================================================================================
                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549


                                   FORM 10-K/A
                                (Amendment No. 1)


              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                   For the fiscal year ended December 31, 2002

                        Commission File Number: 000-25386

                                 FX ENERGY, INC.
              ----------------------------------------------------
             (Exact name of registrant as specified in its charter)


             Nevada                                              87-0504461
---------------------------------                           --------------------
 (State or other jurisdiction of                              (I.R.S. Employer
 incorporation or organization)                              Identification No.)

   3006 Highland Drive, Suite 206, Salt Lake City, Utah             84106
  ------------------------------------------------------         ----------
         (Address of principal executive offices)                (Zip Code)


Registrant's telephone number, including area code:     Telephone (801) 486-5555
                                                         Telecopy (801) 486-5575


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

 Title of each class                   Name of each exchange on which registered
 -------------------                   -----------------------------------------
        None                                               None


         Securities registered pursuant to Section 12(g) of the Act:

                         Common Stock, Par Value $0.001
                         Preferred Stock Purchase Rights
                        --------------------------------
                                (Title of class)

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

         Indicate by check mark if disclosure of delinquent filers in response
to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. [ ]

         Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes [ ] No [X]

         State the aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price at which the
common equity was last sold, or the average bid and asked price of such common
equity, as of the last business day of the registrant's most recently completed
second fiscal quarter. As of June 30, 2002, the aggregate market value of the
voting and nonvoting common equity held by nonaffiliates of the registrant was
$36,259,913.

         Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. As of March 20,
2003, FX Energy had outstanding 17,708,025 shares of its common stock, par value
$0.001.


DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy Statement in
connection with the 2003 Annual Meeting of Stockholders is incorporated by
reference in response to Item 11 of Part III of this Annual Report.

<PAGE>
--------------------------------------------------------------------------------
                                 FX ENERGY, INC.
              Form 10-K for the fiscal year ended December 31, 2002
--------------------------------------------------------------------------------


                                Table of Contents


   Item                                                                   Page
------------                                                           ---------
                                     Part I

    --       Special Note on Forward-Looking Statements....................   1
  1 and 2    Business and Properties.......................................   2
     3       Legal Proceedings.............................................  18
     4       Submission of Matters to a Vote of Security Holders...........  18

                                     Part II

     5       Market for Registrant's Common Equity and
               Related Stockholder Matters.................................  19
     6       Selected Financial Data.......................................  21
     7       Management's Discussion and Analysis of Financial
               Condition and Results of Operation..........................  22
    7A       Quantitative and Qualitative Disclosures about Market Risk....  37
     8       Financial Statements and Supplementary Data...................  38
     9       Changes in and Disagreements with Accountants on
               Accounting and Financial Disclosure.........................  38

                                    Part III

    10       Directors and Executive Officers of the Registrant............  39
    11       Executive Compensation........................................  41
    12       Security Ownership of Certain Beneficial Owners and
               Management and Related Stockholder Matters..................  42
    13       Certain Relationships and Related Transactions................  44
    14       Controls and Procedures.......................................  44

                                     Part IV

    15       Exhibits, Financial Statement Schedules and Reports
               on Form 8-K.................................................  45
    --       Signatures....................................................  49
    --       Report of  Independent Accountants............................ F-1

                                       i
<PAGE>


                                Explanatory Note


         This Form 10-K/A constitutes Amendment No. 1 to the Registrant's 10-K
for the fiscal year ended December 31, 2002. The following changes are
reflected:

         The Company has determined that certain adjustments are required to
restate the consolidated financial statements for the years ended December 31,
2002, 2001 and 2000. Overall, the adjustments decreased the net loss for the
year ended December 31, 2000, by $597,818, or $0.04 per share. The adjustments
also reduced the accumulated deficit at December 31, 2000, by $973,990 and
increased the cost basis of treasury stock by the same amount. These adjustments
were necessary to account for certain loans to officers in 1998 using variable
stock option accounting.

                                       ii
<PAGE>

--------------------------------------------------------------------------------
                   SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS
--------------------------------------------------------------------------------


         This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "could," "should,"
"expect," "anticipate," "estimate," "project," "propose," "plan," "intend" and
similar words and expressions. We intend that the forward-looking statements
will be covered by the safe harbor provisions for forward-looking statements
contained in Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Statements that describe our future strategic
plans, goals or objectives are also forward-looking statements.


         Readers of this report are cautioned that any forward-looking
statements, including those regarding us or our management's current beliefs,
expectations, anticipations, estimations, projections, proposals, plans or
intentions, are not guarantees of future performance or results of events and
involve risks and uncertainties, such as:


         o        our future ability to attract industry or financial
                  participants to share the costs of exploration, exploitation,
                  development and acquisition activities;


         o        the cost of additional capital that we may require and
                  possible related restrictions on our future operating or
                  financing flexibility;


         o        future plans and the financial and technical resources of
                  industry or financial participants;


         o        future events that may result in the need for additional
                  capital;

         o        future drilling and other exploration schedules and sequences
                  for various wells and other activities;

         o        the future results of drilling individual wells and other
                  exploration and development activities;

         o        future variations in well performance as compared to initial
                  test data;

         o        the prices at which we may be able to sell oil or gas;

         o        fluctuations in prevailing prices for oil and gas;

         o        uncertainties of certain terms to be determined in the future
                  relating to our oil and gas interests, including exploitation
                  fees, royalty rates and other matters;

         o        uncertainties regarding future political, economic,
                  regulatory, fiscal, taxation and other policies in Poland; and

         o        other factors that are not listed above.


         The forward-looking information is based on present circumstances and
on our predictions respecting events that have not occurred, that may not occur,
or that may occur with different consequences from those now assumed or
anticipated. Actual events or results may differ materially from those discussed
in the forward-looking statements. The forward-looking statements included in
this report are made only as of the date of this report.

                                       1
<PAGE>

                                     PART I

--------------------------------------------------------------------------------
                     ITEMS 1 AND 2. BUSINESS AND PROPERTIES
--------------------------------------------------------------------------------

Introduction


         We are an independent oil and gas company focused on exploration,
development and production opportunities in the Republic of Poland, much of it
in association with the Polish Oil and Gas Company, or POGC, and others. We
believe the cooperative working environment with POGC in Poland allows us to
operate effectively with in-country operating and technical personnel, access
geological and geophysical data readily, and interact in general with
governmental and industry contacts in Poland. We also produce oil and have an
oilfield services company in the United States.

         We are focused on Poland because we believe it provides attractive oil
and gas exploration and production opportunities. In our view, these
opportunities exist because all or key areas of the country were closed to
competition from foreign oil and gas companies. As a result, we believe its
known productive areas are underexplored, underdeveloped and underexploited
today. Poland is a net importer of gas and oil. We believe Poland's fiscal
regime is favorable to foreign investment, which reinforces the attractiveness
of Poland.


Strategy


         We seek the potential rewards of high potential exploration
opportunities while endeavoring to minimize our exposure to the risks normally
associated with exploration. We compensate for our small size and limited
capital by seeking farmout arrangements with industry participants in which we
agree to convey an interest in our exploration projects in exchange for
contribution of the financial and technical resources by larger industry
participants.

