<PAGE>   1

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

                                   FORM 20-F
(Mark One)
[   ]      REGISTRATION STATEMENT PURSUANT TO SECTION
           12(B) OR (G) OF THE SECURITIES EXCHANGE ACT OF 1934

                                    OR

[ X ]      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
           THE SECURITIES EXCHANGE ACT OF 1934
              For the twelve months ended December 31, 1999

[   ]     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
          OF SECURITIES EXCHANGE ACT OF 1934
   For the transition period from...................to......................

                         Commission file number 0-28608

                               PETSEC ENERGY LTD
             (Exact name of Registrant as specified in its charter)

                           NEW SOUTH WALES, AUSTRALIA
                (Jurisdiction of incorporation or organization)

             LEVEL 13, 1 ALFRED STREET, SYDNEY, NSW 1225, AUSTRALIA
                    (Address of principal executive offices)

 Securities registered or to be registered pursuant to Section 12(b) of the Act.
        Title of each                                Name of each exchange
            class                                      on which registered
            None                                             None

 Securities registered or to be registered pursuant to Section 12(g) of the Act.

                           American Depositary Shares

     Securities for which there is a reporting obligation pursuant to
     Section 15(d) of the Act.
                                      None

   Indicate the number of outstanding shares of each of the issuer's classes
           of capital or common stock as of the close of the period
                         covered by the annual report.

                          107,401,041 Ordinary Shares

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           No

Indicate by check mark which financial statement item the registrant has
elected to follow.

                   Item 17                     Item 18
<PAGE>   2
                               TABLE OF CONTENTS
<TABLE>
<CAPTION>
                                                                                        Page
<S>                                                                                  <C>
Introduction.........................................................................     3
Glossary of Certain Industry Terms...................................................   4 - 5


                                     PART I

Item 1.   Description of Business....................................................   6 - 18
Item 2.   Description of Properties..................................................     18
Item 3.   Legal Proceedings..........................................................     19
Item 4.   Control of Registrant......................................................     19
Item 5.   Nature of Trading Market...................................................   20 - 21
Item 6.   Exchange Controls and Other Limitations Affecting Security Holders.........   21 - 22
Item 7.   Taxation...................................................................   22 - 23
Item 8.   Selected Financial Data....................................................   23 - 25
Item 9.   Management's Discussion and Analysis of Financial Condition and
            Results of Operations....................................................   25 - 33
Item 9A.  Quantitative and Qualitative Disclosure about Market Risk..................   33 - 34
Item 10.  Directors and Officers of Registrant.......................................   34 - 35
Item 11.  Compensation of Directors and Officers.....................................   36 - 37
Item 12.  Options to Purchase Securities from Registrant or Subsidiaries.............   36 - 37
Item 13.  Interest of Management in Certain Transactions.............................   36 - 37


                             PART II

Item 14.  Description of Securities to be Registered.................................     37


                             PART III

Item 15.  Defaults Upon Senior Securities............................................     37
Item 16.  Changes in Securities......................................................     37


                             PART IV

Item 17.  Financial Statements.......................................................     37
Item 18.  Financial Statements.......................................................     37

Signatures...........................................................................     38

Item 19.  Financial Statements.......................................................  F1 - F24
</TABLE>


                                       2
<PAGE>   3
                                     PART I

                                  INTRODUCTION

Unless the context otherwise indicates, references in this Form 20-F to
"Petsec" or the "Company" are to Petsec Energy Ltd, an Australian public
company (Australian Company Number 000 602 700), and its majority-owned
subsidiaries and entities in which it owns at least a 50% ownership interest.
The reference "PEL" is used to refer to Petsec Energy Ltd, the Australian
public company, separately from its subsidiaries. The Company publishes
consolidated financial statements in Australian dollars as required under
Australian law and under Australian generally accepted accounting principles
("Australian GAAP"). It also publishes consolidated financial statements in US
dollars and under US generally accepted accounting principles ("US GAAP") as
set out under Item 18 in this Form 20-F. All financial information in this Form
20-F is based on US GAAP.

As used herein the term "fiscal" prior to a calendar year means the Company's
fiscal year ended June 30 of such year until June 30, 1996 and the Company's
fiscal years ended December 31, 1997, 1998 and 1999. The Company's fiscal year
end changed in 1996 from June 30 to December 31 and this report covers the
fiscal years ended December 31, 1997, 1998 and 1999.

References to "US dollars" or "US$" or "$" are to United States dollars and
references to "A$" are to Australian dollars.




                                       3

<PAGE>   4
                       GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below apply to the indicated terms as used in this
Form 20-F. 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 of gas 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.

           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%.

                                       4
<PAGE>   5
           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.

           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.

                                       5
<PAGE>   6
                                     PART I

                        ITEM 1 - DESCRIPTION OF BUSINESS
GENERAL

           Petsec Energy Ltd is an independent oil and gas exploration and
production company operating in the shallow waters of the Gulf of Mexico,
U.S.A. It is an Australian public company with ordinary shares traded on the
Australian Stock Exchange (symbol: PSA), and American Depositary Receipts
("ADRs") traded on the OTC Bulletin Board (symbol: PSJEY.OB). In 1990, the
Company incorporated Petsec Energy Inc. ("PEI"), its wholly owned subsidiary,
and commenced evaluating oil and gas exploration opportunities in the United
States, initially in the Paradox Basin in Colorado, and 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.

           As of December 31, 1999, the Company's estimated net proved reserves
were 83.6 Bcfe (approximately 68% of which were attributable to natural gas),
with a PV10 of approximately $113.1 million.

           At December 31, 1999, the Company held working interests in 48
leases on the OCS. Effective April 11, 2000, the Company sold its working
interest in 7 leases to an unrelated third party purchaser. Subsequently, one
lease on the OCS was depleted and has terminated. The Company presently owns
working interests in 40 OCS leases. All of the Company's reserves and leases
are held in PEI.


BUSINESS  HISTORY

The Company has acquired substantially all of its 40 leases on the OCS at
federal or state lease sales, of which 21 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 PEI's outstanding debt to reach unacceptable levels. Effective January
1, 1999, PEI 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.

      PEI 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"). PEI 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"). PEI began discussions with a subcommittee of
holders of the 9 1/2% Notes on January 18, 2000 regarding alternative solutions
to its financial situation.

      PEI subsequently filed a voluntary petition under Chapter 11 of the US
Bankruptcy Code (the "Bankruptcy Code") on April 13, 2000 in the United States
Bankruptcy Court for the Western District of Louisiana, Opelousas Division (the
"Bankruptcy Court"). On June 16, 2000, an agreement was reached with PEI's
creditors to sell PEI or all of its assets. PEI anticipates filing a Plan of
Reorganization which contemplates an agreed distribution of the sale proceeds
to PEI's creditors, the Company, as equity owner, and certain of PEI's senior
management team in the USA. The financial statements do not include any
adjustments which might result from the filing of the petition or the agreement
that was subsequently reached. Details of the agreement are described in the
6-K current report filed by the Company with the Securities and Exchange
Commission (the "SEC") on June 19, 2000. See "Item 9 -- Management's Discussion
and Analysis of Financial Condition and Results of Operations; Risk Factors --
Liquidity Problems."

           PEL owned 31,173,935 shares (30.6%) of the outstanding ordinary
shares in Climax Mining Ltd, an Australian public company whose stock is traded
on the Australian Stock Exchange. In November 1999 the Company sold its holding
in Climax Mining Ltd shares to eligible Petsec's shareholders by way of a
pro-rata entitlement offer. The distribution completed the separation of the
two companies.

                                       6
<PAGE>   7
LIKELY DEVELOPMENTS

           As a result of the agreement with PEI's creditors, the structure and
extent of the Company's operations will change. PEI or all of its assets will
be put up for sale. Other than PEI, PEL's primary asset is cash in the
approximate amount of $16.0 million as of June 27, 2000. The future direction
of PEL is undecided. PEL may seek exploration and production opportunities
outside of the Gulf of Mexico, and investments in industries other than energy.
The Company's Board of Directors expects to decide on the Company's future
direction after the PEI sale process is completed.


