest payment under the Indenture in
the amount of $4.75 million due on December 15, 1999, was also not paid. The
Foothill Credit Facility prohibits the Company from paying interest or principal
due under the Indenture. Given the Company's current liquidity position and the
prohibition in the Foothill Credit Facility on the payment of interest due under
the Indenture, it is unlikely the Company will make this payment in the
foreseeable future. The Company has commenced discussions with

                                                                              15

<PAGE>   16
the holders of the 9 1/2% Notes on alternative solutions to its financial
situation. There can be no assurance that discussions with these holders will
result in a satisfactory solution in respect of the 9 1/2% Notes, or the holders
or trustee of the 9 1/2% Notes will not commence collection proceedings against
the Company. Whether or not a consensual resolution can be reached, it is likely
that the Company will need to seek protection under Chapter 11 of the United
States Bankruptcy Code.

     If the Company is able to resolve its current liquidity problems, it still
may have substantial indebtedness. 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 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 depressed. In 1999 oil prices
significantly improved, 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.

     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."

                                                                              16

<PAGE>   17

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, L.P., 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, L.P. 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 59% of the Company's total proved reserves at December 31,
1999 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, L.P., 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, that the Company
will have adequate capital resources to make the expenditures when anticipated
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.


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.

                                                                              17


<PAGE>   18

     Given the discussions that are underway presently with the holders of the
9 1/2% Notes and the Company liquidity problems, the Company's drilling program
has been curtailed substantially and its future drilling plans are uncertain.
Accordingly, there can be no assurance that the Company's management will be
able to effect a strategy that will result in significant additional reserves or
that the Company will have 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

     In the past, the Company has made substantial expenditures for development,
exploration, acquisition and production of oil and gas reserves. Capital
expenditures were $19 million in 1999, $125 million in 1998 and $155 million in
1997. Substantial capital expenditures will be required in the future to access
existing reserves and undertake a drilling program to find new reserves. The
Company's financial resources are limited, and 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.

     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


                                                                              18

<PAGE>   19

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."

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


                                                                              19

<PAGE>   20

Federal OCS lease sales. At December 31, 1999, the Company had 48 lease blocks
in the Gulf of Mexico. All of the Company's proved oil and gas reserves at
December 31, 1999 were in these blocks.


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 23.


                           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.

     In addition, the Company is the plaintiff in a lawsuit brought against
certain of its underwriters based on the underwriters' denial of a portion of an
insurance claim in the amount of approximately $820,000 to recover losses
arising from Hurricane Georges in September 1998. The lawsuit was filed in
February 2000 in the Western District of Louisiana, Lafayette Division. No trial
date has been set. The Company maintains that certain contractual obligations it
incurred to Falcon Drilling Company, Inc. resulting from hurricane damage to a
Falcon drilling rig are covered under its energy insurance policy. The
underwriters on the insurance policy disagree. While there can be no assurance
that the Company will prevail in this lawsuit, the Company believes it has a
strong basis for its claim and will pursue the matter vigorously.


          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.


                                                                              20


<PAGE>   21

                        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, 1995, 1996, 1997, 1998 and 1999 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,
                                                     -----------------------------------------------------------------------
                                                         1995          1996           1997           1998           1999
                                                     -----------    -----------    -----------    -----------    -----------
                                                                                 (in thousands)

<S>                                                  <C>             <C>           <C>            <C>            <C>
Statement of Operations data:
   Oil and gas sales                                 $    30,462    $    67,027    $   125,139    $    92,017    $    31,000
   Lease operating expenses                                4,757          6,161         11,527         14,989          7,045
   Depletion, depreciation and amortization                9,256         29,639         63,864         57,576         21,261
   Exploration expenditures                                3,396          7,061          7,328          7,427          2,750
   Dry hole costs and abandonments                            --             --         10,454         27,503          2,840
   Impairments                                                --             --             --         72,916          7,480
   General and administrative                              4,502          5,259          6,054          7,868          5,287
   Stock compensation                                         --            481            905            591            246
                                                     -----------    -----------    -----------    -----------    -----------

         Total operating expenses                         21,911         48,601        100,132        188,870         46,909
                                                     -----------    -----------    -----------    -----------    -----------
     Income (loss) from operations                         8,551         18,426         25,007        (96,853)       (15,909)
   Other income (expense):                                    35             --          1,418            517           (322)
   Gain on sale of property, plant and
       equipment                                           4,312              6             --             --             --
   Interest expense                                       (2,452)        (3,369)        (7,586)       (11,721)       (13,517)
   Interest income                                            64            172            871            302            260
                                                     -----------    -----------    -----------    -----------    -----------
      Income (loss) before income taxes                   10,510         15,235         19,710       (107,755)       (29,488)
   Income tax (expense) benefit                           (3,537)        (6,311)        (6,610)        16,458             --
                                                     -----------    -----------    -----------    -----------    -----------
      Net income (loss)                              $     6,973    $     8,924    $    13,100    $   (91,297)   $   (29,488)
                                                     ===========    ===========    ===========    ===========    ===========
</TABLE>

<TABLE>
<CAPTION>
                                                                                As of December 31,
                                                     -----------------------------------------------------------------------
                                                         1995           1996           1997           1998          1999
                                                     -----------    -----------    -----------    -----------    -----------
                                                                                  (in thousands)
<S>                                                  <C>            <C>            <C>            <C>            <C>
Balance Sheet Data:
   Total assets                                      $    89,110    $   146,145    $   234,104    $   185,032    $    93,508
   Senior subordinated notes                                  --             --         99,630         99,656         99,684
   Bank credit facility                                   32,350         37,000             --         74,000          7,875
   Subordinated shareholder loan                          25,038         57,954         37,298         36,792         37,330
   Shareholder's equity (deficit)                          5,631         15,036         48,635        (42,071)       (71,313)
</TABLE>


                                                                              21

<PAGE>   22

                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, 1999. Financial Statements and notes
thereto included elsewhere in this Annual Report should be referred to in
conjunction with the following discussion.

     In order to preserve available cash, the Company did not make principal
payments due October 29, 1999, in the amount of $3.2 million under its revolving
credit facility at the time, in which The Chase Manhattan Bank, N.A., Bank of
America, N.A. (formerly NationsBank, N.A.) and Credit Lyonnais were
participants. The Company was in default under the Chase Credit Facility, and
this default caused a cross default under the Indenture governing the 9 1/2%
Notes. Accordingly, the amounts outstanding under the 9 1/2% Notes have been
reclassified as current liabilities. See discussion, "Liquidity and Capital
Resources."

     Subsequent to year end, the Company refinanced the Chase Credit Facility
with the completion of the $30 million Foothill Credit Facility. The Company has
commenced discussions with the holders of the 9 1/2% Notes regarding alternative
solutions to its financial situation. The Company has commenced discussions with
the holders of the 9 1/2% Notes on alternative solutions to its financial
situation. There can be no assurance that discussions with these holders will
result in a satisfactory solution in respect of the 9 1/2% Notes or the holders
or trustee of the 9 1/2% Notes will not commence collection proceedings against
the Company. Whether or not a consensual resolution can be reached, it is likely
that the Company will need to seek protection under Chapter 11 of the United
States Bankruptcy Code.

     The liquidity issues faced by the Company are discussed in detail in the
"Liquidity and Capital Resources" section of this 10-K.


OVERVIEW

     The Company is the wholly owned principal operating subsidiary of the
Parent. The Parent is an Australian public company with ordinary shares listed
on the Australian Stock Exchange (symbol: PSA) and American Depositary Receipts
("ADRs") traded on the OTC Bulletin Board (symbol: PSJEY). The results discussed
in this report refer only to the Company. The Parent's results are filed with
the Securities and Exchange Commission separately under Forms 6-K (quarterly)
and 20-F (annually). Shareholders and ADR holders are advised to refer to these
filings.