         Our primary strategic relationship is with POGC, a fully integrated oil
and gas company owned by the Treasury of the Republic of Poland that is its
principal domestic oil and gas exploration entity. Under our existing
agreements, POGC provides us with access to exploration opportunities, important
previously-collected exploration data, and technical and operational support.
For example, as detailed below, we participate with POGC in substantially all of
our ongoing activities in Poland, including:

         o        the Fences I project area in which we agreed in April 2000 to
                  spend $16.0 million on reviewing data provided by POGC and
                  drilling and other exploration costs to earn a 49% interest in
                  approximately 265,000 gross acres;

         o        the Fences II project area in which POGC has provided
                  technical data, and we have the right under a January 2003
                  agreement to earn a 49% interest in approximately 670,000
                  gross acres, subject to fulfilling our Fences I commitments;
                  and

         o        the Pomeranian project area, in which POGC exercised its
                  option to participate in the Tuchola and Chojnice wells before
                  the option expired.

In each of the above project areas, POGC provided us with existing geological
and geophysical data and advised during all phases of exploration. Previously,
we participated with POGC in exploration in other project areas in which we have
terminated our interest after initial exploration that did not discover
commercial oil or gas. We believe that we have a good working relationship with
POGC that will continue to provide access to additional opportunities in Poland.

POGC is the designated operator in the Fences I and II project areas and Apache
Corporation is designated as the operator in the Wilga project area.

                                       2
<PAGE>

         We have shifted our focus away from pure exploration to concentrate on
underexplored acreage in productive fairways or geologic trends where we believe
we have the opportunity to find significant gas reserves with lower risk. Our
strategy is to:


         o        acquire large acreage positions in underexplored areas of
                  known production fairways, particularly where there has been
                  little or no exploration for many years;


         o        carry out the work necessary to advance these properties
                  toward exploration drilling, including collecting, evaluating
                  and reprocessing data, identifying prospects that we believe
                  merit drilling based on available data and preparing a
                  detailed exploration work program, which we believe generally
                  enhances the value of the property at relatively low cost; and

         o        market these properties to industry on conventional farmout
                  terms in which others will generally pay initial exploration
                  drilling and seismic costs.

         We expect this strategy to allow us to more than recoup our costs, earn
a carried interest in the initial exploration drilling phase without direct
financial exposure of our own, and retain the upside of a substantial interest
in potential reserves.


Project Areas


         Our ongoing activities in Poland are conducted in five project areas:
Fences I, II and III, Pomeranian and Wilga. Our focus today is on the three
Fences project areas, where the gas-bearing Rotliegendes sandstone reservoir
rock in Poland's Permian basin is a direct parallel to the Southern North Sea
gas basin offshore England.

         Fences I project area is 265,000 acres (1,074 sq. km) in western
Poland's Permian basin. Several gas fields located in the Fences I block are
excluded or "fenced off" from our exploration acreage. These fields, discovered
by POGC between 1974 and 1982, produce from Rotliegendes sandstone reservoirs.
In April 2000, we agreed to spend $16.0 million on exploration costs in the
Fences I project area to earn a 49% interest. When expenditures exceed $16.0
million, POGC will pay its 51% share of further costs. To date, we have incurred
expenditures of $10.6 million (including $4.4 million in accrued liabilities
payable to POGC on or before December 31, 2003) toward the $16.0 million
commitment, leaving a remaining work commitment of $5.4 million.

         Fences II project area is 670,000 acres (2,715 sq. km) located north of
and contiguous with the Fences I block. POGC's Radlin field forms part of the
Fences II's southern border. Under a January 2003 agreement, we have the right
to earn a 49% interest from POGC, subject to satisfactory completion of our
obligations in Fences I and our expenditure of $4.0 million in exploration
costs.

         Fences III project area is 770,000 acres (3,122 sq. km) located
approximately 25 miles south of Fences I. In March 2003, we reached agreement
with the Ministry of the Environment in Poland on final principal terms, subject
to formal documentation, for 100% of the exploration rights to the Fences III
project area. As with the Fences I block, several gas fields located in the
Fences III block are fenced off from the exploration acreage. These fields,
discovered by POGC between 1967 and 1976, produced from both Rotliegendes
sandstone and Zechstein carbonate reservoirs. There has not been an exploration
program on this acreage in more than 25 years.

         We signed a Farmout Agreement covering the Fences I block in January
2003, with CalEnergy Gas (Holdings), Ltd., the upstream gas business unit of
MidAmerican Energy Holdings Company, whereby CalEnergy Gas has the right, but
not the obligation, to earn a 24.5% interest by spending a total of $10.6
million, including the cost to drill two wells, plus certain cash payments to
us. We are in early stage discussions with several SNS-experienced companies
regarding Fences II and Fences III.

         The Fences I, II and III project areas (a total of 1.7 million gross
acres or 6,911 sq. km) are all within an area of underexplored Rotliegendes
sandstone. To our knowledge, no exploration program focused on Rotliegendes gas
reserves has been undertaken in Poland using the technology available today, and
no sustained exploration effort has been made in the three Fences project areas
for Rotliegendes gas fields in the last 20 years.

                                       3
<PAGE>

         During the balance of 2003, we anticipate that CalEnergy Gas will drill
two wells in the Fences I project area. We will also be marketing the Fences II
project area to industry for farmout, and may see one well drilled in this area
in 2003. In addition, we will be evaluating and reprocessing seismic data, and
perhaps acquiring new seismic data, in the Fences III project area to prepare
for farming out. We also expect to advance our discussions with POGC concerning
the possible expansion of our joint interests in Poland.


         We are the operator and have a 100% interest in the Pomeranian project
area, except for Block 108, where we have an 85% interest and POGC has a 15%
interest. The Pomeranian project area is located in northwestern Poland and
consists of exploration rights covering approximately 2.2 million gross acres
lying along the underexplored northern edge of the Permian Basin in northwestern
Poland. The Pomeranian project area is relatively unexplored and has had little
oil and gas production. We believe portions of the Pomeranian project area may
be geologically similar to the producing trends along the southern edge of
Poland's Permian Basin. In the past, POGC provided us with existing seismic data
and well logs and cores from the Pomeranian project area for reprocessing and
analysis.

         The Wilga project area in central southeast Poland consists of
exploration rights on approximately 250,000 gross acres held by us, Apache
Corporation and POGC in Block 255, where the Wilga 2 discovery well is located.
We have a 45% working interest in the Wilga project area, which is operated by
Apache Corporation. We and our participants successfully completed an extended
flow test on the Wilga 2, confirming that the well appears to be capable of
producing at a commercial rate, but the well continues to be shut-in.


         References to us in this report include FX Energy, Inc., our
subsidiaries and the entities or enterprises organized under Polish law in which
we have an interest and through which we conduct our activities in that country.