OIL AND GAS RESERVES

           The following table sets forth estimated net proved oil and gas
reserves of the Company, (all of which is held in PEI) 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 relating to estimated net proved oil and gas
reserves and the estimated future net cash flows attributable thereto is based
upon reports by Ryder Scott Company L.P., Petroleum Consultants. All
calculations of estimated net proved reserves have been made in accordance with
the rules and regulations of the SEC, 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:
     Oil (MBbls)                                                10,641           5,337            4,469
     Gas (MMcf)                                                122,149          58,252           56,783
     Total (MMcfe)                                             185,995          90,274           83,597

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

Estimated future net revenues before income  taxes
   (in thousands)                                             $316,855         $83,132         $150,828
Present value of estimated future net revenues before
   income taxes(in thousands) (1)                             $255,839         $67,053         $113,139
Standardized measure of discounted future net cash flows
   (in thousands) (2) (3)                                     $204,114         $67,053         $113,139
Average prices used in calculating the net
present  values:

Oil ($ per Bbl)                                                 $17.00          $11.98           $25.61
Gas ($ per Mcf)                                                  $2.39           $2.04           $ 2.43
</TABLE>

(1)   The present value of estimated future net revenues attributable to the
      Company's reserves was prepared using constant prices, including the
      effects of hedging as of the calculation date, discounted at 10% per
      annum on a pre-tax basis. These prices have varied significantly from
      year to year, affecting the net present values, and are not necessarily
      representative of current prices.

(2)   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.

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

                                       7
<PAGE>   8
           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 in the Gulf of Mexico
during the period indicated. This table does not include costs incurred in
other areas in the United States or in Australia.

                                       FISCAL YEARS ENDED DECEMBER 31,
                                       -------------------------------
                                    1997             1998            1999
                                    ----             ----            ----

  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
                                  ========        ========         =======

           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. (All wells and acreage are owned by PEI.)


                                             GROSS                 NET
                                             -----                 ---
  Productive wells (1):
  Oil                                           17                   8.5
  Gas                                           37                  19.5
                                           -------               -------

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

  Developed Acreage (1)                     51,823                28,412
  Undeveloped Acreage (1) (2)              103,971                71,926
                                           -------               -------

  Total                                    155,794               100,338
                                           =======               =======

(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)     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.

                                       8
<PAGE>   9
           Drilling activity. The following table sets forth the Company's
drilling activity for the periods indicated, all of which was conducted by PEI.

<TABLE>
<CAPTION>
                                                   Fiscal 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 that affect the market in the U.S.,
for oil and gas, including the extent of domestic production and imports of oil
and gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and gas, the marketing of competitive
fuels and the effects of state and federal regulations on 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 9 -
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. U.S. 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.


PRODUCTION SALES CONTRACTS

           The Company markets substantially all of the oil and gas production
from its properties. Oil and gas production from one lease operated by LLOG
Exploration Offshore, Inc. is marketed on PEI's behalf by the operator. 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
with PEI. Natural gas sales contracts are based upon field posted prices plus
negotiated bonuses, except for natural gas sold pursuant to fixed price
contracts for hedging purposes. See "Item 9-- Management's Discussion and
Analysis of Financial Condition and Results of Operations - Hedging
Transactions." In 1999, Apache Corporation marketed all of the Company's oil
production through marketing arrangements it had 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 with PEI,
that provided for monthly market pricing adjustments. The Enron contract was
extended on April 1, 2000 for another year. Effective April 1, 2000 the Company
commenced marketing its oil production with GulfMark Energy, Inc. 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.

                                       9
<PAGE>   10



           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 PEI.
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. If after PEI is
sold, the Company decides to remain in this industry, it will compete 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.


REGULATION

           The U.S. domestic oil and gas industry is extensively regulated by
United States 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 are under constant review
for amendment and expansion for 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 or 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

                                      10
<PAGE>   11
valuation of production for this purpose, and removal of facilities. To cover
the various obligations of lessees on the OCS, the MMS generally requires that
lessees post substantial bonds or other acceptable assurances that such
obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be
obtained in all cases. Under certain circumstances, the MMS may require Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations.

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

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

           Several major regulatory changes have been implemented by the FERC
from 1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
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 PEI, 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 PEI 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 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 PEI will be affected by any
action taken materially differently than other natural gas producers and
marketers with which it competes.

                                      11
<PAGE>   12
           The FERC has issued numerous orders approving the spin-down or
spin-off by interstate pipelines of their gathering facilities. A "spin-off" is
a FERC-approved sale of gathering facilities to a non-affiliate. A "spin-down"
is a transfer of gathering facilities to an affiliate. These approvals were
given despite the strong protests of a number of producers concerned that any
diminution in FERC's oversight of interstate pipeline-related gathering
services might result in the 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 new
gathering policy will have on producers such as PEI 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 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 PEI's operations.

           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 PEI competes.

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

           Environmental regulation. Activities of the Company with respect to
the exploration, development and production of oil and natural gas are subject
to stringent environmental regulation by state and federal authorities
including the EPA. Such regulation has increased the cost of planning,
designing, drilling, operating and in some instances, abandoning wells. In most
instances, the regulatory requirements relate to the handling and disposal of
drilling and production waste products and waste created by water and air
pollution control procedures. Although the Company believes that compliance
with environmental regulations will not have a material adverse effect on
operations or earnings, the risks of substantial costs and liabilities are
inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including criminal penalties, will not be
incurred. Moreover, it is possible that other developments, such as stricter
environmental laws and regulations, and claims for damages to property or
person resulting from the Company's operations could result in substantial
costs and liabilities.

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

           The Company generates wastes, including hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The EPA and various state agencies have limited the
disposal options for certain hazardous and non-hazardous 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

                                      12
<PAGE>   13
released on or under the properties owned or leased by the Company or on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
the Company's control. These properties and the wastes disposed thereon may be
subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company
could be required to remove or remediate previously disposed wastes (including
wastes disposed of or released by prior owners or operators) or property
contamination (including groundwater contamination) or to perform remedial
plugging operations to prevent future contamination.

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

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

                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

                                      13
<PAGE>   14
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, explosion, 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.

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

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


EMPLOYEES

           As of June 27, 2000, the Company had 27 full-time staff, primarily
professionals, including geologists, geophysicists and engineers, with 23 of
the staff in Lafayette, Louisiana, U.S.A. and 4 in Australia. 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 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

           In late 1999, PEI experienced tight liquidity conditions and engaged
a financial advisor. As of December 31, 1999, PEI'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. Of this amount,
$107.6 was delinquent December 31, 1999.

           On April 13, 2000, PEI filed a voluntary petition for relief under
Chapter 11 of the Bankruptcy Code The Bankruptcy Court assumed jurisdiction on
that day. The case name is In Re Petsec Energy Inc., and the docket number is
00BK-50741 (the "Bankruptcy Case"). Subject to the supervision of the
Bankruptcy Court, PEI remains in possession of the Company's assets and will
manage the business for the benefit of PEI's creditors and PEL in accordance
with Sections 1107 and 1108 of the Bankruptcy Code.

           On October 29, 1999, PEI elected not to pay $3.2 million due to the
syndicate of banks under its revolving credit facility of which $7.9 million
was drawn (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, PEI
refinanced the Chase Credit Facility

                                      14
<PAGE>   15
with Foothill Capital Corporation ("Foothill"), completing a $30 million
revolving credit facility on January 18, 2000 (the "Foothill Credit Facility").
PEI completed a new post-petition debtor-in-possession credit facility with
Foothill ("the Foothill DIP Facility") on June 20, 2000. PEI has obtained court
approval to use the Foothill DIP Facility to pay future expenses that fall due
beyond June 20, 2000. The Company believes that this facility will provide PEI
with sufficient capital resources to meet its anticipated expenditures through
the duration of the Bankruptcy Case.

           PEI did not make the $4.75 million interest payment due on December
15, 1999 to the holders of the 9 1/2% Notes. On January 18, 2000, after asking
the noteholders to organize, PEI met with an informal subcommittee of the
holders of the 9 1/2% Notes in an effort to reach a solution to its financial
situation.

           Following the filing by PEI for protection under Chapter 11 of the
Bankruptcy Code, PEI continued to negotiate with the Official Committee of
Unsecured Creditors' in the Bankruptcy Case and its other creditors, including
certain holders of the 9 1/2% Notes, who are not on the Official Committee of
Unsecured Creditors'. An agreement was reached with PEI's creditors on
June 16, 2000 to sell PEI or all of its assets. PEI anticipates filing a Plan
of Reorganization which contemplates an agreed distribution of the sale
proceeds to the creditors, PEL, as the equity owner, and certain of PEI's
senior management team in the USA . Details of the agreement with the Official
Committee of Unsecured Creditors were described in the 6-K current report
filed by the Company on June 19, 2000.


VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION

           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. 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 9 - Management's Discussion
and Analysis of Financial Condition and Results of Operations" and "Item 1--
Description of Business -- Oil and Gas Marketing."


UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES

           This Annual Report contains estimates of the Company's proved oil
and gas reserves and the estimated future net revenues therefrom based upon the
reserve report prepared by Ryder Scott Company, L.P., Petroleum Consultants
that rely upon various assumptions, including assumptions required by the SEC
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, Petroleum Consultants. 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

                                      15
<PAGE>   16
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., Petroleum Consultants 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. Moreover, given the agreement that
has been reached with PEI's creditors, it is expected that these reserves will
be sold rather than developed by the Company. See "Item 1 -- Description of
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. While the present
value analysis discussed in this Annual Report is one indicator of value, there
are others. No assurance can be given by the Company that PEI will achieve
these valuations in the sale process. In accordance with applicable
requirements of the SEC, 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 expenses in connection with development and
production of oil and gas properties. In addition, the 10% discount factor,
which is required by the SEC 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.

           Given the agreement that has been reached, with PEI's creditors to
sell PEI or all of its assets, 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."


CAPITAL REQUIREMENTS

           In the past, the Company has made substantial expenditures for the
development, exploration, acquisition and production of oil and natural gas
reserves. Capital expenditures were $19 million in 1999, $125 million in 1998
and $155 million in 1997. Substantial capital expenditures may be required in
the future to access 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. See "Item 9 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Capital Resources
and Liquidity."


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. PEI expects to have a modest drilling and workover

                                      16
<PAGE>   17
program during the sale process, but operations may be necessary to preserve
the value of the assets. To the extent that PEI participates in such
operations, there can be no assurance that operations conducted on behalf of the
Company will be successful 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 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 PEI 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 -- Description of 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, and the loss of such personnel could have a detrimental effect on the
PEI sale process and the Company. In fact, the employment contracts of PEI's
U.S.-based employees are expected to be terminated as a consequence of the
bankruptcy case. As the sale process unfolds, employees no longer essential to
the operations of PEI will be terminated. In addition, the contract pursuant to
which Maynard Smith, PEL's Chief Operating Officer, provided services to the
Company expired on May 31, 2000. Mr. Smith is working on a month-to-month basis
to assist with the sale of PEI. See "Item 10 -- Directors and Officers of
Registrant."

                                      17
<PAGE>   18
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 -- Description of Business -- Competition."

RISK 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 9 - Management's Discussion and Analysis of
Financial Condition and Results of Operations - Hedging transactions" and "Item
1 -- Description of Business -- Oil and Gas Marketing."


                       ITEM 2 - DESCRIPTION OF PROPERTIES

ITEM 2(A) - SIGNIFICANT PROPERTIES

           The Company has grown principally through the acquisition and
development of properties in the Gulf of Mexico offshore Louisiana. The first
four leases were acquired from the State of Louisiana, four leases were
purchased from third parties and the remaining leases have been acquired at
Gulf of Mexico State and Federal OCS lease sales. At December 31, 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. Seven leases
were sold in a sale that closed on April 11, 2000, and since then, one lease
has terminated. Presently, the Company has working interests in 40 leases in
the Gulf of Mexico. All of the Company's leases and proved oil and gas reserves
are owned by PEI. See "Item 1 -- Description of Business; Risk Factors --
Liquidity Problems."


ITEM 2 (B) - RESERVES

           The information on the Company's oil and gas reserves is set out
under Item 1 on page 7.

           The information on the Company's oil and gas production is set out
under Item 9 on page 27.

                                      18
<PAGE>   19
                           ITEM 3 - LEGAL PROCEEDINGS

LEGAL PROCEEDINGS

           PEI 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, PEI 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. PEI 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 - CONTROL OF REGISTRANT
           The following table sets forth certain information regarding the
beneficial ownership of the Company's ordinary shares ("Ordinary Shares") as of
May 31, 2000 by each person who is known by the Company to own beneficially 10%
or more of the Ordinary Shares and by all directors and executives of the
Company and Petsec Energy Inc, as a group. The percentages herein have been
calculated based on the 107,401,041 Ordinary Shares outstanding on March 31,
2000.

                                              NUMBER OF        PERCENTAGE
NAME                                      ORDINARY SHARES   BENEFICIALLY OWNED

All Directors and executives as a group
   (10 persons) (1) (2) (3)                  28,240,066           26.3%
Terrence N. Fern (2) (3)                     26,882,498           25.0%
Den Duyts Corporation Pty Limited (3)        18,344,639           17.1%

(1)     Includes Ordinary Shares held by family-controlled entities or
        companies associated with such individuals. Also includes Ordinary
        Shares reflected for Terrence N. Fern, Chairman and Managing Director
        of the Company. See Notes (2) and (3) below.

(2)     Includes 4,000 Ordinary Shares held by Mr. Fern directly; 96,509
        Ordinary Shares held by a trust of which Mr. Fern is a shareholder of
        the corporate trustee; 6,470,661 Ordinary Shares held by a trust of
        which Den Duyts Corporation Pty Limited ("Den Duyts") is a shareholder
        and Mr. Fern is a director of the corporate trustee; 1,966,689 Ordinary
        Shares held by a corporation of which Mr. Fern is a shareholder; and
        18,344,639 Ordinary Shares held by a trust Den Duyts. Excludes 4,000
        Ordinary Shares held by Mr. Fern's wife of which he disclaims that he
        is the beneficial owner and 12,000 Ordinary Shares held by Mr. Fern's
        adult children of which he disclaims that he is the beneficial owner
        (as defined under Rule 13D-3 of the Securities Exchange Act of 1934
        (the "Exchange Act") ("Beneficial Owner")). See Note (3) below.

(3)     Den Duyts is a company which acts as the trustee of a trust, the
        beneficiaries of which include members of Mr. Fern's family.
        Mr. Fern is deemed to be the Beneficial Owner of such shares.

        Under Australian law a shareholder is required to disclose to the
        Company if the shareholder is "entitled" to 5% or more of the Company's
        Ordinary Shares. A shareholder making such disclosure is required to
        aggregate with the shares held personally and beneficially by such
        shareholder any other shares in which the shareholder or an "associate"
        of the shareholder has a "relevant interest". Under Australian law, a
        person has a "relevant interest" in a share held by another person if

                                      19
<PAGE>   20
        the first person or a corporate entity controlled by the first person
        has the right to exercise or control the exercise of the voting rights
        in respect of that share or has the power to dispose of or control the
        disposal of that share. An "associate" is defined broadly and includes
        any person with whom the first person has an agreement, arrangement or
        understanding relating to control over shares, or with whom the first
        person proposes to act in concert. The "relevant" interests of Den
        Duyts including its associates at May 31, 2000, were 26,882,498
        Ordinary Shares and the "relevant" interests of Mr. Fern were
        26,882,498 Ordinary Shares.

                       ITEM 5 - NATURE OF TRADING MARKET
           The trading market for the Company's Ordinary Shares is the
Australian Stock Exchange Limited ("ASX"), which is the only stock exchange in
Australia. The Company's symbol on the ASX is "PSA".

           All on-market transactions for the Company's shares are executed on
the ASX's electronic trading system and information on transactions is
therefore immediately available. Current ASX settlement requirements are within
five days after the transaction.

           Effective July 23, 1996 the Company's ADRs commenced quotation and
trading on the Nasdaq National Market (symbol: PSALY) and on May 18, 1998
transferred to the New York Stock Exchange (symbol: PSJ). On March 6, 2000,
trading on the New York Stock Exchange terminated, and the ADR's commenced
trading on the OTC Bulletin Board under the new ticker symbol PSJEY.OB. Each
ADR evidences one American Depositary Share ("ADS"), which represents five
Ordinary Shares. The depositary of the ADRs representing the ADSs is The Bank
of New York ("Depositary").

           As at March 31, 2000, 2,940,039 ADRs were on issue. These were
equivalent to 14,700,195 Ordinary Shares or approximately 14% of the Company's
issued capital.

           The following table sets forth, for the periods indicated, the high
and low closing sale prices per Ordinary Share as reported on the ASX in
Australian dollars and translated into US dollars at the Noon Buying Rate on
the respective dates on which such closing prices occurred, unless otherwise
indicated.