     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 48 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. Effective January 1, 1999, the Company sold a 50%
working interest in 17 developed leases and 6 exploration leases to Apache
Corporation. In addition, Apache assumed operatorship of these assets. The $68.3
million sale was completed on February 1, 1999, reducing debt at that time to $9
million under the Chase Credit Facility and total debt, including the 9 1/2%
Notes and the subordinated shareholder loan, to $145.4 million.


                                                                              22
<PAGE>   23
     The Company is allocated stock compensation expense in respect to options
in the Parent which are granted to the Company's employees and certain
consultants. The Parent accounts for stock compensation according to 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 its operations. In addition, the Company has received
subordinated loans from the Parent to finance its operations. See discussion,
"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. Notwithstanding the recent increase in oil and gas
prices, a substantial or extended decline in 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 may be
economically produced.

     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,
                                                               ---------------------------------------
                                                                   1997          1998          1999
                                                               -----------   -----------   -----------

<S>                                                            <C>           <C>           <C>
Net production:
         Gas (MMcf)                                                 27,940        25,390         8,247
         Oil (MBbls)                                                 3,078         2,353           812
         Total (MMcfe)                                              46,408        39,511        13,119

Net sales data (in thousands):
         Gas                                                   $    64,770   $    54,171   $    18,430
         Oil                                                   $    60,369   $    37,846   $    12,570
         Total                                                 $   125,139   $    92,017   $    31,000

Average sales price (1):
         Gas (per Mcf)                                         $      2.32   $      2.13   $      2.23
         Oil (per Bbl)                                         $     19.61   $     16.08   $     15.48
         Total (per Mcfe)                                      $      2.70   $      2.33   $      2.36

Average costs (per Mcfe):
         Lease operating expenses                              $      0.25   $      0.38   $      0.54
         General, administrative and other expenses            $      0.13   $      0.20   $      0.40
</TABLE>


(1)      Includes effects of hedging activities.



                                                                              23

<PAGE>   24


RESULTS OF OPERATIONS


1999 COMPARED TO 1998

     General. The Company participated in ten wells during the year ended
December 31, 1999, of which two have been completed and brought into production,
six are awaiting installation of facilities and pipelines in order to commence
production, one was a dry hole and one was abandoned. Production in 1999 of 13.1
Bcfe was 67% less than 1998 (29% due to the asset sale to Apache, 38% due to
natural decline).

     Oil and Gas Revenues. Oil and gas revenues for 1999 were $31 million, a
decrease of $61.0 million, or 66% below 1998 revenues of $92 million. A 65%
decrease in oil production (34% related to the Apache asset sale, 31% due to
natural decline) coupled with a 4% decrease in oil prices combined to account
for $25 million of the decrease. A 68% decrease in gas production (27% related
to the asset sale to Apache, 41% due to natural decline) partially offset by a
5% increase in the gas price accounted for the remaining $36 million of the
decrease.

     The average realized gas price in 1999 was $2.23 per Mcf, or 7% above the
$2.09 per Mcf average gas price before hedging. In the same period, the average
realized oil price was $15.48 per Bbl, or 7% below the $16.57 per Bbl average
oil price before hedging. In 1998 the average realized gas price was $2.13 per
Mcf, or 2% above the $2.08 per Mcf price average gas price before hedging. In
the same period the average realized oil price was $16.08 per Bbl, or 20% above
the $13.36 per Bbl average oil price before hedging. Hedging activities
resulted in a $0.3 million increase in revenues for 1999 compared to a $7.7
million increase in 1998.

     Lease Operating Expenses (including production taxes). Lease operating
expenses in 1999 were $7.0 million, a decrease of $8.0 million, or 53%, from
$15.0 million in 1998. The decrease was attributable to the asset sale. Due to
lower production, the per unit rate increased from $0.38 per Mcfe in 1998 to
$0.54 per Mcfe in 1999.

     Depletion, Depreciation and Amortization ("DD&A"). DD&A expense decreased
$36.3 million, or 63%, from $57.6 million in 1998 to $21.3 million in 1999. The
decrease is due to lower production offset by an increase in the unit rate. The
average rate per unit increased from $1.46 to $1.62 per Mcfe due to Ryder Scott
Company, L.P., downward reserve revisions in the fourth quarter. The unit DD&A
rate increased to $1.83 per Mcfe in the fourth quarter compared to an average
rate of $1.56 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 in 1999 $2.8 million was expensed as
incurred for dry hole costs and abandonments, and $2.8 million was expensed for
seismic, geological and geophysical expenditures. In 1998 the comparative
expense was $27.5 million for dry hole costs and $7.4 million for seismic,
geological and geophysical expenditures.

     Impairments. A non-cash charge of $7.5 million reflecting an adjustment to
the carrying value of three of the Company's oil and gas properties was taken in
1999. 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
taken in 1998.

     General and Administrative Expense. General and administrative expense
decreased $2.6 million, or 33%, to $5.3 million in 1999 from $7.9 million in
1998. Contributing to this decrease are costs associated with staff downsizing
following the sale of a 50% working interest in certain properties to Apache. On
a per Mcfe basis the rate increased 100% from $0.20 to $0.40 due to decreased
production.


                                                                              24

<PAGE>   25
     Interest Expense. Interest expense in 1999 increased $1.8 million, or 15%,
to $13.5 million from $11.7 million in 1998 due to no capitalized interest in
1999.

     Net Loss. As a result of the conditions noted above, a net loss of $29.5
million was recorded for 1999, a decrease of $61.8 million over the loss of
$91.3 million for 1998.


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 were suspended pending further
evaluation at December 31, 1998, 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 before hedging. In the same period, the average
realized oil price was $16.08 per Bbl, or 20% above the $13.36 per Bbl average
oil price before hedging. In 1997 the average realized gas price was $2.32 per
Mcf, or 8% below the $2.53 per Mcf average gas price before hedging. In the same
period the average realized oil price was $19.61 per Bbl, or 3% above the $19.10
per Bbl average oil price before hedging. 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 Company, L.P., 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 taken in 1998. There were no impairments recorded in 1997.

     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


                                                                              25

<PAGE>   26

in severance charges 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.

     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.


LIQUIDITY AND CAPITAL RESOURCES

     In 1999, the Company experienced liquidity problems. On October 29, 1999,
in order to preserve available cash, the Company elected not to pay $3.2 million
due to the Banks under the Chase Credit Facility. This caused a default under
the Chase Credit Facility and a cross default under the Indenture. On January
18, 2000 the Company refinanced the Chase Credit Facility through a new $30
million revolving credit facility with Foothill. The Foothill Credit Facility
has lessened the severity of the Company's liquidity problem in the near term,
but the Company still has inadequate capital resources to service its debt and
meet anticipated capital requirements necessary to maintain and grow its
business. At March 22, 2000, the Company's borrowing base was $29.3 million.
After subtracting borrowings and letters of credit issued under the Foothill
Credit Facility to secure hedging obligations, the Company had $15.3 million
available for additional borrowing at March 22, 2000.

     As a consequence of the October 29, 1999 default on the Chase Credit
Facility, and the cross default under the Indenture, the Indenture trustee or
the holders of $25 million or more of the 9 1/2% Notes can elect to accelerate
the entire debt that is due to them, which is $100 million, and to commence
collection proceedings. The semi-annual interest payment under the Indenture in
the amount of $4.75 million that was due on December 15, 1999 was not paid, and
given the Company's current liquidity position and prohibitions in the Foothill
Credit Facility on the payment of interest due under the Indenture, it is
unlikely the Company will make this payment. The Company has commenced
discussions with the holders of the 9 1/2% Notes regarding alternative solutions
to its financial situation. There can be no assurance that discussions with
these holders will result in a satisfactory proposal in respect of the 9 1/2%
Notes, or the holders or trustee of the 9 1/2% Notes will not commence
collection proceedings against the Company. Whether or not a satisfactory
resolution can be reached, it is likely that the Company will need to seek
protection under Chapter 11 of the United States Bankruptcy Code.