The Republic of Poland

         The Republic of Poland is located in central Europe, has a population
of approximately 39 million people and covers an area comparable in size to New
Mexico. During 1989, Poland peacefully asserted its independence and became a
parliamentary democracy. Since 1989, Poland has enacted comprehensive economic
reform programs and stabilization measures that have enabled it to form a
free-market economy and turn its economic ties from the east to the west, with
most of its current international trade with the countries of the European Union
and the United States. The economy has undergone extensive restructuring in the
post-communist era. Gross domestic production had been strong and steady in 1993
through 2000, but fell back in 2001 and 2002 with slowdowns in domestic
investment and consumption and the persistent weakness in the European economy,
according to the CIA fact book on Poland. The contribution of the private sector
to gross domestic production rose from around 18% in 1989 to 39% in 1995 and 70%
in 1999, even though privatization has gone relatively slowly. Private-sector
nonagricultural employment rose from 14% of the labor force in 1989 to 61% in
1999. The Polish government credits foreign investment as a forceful growth
factor in successfully creating a stable free-market economy. According to the
Polish Foreign Investment Agency, cumulative foreign direct investment flow into
Poland is estimated to have aggregated approximately $62 billion from 1989
through mid-2002.

         Since its transition to a market economy and a parliamentary democracy,
Poland has experienced significant economic growth and political change. Poland
has developed and is refining legal, tax and regulatory systems characteristic
of parliamentary democracies with interpretation and procedural safeguards. The
Polish government has generally taken steps to harmonize Polish legislation with
that of the European Union in anticipation of Poland's entry into the European
Union in 2004 and to facilitate interaction with European Union members. Since
1995, the Polish corporate income tax rate has been reduced each year, and now
stands at 27% of net income.

         Poland has created an attractive legal framework and fiscal regime for
oil and gas exploration by actively encouraging investment by foreign companies
to offset its lack of capital to further explore its oil and gas resources. In
July 1995, Poland's Council of Ministers approved a program to restructure and
privatize the Polish petroleum sector. So far under this plan, a refinery
located in Plock has been privatized as a publicly-held company with its stock
trading on the London and Warsaw stock exchanges. We expect that the gas
distribution segments of POGC will be privatized next, followed by the
exploration, production and oilfield services segment. Increased participation

                                       4
<PAGE>

by Western companies using Western capital in the oil and gas sector is
consistent with the approved privatization policy.

         Prior to becoming a parliamentary democracy during 1989, the
exploration and development of Poland's oil and gas resources were hindered by a
combination of foreign influence, a centrally-controlled economy, limited
financial resources, and a lack of modern exploration technology. As a result,
Poland is currently a net energy importer. Oil is imported primarily from
countries of the former Soviet Union and the Middle East, and gas is imported
primarily from Russia. In the early 1990s, the World Bank loaned Poland $250
million to fund the purchase of new exploration and drilling equipment for
Poland's oil and gas industry to help shift its domestic sources of energy
consumed from coal to oil and natural gas. The following table highlights
selected statistics obtained from the U.S. Department of Energy regarding the
oil and gas industry in Poland:
<TABLE>
<CAPTION>
                                                               Oil                    Gas
                                                      ----------------------- ---------------------
         <S>                                           <C>                       <C>
         Proved reserves as of January 1, 2002.......    114.9 MMBbls            5.1 Tcf
         Average production per day during 2001......   14,000 Bbls per day      0.5 Bcf per day
         Average imports per day during 2001.........  420,000 Bbls per day      0.8 Bcf per day
</TABLE>

         During 1998, Poland joined NATO and has been invited to join the
European Union in 2004. In order to achieve member status in the European Union,
Poland must raise its environmental standards. In Poland, coal is the dominant
energy source, accounting for 65.4% of the country's annual energy consumption
as recently as 2000. Increased consumption of natural gas, as an alternative to
coal, is considered to be a key component in meeting the European Union's strict
environmental guidelines for its members. The demand for gas in Poland is
expected by some to increase in the future, primarily due to increased economic
growth coupled with the conversion to gas from coal as an energy source for
power plants. However, the demand for natural gas has remained flat and is
predicted by others to remain so over the next decade, due in large part to the
fact that natural gas is uneconomical for power generation in Poland compared to
coal, which is widely and cheaply produced.


         Poland has crude oil pipelines serving the major refineries and a
network of gas pipelines serving major metropolitan, commercial, industrial and
gas production areas, including significant portions of our acreage. Poland has
a well-developed infrastructure of hard-surfaced roads and railways over which
we believe oil produced could be transported for sale. There are refineries in
Gdansk and Plock in Poland and one in Germany near the western Polish border
that we believe could process any crude oil we may produce in Poland. All
facilities and pipelines currently used to gather and transport oil and gas in
Poland are owned and operated by POGC.

Exploration, Development and Production Activities in Poland

     Exploratory Activities in Poland

         Our strategy is to bring industry participants into our projects in
Poland to provide the capital for early-stage exploration drilling. In January
2003, we entered into a farmout agreement with CalEnergy Gas that allows it to
spend a total of $10.6 million by December 15, 2003, including the cost to drill
two wells plus certain cash payments to us, to earn a 24.5% interest (half of
our 49% interest) in our Fences I project area. Full performance by CalEnergy
Gas would more than cover our $4.4 million obligation to POGC and complete our
$16.0 million earning requirement for the Fences I project area. However, any
such payment to us is pledged to Rolls-Royce Power Ventures Limited, or RRPV,
until the note, with a principal balance of approximately $3.3 million, plus
interest, has been satisfied in full. We are seeking an industry participant for
our Fences II project area, and following our initial evaluation of the Fences
III area, we plan to seek other industry participants to join us.

                                       5
<PAGE>

     Polish Exploration Rights

         As of December 31, 2002, our oil and gas exploration rights in Poland
were comprised of the following gross acreage components:
<TABLE>
<CAPTION>
                                                                        Operator
                                                     -----------------------------------------------     Total
                                                       FX Energy         Apache           POGC          Acreage
                                                     --------------- --------------- --------------- ---------------
         <S>                                            <C>               <C>              <C>          <C>
         Project Area:
           Fences I(1)...............................          --              --          265,000        265,000
           Pomeranian(2).............................   2,200,000              --               --      2,200,000
           Wilga(3)..................................          --         250,000               --        250,000
                                                     --------------- --------------- --------------- ---------------
             Total gross acreage.....................   2,200,000         250,000          265,000      2,715,000
                                                     =============== =============== =============== ===============
</TABLE>
---------------------------
(1)  In April 2000, we entered into an agreement with POGC to earn 49% of POGC's
     100% interest in the Fences I project area by spending $16.0 million of
     exploration costs.
(2)  We own a 100% interest in the Pomeranian project area, except for Block 108
     (approximately 250,000 acres), where we own an 85% interest and POGC owns a
     15% interest.
(3)  We own a 45% interest, Apache owns a 45% interest and POGC owns a 10%
     interest in the Wilga project area.

The foregoing table excludes 670,000 acres in the Fences II project area,
operated by POGC, in which we have the right to acquire a 49% interest under a
January 2003 agreement, and 770,000 acres in the Fences III project area, to be
operated by us, in which we will have the right to acquire 100% of the
exploration rights, subject to final documentation.