                                              A$                     US$
                                       High         Low        High       Low
Year ended June 30, 1996:
  First Quarter                        3.40         2.10       2.59       1.49
  Second Quarter                       3.40         2.70       2.53       2.02
  Third Quarter                        3.60         3.20       2.69       2.39
  Fourth Quarter                       4.95         3.25       3.92       2.54
Six Months ended December 31, 1996:
  First Quarter                        5.88         4.80       4.65       3.80
  Second Quarter                       6.00         5.00       4.73       3.94
Year ended December 31, 1997:
  First Quarter                        7.02         4.95       5.42       3.95
  Second Quarter                       6.53         4.85       4.97       3.76
  Third Quarter                        7.25         5.90       5.22       4.34
  Fourth Quarter                       7.30         4.02       5.33       2.63
Year ended December 31, 1998:
  First Quarter                        5.69         4.07       3.76       2.65
  Second Quarter                       6.50         4.21       4.17       2.57
  Third Quarter                        5.70         1.70       3.59       1.00
  Fourth Quarter                       1.85         0.43       1.10       0.27
Year ended December 31, 1999:
  First Quarter                        0.53         0.34       0.33       0.22
  Second Quarter                       0.72         0.37       0.47       0.23
  Third Quarter                        0.55         0.31       0.36       0.20
  Fourth Quarter                       0.36         0.19       0.23       0.12

                                      20
<PAGE>   21


The following table sets forth for the periods indicated the high and low
closing prices per ADR on the US markets discussed above in US dollars:

                                                         US$
                                              High               Low
Six Months ended December 31, 1996:
  First Quarter (from July 23, 1996)          23.25              19.75
  Second Quarter                              23.63              20.00

Year ended December 31, 1997:
  First Quarter                               27.38              19.63
  Second Quarter                              25.13              18.63
  Third Quarter                               26.75              21.75
  Fourth Quarter                              26.63              13.06

Year ended December 31, 1998:
  First Quarter                               16.50              13.50
  Second Quarter                              21.75              13.44
  Third Quarter                               17.00               4.94
  Fourth Quarter                               5.56               1.38

Year ended December 31, 1999:
  First Quarter                                1.88               1.00
  Second Quarter                               2.19               1.13
  Third Quarter                                1.69               0.81
  Fourth Quarter                               1.13               0.38


  ITEM 6 - EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS

           The Australian government currently does not impose any limits,
including any foreign exchange controls, that restrict the export or import of
capital by the Company or that affect the remittance of dividends, interest or
other payments to non-resident holders of the Company's securities (except as
set out below in this Item 6). Any transfer of Australian or foreign currency
of A$10,000 or more by a person and any international funds transfer into or
out of Australia by certain banks and other cash dealers must be reported to
the Australian government's Transaction Reports and Analysis Centre (AUSTRAC).
See also "Taxation - Australian Taxation" for a discussion of the Australian
dividend withholding tax.

           There is no provision in Australian law (except as stated below in
this Item 6) or in the Company's constituent documents that prevents or
restricts a non-resident of Australia from freely owning and voting the
Ordinary Shares which underlie the Company's ADRs.

           Non-Australian shareholders should be aware that Australian law
contains certain provisions that may apply if a significant interest in the
Ordinary Shares is proposed to be acquired. The following brief discussion of
relevant Australian law restrictions on non-Australian ownership of securities
is in no way intended to be an exhaustive statement of the Australian position.
The discussion does not address general restrictions in Australian law on
securities ownership per se.

           The Australian Foreign Acquisitions and Takeovers Act of 1975 (the
"Foreign Takeovers Act") requires notification to the Australian government of
any proposed acquisition by a foreign person which would result in such person
and any of its associates controlling not less than 15% of the voting power or
holding an interest in not less than 15% of the shares of an Australian company
with total assets valued at A$5 million or more. Upon receipt of such
notification, the Australian government has the authority to review such
acquisition. The Australian government also has the authority to review any
transaction involving two or more foreign persons who, with their associates,
are able to control at least 40% of the voting power or hold interests in not
less than 40% of the shares of an Australian corporation. Under its present
policy and except in certain special cases, the Australian government will
automatically approve such acquisitions if the corporation has total assets of
less than A$50 million. Where the corporation has assets in excess of A$50
million (as does the Company), the Australian government either may permit the
proposed acquisition to proceed subject to conditions or may prohibit the
transaction as contrary to the national interest. Under the terms of the
Foreign Takeovers Act, ownership of ADRs will constitute ownership of shares or
voting power of the Company.

           Section 671B of the Australian Corporations Law requires a
shareholder who is entitled (within the meaning of the Australian Corporations
Law) to 5% or more of the voting shares of a corporation (a "substantial
shareholder') to notify the corporation of such shareholding within two
business days after the shareholder becomes aware that the shareholder is a

                                      21
<PAGE>   22
substantial shareholder. Section 671B of the Australian Corporations Law also
requires a substantial shareholder to further notify the corporation when its
entitlement changes by an amount equal to 1% or more of the voting shares.
Under Australian Corporations Law, a person who holds an ADR is deemed to be
entitled to the underlying shares.

           Section 606 of the Australian Corporations Law prohibits, subject to
the making of a formal takeover offer or certain limited exceptions, a
shareholder from acquiring shares in an Australian company if the acquisition
would result in the shareholder having an entitlement (within the meaning of
the Australian Corporations Law) to more than 20% of the voting shares of the
corporation (or the acquisition would result in a shareholder who is already
entitled to not less than 20% but less than 90% of the shares becoming entitled
to a greater percentage).

           The Australian Trade Practices Act of 1974 regulates, among other
matters, offshore acquisitions affecting Australian markets. Under Section 50A
of such Act, the Australian Competition Tribunal may, in certain circumstances,
make a declaration that prohibits a corporation from carrying on business in a
particular market for goods and services in Australia where a foreign
acquisition would have the effect or be likely to have the effect of
substantially lessening competition in that market. Such acquisitions may be
examined by the Australian Competition Tribunal on public interest grounds.

           Shareholders who could possibly be affected by any of the above
legislation should seek independent advice from a qualified Australian
attorney.

                               ITEM 7 - TAXATION

AUSTRALIAN TAXATION

           The following is a summary of the principal Australian tax
consequences of the purchase, ownership and sales of ADSs (which are evidenced
by ADRs) by United States resident shareholders. It is not a complete analysis
or listing of all the possible tax consequences of such purchase, ownership and
sale. Such shareholders therefore should consult their tax advisors with
respect to the tax consequences of the purchase, ownership and the sale of
Ordinary Shares or ADRs, including consequences under state and local tax laws.

           The taxation treatment of a United States resident shareholder of
Ordinary Shares or ADRs will depend on the particular circumstances of that
shareholder. The following summarizes the general principles of the application
of Australian taxation laws.

           To the extent that dividends paid to United States resident
shareholders are "unfranked" (essentially, not paid out of profits which have
borne Australian tax), pursuant to Australian tax laws and the Australia/United
States Double Taxation Agreement they will be subject to a 15% Australian
dividend withholding tax except where the shares are effectively connected with
a permanent establishment of a United States shareholder who carries on
business in Australia or with a fixed base of a United States shareholder who
provides independent personal services in Australia, in which case they will be
subject to ordinary Australian tax rates. The Company may pay a dividend out of
foreign profits which, even though unfranked, would not be subject to
Australian dividend withholding tax.

           United States resident securities traders who are not residents of
Australia for tax purposes are not subjected to Australian tax on capital gains
arising on the sale of the Ordinary Shares or ADRs provided that the investor
and its associates do not at any time during the five years preceding disposal
beneficially own 10% or more of the Company's issued share capital.

           Under the New South Wales Stamp Duties Act no New South Wales stamp
duty will be payable on the acquisition or disposal of ADRs. Any transfer of
Ordinary Shares will in most cases require the payment of New South Wales Stamp
Duty calculated at 0.3% of the transaction value. If the transfer takes place
on the ASX, the stamp duty is split between the transferor and transferee. If
the transfer does not take place on the ASX, the transferee is liable for the
full stamp duty, and the transfer cannot be registered until the duty is paid.


UNITED STATES FEDERAL TAXATION

           The following is a summary of the principal United States federal
income tax consequences of the purchase, ownership and sale of ADSs (which are
evidenced by ADRs) by a citizen, resident or corporation of the United States
(as the

                                      22
<PAGE>   23
case may be, a "US Holder"). It is not a complete analysis or listing of all of
the possible tax consequences of such purchase, ownership and sale and does not
address tax consequences to special persons such as tax-exempt entities and
corporations owning at least 10% of the stock of the Company. Shareholders
therefore should consult their tax advisors with respect to the tax
consequences of the purchase, ownership and sale of Ordinary Shares or ADRs,
including consequences under the estate and local tax laws.


TAXATION OF CASH DIVIDENDS

           For United States federal income tax purposes, US Holders of ADRs
generally will be treated as the owners of the underlying Ordinary Shares.
Dividends paid with respect to the Ordinary Shares represented by ADRs will be
includable in the gross income of the US Holder as ordinary income when the
dividends are received by the Depositary and will not be eligible for the
dividends received deduction generally allowed to corporations under the
Internal Revenue Code of 1986, as amended, and will be treated as foreign
source dividend income. Dividends paid in Australian dollars will be includable
in income in the US dollar amount based on the exchange rate on the date such
dividends are paid by the Company. US Holders of ADRs will be required to
recognize their share of any exchange gain or loss realized by the Depositary
upon the conversion of Australian dollars into US dollars and any such gain or
loss will be ordinary gain or loss.