     The Company would incur material non-recourse financial penalties under its
joint venture agreements if because of liquidity problems it were unable to
participate in operations proposed by its joint venture partners.


Cash Flow

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

<TABLE>
<CAPTION>
                                                                              Years Ended December 31,
                                                                      --------------------------------------
                                                                          1997          1998         1999
                                                                      ------------   ----------   ----------
                                                                                   (in thousands)
<S>                                                                   <C>            <C>          <C>
CASH FLOW DATA:

         Net cash provided by operating activities                    $    92,401    $   54,711   $   11,137
         Net cash (used in) provided by investing activities             (145,093)     (135,118)      57,871
         Net cash provided by (used in) financing activities               59,781        74,000      (66,125)
</TABLE>


                                                                              26

<PAGE>   27

     The decrease in cash provided by operating activities from 1998 to 1999 was
due to the sale to Apache of a 50% working interest in certain oil and gas
properties coupled with natural decline in production. The decrease in cash
provided by operating activities from 1997 to 1998 was due to lower oil and gas
production coupled with lower prices. Before changes in operating assets and
liabilities, cash flow from operations was $2.7 million in 1999, $51.4 million
in 1998 and $93.7 million in 1997.

     The cash provided by investing activities in 1999 was due to the receipt of
proceeds from the sale of a 50% working interest in certain assets to Apache. 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.

     The cash used in financing activities in 1999 reflects the proceeds from
the Apache sale being utilized to repay the Chase Credit Facility. In 1998, cash
provided by financing activities consisted entirely of borrowings under the
Chase Credit Facility. The cash provided by financing activities in 1997
consisted of proceeds from the 9 1/2% Note issue in June 1997 (described below)
a portion of which was used to repay outstanding borrowings under the Chase
Credit Facility.


Capital Expenditures and Commitments

     In response to changing market conditions and restricted capital
availability, in 1999 the Company took a more risk averse approach to its
exploration and development program resulting in a much lower capital budget
than previous years. During 1999, the Company signed participation agreements
over certain exploration leases with Coastal Oil & Gas USA., L.P. ("Coastal")
and LLOG Exploration Inc ("LLOG"). Under the terms of the participation
agreements the Company recovered $3.4 million in leasehold costs. In addition,
Coastal and LLOG were required to pay a disproportionate share of the drilling
costs of the initial test wells on the leases to earn their respective working
interests.

     During 1999, the Company spent $19 million in capital and exploration
expenditures. In the comparable periods in 1998 and 1997 the Company spent $125
million and $155 million, respectively. During the 1999 year, the Company was a
successful bidder on 4 leases at the Central and Western Gulf of Mexico federal
lease sales and paid $2.7 million for award of the leases. In addition the
Company was awarded a Texas State lease for $126,875 as successful bidder at the
State of Texas lease sale in October 1999.

     Given the uncertainties arising from the Company's negotiations with the
holders of the 9 1/2% Notes on the restructure of this debt, the Company has not
formulated a capital expenditure program for 2000. The Company does intend to
participate in certain exploration and development activities that it expects
its joint venture partners to propose during the year. However, if liquidity
problems restrict the Company from participating in operations proposed by its
joint venture partners, the Company would incur substantial non-recourse
penalties under its joint venture agreements. These penalties would not create
liabilities to the Company but would require the forfeiture of certain mineral
interests and of the revenues associated with those mineral interests until the
penalties were recouped by the joint venture partners.



Senior Secured Bank Loans

     In April 1996, the Company entered into the Chase Credit Facility. Under
the Chase Credit Facility, $3.2 million in principal was due on October 29,
1999. Of this amount, $2.075 million resulted from the required repayment of
principal with respect to a borrowing base redetermination on July 30, 1999, and
$1.125 million was a regularly scheduled quarterly installment payment. The
Company did not make the payment, which created a default under the Chase Credit
Facility.


                                                                              27


<PAGE>   28
     Subsequent to year end, the Company completed a refinancing of its Chase
Credit Facility with a $30 million revolving credit facility with Foothill.
Outstanding borrowings accrue interest at the prime rate plus a margin of 2.5%
per annum. The Company is also required to pay an unused line fee of 0.5% of the
unused line available for borrowing, a $10,000 per month service charge and
certain other fees and expenses. The Company has paid all interest that is
presently due. Borrowings under the Foothill Credit Facility were $10.9 million
at March 22, 2000.

     The Foothill Credit Facility is secured by a lien on all of the Company's
assets and contains financial covenants that require the Company to maintain the
sum of net income plus interest expense, plus income tax expense, plus
depreciation and amortization expense at no less than the following:

<TABLE>
<CAPTION>
                                  Period                                              Amount
------------------------------------------------------------------------           ------------
<S>                                                                                <C>
Three months ending March 31, 2000                                                 $  1,900,000

Six months ending June 30, 2000                                                    $  6,700,000

Nine months ending September 30, 2000                                              $ 12,000,000

Twelve months ending December 31 2000                                              $ 16,500,000
   and the twelve month period ending each March 31, June 30, September
   30 and December 31 thereafter
</TABLE>

     In addition, the Foothill Credit Facility limits the amount that the
Company can spend on capital expenditures and development expenditures. The
Company was in compliance with all financial covenants under the Foothill Credit
Facility at February 29, 2000.

     The Company's ability to borrow under the Foothill Credit Facility is
dependent upon the reserve value of its oil and gas properties, as determined
monthly by Foothill. If the reserve value of the Company's borrowing base
declines, the amount available to the Company under the Foothill 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 Foothill Credit
Facility, the Company will be obligated to repay such excess amount immediately
upon receipt of notice from Foothill. Additionally, Foothill also has broad
discretion to place reserves against the borrowing base. At March 22, 2000, the
Company's borrowing base was $29.3 million. After subtracting borrowings and
letters of credit issued under the Foothill Credit Facility to secure hedging
obligations, the Company had $15.3 million available for additional borrowing at
March 22, 2000.

Public Senior Subordinated Indebtedness

     In June 1997 the Company issued $100 million of 9 1/2% Notes. The principal
is due in a lump sum in June 2007. The 9 1/2% Notes were issued at a discount
with a yield to maturity of 9.56% per annum. Interest at the rate of 9.5% per
annum is payable semiannually on June 15 and December 15 of each year. 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 Chase
Credit Facility. The remainder 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.

     The Company engaged a financial advisor in October 1999 to assist with the
restructure of its 9 1/2% Notes due 2007. The Company did not make the interest
payment due on the 9 1/2% Notes at December 15, 1999, and is in default under
the Indenture governing the 9 1/2% Notes. The Company began discussions with a
subcommittee of holders of the 9 1/2% Notes on January 18, 2000 to restructure
the indebtedness due under the 9 1/2% Notes. While the Company is hopeful that a
solution acceptable to both the holders of the 9 1/2% Notes and the Company can
be reached, there can be no assurance that the Company will be able to reach
agreement on these proposals. Whether or not an acceptable agreement is reached,
it is likely that the Company will need to seek protection



                                                                              28

<PAGE>   29
under the United States Bankruptcy Code. The Company does not intend to make any
further public comments about the restructuring process until either agreement
on a solution is reached with the holders of the 9 1/2% Notes or it becomes
apparent that no such agreement can be reached.


Subordinate Loans from Parent

     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 the net proceeds from a U.S. offering of ADRs in July 1996.

     Funds advanced by the Parent historically have been provided substantially
in the form of subordinated loans denominated in Australian and US dollars.
These loans are subordinated to the payment of both the Foothill Credit Facility
and the 9 1/2% Notes. At December 31, 1999, the US dollar loans bear interest at
7.08% and in the case of Australian dollar borrowings, 6.48%. However the
Foothill Credit Facility currently restricts the payment of interest on the
subordinated loans to the Parent, and the biannual interest payment normally
paid in January was not paid in January 2000. The loans from the Parent do not
have mandatory principal payments due until December 31, 2007. Any payments or
distributions made by the Company to its Parent have been for reimbursement of
direct expenses incurred in connection with the Company's operations and
interest under the subordinated loans. The Parent has no commitments to make any
further advances to the Company.