         As we continue to explore and evaluate our acreage in Poland, we expect
to increasingly focus our operational and financial efforts on known productive
trends and recent discoveries. As we do so, we may elect not to retain our
interest in acreage that we determine carries a higher exploration risk.

         Fences I Project Area


         The Fences I project area consists of approximately 265,000 gross acres
(1,074 sq. km) in western Poland's Permian basin. Several gas fields located in
the Fences I block are excluded or "fenced off" from the exploration acreage.
These fields, discovered by POGC between 1974 and 1982, produce from
Rotliegendes sandstone reservoirs. The Rotliegendes is the primary target
horizon throughout most of the Fences I project area, at depths from about 2,800
to 3,200 meters, except along the extreme southwest portion where the target
reservoir is carbonates of the lower Permian.


         In April 2000, we agreed to spend $16.0 million on exploration costs in
the Fences I project area to earn a 49% interest. When expenditures exceed $16.0
million, POGC will pay its 51% share of further costs. To date, we have incurred
expenditures of $10.6 million (including $4.4 million in accrued liabilities
payable to POGC on or before December 31, 2003) toward the $16.0 million
commitment, leaving a remaining work commitment of $5.4 million.


         During 2000, we drilled the Kleka 11, our first Rotliegendes target,
which began producing in early 2001. During 2001, we drilled the Mieszkow 1, an
exploratory dry hole. The Mieszkow well demonstrated the need to apply modern
seismic processing and to assure careful handling of velocities in seismic
interpretation. In 2002, we reprocessed approximately 1,200 kilometers of
two-dimensional, or 2-D, seismic data that had not previously been processed
with modern geophysical techniques, covering most of the Fences area. POGC has
since begun reprocessing some of the three-dimensional, or 3-D, data in the
Fences I area.

         In January 2003, we entered into a Farmout Agreement with CalEnergy
Gas, the upstream gas business unit of MidAmerican Energy Holdings Company,
whereby CalEnergy Gas has the right, but not the obligation, to earn a 24.5%
interest by spending a total of $10.6 million, including the cost to drill two
wells plus certain cash payments to us, all to be completed by December 15,
2003. The operating committee has approved the Zaniemysl prospect as the first

                                       6
<PAGE>

well to be drilled under this farmout agreement, but the date drilling will
commence has not been determined. The parties are now preparing the drilling
plan, soliciting bids from drilling contractors, and completing other
predrilling details. If CalEnergy Gas completes all the earning requirements,
the work performed and payments will exceed our remaining obligations to POGC to
complete our earning requirements in the Fences I project area. However, any
such payment to us is pledged to RRPV until the note, with a principal balance
of approximately $3.3 million, plus interest, has been satisfied in full.

         In late 2002, as part of our discussions with POGC concerning the
CalEnergy Gas (Holdings), Ltd. Farmout Agreement and the opportunity to
participate with pogc in other exploration projects, we reaffirmed our intent to
fulfill the $16.0 million commitment with pogc under an agreement to restructure
our payments to pogc. See Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation: Introduction--Fences I Settlement
Agreement." As part of our future payments towards the remaining commitment, we
have agreed to assign in 2003, as soon as is practicable, all of our rights to
the Kleka 11 well, including $606,986 recorded as accounts receivable as of
December 31, 2002, for Kleka gas sales. The liability will be further offset in
2003 by the value of the remaining gas reserves associated with the Kleka well,
as determined by an independent engineer. As of December 31, 2002, we had
estimated proved, developed, producing gas reserves of 1,374 million cubic feet
of gas, with an estimated net present value, discounted at 10%, of approximately
$1.1 million. As a result of this agreement to transfer the Kleka 11 well, we
have not had any interest in production in Poland since December 31, 2002. We
agreed to convey our interest in the Kleka 11 well in order to conserve cash
while reducing the balance of our $16.0 million commitment to POGC in view of
our limited liquidity.


         Fences II Project Area

         The Fences II project area is 670,000 acres (2,715 sq. km) located
north of and contiguous with the Fences I block. POGC's Radlin field forms part
of the Fences II southern border. Under a January 2003 agreement, we have the
right to earn a 49% interest from POGC, subject to satisfactory completion of
our obligations in Fences I and our expenditure of $4.0 million in exploration
costs. In early 2002, Conoco, Inc., Ruhrgas and POGC drilled a dry hole in the
northeast of the Fences II area. The well, although dry, did confirm the
presence of reservoir quality Rotliegendes sandstone at a depth of more than
3,700 meters, which makes virtually the entire block prospective for
Rotliegendes subject to accurate geophysical resolution of the trapping
features.

         A significant amount of geological and geophysical work was completed
by POGC and Conoco before Conoco's withdrawal from the project at the end of
2002. As a result, we were able immediately to begin marketing drill-ready
prospects in the Fences II project area. We seek a farmout with an industry
participant as soon as possible, perhaps in time to drill in 2003. We are
currently evaluating the seismic data for possible reprocessing. Later this
year, we may acquire new 2-D data to define additional prospects for drilling.


         Fences III Project Area


         The Fences III project area is 770,000 acres (3,122 sq. km) located
approximately 25 miles south of Fences I. In March 2003, we reached agreement
with the Ministry of the Environment in Poland on final principal terms, subject
to formal documentation, for 100% of the exploration rights to the Fences III
project area. As with the Fences I block, several gas fields located in the
Fences III block are fenced off from the exploration acreage. These fields,
discovered by POGC between 1967 and 1976, produced from both Rotliegendes
sandstone and Zechstein carbonate reservoirs. There has not been an exploration
program on this acreage in 25 years.

         We are currently assembling the seismic data, quite abundant in the
northern portion of the block, for evaluation, mapping and possible
reprocessing. We will have to carry out a geophysical exploration program to
identify leads and prospects that merit drilling. Subject to the availability of
funds, we will carry out this work before seeking a farmout with an industry
participant. However, as we hold 100% interest in the area, we have greater
flexibility and could seek a farmout with an industry participant to help with
the geophysical costs if we so elected.

         The Fences I, II and III project areas (a total of 1.7 million gross
acres or 6,911 sq. km) are all within an area of underexplored Rotliegendes
sandstone. To our knowledge, no exploration program focused on Rotliegendes gas
reserves has been undertaken in Poland using the technology available today, and
no sustained exploration effort has been made in the three Fences project areas
for Rotliegendes gas fields in the last 20 years.

                                       7
<PAGE>

         Pomeranian Project Area

         We are the operator and have a 100% interest in the Pomeranian project
area, except for Block 108, where we have an 85% interest and POGC has a 15%
interest. The Pomeranian project area is located in northwestern Poland and
consists of exploration rights covering approximately 2.2 million gross acres
(9,000 sq. km.) lying along the underexplored northern edge of the Permian Basin
in northwestern Poland. The Pomeranian project area is relatively unexplored and
has had little oil and gas production. We believe portions of the Pomeranian
project area may be geologically similar to the producing trends along the
southern edge of Poland's Permian Basin. In the past, POGC provided us with
existing seismic data and well logs and cores from the Pomeranian project area
for reprocessing and analysis.