TAXATION OF WITHDRAWALS

           US Holders of ADRs that exercise their right to withdraw Ordinary
Shares from the Depositary in exchange for the ADR representing such ADRs will
generally not be subject to United States federal income tax on such
withdrawal. The aggregate basis of the Ordinary Shares so received will be
equal to the US Holder's aggregate adjusted basis on ADRs exchanged therefor.


TAXATION OF CAPITAL GAINS

           A US Holder that holds ADRs as a capital asset will recognize
capital gain or loss for United States federal income tax purposes upon a sale
or other disposition of such ADRs in an amount equal to the difference between
such US Holder's basis in the ADRs and the amount realized on their
disposition. Such capital gain or loss will be deemed long-term capital gain or
loss if the US Holder holds such ADRs for more than one year. Certain
limitations exist on the deductibility of capital losses by both corporate and
individual taxpayers. Capital gains and losses on the sale or other disposition
by a US Holder of ADRs generally will constitute gains or losses from sources
within the United States.


                        ITEM 8 - SELECTED FINANCIAL DATA


SELECTED FINANCIAL DATA

           The following table sets forth in US dollars and under US GAAP
selected historical consolidated financial data for the Company as of and for
each of the periods indicated. The financial data for the fiscal year ended
June 30, 1996, the six months ended December 31, 1996 and the three fiscal
years ended 1997, 1998 and 1999is derived from the Company's US Dollar
Financial Statements, which were prepared under US GAAP. The following data
should be read in conjunction with "Item 9 -Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the financial
statements and notes thereto included elsewhere in this Annual Report.


                                      23
<PAGE>   24
<TABLE>
<CAPTION>
                                                                             Six months to              Fiscal year ended
                                                Fiscal years ended June 30    December 31                  December 31
                                                     1995          1996           1996           1997           1998         1999

                                                                     (In thousands, except per share data)
<S>                                              <C>           <C>            <C>             <C>          <C>            <C>
INCOME STATEMENT DATA:
  Oil and gas sales (net of royalties)              $17,031     $  51,150      $  37,521      $ 125,139     $  92,017      $ 31,000
                                                   --------      --------       --------       --------      --------      --------

  Lease operating expenses                            3,808         6,892          3,279         11,527        14,989         7,045
  Depletion, depreciation and amortization            5,661        21,098         15,368         63,903        57,672        21,295
  Exploration expenditure                             2,697         2,175          5,249          7,328         7,427         2,750
  Dry hole and abandonment costs                          -         1,145              -         10,454        27,503         2,840
  Impairment expense                                      -             -              -              -        72,916         7,480
  General, administrative and other expenses          4,543         7,001          3,339          9,001        10,777         6,859
  Stock compensation expense                            102         1,749            677          1,461           937           260
                                                   --------      --------       --------       --------      --------       -------

      Total operating expenses                       16,811        40,060         27,912        103,674       192,221        48,529
                                                   --------      --------       --------       --------      --------       -------

  Income (loss) from operations                         220        11,090          9,609         21,465      (100,204)      (17,529)
  Other income (expense)                                 52           223              -            132           (86)          260
  Profit (loss) on sale of assets                     4,296           257          7,208             31            68           241
  Profit on sale of investments                           -             -              -              -             -         2,561
  Interest expense                                   (1,725)       (3,687)        (1,472)        (6,022)       (9,044)      (10,963)
  Interest income                                       210           485            822          1,685         1,214         1,070
  Equity in income (loss) of affiliates             (3,864)           282        (1,326)         (1,595)            -             -
                                                   --------      --------       --------       --------      --------       -------

  Income (loss) before tax                             (811)        8,650         14,841         15,696      (108,052)      (24,360)
  Income tax benefit (expense)                          465          (895)        (3,888)        (5,416)       11,547          (764)
                                                   --------      --------       --------       --------      --------       -------

      Net income (loss)                           $    (346)   $    7,755      $  10,953     $   10,280   $   (96,505)     $(25,124)
                                                   --------      --------       --------       --------      --------       -------

BASIC AND DILUTED EARNINGS PER  SHARE:
  Earnings (loss) per ordinary share             $    (0.01)   $     0.09      $    0.10     $     0.10   $     (0.90)     $  (0.23)
  Earnings (loss) per ADR (1)                    $    (0.02)   $     0.45      $    0.52     $     0.48   $     (4.48)     $  (1.17)
  Weighted average number of ordinary
      shares outstanding                             75,874        86,297        104,977        107,320       107,601       107,429

CASH FLOW DATA:
  Net cash provided by operating activities       $   9,572     $  38,601      $  26,454     $   90,806   $    55,056      $ 12,588
  Net cash (used in) provided by investing
    activities                                      (24,559)      (73,228)       (33,227)      (145,790)     (134,750)       60,408
  Net cash provided by (used in) financing
    activities                                       15,291        37,734         15,760         61,512        74,011       (66,125)

BALANCE SHEET DATA:
  Total assets                                    $  63,857     $  125,690     $  161,083    $   247,962  $    199,213     $110,536
  Current maturities - credit facility                    -              -              -              -        67,250        7,875
  Borrowings less current maturities (2)             14,900         52,000         37,000         99,630       106,406       99,684
  Shareholders' equity (deficiency)                  20,904         47,479         91,401        101,155         4,355      (19,526)
</TABLE>


(1)     No ADRs were issued prior to June 30, 1996; net income (loss) per ADR
        has been calculated by dividing net income (loss) by the weighted
        average number of ordinary and ordinary equivalent shares outstanding,
        multiplied by five (the Ordinary Share to ADR ratio).
(2)     Amount for 1999 is classified as a current liability - See Note 9 to
        Notes to the Financial Statements.

                                      24

<PAGE>   25
EXCHANGE RATES

           Where US dollar amounts in this Form 20-F have not been derived from
the Financial Statements (and therefore translated using the exchange rates in
the notes to the Financial Statements), the translations of Australian dollars
into US dollars (unless otherwise indicated) have been made at the appropriate
Noon Buying Rate as specified.

           The following table sets forth certain information with respect to
historical exchange rates, using the Noon Buying Rates for Australian dollars
expressed in US dollars per Australian dollar:
<TABLE>
<CAPTION>
                                                           US Dollar Per Australian Dollar
                                                 --------------------------------------------------------
Period                                           Average*          High         Low         End of Period
------                                           --------          ----         ---         -------------
<S>                                              <C>            <C>          <C>            <C>
Year ended June 30, 1995                          0.7412         0.7778       0.7108               0.7108
Year ended June 30, 1996                          0.7627         0.8026       0.7100               0.7856
Six months ended December 31, 1996                0.7928         0.8180       0.7721               0.7944
Year ended December 31, 1997                      0.7385         0.7978       0.6490               0.6515
Year ended December 31, 1998                      0.6295         0.6868       0.5550               0.6123
Year ended December 31, 1999                      0.6444         0.6705       0.6179               0.6560
</TABLE>

*  Average of Noon Buying Rates for the period based on month end rates

           Fluctuations in the Australian dollar/US dollar exchange rate will
affect the US dollar equivalent of the Australian dollar price of the Company's
Ordinary Shares on the ASX and, as a result, are likely to affect the market
price of the Company's ADRs in the United States. Such fluctuations also would
affect the US dollar amounts received by holders of ADRs on conversion by the
Depositary of cash dividends, if any, paid in Australian dollars on the
Ordinary Shares underlying the ADRs.

           The Company's primary operations are in the United States (through
PEI, PEL's wholly owned U.S. operating subsidiary), and its sales and operation
costs are denominated predominantly in US dollars. For the foreseeable future,
therefore, fluctuations in the Australian dollar/US dollar exchange rate are
expected to have only a small effect on the Company's underlying performance,
as measured in US dollars, and on the Company's financial statements prepared
in US dollars. Such fluctuations would affect the Company's financial results
as reported in Australian dollars.

           The Company has not paid any dividends for the fiscal year ended
June 30, 1996, the six month period ended December 31, 1996 and years ended
December 31, 1997, 1998 and 1999.


    ITEM 9 - 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 financial position for the fiscal year ended June 30, 1996,
the six month period ended December 31, 1996 and the fiscal years ended
December 31, 1997, 1998 and 1999. The Financial Statements for these periods
are set out under Item 18 and should also be referred to in conjunction with
the following discussion.