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, 1999, hedging activities increased revenues
by $0.3 million. For the year ended December 31, 1998, hedging activities
increased revenues by $7.7 million. For the year ended December 31, 1997,
hedging activities reduced revenues by $4.4 million.



                                                                              29

<PAGE>   30

YEAR 2000

     As of the date of this report, the Company has not experienced any
significant disruptions in its operations during the transition into the Year
2000 ("Y2K"). In the third quarter of 1999, the Company announced that it had
completed its assessment of Y2K risks and that it had formulated contingency
plans to mitigate potential adverse effects which might have arisen from
noncompliant systems or third parties who had not adequately addressed the Y2K
issue. To date, the Company has not incurred any significant costs related to
Y2K issues. The Company will continue to monitor its operations and systems and
address any date-related problems that may arise as the year progresses.


NEW ACCOUNTING PRONOUNCEMENTS

     In June of 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities". Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains and losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000. The Company is assessing
the impact of adoption of Statement 133, and at the present time, has not
quantified the effect of adoption or continuing impact of such adoption.


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.


     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.


                                                                              30

<PAGE>   31

     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 Note 11 to the Financial Statements.



                                                                              31

<PAGE>   32


     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, 1999, the potential change in the fair value of commodity
derivative instruments assuming a 10 percent adverse movement in the underlying
commodity price is a $1.4 million increase in the deferred cost at December 31,
1999.

     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 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 for the Company's debt obligations at December
31, 1999:

<TABLE>
<CAPTION>
                                         2000           2001       2002       2003        2004     THEREAFTER    TOTAL    FAIR VALUE
                                       ---------     ---------   ---------  ---------   ---------  ----------  ---------  ----------
<S>                                    <C>           <C>         <C>        <C>          <C>       <C>         <C>        <C>
Long-term debt, including
 current maturities
    Variable rates - bank(1)             7,875          --          --          --          --          --       7,875       7,875
    Average interest  rates                8.2%         --          --          --          --          --         8.2%
    Variable rates - shareholder loan       --          --          --          --          --      37,330      37,330         N/A
    Average interest  rates                7.0%        7.0%        7.0%        7.0%        7.0%        7.0%        7.0%

    Fixed  rates(2)                    100,000          --          --          --          --          --     100,000      45,000
    Average interest  rates                9.5%         --          --          --          --          --         9.5%
</TABLE>


     If market interest rates average 1% higher or lower in 2000 than in 1999,
interest expense on variable rate debt would increase (decrease), and loss
before income taxes would increase (decrease) by approximately $0.5 million
based on the total variable rate debt outstanding at December 31, 1999.

(1) Amount subsequently refinanced - See Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations -"Liquidity and
Capital Resources."

(2) Amount contractually due in 2007, however, the 9 1/2 % Notes are in default
at December 31, 1999.- See Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations -"Liquidity and Capital
Resources."


              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.


                                                                              32

<PAGE>   33

      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                     52       Chairman of the Board and Chief Executive Officer and President

Maynard V. Smith                     49       General Manager--Exploration and Production

Ross A. Keogh                        40       Director, Vice-President--Chief Financial Officer and Treasurer

James E. Slatten  III                41       Director, Vice-President--Land and Legal and Secretary

John T. Bellatti                     42       Vice-President--Exploration and Chief Geophysicist

William R. Sack                      38       Vice-President--Exploration and Joint Ventures

Howard H. Wilson, Jr.                41       Vice-President--Operations
</TABLE>

     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.



                                                                              33

<PAGE>   34

     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 20
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.

     JAMES E. SLATTEN III who joined the Company in January 1998 is
Vice-President--Land and Legal. He has over 16 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.

     JOHN T. BELLATTI is Vice President--Exploration and Chief Geophysicist 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 Vice President--Exploration and Joint Ventures for 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.

     HOWARD H. WILSON, JR. has served as Vice President--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.




                        ITEM 11 - EXECUTIVE COMPENSATION



COMPENSATION OF EXECUTIVE OFFICERS

     The following table sets forth certain information for the three years
ended December 31, 1999 with respect 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.


                                                                              34

<PAGE>   35


                           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) ..........  1999             0         0                0                0                  0
  Chairman of the Board,         1998             0         0                0                0                  0
  Chief Executive Officer        1997             0         0                0                0                  0
  and President

Ross A. Keogh .................  1999       172,114    20,000                0          450,000                  0
  Director, Vice President,      1998       154,066         0                0                0                  0
  Chief Financial Officer        1997       134,500         0                0                0                  0
  and Treasurer

Howard H. Wilson, Jr...........  1999       171,736    14,000                0          375,000                  0
  Vice President--Operations     1998       165,078         0                0                0                  0
                                 1997       150,000    32,007                0                0                  0

John T. Bellatti...............  1999       157,733    23,500                0          450,000                  0
  Vice President--Exploration    1998       151,865         0                0                0                  0
  and Chief Geophysicist         1997       131,150    23,847                0                0                  0

William R. Sack................  1999       157,430    23,500                0          450,000                  0
  Vice President(Exploration     1998       151,593         0                0                0                  0
  and Joint Ventures             1997       131,150    23,717           28,334                0                  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 $298,000, $437,000 and $290,000 in 1999, 1998 and
     1997, respectively.
(2)  "Other Annual Compensation" includes payments to Mr. Sack of $28,334 for
     relocation costs.
(3)  Options issued are in respect of ordinary shares in the Parent.


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,
1999, all employees and directors of the Company, in the aggregate, owned
1,525,000 Ordinary Shares subject to the terms of this Plan.



                                                                              35
<PAGE>   36
     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, 1999, all directors and employees of the Company, in the
aggregate, held options to purchase an aggregate of 2,624,500 Ordinary Shares
pursuant to the Option Plan.


STOCK OPTION GRANTS AND EXERCISES

     The following table sets forth the stock options granted by the Parent to
the Named Executive Officers of the Company in 1999.

                OPTIONS GRANTED BY PARENT IN THE LAST FISCAL YEAR

<TABLE>
<CAPTION>
                                           % OF
                                          TOTAL
                           NUMBER OF     OPTIONS
                           ORDINARY     GRANTED TO                                         POTENTIAL REALIZABLE VALUE
                            SHARES      EMPLOYEES      EXERCISE                             AT ASSUMED ANNUAL RATES OF
                          UNDERLYING     IN 1999       OR BASE                              STOCK PRICE APPRECIATION
                            OPTIONS       FISCAL        PRICE            EXPIRATION         FOR OPTION TERM (1)(2)(3)
NAME                      GRANTED (#)      YEAR       ($/SH) (1)            DATE           0%        5%             10%
----                      -----------     ------      ----------       --------------      --        --             ---
<S>                         <C>            <C>         <C>             <C>                 <C>     <C>           <C>
Terrence N. Fern                 --
Ross A. Keogh               450,000        16.2%       A$0.41          April 18, 2004      --      A$49,500      A$540,000
Howard H. Wilson, Jr.       375,000        13.5%       A$0.41          April 18, 2004      --      A$41,250      A$450,000
John T. Bellatti            450,000        16.2%       A$0.41          April 18, 2004      --      A$49,500      A$540,000
William R. Sack             450,000        16.2%       A$0.41          April 18, 2004      --      A$49,500      A$540,000
</TABLE>

(1)  The exercise prices and the potential realizable value for the options are
     in Australian dollars ("A$"), being the currency of the ordinary shares
     subject to the options. The exchange rate on March 24, 2000 was
     US$0.6064=A$1.00, based on the noon buying rate in New York City for cable
     transfers in Australian dollars as certified for customs purposes by the
     Federal Reserve Bank of New York.