         During 2000 and 2001, we, Apache Corporation as operator, and POGC
acquired approximately 600 kilometers of new 2-D seismic data in the Pomeranian
project area and drilled two wells: the Tuchola 108-2 and the Chojnice 108-6. An
open-hole test on the Tuchola 108-2 resulted in a flow rate of 9.5 MMcf of gas
per day from the Main Dolomite Reef formation at a depth between 2,535 meters
and 2,595 meters. The Tuchola 108-2 well was subsequently completed in an
approximately 200 foot thick section of the Main Dolomite, but remains shut-in.
The Chojnice 108-6 was drilled at an offset location approximately three
kilometers northwest of the Tuchola 108-2 and was subsequently determined to be
an exploratory dry hole. The sustainable flow rate from the well cannot be
allowed to exceed 1.0 million cubic feet of gas per day to avoid production of
salt water, which would eventually choke off the production lines. We have been
approached by a potential gas customer with a proposal to utilize gas from the
Tuchola well for onsite power generation. In view of the limited sustainable
flow rate, we are not considering a pipeline connection. We intend to farm out
part of our interest in the entire Pomeranian project area to an industry
participant prior to conducting further exploratory activities.


         Wilga/Block 255 Project Area


         The Wilga project area in central southeast Poland consists of
exploration rights on approximately 250,000 gross acres held by us, Apache and
POGC in Block 255, where the Wilga 2 discovery well is located. We have a 45%
working interest in the Wilga project area, which is operated by Apache. Initial
production tests on the Wilga 2 yielded a combined gross flow rate of 16.9 MMcf
of gas and 570 Bbls of condensate per day from the Carboniferous formation at a
depth of approximately 2,800 meters. During 2001, we and our participants
successfully completed an extended flow test on the Wilga 2, confirming that the
well is capable of producing at a rate of approximately 5.0 million cubic feet
of gas and 300 barrels of oil per day. However, given the limited total reserves
and the estimated cost of production facilities and pipeline connection
approximately 18 kilometers distant, the well continues to be shut-in. We have
no current plans to place this well into commercial production in the light of
pipeline and facility expenditures that would be required. No further
exploration is planned for the block at this time, and we may farm out or sell
our interest.


Polish Properties

     Legal Framework

         General Usufruct and Concession Terms

         In 1994, Poland adopted the Geological and Mining Law, which specifies
the process for obtaining domestic exploration and exploitation rights. All of
our rights in Poland have been awarded pursuant to this law. Under the
Geological and Mining Law, the concession authority enters into oil, gas and
mining usufruct (lease) agreements that grant the holder the exclusive right to
explore or exploit the designated oil and gas or minerals for a specified period
under prescribed terms and conditions. The holder of the mining usufruct must
also acquire an exploration concession to obtain surface access to the
exploration area by applying to the concession authority and providing the
opportunity for comment by local governmental authorities.

         The concession authority has granted us oil and gas exploration rights
on the Wilga and Pomeranian project areas, is expected to do so on the Fences
III project area in the near future, and has granted POGC oil and gas

                                       8
<PAGE>

exploration rights on the Fences I and II project areas. The agreements divide
these areas into blocks, generally containing approximately 250,000 acres each.
Concession licenses have been acquired for surface access to all areas that lie
within existing usufructs, except Fences III. The first three-year exploration
period begins after the date of the last concession signed under each respective
usufruct. We believe all material concession terms have been satisfied to date.

         If commercially viable oil or gas is developed, the concession owner
would be required to apply for an exploitation concession, as provided by the
usufructs, generally with a term of 25 to 30 years or so long as commercial
production continues. Upon the grant of the exploitation concession, the
concession owner may become obligated to pay a fee, to be negotiated but
expected to be less than 1% of the market value of the estimated recoverable
reserves in place. The concession owner would also be required to pay a royalty
on any production, the amount of which will be set by the Council of Ministers,
within a range established by legislation for the mineral being extracted. The
royalty rate for gas is currently $0.03 per Mcf. This rate could be increased or
decreased by the Council of Ministers between $0.02 and $0.08 per Mcf (the
current statutory minimum and maximum royalty rate). Local governments will
receive 60% of any royalties paid on production. The holder of the exploitation
concession license must also acquire rights to use the land from the surface
owner. The usufruct owner could be subject to significant delays in obtaining
the consents of local authorities or satisfying other governmental requirements
prior to obtaining an exploitation concession.

         Fences I Project Area

         The Fences I project area consists of a single oil and gas exploration
concession controlled by POGC. Three producing fields lie within the concession
boundaries (Radlin, Kleka and Kaleje), but are excluded from the Fences I
project area. The concession is for a period of six years ending in September
2007 and carries a work requirement during the first three years of one
exploratory well, 70 square kilometers of 3-D seismic data, and reprocessing of
400 kilometers of 2-D seismic data. The seismic reprocessing requirement has
been completed.

         Fences II Project Area

         The Fences II project area consists of four oil and gas exploration
concessions controlled by POGC. The concessions have expiration dates ranging
from July 2004 to August 2007, with three-year extension rights. Remaining work
commitments in the aggregate include 70 kilometers of 3-D seismic, 250
kilometers of new 2-D seismic, 100 kilometers of seismic reprocessing and
drilling four wells.

         Fences III Project Area

         We expect that the formal agreement, when completed, for the Fences III
project area will provide for a single oil and gas exploration concession that
will be held by us. Several producing fields lie within the concession
boundaries, but are excluded from the Fences III project area. The concession
will be for a period of six years ending in mid-2009 and will carry a work
requirement during the first two years, which will not include any drilling.

         Wilga/Block 255 Project Area

         The Wilga project area consists of a single oil and gas exploration
concession controlled by Apache. The concession is for a period of six years
ending in August 2003, when the concession must be relinquished except for lands
within exploitation concessions or for which an application for an exploitation
concession has been filed. All work commitments have been completed.

         Pomeranian Project Area

         The Pomeranian project area consists of 10 oil and gas concessions
controlled by us. The concessions are for a period of six years ending in
December 2004, when the concession must be relinquished except for lands within
exploitation concessions or for which an application for an exploitation
concession has been filed. All work commitments have been completed except for
the drilling of one well in 2004.

                                       9
<PAGE>

         As of December 31, 2002, all required usufruct/concession payments had
been made for each of the above project areas.

     Production, Transportation and Marketing

         Poland has crude oil pipelines traversing the country and a network of
gas pipelines serving major metropolitan, commercial, industrial and gas
production areas, including significant portions of our acreage. Poland has a
well-developed infrastructure of hard-surfaced roads and railways over which we
believe oil produced could be transported for sale. There are refineries in
Gdansk and Plock in Poland and one in Germany near the western Polish border
that we believe could process crude oil produced in Poland. Should we choose to
export any oil or gas we produce, we will be required to obtain prior
governmental approval.