           In October 1999, PEI engaged financial advisors to seek solutions to
its financial situation. In order to preserve available cash, the Company's
wholly owned U.S. subsidiary PEI 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. PEI 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."

           In January 2000, PEI refinanced the Chase Credit Facility with the
completion of a $30 million Credit Facility with Foothill Capital Corporation.
On January 18, 2000 PEI commenced discussions with the holders of the 9 1/2%
Notes regarding alternative solutions to its financial situation. PEI filed a
voluntary petition under Chapter 11 of the Bankruptcy Code on April 13, 2000.
After filing the Bankruptcy Case, PEI continued discussions with the holders of
the 9 1/2% Notes. On June 16, 2000,an agreement was reached with the Official
Committee of Unsecured Creditors in the Bankruptcy Case and certain holders of

                                      25
<PAGE>   26
the 9 1/2% notes who are not members of the Official Committee to sell PEI or
all of its assets. PEI anticipates filing a Plan of Reorganization which
contemplates an agreed distribution of the sale proceeds to the creditors, PEL,
as the equity owner, and certain of PEI's senior management team in the U.S.A.
The distribution to PEL will be based on a percentage of distributions received
by the holders of the 9 1/2% Notes in connection with the sale of PEI and its
assets. The details of the agreement and the distribution percentages to which
PEL will be entitled is set out in a term sheet that was filed as an attachment
to the 6-K Current Report dated June 19, 2000. Substantially all of the
proceeds from the sale of PEI's assets will be distributed to the noteholders
and other creditors of PEI until these creditors are paid in full. The
financial statements do not include any adjustments which might result from the
outcome of this uncertainty.

           The liquidity issues faced by PEI are discussed in detail in the
"Liquidity and Capital Resources" section of this Form 20-F.


OVERVIEW

           The Company's income from operations is almost exclusively generated
from its operations in the Gulf of Mexico, which is the primary focus of this
discussion. All of the Company's oil and gas operations are owned by PEI. For
the periods discussed, however, other factors also impacted income from
operations and net income, which are discussed below under the caption "Other
Items Affecting Results."

           The Company acquired substantially all of its 40 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 the assets. The $68.3
million sale was completed on February 1, 1999, reducing debt to $9 million
under the Chase Credit Facility and total debt to $108.7 million.

           The Company is currently producing from 21 of its lease blocks.
Production in 1997 was 46,408 MMcfe but through natural decline decreased in
1998 to 39,511 MMcfe. In 1999 production decreased to 13,119 MMcfe as a result
of the sale to Apache Corporation and natural decline. As of December 31, 1999
the Company's net proved reserves were 83.6 Bcfe, 68% of which were natural
gas.

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

           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.


                                      26
<PAGE>   27
<TABLE>
<CAPTION>
                                    Fiscal year ended       Six months to                         Years ended
                                         June 30,           December 31,                          December 31,
                                         --------           ------------                          ------------
                                             1996           1995          1996           1996         1997        1998       1999
                                             ----           ----          ----           ----         ----        ----       ----
<S>                                      <C>           <C>           <C>           <C>          <C>           <C>        <C>
Net production:
  Oil (MBbls)                               1,680            670         1,145          2,155        3,078       2,353        812
  Gas (MMcf)                               11,529          5,881         6,074         11,722       27,940      25,390      8,247
  Total (MMcfe)                            21,609          9,901        12,944         24,652       46,408      39,511     13,139

Net sales data (in thousands):
  Oil                                     $29,937        $10,674       $24,904        $44,168      $60,369     $37,846    $12,570
  Gas                                      21,213         10,773        12,617         23,056       64,770      54,171     18,430
                                         --------       --------      --------        -------     --------     -------    -------

  Total                                   $51,150        $21,447       $37,521        $67,224     $125,139     $92,017    $31,000
                                         --------       --------      --------        -------      -------    --------    -------

Average sales prices (1):
  Oil (per Bbl)                            $17.82        $ 15.93       $ 21.75       $  20.50     $  19.61    $  16.08    $ 15.48
  Gas (per Mcf)                              1.84           1.83          2.08           1.97         2.32        2.13       2.23
  Total (per Mcfe)                           2.37           2.17          2.90           2.73         2.70        2.33       2.36

Average costs (per Mcfe):
  Lease operating expenses                  $0.32       $   0.36       $  0.25        $  0.26        $0.25       $0.38      $0.54
  Depletion, depreciation
      and amortization                       0.98           0.72          1.19           1.20         1.38        1.46      $1.62
  General, administrative
      and other expenses                     0.32           0.31          0.26           0.29         0.19        0.27       0.52
</TABLE>

(1)  Includes effects of hedging activities.


RESULTS OF OPERATIONS


FISCAL 1999 COMPARED TO FISCAL 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 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.

                                      27
<PAGE>   28
           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., Petroleum Consultants 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 $3.9 million, or 36%, to $6.9 million in 1999 from
$10.8 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 93% from $0.27 to
$0.52 due to decreased production.

           Interest Expense. Interest expense in 1999 increased $1.8 million,
or 22%, 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
$25.1 million was recorded for 1999, a decrease of $71.4 million over the loss
of $96.5 million for 1998.


FISCAL 1998 COMPARED TO FISCAL 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 before hedging. In 1997 the average realized gas price was $2.32 per Mcf,
or 8% below the $2.53 per Mcf 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
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 $6.2 million, or 10%, from $63.9 million in 1997 to $57.7 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., Petroleum Consultants 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.

                                      28
<PAGE>   29
           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 commodity prices on the carrying value of the Company's oil and
gas properties was expensed in 1998. There were no impairments recorded in
1997.

           General and Administrative Expense. General and administrative
expense increased $1.8 million, or 20%, to $10.8 million in 1998 from $9.0
million in 1997.

OTHER ITEMS AFFECTING RESULTS

           Profit on sale of investments. In November 1999 the Company sold its
holding in Climax Mining Ltd shares to the Company's own shareholders realizing
a gain of $2.6 million.

           Net operating losses and other carryforwards. For U.S. federal
income tax purposes, at December 31, 1999 the Company had net operating losses
("NOLs") of approximately $104.9 million which are available to offset future
federal taxable income, if any, from 2005 through 2019. The effective tax rate
has altered mainly due to the recognition of valuation allowances (primarily in
1998 and 1999) on carryforward losses due to the uncertainty of future
realization.

           For alternative minimum tax purposes, NOLs may be further adjusted
to determine the allowable alternative tax NOLs, and the alternative tax NOLs
can be used to offset no more than 90% of alternative minimum tax income.
Accordingly, the Company may owe an alternative minimum tax even though its
NOLs otherwise eliminated its regular tax liability.


LIQUIDITY AND CAPITAL RESOURCES

           Since 1990 the Company has financed its operations and growth
primarily with cash flow from operations, borrowings, equity offerings and
asset sales. The Company made an initial cash investment of $11.4 million in
its US operations, and, subsequently, increased this investment with advances
of $18.4 million from an Australian offering of 8.3 million Ordinary Shares in
September 1995 and the public offering of 4,000,000 American Depositary
Receipts (each representing 5 Ordinary Shares) at $19 per ADR, raising $70.4
million, net of costs in July 1996. $41.2 million of this was used to buy back
the 11.7 million Ordinary Shares held by an affiliate company, Climax Mining
Ltd, under approval from shareholders granted in June 1996. $13.7 million was
also raised at the same time from selling the Company's interest in the
gold/copper project at Didipio in the Philippines to Climax Mining Ltd.

      In late 1999, PEI experienced liquidity problems and engaged financial
advisors. On October 29, 1999, in order to preserve available cash, PEI 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. PEI did not pay the semi-annual interest payment under the Indenture
in the amount of $4.75 million that was due on December 15, 1999. On January
18, 2000 PEI refinanced the Chase Credit Facility through a new $30 million
revolving credit facility with Foothill Capital Corporation.

           PEI commenced discussions with the holders of the 9 1/2% Notes
regarding alternative solutions to its financial situation on January 18, 2000,
and subsequently filed a voluntary petition under Chapter 11 of the Bankruptcy
Code on April 13, 2000. PEI continued its operations under the protection of
the Bankruptcy Court while it continued discussions with the holders of the 9
1/2% Notes. On June 16, 2000 an agreement was reached with the Official
Committee of Unsecured Creditors in the Bankruptcy Case and certain holders of
the 9 1/2% Notes that are not members of the Official Committee to sell PEI or
all of its assets. PEI anticipates filing a Plan of Reorganization which
contemplates an agreed distribution of the sale proceeds to the creditors, the
equity owner and certain of PEI's senior management team in the U.S.A. The
distribution to PEL will be based on a percentage of distributions received by
the holders of the 9 1/2% Notes in connection with the sale of PEI and its
assets. The details of the agreement and the distribution percentages to which
PEL will be entitled is set out in a term sheet that was filed as an attachment
to the 6-K Current Report dated June 19, 2000. Substantially all of the
proceeds from the sale of PEI's assets will be distributed to the noteholders
and other creditors of PEI until these creditors are paid in full. The
financial statements do not include any adjustments which might result from the
outcome of this uncertainty.