(2)  The 5% and 10% assumed annual rates of compounded stock price appreciation
     are mandated by rules of the Securities and Exchange Commission and do not
     represent the Company's estimate or projection of the Parent's future
     Ordinary Share prices. These amounts represent certain assumed rates of
     appreciation only. Actual gains, if any, on stock option exercises are
     dependent on the future performance of the Ordinary Shares and overall
     stock market conditions. The amounts reflected in this table may not
     necessarily be achieved.

(3)  The options in this table are subject to vesting periods of one, two or
     three year periods. Options with one year vesting are only exercisable if
     the market price of the Parent's ordinary shares is at least A$0.50, those
     options with two year vesting are only exercisable if the market price of
     the Parent's ordinary shares is at least A$0.60 and those with three year
     vesting are only exercisable if the market price of the Parent's ordinary
     shares is at least A$0.70. The potentially realizable values reflect the
     fact that the options have no value unless these targets are reached.


     The following table sets forth the aggregated option exercises by each of
the Named Executive Officers during the year ended December 31, 1999.



                                                                              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>               <C>              <C>                        <C>
Terrence N. Fern                   --            $     --              --/--                       --/--
Ross A. Keogh                      --            $     --              --/450,000                  --/--
Howard H. Wilson, Jr.              --            $     --              --/375,000                  --/--
John T. Bellatti                   --            $     --              --/450,000                  --/--
William R. Sack                    --            $     --              --/450,000                  --/--
</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 1999, 1998 or 1997.


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

     Effective May 1, 1999, John T. Bellatti, Ross A. Keogh, William R. Sack,
James E. Slatten, and Howard H. Wilson entered into new 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. In addition should these employees be terminated without cause or
certain material conditions of their employment be altered, they are entitled to
receive a severance benefit equal to between two and three years' base salary
due under their contracts net of any benefit received under the Petsec Energy
Inc. Year 2000 Severance Plan described below.

     Effective December 31, 1999 the Petsec Energy Inc. Year 2000 Severance Plan
was adopted whereby under certain conditions the employees of the Company are
entitled to receive a severance benefit if they are terminated without cause or
certain material conditions of their employment are altered prior to January 1,
2001. The severance benefit is an amount equal to base salary for three months
plus three weeks per year of service.



                                                                              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 a 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, 1999, the amount of Subordinated Shareholder Loan
outstanding was $37.3 million.

     One executive, Maynard Smith, owns 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.


                                     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, 1998, and 1999  ..................................................... 41
Statements of Operations and Retained Earnings (Deficit) for the years ended
  December 31, 1997, 1998 and 1999 .................................................................... 42
Statements of Cash Flows for the years ended December 31, 1997, 1998 and 1999 ......................... 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, 1999 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, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to report on
these financial statements based on the results of 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 report.

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

The accompanying financial statements have been prepared assuming that Petsec
Energy Inc. will continue as a going concern. As discussed in Note 3 to the
financial statements, the Company has suffered losses from operations and has
net capital deficiencies. During 1999, the Company defaulted on its $100 million
Senior Subordinated Notes due 2007 through the non-payment of interest
obligations. At December 31, 1999, these circumstances raise substantial doubt
about the entity's ability to continue as a going concern. Management's plans in
regard to these matters are also described in Note 3. The 1999 financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.

Because of the significance of the uncertainty discussed in the preceding
paragraph, we are unable to express, and we do not express, an opinion on the
accompanying 1999 financial statements.



                                                                       KPMG LLP


New Orleans, Louisiana
February 25, 2000


                                                                              40

<PAGE>   41

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

                                 BALANCE SHEETS
                  (Dollars in thousands, except share amounts)

<TABLE>
<CAPTION>
                                     ASSETS
                                                                          DECEMBER 31,
                                                                       1998           1999
                                                                   ------------   ------------
<S>                                                                <C>            <C>
Current Assets
   Cash                                                            $      1,024   $      3,907
   Accounts receivable                                                    8,279          3,980
   Other receivables                                                      4,626             31
   Inventories of crude oil                                                  45             45
   Prepaid expenses                                                         274          1,363
   Assets held for sale                                                  68,300             --
                                                                   ------------   ------------

            Total Current Assets                                         82,548          9,326
                                                                   ------------   ------------

Property, plant and equipment - at cost under the successful
   efforts method of accounting for oil and gas properties               99,802         81,587

Other Assets                                                              2,682          2,595
                                                                   ------------   ------------

            Total Assets                                           $    185,032   $     93,508
                                                                   ============   ============

                      LIABILITIES AND SHAREHOLDER'S DEFICIT

Current Liabilities:
   Trade accounts payable                                                 8,572          2,531
   Interest payable                                                       2,214          6,497
   Other accrued liabilities                                              3,381          8,011
   Bank credit facility                                                  67,250          7,875
   Senior Subordinated notes (due 2007, in default)                          --         99,684
                                                                   ------------   ------------

            Total Current Liabilities                                    81,417        124,598

Senior Subordinated notes                                                99,656             --
Bank credit facility                                                      6,750             --
Subordinated shareholder loan                                            36,792         37,330
Provision for dismantlement                                               2,488          2,893
                                                                   ------------   ------------

            Total Liabilities                                      $    227,103   $    164,821
                                                                   ------------   ------------

Shareholder's Deficit:
  Common stock, $1 par value; authorized 1,000,000 shares;
       issued and outstanding 1 share                                        --             --
  Additional paid-in-capital                                             21,572         21,818
  Accumulated deficit                                                   (63,643)       (93,131)
                                                                   ------------   ------------

            Total Shareholder's Deficit                                 (42,071)       (71,313)
                                                                   ------------   ------------

                                                                   $    185,032   $     93,508
                                                                   ============   ============
</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,

                                                                  1997           1998           1999
                                                              ------------   ------------   ------------

<S>                                                           <C>            <C>            <C>
Revenue:
   Oil and gas sales                                          $    125,139   $     92,017   $     31,000

Operating expenses:
   Lease operating expenses                                         10,825         14,379          6,808
   Production taxes                                                    702            610            237
   Exploration expenditures                                          7,328          7,427          2,750
   Dry hole costs and abandonments                                  10,454         27,503          2,840
   Impairments                                                          --         72,916          7,480
   General and administrative                                        6,054          7,868          5,287
   Stock compensation                                                  905            591            246
   Depletion, depreciation and amortization                         63,864         57,576         21,261
                                                              ------------   ------------   ------------

Total operating expenses                                           100,132        188,870         46,909
                                                              ------------   ------------   ------------

Income (loss) from operations                                       25,007        (96,853)       (15,909)

Other income (expenses):
   Interest expense                                                 (7,586)       (11,721)       (13,517)
   Interest income                                                     871            302            260
   Other, principally foreign exchange gain (loss)                   1,418            517           (322)
                                                              ------------   ------------   ------------

                                                                    (5,297)       (10,902)       (13,579)
                                                              ------------   ------------   ------------


Income (loss) before income taxes                                   19,710       (107,755)       (29,488)

Income taxes                                                        (6,610)        16,458             --
                                                              ------------   ------------   ------------

Net income (loss)                                                   13,100        (91,297)       (29,488)

Retained earnings (deficit) at beginning of period                  14,554         27,654        (63,643)
                                                              ------------   ------------   ------------

Retained earnings (deficit) at end of period                  $     27,654   $    (63,643)  $    (93,131)
                                                              ============   ============   ============
</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,

                                                                            1997           1998          1999
                                                                        ------------   ------------   ------------

<S>                                                                     <C>             <C>           <C>
Cash flows from operating activities:
Net income (loss)                                                       $     13,100   $    (91,297)  $    (29,488)
Adjustments to reconcile net income (loss) to net cash provided by
   operating activities:
   Depletion, depreciation and amortization                                   63,864         57,576         21,261
   Deferred income taxes                                                       6,610        (16,458)            --
   Dry hole costs and abandonments                                            10,454         27,503          2,840
   Impairments                                                                    --         72,916          7,480
   Other                                                                        (323)         1,112            570
   Changes in operating assets and liabilities:
      Decrease (increase) in receivables                                      (2,123)         5,699          4,299
      Decrease (increase) in inventories                                           2             (2)            --
      Increase in prepayments                                                    (90)           (16)        (1,089)
      Decrease (increase) in other receivables                                    21         (4,546)         4,595
      Increase (decrease) in trade accounts payable                           (1,494)           755         (3,588)
      Increase (decrease) in other accrued liabilities                           862            975            (26)
      Increase in interest payable                                             1,518            494          4,283
                                                                        ------------   ------------   ------------