         During early 2001, we and POGC constructed a pipeline from the Kleka 11
well approximately four kilometers to POGC's Radlin field gas processing
facility and began selling gas produced to POGC at a price of $2.02 per MMBtu
under a five-year contract that may be terminated by us with a 90-day written
notice. The Kleka 11 is currently producing at a gross rate of approximately 1.0
MMcf of gas per day. As part of an agreement with POGC, we have agreed to assign
our interest in the Kleka 11 well, including amounts representing unpaid gas
sales, to POGC as partial settlement of the remaining obligation under our $16.0
million commitment to POGC. Accordingly, we will receive no net gas production
from the Kleka 11 well in 2003. See Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operation.

         The following table sets forth our average net daily gas production,
average sales price and average production costs associated with our Polish gas
production during 2002 and 2001:

                                                                2002      2001
                                                                ----      ----
         Polish producing property data:
           Average daily net gas production (Mcf)(1)........      494       800
           Average sales price per Mcf......................   $ 1.58    $ 1.58
           Average production costs per Mcf(2)..............   $ 0.16    $ 0.16
---------------------
(1)  Consists solely of the Kleka 11 well, which began producing on February 22,
     2001, and which we have now agreed to transfer to POGC. Production was
     curtailed in 2002 to control the production of water.
(2)  Production costs include lifting costs (electricity, fuel, water, disposal,
     repairs, maintenance, pumper, transportation and similar items). Production
     costs do not include such items as G&A costs, depreciation, depletion or
     Polish income taxes.

         We did not have any Polish oil or gas production during 2000.

                                       10
<PAGE>

United States Properties

     Producing Properties

         In the United States, we currently produce oil in Montana and Nevada.
All of our producing properties, except for the Rattlers Butte field (an
exploratory discovery during 1997), were purchased during 1994. A summary of our
average daily production, average working interest and net revenue interest for
our United States producing properties during 2002 follows:
<TABLE>
<CAPTION>
                                                     Average Daily Production
                                                              (Bbls)                Average           Average
                                                    ----------------------------    Working         Net Revenue
                                                       Gross           Net         Interest          Interest
                                                    ------------- -------------- -------------- --------------------
         <S>                                             <C>           <C>             <C>             <C>
         United States producing properties:
           Montana:
             Cut Bank............................        257           220             99.5%           85.7%
             Bears Den...........................         16             6             48.0            39.2
             Rattlers Butte......................         48             3              6.3             5.1
                                                    ------------- --------------
               Total.............................        321           229
                                                    ------------- --------------
           Nevada:
             Trap Spring.........................         10             2             21.6            20.0
             Munson Ranch........................         40            14             36.0            34.1
             Bacon Flat..........................         36             4             16.9            12.5
                                                    ------------- --------------
               Total.............................         86            20
                                                    ------------- --------------
                 Total United States producing
                    properties...................        407           249
                                                    ============= ==============
</TABLE>


         In Montana, we operate the Cut Bank and Bears Den fields and have an
interest in the Rattlers Butte field, which is operated by an industry
participant. Production in the Cut Bank field commenced with the discovery of
oil in the 1940s at an average depth of approximately 2,900 feet. The Southwest
Cut Bank Sand Unit, which is the core of our interest in the field, was
originally formed by Phillips Petroleum Company in 1963. An initial pilot
waterflood program was started in 1964 by Phillips and eventually encompassed
the entire unit with producing wells on 40 and 80-acre spacing. In the Cut Bank
field, we own an average working interest of 99.5% in 93 producing oil wells, 27
active injection wells and one active water supply well. The Bears Den field was
discovered in 1929 and has been under waterflood since 1990. In the Bears Den
field, we own a 48% working interest in three active water injection wells and
five producing oil wells, which produce oil at a depth of approximately 2,430
feet. The Rattlers Butte field was discovered during 1997. In the Rattlers Butte
field, we own a 6.3% working interest in two oil wells producing at a depth of
approximately 5,800 feet and one active water injection well.

         In Nevada, we operate the Trap Spring and Munson Ranch fields and have
an interest in the Bacon Flat field, which is operated by an industry
participant. The Trap Spring field was discovered in 1976. In the Trap Spring
field, we produce oil from a depth of approximately 3,700 feet from one well,
with a working interest of 21.6%. The Munson Ranch field was discovered in 1988.
In the Munson Ranch field, we produce oil at an average depth of 3,800 feet from
five wells, with an average working interest of 36%. The Bacon Flat field was
discovered in 1981. In the Bacon Flat field, we produce oil from one well at a
depth of approximately 5,000 feet, with a 16.9% working interest.

                                       11
<PAGE>

     Production, Transportation and Marketing

         The following table sets forth our average net daily oil production,
average sales price and average production costs associated with our United
States oil production during 2002, 2001 and 2000:
<TABLE>
<CAPTION>
                                                                                    Years Ended December 31,
                                                                              -------------------------------------
                                                                                 2002         2001         2000
                                                                              -----------  -----------  -----------
         <S>                                                                   <C>          <C>         <C>
         United States producing property data:
           Average daily net oil production (Bbls)..........................      249          256          265
           Average sales price per Bbl......................................   $21.19       $19.41       $26.14
           Average production costs per Bbl(1)..............................   $14.59       $14.50       $13.99
</TABLE>
-------------------------
(1)  Production costs include lifting costs (electricity, fuel, water, disposal,
     repairs, maintenance, pumper, transportation and similar items) and
     production taxes. Production costs do not include such items as G&A costs,
     depreciation, depletion, state income taxes or federal income taxes.

         We sell oil at posted field prices to one of several purchasers in each
of our production areas. For the first half of 2002 and for the years ended
December 31, 2001 and 2000, more than 85% of our total oil sales were to CENEX,
a regional refiner and marketer. In June 2002, we began selling our Montana
production, which represents over 85% of our total oil sales, to Plains
Marketing Canada L.P. Posted prices are generally competitive among crude oil
purchasers. Our crude oil sales contracts may be terminated by either party upon
30 days' notice.

     Oilfield Services - Drilling Rig and Well-Servicing Equipment


         In Montana, we perform, through our drilling subsidiary, FX Drilling
Company, Inc., a variety of third-party contract oilfield services, including
drilling, workovers, location work, cementing and acidizing. We currently have a
drilling rig capable of drilling to a vertical depth of 6,000 feet, a workover
rig, two service rigs, cementing equipment, acidizing equipment and other
associated oilfield servicing equipment. We first started our oilfield servicing
business in 1998 in an effort to increase our United States revenues, which had
been declining due to the depressed oil prices that had occurred throughout that
year.


Proved Reserves

         Proved reserves are the estimated quantities of crude oil that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reserves under existing economic and
operating conditions. Our proved oil and gas reserve quantities and values are
based on estimates prepared by independent reserve engineers in accordance with
guidelines established by the Securities and Exchange Commission, or SEC.
Operating costs, production taxes and development costs were deducted in
determining the quantity and value information. Such costs were estimated based
on current costs and were not adjusted to anticipate increases due to inflation
or other factors. No price escalations were assumed and no amounts were deducted
for general overhead, depreciation, depletion and amortization, interest expense
and income taxes. The proved reserve quantity and value information is based on
the weighted average price on December 31, 2002, of $25.00 per Bbl for oil in
the United States and $2.60 per Mcf of gas in Poland. The determination of oil
and gas reserves is based on estimates and is highly complex and interpretive,
as there are numerous uncertainties inherent in estimated quantities and values
of proved reserves, projecting future rates of production and timing of
development expenditures. The estimated present value, discounted at 10% per
annum, of the discounted future net cash flows, or PV-10 Value, was determined
in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities" and SEC
guidelines. Our proved reserve estimates are subject to continuing revisions as
additional information becomes available or assumptions change.