                                      29
<PAGE>   30
                PEI completed negotiations with Foothill on a post-petition
revolving credit facility which the Bankruptcy Court authorized on June 20,
2000. This facility is expected to provide PEI with sufficient liquidity
throughout the Bankruptcy Case.

                Aside from cash on hand in PEI, PEL has cash available in the
amount of approximately $16 million at June 27, 2000.


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             $  90,806         $ 55,056      $12,588
           Net cash (used in) provided by investing activities    (145,790)        (134,750)      60,408
           Net cash provided by (used in) financing activities      61,512           74,011      (66,125)
</TABLE>

                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 $3.9 million in 1999,
$51.8 million in 1998 and $93.1 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 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 Offshore 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.

           The Company intends to participate in certain exploration and
development activities that it expects its joint venture partners to propose
during the year. The Company expects to be able to meet its anticipated capital
requirements from cash flows from operations and the Foothill DIP Facility.

                                      30
<PAGE>   31
Secured Credit Facilities

           In April 1996, PEI entered into the Chase Credit Facility. Under the
Chase Credit Facility, $3.2 million in principal was due on October 29, 1999.
PEI did not make the payment, which created a default under the Chase Credit
Facility.

           Subsequent to year end, PEI completed a refinancing of its Chase
Credit Facility with a $30 million revolving credit facility with Foothill. The
filing of the Bankruptcy Case required PEI and Foothill to enter into a
replacement credit facility. The Foothill DIP Facility was entered into by PEI
and Foothill on June 20, 2000. The Foothill DIP Facility, which incorporates
substantially all of the terms of the Foothill Credit Facility provides that
outstanding borrowings accrue interest at the reference rate most recently
announced by Wells Fargo Bank, N.A., (9.5% per annum as of May 31, 2000) plus a
margin of 2.5% per annum; the default rate is the reference rate plus 6.5%. PEI
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 DIP Facility terminates on April 20, 2001, but at PEI's election,
the term can be extended for an additional 90 days. Borrowings under the DIP
Credit Facility were $4.8 million at June 20, 2000.

           PEL is not obligated contractually with Foothill to repay the
Foothill DIP Facility or any costs associated with this facility and is not a
guarantor of PEI's obligations under the Foothill DIP Facility.


Public Senior Subordinated Indebtedness

           In June 1997 PEI 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. PEI
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 PEI and to fund further exploration and development of its oil and gas
properties, the acquisition of lease blocks and other general corporate
purposes.

           PEI did not make the $4.75 million 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. PEI 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.

           Following the filing of the Bankruptcy Case, PEI continued these
discussions with the holders of the 9 1/2% Notes and expanded the discussions
to include the Official Committee of Unsecured Creditors' in the Bankruptcy
Case in an effort to reach a consensual solution to PEI's financial problems.
Pursuant to these discussions, an agreement was reached with PEI's creditors on
June 16, 2000 to sell PEI or all of its assets. PEI anticipates filing a Plan
of Reorganization which contemplates an agreed distribution of the sale
proceeds to the creditors, the equity owner and certain of PEI's senior
management team in the USA. Details of the agreement with the Unsecured
Creditors Committee are described in the 6-K current report filed by the
Company on June 19, 2000.

           The 9 1/2% Notes were issued under the Indenture between PEI as
issuer and The Bank of New York as trustee. PEL is not obligated contractually
under the Indenture to repay the 9 1/2% Notes and is not a guarantor of PEI's
Indenture obligations.


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 has entered into forward swap contracts with major
financial institutions to reduce the effect of price volatility on oil and gas
sales. In swap agreements, the Company receives the difference between an
agreed fixed price per

                                      31
<PAGE>   32
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
to the third party and vice versa.

           The Company also has entered 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 does not trade in derivatives without underlying
estimated production and proved reserves to cover the hedging contracts in
which it enters.

           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.

           On April 25, 2000, PEI had hedging arrangements in place with The
Chase Manhattan Bank, N.A., and Bank of America, N.A. PEI was prohibited by
bankruptcy law from paying certain pre-petition debts falling due on April 25,
2000 with respect to these contracts. On April 26, 2000, the counterparties
drew on letters of credit PEI had posted to secure its obligations to pay these
obligations. In addition, the counterparties terminated the hedging
arrangements with respect to future transactions, and closed out all hedging
arrangements. The cost to terminate these contracts was $3.4 million.

           As a consequence of the early termination by The Chase Manhattan
Bank, N.A., and Bank of America, N.A., PEI does not have any hedging
arrangements in place presently. However, the Company has arranged to sell
approximately 40% of its anticipated net daily gas production for June, July
and August 2000 at $3.305 per mmbtu.


NEW ACCOUNTING PRONOUNCEMENTS

           In June of 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 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.


OTHER MATTERS

           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. Additionally, the MMS may require operators in
the OCS to post supplemental bonds in excess of lease and area-wide bonds with
respect to abandonment obligations. Under certain circumstances, the MMS may
require any 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. See "Business - Regulation".

           The Company's operations are subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company believes its current operations are in material compliance with current
applicable environmental laws and regulations. However, there can be no
assurance that current regulatory requirements will not change, currently
unforeseen environmental incidents will not occur or past unknown
non-compliance with environmental laws will not be discovered.

                                      32
<PAGE>   33
           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.


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.

FORWARD-LOOKING STATEMENTS


           This Annual Report includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). Except for
statements of historical facts included in this Annual Report, all statements,
including without limitation statements under "Item 9 -- Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Item 1 -- Description of 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 above. 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 9A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

                Commodity Price Risk. The Company produces and sells natural
gas and crude oil. As a result, the Company's financial results can be
significantly affected as these commodity prices fluctuate widely in response
to changing market forces. The Company has made use of derivative financial
instruments such as forward swap contracts and collars as a hedging strategy to
manage commodity prices associated with oil and gas sales and to reduce the
impact of commodity price fluctuations. The Company used the hedge or deferral
method of accounting for these instruments and, as a result, gains and losses
on commodity derivative financial instruments were generally offset by similar
changes in the realized prices of the commodities. See "Item 9 -- Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Hedging Transactions."

                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 short-term and long-term debt with both fixed and
floating interest rates. The following table presents principal amounts (stated
in thousands) and related average interest rates by year of maturity for the
Company's debt obligations at December 31, 1999:

                                      33
<PAGE>   34
<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%

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


            If market interest rates average 1% higher or lower in 2000 than in
1999, interest expense would increase (decrease), and loss before income taxes
would increase (decrease) by approximately $0.1 million based on the total
variable rate debt outstanding at December 31, 1999.

(1)   Amount subsequently refinanced - See Item 9-- 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 9 -- Management's Discussion and Analysis
      of Financial Condition and Results of Operations -- "Liquidity and
      Capital Resources."

                  ITEM 10 DIRECTORS AND OFFICERS OF REGISTRANT

   The following table sets forth the name, age and position of each director
                         and executive of the Company.

Name                         Age         Position

Directors:*
Terrence N. Fern (1)            52       Chairman, Managing Director and Chief
                                          Executive Officer
David A. Mortimer               55       Director

Peter E. Power                  67       Director

Executives:

Maynard V. Smith (1)            49       Chief Operating Officer
Ross A. Keogh                   41       Chief Financial Officer
Howard H. Wilson, Jr. (2)       42       Vice President - Operations
John T. Bellatti (2)            42       Vice President - Exploration and
                                          Chief Geophysicist
William R. Sack (2)             38       Vice President - Exploration and
                                          Joint Ventures
James E. Slatten III (2)        41       Vice President - Land and Legal
Geoffrey H. Fulcher             58       Company Secretary

  * R. Bruce Corlett retired as a director of PEL on April 6, 2000.

 (1)  Messrs. Fern and Smith provide services to the Company through
      contractual arrangements between the Company and their respective
      corporate affiliates. See "Executive and director compensation and
      interests of management in certain transactions".

(2)   The titles shown for Messrs. Wilson, Bellatti, Sack and Slatten are
      positions held with the Company's wholly-owned subsidiary,
      Petsec Energy Inc.

                                      34
<PAGE>   35
      The following biographies describe the business experience of the
directors and executives of the Company and Petsec Energy Inc.