            Net cash provided by operating activities                         92,401         54,711         11,137
                                                                        ------------   ------------   ------------

Cash flows from investing activities:
   Proceeds from sale of oil and gas properties                                   --             --         71,730
   Lease acquisitions                                                         (8,074)        (8,771)        (2,271)
   Exploration and development expenditures                                 (136,561)      (125,871)       (11,585)
   Other asset additions                                                        (458)          (476)            (3)
                                                                        ------------   ------------   ------------

            Net cash (used in) provided by investing activities             (145,093)      (135,118)        57,871
                                                                        ------------   ------------   ------------

Cash flows from financing activities:
   Proceeds from senior subordinated notes                                    96,446             --             --
   Proceeds from bank credit facility                                         21,000         74,000             --
   Repayment of bank credit facility                                         (58,000)            --        (66,125)
   Proceeds from shareholder loan                                              1,500             --             --
   Repayment of shareholder loan                                              (1,165)            --             --
                                                                        ------------   ------------   ------------

            Net cash provided by (used in) financing activities               59,781         74,000        (66,125)
                                                                        ------------   ------------   ------------

Net increase (decrease) in cash                                                7,089         (6,407)         2,883
Cash at beginning of period                                                      342          7,431          1,024
                                                                        ------------   ------------   ------------
Cash at end of period                                                   $      7,431   $      1,024   $      3,907
                                                                        ============   ============   ============
</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.


                                                                              44

<PAGE>   45

     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 associated with proved reserves. 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.

     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.




                                                                              45

<PAGE>   46

                               PETSEC ENERGY INC.
                    NOTES TO FINANCIAL STATEMENTS (CONTINUED)


     (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.

     In June of 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities". Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains and losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000. The Company is assessing
the impact of adoption of Statement 133, and at the present time, has not
quantified the effect of adoption or continuing impact of such adoption.

     (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 1999 financial statement presentation.


                                                                              46

<PAGE>   47

                               PETSEC ENERGY INC.
                    NOTES TO FINANCIAL STATEMENTS (CONTINUED)



2.   PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                                             1998          1999
                                                                        ------------   ------------
                                                                          (dollars in thousands)

<S>                                                                     <C>            <C>
Oil and gas properties:

         Proved                                                         $    156,265   $    163,398
         Unproved                                                             31,984         14,036
         Production facilities                                                43,321         44,483
                                                                        ------------   ------------
                                                                             231,570        221,917
             Other                                                             1,970          1,933
                                                                        ------------   ------------
                                                                             233,540        223,850
             Less accumulated depletion, depreciation and amortization      (133,738)      (142,263)
                                                                        ------------   ------------
                                                                        $     99,802   $     81,587
                                                                        ============   ============
</TABLE>

     The Company capitalized interest of $0.9 million, $3.5 million and $0 in
1997, 1998 and 1999, respectively, which is included in Property, Plant and
Equipment.

     The non-cash impairment charges of approximately $72.9 million and $7.5
million in 1998 and 1999, respectively, were 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. In 1999, downward reserve adjustments based on
well performance resulted in the asset impairment. The carrying values for
assets determined to be impaired were adjusted to estimated fair value based on
projected future discounted net cash flow for such assets. In 1998, the
continued low prices received for the sale of oil and natural gas, along with
the sale of certain assets (See Note 14) resulted in the asset impairment. The
carrying values for assets determined to be impaired were adjusted to estimated
fair value based on projected future discounted net cash flow for such assets
and the value for the sale of certain assets sold in February 1999. The Company
has exposure to future impairments if oil and gas prices deteriorate from
December 1999 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 1999, the Company experienced liquidity problems. The Company has
suffered losses from operations and has net capital deficiencies. In order to
preserve available cash, the Company did not make principal payments due October
29, 1999 in the amount of $3.2 million under the Chase Credit Facility. The
Company was in default under the Chase Credit Facility, and this default caused
a cross default under the Company's Indenture governing its $100 million 9 1/2%
notes due 2007.

     In January 2000, the Company refinanced its Chase Credit Facility with the
completion of a $30 million revolving credit facility with Foothill Capital
Corporation. Outstanding borrowings accrue interest at the prime rate plus a
margin of 2.5% per annum. The Company is also required to pay an unused line
fee of 0.5% of the unused line available for borrowing, and certain other fees
and expenses. The final maturity date of amounts due under the Foothill Credit
Facility is January 12, 2003. The Foothill Credit Facility is secured by a lien
on all the Company's assets and


                                                                              47

<PAGE>   48

contains financial covenants that require the Company to maintain an increasing
level of debt coverage over the next twelve months. In addition, the Foothill
Credit Facility limits the amount that the Company can spend on capital and
developmental operations.

     The Company's ability to borrow under the Foothill Credit Facility is
dependent upon the reserve value of its oil and gas properties, as determined
monthly by Foothill. If the reserve value of the Company's borrowing base
declines, the amount available to the Company under the Foothill 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 Foothill Credit
Facility, the Company will be obligated to repay such excess amount immediately
upon receipt of notice from Foothill. Additionally, Foothill also has broad
discretion to place reserves against the borrowing base.

     The Company engaged a financial advisor in October 1999 to assist with the
restructure of its $100 million 9 1/2% Senior Subordinated Notes due 2007. The
Company did not make the interest payment due on the 9 1/2% Notes at December
15, 1999, and is in default under the indenture governing the 9 1/2% Notes.
Accordingly, at December 31, 1999 the 9 1/2% Notes are classified as current
obligations. The Company began discussions with a subcommittee of holders of the
9 1/2% Notes on January 18, 2000 to restructure the indebtedness due under the
9 1/2% Notes. While the Company is hopeful that a solution acceptable to both
the holders of the 9 1/2% Notes and the Company can be reached, there can be no
assurance that the Company will be able to reach agreement on a solution.
Whether or not a consensual resolution is reached, it is likely that the Company
will need to seek protection under the United States Bankruptcy Code.

     The financial statements do not include any adjustments that might result
from the outcome of this uncertainty. At December 31, 1998 and 1999, the fair
value of the 9 1/2% Notes was $57 million and $45 million, respectively, based
on quoted market prices.



4.   SUBORDINATED SHAREHOLDER LOAN

     Petsec (U.S.A.) Inc. had advances outstanding to the Company of $36.8
million and $37.3 million at December 31, 1998 and 1999, respectively. A summary
(including foreign exchange gains and (losses)) of activity is as follows (in
thousands):

<TABLE>
<CAPTION>
                     Beginning                                        Ending
                      Balance       Additions    Reductions           Balance

<S>                   <C>           <C>          <C>                  <C>
          1997        57,954          1,500       (22,156)            37,298

          1998        37,298             --          (506)            36,792

          1999        36,792            538            --             37,330
</TABLE>


     The average balance outstanding for the years ended 1997, 1998 and 1999 was
$47.0 million, $37.0 million, and $37.1 million, respectively.


                                                                              48

<PAGE>   49


                               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 and 1999, the interest
rates were 6.83% and 7.08%, respectively, for the $29 million U.S. dollar loan
and 7.25% and 6.48%, respectively, for the equivalent US$7.8 million and US$8.3
million, respectively, 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. The Foothill Credit Facility discussed in Note 3
currently restricts the payment of interest on the advances from the Parent.
Accordingly, no such payments have been made since July 1999.