         Estimates of our proved United States oil reserves were prepared by
Larry Krause Consulting, an independent engineering firm in Billings, Montana.
Estimates of our proved Polish gas reserves were prepared by Troy-Ikoda Limited,
an independent engineering firm in the United Kingdom. No estimates of our
proved reserves have been filed with or included in any report to any other
federal agency during 2002.

                                       12
<PAGE>

         The following summary of proved reserve information as of December 31,
2002, represents estimates net to us only and should not be construed as exact:
<TABLE>
<CAPTION>
                                               United States                    Poland
                                        ----------------------------  ---------------------------       Total
                                            Oil       PV-10 Value         Gas       PV-10 Value      PV-10 Value
                                        ------------ ---------------  ------------ -------------- ------------------
                                          (MBbls)    (In thousands)      (MMcf)    (In thousands)   (In thousands)
         Proved reserves:
         <S>                              <C>             <C>            <C>          <C>             <C>
           Developed producing.........    1,015          $  5,190       1,374        $  1,066        $  6,256
           Undeveloped.................       27               190       2,836           3,774           3,964
                                        ------------ ---------------  ------------ -------------- ------------------
             Total.....................    1,042          $  5,380       4,210        $  4,840         $10,220
                                        ============ ===============  ============ ============== ==================
<CAPTION>
Drilling Activities

         The following table sets forth the exploratory wells that we drilled
during the years ended December 31, 2002, 2001 and 2000:

                                                                      Years Ended December 31,
                                                 -------------------------------------------------------------------
                                                         2002                   2001                   2000
                                                 ---------------------  ---------------------  ---------------------
                                                   Gross       Net       Gross        Net       Gross        Net
                                                 ---------- ----------  ---------  ----------  ---------  ----------
         <S>                                        <C>         <C>       <C>        <C>          <C>        <C>
         Discoveries:
           United States.......................     --          --        --         --           --         --
           Poland..............................     --          --         1.0        0.5          1.0        0.5
                                                 ---------- ----------  ---------  ----------  ---------  ----------
             Total.............................     --          --         1.0        0.5          1.0        0.5
                                                 ---------- ----------  ---------  ----------  ---------  ----------

         Exploratory dry holes:
           United States.......................     --          --        --         --           --         --
           Poland..............................     --          --         2.0        1.0          2.0        1.0
                                                 ---------- ----------  ---------  ----------  ---------  ----------
             Total.............................     --          --         2.0        1.0          2.0        1.0
                                                 ---------- ----------  ---------  ----------  ---------  ----------

         Total wells drilled...................     --          --         3.0        1.5          3.0        1.5
                                                 ========== ==========  =========  ==========  =========  ==========
</TABLE>
         We did not drill any exploratory wells in 2002, and we did not drill
any development wells during 2002, 2001 or 2000.

Wells and Acreage

         As of December 31, 2002, our producing gross and net well count
consisted of the following:

                                                              Number of Wells
                                                         -----------------------
                                                           Gross         Net
                                                         -----------  ----------
         Well count:
           United States(1)...............................   118.0       107.2
           Poland(2)......................................     1.0         0.5
                                                         -----------  ----------
             Total........................................   119.0       107.7
                                                         ===========  ==========
------------------------
(1) All of our United States wells are producing oil wells. We have no gas
    production in the United States.
(2) Includes only the Kleka 11, a producing gas well which we have now agreed
    to transfer to POGC.

                                       13
<PAGE>

         The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2002:
<TABLE>
<CAPTION>
                                                                   Developed                    Undeveloped
                                                          ----------------------------  ----------------------------
                                                             Gross           Net           Gross           Net
                                                          ----------------------------  ----------------------------
<S>                                                           <C>            <C>          <C>           <C>
         United States:
           North Dakota.................................          --             --           7,955         5,351
           Montana......................................      10,732         10,418           1,150         1,057
           Nevada.......................................         400            128              37            16
                                                          -------------  -------------  -------------  --------------
              Total.....................................      11,132         10,546           9,142         6,424
                                                          -------------  -------------  -------------  --------------

         Poland: (1)(2)
           Fences I project area(3).....................         225            110         265,000       130,000
           Wilga project area...........................         543            244         250,000       113,000
           Pomeranian project area(4)...................          --             --       2,200,000     2,135,000
                                                          -------------  -------------  ------------- --------------
               Total Polish acreage.....................         768            354       2,715,000     2,378,000
                                                          -------------  -------------  ------------- --------------

         Total Acreage..................................      11,900         10,900       2,724,142     2,384,424
                                                          =============  =============  ============= ==============
</TABLE>
----------------------
(1)  All gross undeveloped Polish acreage is rounded to the nearest 50,000 acres
     and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.
(2)  Developed acreage in the Fences project areas is attributable only to the
     Kleka 11 well, which we have now agreed to transfer to POGC. The net
     acreage amount assumes we spend $16.0 million of exploration expenditures
     to earn a 49% interest.
(3)  Excludes acreage in which we may earn an interest under arrangements
     reached after December 31, 2002.
(4)  We own a 100% interest in the Pomeranian project area, except for Block 108
     (approximately 250,000 acres), where we own an 85% interest.

Government Regulation

     Poland

         Our activities in Poland are subject to political, economic and other
uncertainties, including the adoption of new laws, regulations or administrative
policies that may adversely affect us or the terms of our exploration or
production rights; political instability and changes in government or public or
administrative policies; export and transportation tariffs and local and
national taxes; foreign exchange and currency restrictions and fluctuations;
repatriation limitations; inflation; environmental regulations and other
matters. These operations in Poland are subject to the Geological and Mining Law
dated as of September 4, 1994, and the Protection and Management of the
Environment Act dated as of January 31, 1980, which are the current primary
statutes governing environmental protection. Agreements with the government of
Poland respecting our areas create certain standards to be met regarding
environmental protection. Participants in oil and gas exploration, development
and production activities generally are required to (1) adhere to good
international petroleum industry practices, including practices relating to the
protection of the environment; and (2) prepare and submit geological work plans,
with specific attention to environmental matters, to the appropriate agency of
state geological administration for its approval prior to engaging in field
operations such as seismic data acquisition, exploratory drilling and field-wide
development. Poland's regulatory framework respecting environmental protection
is not as fully developed and detailed as that which exists in the United
States. We intend to conduct our operations in Poland in accordance with good
international petroleum industry practices and, as they develop, Polish
requirements.

         As Poland continues to progress towards its stated goal of becoming a
member of the European Union, it is expected to pass further legislation aimed
at harmonizing Polish environmental law with that of the European Union.