           TERRENCE N. FERN has over 29 years of extensive international
experience in petroleum and minerals exploration, development and financing. He
holds a Bachelor of Science degree from The University of Sydney and has
followed careers in both exploration geophysics and natural resource
investment. Mr. Fern is also the Chariman of Climax Mining Ltd.

           DAVID A. MORTIMER was a senior TNT Limited Group Executive from 1973
and in 1997 retired as its Chairman and Chief Executive. He is a director of
Adsteam Marine Limited, Ci Technologies Group Limited (Chairman), Medical
Imaging Australasia Limited (Chairman), F.H. Faulding & Co Limited, Leighton
Holdings Limited and Sydney Airports Corporation Limited (Chairman). Mr.
Mortimer holds a Bachelor of Economics degree from The University of Sydney.

           PETER E. POWER has over 40 years experience in petroleum exploration
worldwide. Dr Power has a Bachelor of Science degree from The University of
Sydney and gained his doctorate at the University of Colorado, USA. He has
served as Chairman of the Australian Petroleum Production and Exploration
Association and President of the Australian Geoscience Council. Dr. Power was
Managing Director of Ampolex Limited from 1987 to 1996.

           MAYNARD V. SMITH has served as General Manager - Exploration and
Production since 1990 and became Chief Operating Officer in 1999. 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 Petsec Energy Inc. 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.

           HOWARD H. WILSON, JR. has served as Vice President - Operations of
Petsec Energy Inc. 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. Mr
Wilson holds a Bachelor of Science degree in Petroleum Engineering from the
Louisiana Polytechnic Institute.

           JOHN T. BELLATTI is Vice President - Exploration and Chief
Geophysicist of Petsec Energy Inc. He joined Petsec Energy Inc. 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
of Petsec Energy Inc. Mr. Sack joined Petsec Energy Inc. in January 1996.
Between 1988 and 1996 Mr. Sack held various technical and supervisory positions
with Shell Offshore Inc., involving exploration, development and business
activities. Mr. Sack holds a Bachelor of Science degree in Earth Science and
Physics from St. Cloud State University (MN), a Master of Science degree in
Geology from Michigan State University, and a Master's degree in Business
Administration from Tulane University.

           JAMES E. SLATTEN III is Vice President - Land and Legal of Petsec
Energy Inc. He has over 15 years experience in corporate and energy law. Prior
to joining Petsec Energy Inc. he was a partner in the Louisiana law firm of
Gordon, Arata, McCollam & Duplantis. Mr. Slatten holds a Bachelors 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.

           GEOFFREY H. FULCHER has had over 30 years experience in the petroleum
and mining industries in field and management positions, with over 15 of those
years as a Corporate Secretary.

                                      35
<PAGE>   36

    ITEMS 11, 12 AND 13 COMPENSATION OF DIRECTORS AND OFFICERS; OPTIONS; AND
                INTERESTS OF MANAGEMENT IN CERTAIN TRANSACTIONS

              EXECUTIVE AND DIRECTOR COMPENSATION AND INTERESTS OF
                      MANAGEMENT IN CERTAIN TRANSACTIONS


           The total compensation received by the directors of the Company for
their services as directors for fiscal 1999 was $245,000. Included in this
amount is a retirement benefit of $142,000 paid to Mr. Fletcher who resigned as
a director and Chairman of the Company on May 14, 1999. The total compensation
received by the six highest compensated executive officers of the Company and
its controlled and related companies for fiscal 1999 was $985,000. In addition,
a company associated with Mr. Fern provided management services to the Company
at a cost of $298,000. Also a company associated with Mr. Smith provided
management and geological services to the Company at a cost of $283,000 and a
company associated with Mr. Fletcher provided management consulting services to
the Company at a cost of $18,000. Mr. Smith also owns overriding royalty
interests on certain leases held by PEI, which were granted prior to July 1994
as incentives. The granting of overriding royalty interests as an incentive was
replaced subsequent to July 1994 by grants under the Company's share and option
plans.

           PEI has entered into employment agreements with Messrs. Bellatti,
Keogh, Sack, Slatten and Wilson. These agreements generally have three year
terms and expire in April 2003. However, the contracts were amended to
eliminate the severance benefit to which the executives would have otherwise
been entitled, and in place of the severance benefit certain guaranteed and
incentive payments were provided for to provide incentives to the U.S. based
managers to remain with PEI during the sale process. These payments are
expected to be less than what the executives would have otherwise been entitled
to under the original employment agreements. Although it is expected that these
employees will be terminated in connection with the sale of PEI or its assets,
these sums will be paid irrespective of whether the employees are terminated.
The employment agreements, as amended, have been approved by the Bankruptcy
Court. The details on the guaranteed and incentive payments that will be paid to
the US-based managers is described in the 6-K filed by PEL on June 19, 2000.

           In April 1999 PEL granted options for Ordinary Shares to key
employees pursuant to the Option Plan in connection with the extension of the
terms of these employment agreements.

           In addition, PEL has entered into agreements with entities
controlled by the families of Messrs Fern and Smith for the provision of
services. Mr. Smith's agreement with PEL expired on May 31, 2000 and has not
been renewed. Mr. Smith continues to work for PEL on a month-to-month basis.

           Other than pursuant to the Share and Option Plans described below,
the Company also has outstanding options for 450,000 Ordinary Shares to a
company controlled by Mr Smith's family: these are at an exercise price of
A$0.50 per Ordinary Share and expire in May 2004. The exercise of the options
is subject to a minimum vesting term and is contingent upon the market price of
the Ordinary Shares on the ASX achieving certain benchmarks.


SHARE AND OPTION PLANS

           The Company maintains an Employee Share Plan (the "Share Plan") and
an Employee Share Option Plan (the "Option Plan"). Both plans were approved by
the shareholders at the Company's 1994 Annual General Meeting and are
administered by a committee (the "Remuneration Committee") appointed by the
Board of Directors. 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 Company, 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 ASX achieving certain benchmarks.
After the vesting of such shares, the grantee may either repay the Company 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 1,665,000
Ordinary Shares subject to the terms of this Share Plan. Subsequent to December
31, 1999, employees and directors ceased to be entitled to 1,605,000 Ordinary
Shares under the Share Plan. On May 25, 2000, total entitlements of employees
and directors amounted to 60,000 Ordinary Shares. As of May 25, 2000, Mr.
Mortimer had a Company loan of A$280,000 ($187,684) in connection with a grant
of 50,000 Ordinary Shares under the Share Plan.

                                      36
<PAGE>   37
           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
2,775,500 Ordinary Shares pursuant to the Option Plan.


                                    PART II
              ITEM 14 - DESCRIPTION OF SECURITIES TO BE REGISTERED

Not applicable

                                    PART III
                   ITEM 15 - DEFAULTS UPON SENIOR SECURITIES
 As disclosed in the Form 20-F, the Company's wholly owned US subsidiary Petsec
Energy Inc. is in default of its $100 million Senior Subordinated Notes due
2007. See discussions in Item 1 and Item 9.


                        ITEM 16 - CHANGES IN SECURITIES

Not applicable - none.


                                    PART IV

                         ITEM 17 - FINANCIAL STATEMENTS

Not applicable - see Item 18 below.


                         ITEM 18 - FINANCIAL STATEMENTS

The US Dollar Financial Statements of the Company and the Independent Auditors'
Report are included on pages F-1 through F-24 of this Form 20-F.

                                      37
<PAGE>   38
                                   SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of
1934, the Registrant, Petsec Energy Ltd, certifies that it meets all the
requirements for filing on Form 20-F and has duly caused this annual report to
be signed on its behalf by the undersigned, thereunto duly authorized.




By: /s/ Ross A. Keogh
Chief Financial Officer
Petsec Energy Ltd


                                       38

<PAGE>   39



                  ITEM 19 - FINANCIAL STATEMENTS AND EXHIBITS

(a)     Financial Statements, including

        o    Consolidated balance sheets of Petsec Energy Ltd and subsidiaries
             as of December 31, 1998 and 1999 and the related consolidated
             statements of operations, consolidated statements of comprehensive
             income (loss), and consolidated statements of cash flows for each
             of the years in the three-year period ended December 31, 1999.

        o    Independent Auditors' Report

(b)     Exhibits
        o    Consent of KPMG
        o    Consent of Ryder Scott Company



                                      39
<PAGE>   40




                               PAGES F-1 TO F-24

                        SEE US DOLLAR ACCOUNTS ATTACHED



               [FINANCIAL STATEMENTS TO BE FILED BY AMENDMENT]




                                      40

<PAGE>   41

                                 EXHIBIT INDEX



                   23.1       Consent of KPMG
                   23.2       Consent of Ryder Scott Company