5.   SIGNIFICANT CUSTOMERS

     Customers which account for 10% or more of revenue for the years ended
December 31, 1997, 1998 and 1999 follow:

<TABLE>
<CAPTION>
                                                       1997       1998       1999
                                                       ----       ----       ----

<S>                                                    <C>         <C>       <C>
         Vision Resources, Inc.                         46%        30%         *
         Duke Energy Trading & Marketing, L.L.C         22%        19%         *
         P G & E Energy Trading Corporation             16%         *         --
         Natural Gas Clearinghouse                      12%        --         --
         Enron North America Corp.**                     *         36%        49%
</TABLE>

*    less than 10%

**   formerly Columbia Energy Services Corporation

     In 1999, the Company's joint venture partner, Apache Corporation, marketed
the Company's oil to various purchasers which accounted for 36% of the revenue
in 1999.

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

     The Company is allocated stock compensation expense in respect to the
options in the Parent which are granted to the Company's employees and certain
consultants. The Parent 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


                                                                              49

<PAGE>   50

                               PETSEC ENERGY INC.
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

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 1997 were 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, and 2.4 to 4.5 years (weighted average 3.4 years); 37%; 0;
and 5.3%, respectively, in 1998. All employee options were cancelled in April
1999 and new employee options were issued. The expected life, volatility,
dividend yield and risk-free interest rates used in determining the fair value
of the new options granted in April 1999 were 1.5 to 3.5 years (weighted average
2.5 years); 76%; 0; and 5% respectively, in 1999.


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 $6.6 million expense, $16.5 million
benefit and $0 for the years ended December 31, 1997, 1998, and 1999,
respectively, and differed from the amounts computed by applying the U.S.
federal income tax rate of 34% to income (loss) before income taxes as a result
of the following:

<TABLE>
<CAPTION>
                                                                     1997         1998          1999
                                                                  ----------   ----------   ----------
                                                                         (dollars in thousands)

<S>                                                               <C>          <C>          <C>
Computed "expected" tax expense (benefit)                         $    6,701   $  (36,637)  $  (10,026)
Increase (reduction) in income taxes resulting from:
         Items not deductible for tax                                     30          481          448
         State income tax expense (benefit)                              368       (1,934)        (564)
         Other                                                          (489)          --           --
         Change in the balance of the valuation allowance for
             deferred tax assets allocated to income tax expense         --        21,632       10,142
                                                                  ----------   ----------   ----------
                                                                  $    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,
1998 and 1999 are presented below.

<TABLE>
<CAPTION>
                                                                                 1998         1999
                                                                              ----------   ----------
                                                                              (dollars in thousands)

<S>                                                                           <C>          <C>
Deferred tax assets:
          Financial provisions not currently deductible for tax purposes      $      851   $      585
          Net operating loss carryforwards                                        32,045       33,876
                                                                              ----------   ----------
             Total gross deferred tax assets                                      32,896       34,461
          Less valuation allowance                                               (21,632)     (31,774)
                                                                              ----------   ----------
             Net deferred tax assets                                          $   11,264   $    2,687

Deferred tax liabilities:
          Differences in depreciation and depletion of oil and gas assets        (11,264)      (2,687)
                                                                              ----------   ----------
             Net deferred tax liabilities                                     $       --   $       --
                                                                              ==========   ==========
</TABLE>


                                                                              50
<PAGE>   51

                               PETSEC ENERGY INC.
                    NOTES TO FINANCIAL STATEMENTS (CONTINUED)

     The net change in the valuation allowance for the years ended December 31,
1998 and 1999, was an increase of $21.6 million and $10.1 million, respectively.
The increases were provided due to the 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, 1999, the Company has net operating loss carryforwards for
federal and state income tax purposes of $94.1 million which are available to
offset future taxable income, if any, from 2005 through 2019.


8.   RELATED PARTY TRANSACTIONS

     The Parent 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.

     For the years ended December 31, 1997, 1998 and 1999, Petsec Energy Inc.
paid amounts of $540,000, $325,000 and $416,000, respectively, 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, 1999, applicable to
noncancelable operating leases, are summarized as follows (in thousands):

<TABLE>
<CAPTION>
          Year               Amount
          ----               ------
<S>                          <C>
          2000               $   90
                             ======
</TABLE>


     Rent expense for the years ended December 31, 1997, 1998 and 1999 was
$264,000, $281,000 and $268,000, respectively.

     The Company has entered into a seismic data purchase agreement through
November 2004 covering 100 lease blocks in the Outer Continental Shelf of the
Gulf of Mexico, which provides for payments of overriding interests to the
seismic provider on three of the Company's unproved leases and on wells drilled
on leases acquired as a result of the seismic data. The Company is committed to
a minimum payment of $1.6 million.

                                                                              51

<PAGE>   52


                               PETSEC ENERGY INC.
                    NOTES TO FINANCIAL STATEMENTS (CONTINUED)

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)                        591
                                     ------------

Balance at December 31, 1998         $     21,572

Stock Options (Note 6)                        246
                                     ------------

Balance at December 31, 1999         $     21,818
                                     ============
</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, 1999, the Company had contracts maturing monthly
through May 2000 on the net sale of 152,000 barrels of oil at an average price
of $19.70 per barrel and on the net sale of 4.6 million MMbtu of gas at an
average price of $2.29 per MMbtu.

     The effect to the Company to terminate these contracts at December 31, 1999
is estimated to be a loss of $0.8 million for oil and $0.5 million for gas.

     For the years ended December 31, 1997, 1998 and 1999 hedging activities
reduced revenues by $4.4 million, and increased revenues by $7.7 million and
$0.3 million, respectively.


12.  SUPPLEMENTAL CASH FLOW INFORMATION

     Cash paid for interest was $6.8 million, $10.9 million and $8.9 million for
the years ended December 31, 1997, 1998 and 1999, respectively. See Note 3. The
Company has not paid any cash for income taxes in these years.




                                                                              52

<PAGE>   53

                               PETSEC ENERGY INC.
                    NOTES TO FINANCIAL STATEMENTS (CONTINUED)


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.  SALE OF WORKING INTEREST

     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. Revenues in 1998 attributed to the 50% working interest that was
sold were $41 million.


                                                                              53

<PAGE>   54

                               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, 1997,
1998 and 1999 were based on studies performed by Ryder Scott Company, L.P.

     No major discovery or other favorable or adverse event subsequent to
December 31, 1999 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.


                                                                              54
<PAGE>   55

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


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, L.P:

<TABLE>
<CAPTION>
                                                                    Crude Oil    Natural Gas
                                                                      (MBbl)       (MMcf)

<S>                                                                 <C>          <C>
Proved developed and undeveloped reserves:
         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                         (52)     (12,974)
                  Extensions, discoveries and other additions           1,168        4,738
                  Sales of reserves in place*                          (4,067)     (31,711)
                  Purchase of reserves in place                            --        1,440
                  Production                                           (2,353)     (25,390)
                                                                   ----------   ----------
         December 31, 1998                                              5,337       58,252
                  Revisions of previous estimates                        (432)      (7,384)
                  Extensions, discoveries and other additions             376       14,162
                  Production                                             (812)      (8,247)
                                                                   ----------   ----------
         December 31, 1999                                              4,469       56,783
                                                                   ==========   ==========
</TABLE>

<TABLE>
<CAPTION>
                                                                    Crude Oil    Natural Gas
                                                                      (MBbl)       (MMcf)

<S>                                                                 <C>          <C>

Proved developed reserves:
         December 31, 1997                                              8,430       88,199
         December 31, 1998                                              3,054       26,965
         December 31, 1999                                              2,090       21,950
</TABLE>


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

     Approximately 59% of the Company's total proved reserves at December 31,
1999 were undeveloped. Recovery of such reserves will require significant
capital expenditures and successful drilling operations. The Company's financial
resources are limited, and there can be no assurance that additional debt or
equity financing or cash generated by operations will be available to meet these
requirements. The Company's revolving credit facility has a borrowing base that
is determined by the value of its oil and gas properties reviewed monthly by the
creditor. The creditor has substantial discretion to place reserves against the
borrowing base. See Note 3 for additional explanation regarding the Company's
liquidity problems.


                                                                              55

<PAGE>   56

                               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,
                                                          1997           1998         1999
                                                                   (in thousands)

<S>                                                   <C>           <C>           <C>
Proved properties                                     $   294,005   $   199,586   $   207,881
Unproved properties                                        20,759        31,984        14,036
                                                      -----------   -----------   -----------
                                                          314,764       231,570       221,917
Accumulated depreciation, depletion and amortization     (106,392)     (132,739)     (140,930)
                                                      -----------   -----------   -----------
         Net capitalized costs                        $   208,372   $    98,831   $    80,987
                                                      ===========   ===========   ===========
</TABLE>


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


<TABLE>
<CAPTION>
                                                               Years Ended December 31,
                                                          1997           1998          1999
                                                                   (in thousands)

<S>                                                   <C>           <C>           <C>
Lease acquisition                                     $     8,437   $     7,836   $     2,610
Exploration                                               115,523       107,111        14,745
Development                                                31,327        10,301         1,216
                                                      -----------   -----------   -----------
      Total costs incurred                            $   155,287   $   125,248   $    18,571
                                                      ===========   ===========   ===========
</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,
L.P. 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.


                                                                              56

<PAGE>   57

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

     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, 1999, approximately 4.6 million
MMbtu of the Company's future gas production and 152,000 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
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 interest 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,
                                                                 1997           1998           1999
                                                                          (in thousands)

<S>                                                         <C>            <C>            <C>
Future cash inflows                                         $    472,470   $    183,371   $    252,284
      Future production costs                                   (101,765)       (55,456)       (46,752)
      Future development and abandonment costs                   (53,851)       (44,783)       (54,704)
      Future income tax expense                                  (64,064)            --             --
                                                            ------------   ------------   ------------
Future net cash flows after income taxes                         252,790         83,132        150,828
10% annual discount for estimated timing of cash flows           (48,676)       (16,079)       (37,689)
                                                            ------------   ------------   ------------
Standardized measure of discounted future net cash flows    $    204,114   $     67,053   $    113,139
                                                            ============   ============   ============
</TABLE>


                                                                              57

<PAGE>   58


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


     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,
                                                              ---------------------------------------
                                                                   1997          1998         1999
                                                                            (in thousands)

<S>                                                           <C>           <C>           <C>
Beginning of the period                                       $   223,381   $   204,114   $    67,053
                                                              -----------   -----------   -----------
Sales and transfers of oil and gas produced, net of              (113,462)      (77,028)      (23,955)
   production costs
Net changes in prices and production costs                       (142,243)      (86,433)       71,653
Extensions, discoveries and improved recoveries, net of           134,467        13,422        30,284
   future production costs
Net changes due to revisions in quantity estimates                 40,994       (21,677)      (18,204)
Development costs incurred during the period                        1,050         2,251           160
Sales of reserves in place*                                            --       (57,164)           --
Purchase of reserves in place                                          --         1,646            --
Change in estimated future development costs                       (5,674)        5,499        (7,562)
Accretion of discount                                              32,481        30,749         6,705
Change in timing of production                                         --            --       (12,995)
Net change in income taxes                                         33,120        51,674            --
                                                              -----------   -----------   -----------
Net increase (decrease)                                           (19,267)     (137,061)       46,086
                                                              -----------   -----------   -----------
End of period                                                 $   204,114   $    67,053   $   113,139
                                                              ===========   ===========   ===========
</TABLE>


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

     The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1999 was based on
average natural gas prices of approximately $2.43 per mcf and on average crude
oil prices of approximately $25.61 per barrel, before hedging effects.


(b)  REPORTS ON FORM 8-K

     No current reports on Form 8-K were filed during the Company's fourth
quarter 1999.


                                                                              58

<PAGE>   59


(c)  EXHIBITS


<TABLE>
<CAPTION>
   Exhibit No.                           Exhibit
  -----------                            -------

<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)

     10.2*     Amended and Restated Loan and Security Agreement by and between
               Petsec Energy Inc., as Borrower, and The Financial Institutions
               Named Therein, as lenders, and Foothill Capital Corporation, as
               Agent, dated as of January 12, 2000

     10.3*     Executive Employment Agreement by and between Petsec Energy Inc.
               and John T. Bellatti dated as of May 1, 1999

     10.4*     Executive Employment Agreement by and between Petsec Energy Inc.
               and Ross A. Keogh dated as of May 1, 1999

     10.5*     Executive Employment Agreement by and between Petsec Energy Inc.
               and William R. Sack dated as of May 1, 1999

     10.6*     Executive Employment Agreement by and between Petsec Energy Inc.
               and James E. Slatten III dated as of May 1, 1999

     10.7*     Executive Employment Agreement by and between Petsec Energy Inc.
               and Howard H. Wilson, Jr. dated as of May 1, 1999

     10.8*     Letter Agreement by and between Petsec Energy Inc. and Gordian
               Group, L.P. dated October 15, 1999

     10.9*     Letter Agreement by and between Petsec Energy Inc. and Houlihan
               Lokey Howard & Zukin Capital, L.P. dated as of February 15, 2000

     10.10*    Petsec Energy Inc. Year 2000 Severance Plan dated as of December
               31, 1999

     23.1*     Consent of Ryder Scott Company

     27*       Financial Data Schedule
</TABLE>

     *         Filed herewith

<PAGE>   60

<TABLE>
<S>            <C>
     10.10*    Petsec Energy Inc. Year 2000 Severance Plan dated as of December
               31, 1999

     23.1*     Consent of Ryder Scott Company

     27*       Financial Data Schedule
</TABLE>

     *         Filed herewith




                                                                              60
<PAGE>   61


                                   SIGNATURES


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

                                         Petsec Energy Inc.



Date:  March 30, 2000                    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                    March 30, 2000
---------------------------------------             (Principal Executive Officer)
          Terrence N. Fern


       /s/ Ross A. Keogh                            Director, Vice-President -- Chief Financial Officer     March 30, 2000
---------------------------------------             and Treasurer (Principal Financial and
          Ross A. Keogh                             Accounting Officer)


     /s/ James E. Slatten III                       Director, Vice-President -- Land and Legal              March 30, 2000
---------------------------------------             and Secretary
       James E. Slatten III
</TABLE>


                                                                              61

<PAGE>   62

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
    EXHIBIT
    NUMBER                            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)

     10.2*     Amended and Restated Loan and Security Agreement by and between
               Petsec Energy Inc., as Borrower, and The Financial Institutions
               Named Therein, as lenders, and Foothill Capital Corporation, as
               Agent, dated as of January 12, 2000

     10.3*     Executive Employment Agreement by and between Petsec Energy Inc.
               and John T. Bellatti dated as of May 1, 1999

     10.4*     Executive Employment Agreement by and between Petsec Energy Inc.
               and Ross A. Keogh dated as of May 1, 1999

     10.5*     Executive Employment Agreement by and between Petsec Energy Inc.
               and William R. Sack dated as of May 1, 1999

     10.6*     Executive Employment Agreement by and between Petsec Energy Inc.
               and James E. Slatten III dated as of May 1, 1999

     10.7*     Executive Employment Agreement by and between Petsec Energy Inc.
               and Howard H. Wilson, Jr. dated as of May 1, 1999

     10.8*     Letter Agreement by and between Petsec Energy Inc. and Gordian
               Group, L.P. dated October 15, 1999

     10.9*     Letter Agreement by and between Petsec Energy Inc. and Houlihan
               Lokey Howard & Zukin Capital, L.P. dated as of February 15, 2000

     10.10*    Petsec Energy Inc. Year 2000 Severance Plan dated as of December
               31, 1999

     23.1*     Consent of Ryder Scott Company

     27*       Financial Data Schedule
</TABLE>

     *         Filed herewith