     United States

         State and Local Regulation of Drilling and Production

         Our exploration and production 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

                                       14
<PAGE>

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, and the plugging and abandoning of wells. Our
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 that may be drilled and the unitization or
pooling of oil and gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. 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.

         Our oil production is affected to some degree by state regulations.
States in which we operate have statutory provisions regulating the production
and sale of oil and gas, including provisions regarding deliverability. Such
statutes and related regulations are generally intended to prevent waste of oil
and gas and to protect correlative rights to produce oil and gas between owners
of a common reservoir. Certain state regulatory authorities also regulate the
amount of oil and gas produced by assigning allowable rates of production to
each well or proration unit.

         Environmental Regulations

         The federal government and various state and local governments have
adopted laws and regulations regarding the control of contamination of the
environment. These laws and regulations may require the acquisition of a permit
by operators before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution resulting from
our operations. These laws and regulations may also increase the costs of
drilling and operation of wells. We may also be held liable for the costs of
removal and damages arising out of a pollution incident to the extent set forth
in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act
of 1990, or OPA `90. In addition, we may be subject to other civil claims
arising out of any such incident. As with any owner of property, we are also
subject to clean-up costs and liability for hazardous materials, asbestos or any
other toxic or hazardous substance that may exist on or under any of our
properties. We believe that we are in compliance in all material respects with
such laws, rules and regulations and that continued compliance will not have a
material adverse effect on our operations or financial condition. Furthermore,
we do not believe that we are affected in a significantly different manner by
these laws and regulations than our competitors in the oil and gas industry.

         The Comprehensive Environmental Response, Compensation and Liability
Act, or 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 who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources, and for the costs of certain
health studies. Furthermore, it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.

         The Resource Conservation and Recovery Act, or RCRA, and regulations
promulgated thereunder govern the generation, storage, transfer and disposal of
hazardous wastes. RCRA, however, excludes from the definition of hazardous
wastes "drilling fluids, produced waters and other wastes associated with the
exploration, development, or production of crude oil, gas or geothermal energy."
Because of this exclusion, many of our operations are exempt from RCRA
regulation. Nevertheless, we must comply with RCRA regulations for any of our
operations that do not fall within the RCRA exclusion.

         The OPA `90 and related regulations impose a variety of regulations on
responsible parties related to the prevention of oil spills and liability for
damages resulting from such spills. OPA `90 establishes strict liability for
owners of facilities that are the site of a release of oil into "waters of the
United States." While OPA `90 liability more typically applies to facilities
near substantial bodies of water, at least one district court has held that OPA
`90 liability can attach if the contamination could enter waters that may flow
into navigable waters.

                                       15
<PAGE>

         Stricter standards in environmental legislation may be imposed on the
oil and gas industry in the future, such as proposals made in Congress and at
the state level from time to time, that would reclassify certain oil and gas
exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent and costly handling, disposal and
clean-up requirements. The impact of any such changes, however, would not likely
be any more burdensome to us than to any other similarly situated company
involved in oil and gas exploration and production.

         Federal and Indian Leases

         A substantial part of our producing properties in Montana consist of
oil and gas leases issued by the Bureau of Land Management or by the Blackfeet
Tribe under the supervision of the Bureau of Indian Affairs. These activities
must comply with rules and orders that regulate aspects of the oil and gas
industry, including drilling and operating on leased land and the calculation
and payment of royalties to the federal government or the governing Indian
nation. Operations on Indian lands must also comply with applicable requirements
of the governing body of the tribe involved including, in some instances, the
employment of tribal members. We believe we are currently in full compliance
with all material provisions of such regulations.

         Safety and Health Regulations

         We must also conduct our operations in accordance with various laws and
regulations concerning occupational safety and health. Currently, we do not
foresee expending material amounts to comply with these occupational safety and
health laws and regulations. However, since such laws and regulations are
frequently changed, we are unable to predict the future effect of these laws and
regulations.

Title to Properties

         We rely on sovereign ownership of exploration rights and mineral
interests by the Polish government in connection with our activities in Poland
and have not conducted and do not plan to conduct any independent title
examination. We regularly consult with our Polish legal counsel when doing
business in Poland.

         Nearly all of our United States working interests are held under leases
from third parties. We typically obtain a title opinion concerning such
properties prior to the commencement of drilling operations. We have obtained
such title opinions or other third-party review on nearly all of our producing
properties, and we believe that we have satisfactory title to all such
properties sufficient to meet standards generally accepted in the oil and gas
industry. Our United States properties are subject to typical burdens, including
customary royalty interests and liens for current taxes, but we have concluded
that such burdens do not materially interfere with the use of such properties.
Further, we believe the economic effects of such burdens have been appropriately
reflected in our acquisition cost of such properties and reserve estimates.
Title investigation before the acquisition of undeveloped properties is less
thorough than that conducted prior to drilling, as is standard practice in the
industry.

Employees and Consultants

         As of December 31, 2002, we had 28 employees, consisting of six in Salt
Lake City, Utah; 19 in Oilmont, Montana; one in Greenwich, Connecticut; and two
in Houston, Texas. Our employees are not represented by a collective bargaining
organization. We consider our relationship with our employees to be
satisfactory. We also regularly engage technical consultants to provide specific
geological, geophysical and other professional services.


         We have no employees residing in Poland but rely on others to conduct
field operations or provide services under consulting or other contracts. Our
executive officers and other management employees regularly travel to Poland to
supervise activities conducted by others under contract on our behalf.

                                       16
<PAGE>

Offices and Facilities

         Our corporate offices, located at 3006 Highland Drive, Salt Lake City,
Utah, contain approximately 3,010 square feet and are rented at $2,960 per month
under a month-to-month agreement. In Montana, we own a 16,160 square foot
building located at the corner of Central and Main in Oilmont, where we utilize
4,800 square feet for our field office and rent the remaining space to unrelated
third parties for $875 per month. In Poland, we rent a small office suite for
$1,400 per month in Warsaw, at Al. Jana Pawla II 29, as an office of record in
Poland.

Oil and Gas Terms

         The following terms have the indicated meaning when used in this
report:

         "Bcf" means billion cubic feet of natural gas.

         "Bbl" means barrel of oil.

         "Btu" means British thermal units.

         "Carried" or "Carry" refers to an agreement under which one party
         (carrying party) agrees to pay for all or a specified portion of costs
         of another party (carried party) on a property in which both parties
         own a portion of the working interest.

         "Condensate" means a light hydrocarbon liquid, generally natural
         gasoline (C5 to C10), that condenses to a liquid (i.e., falls out of
         wet gas) as the wet gas is sent through a mechanical separator near the
         well.

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

         "Exploratory well" means a well drilled to find and produce oil or gas
         in an unproved area, to find a new reservoir in a field previously
         found to be productive of oil or gas in another reservoir or to extend
         a known reservoir.

         "Field" means 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 conditions.

         "Gross" acres and "gross" wells means the total number of acres or
         wells, as the case may be, in which an interest is owned, either
         directly or though a subsidiary or other Polish enterprise in which we
         have an interest.

         "Horizon" means an underground geological formation that is the portion
         of the larger formation that has sufficient porosity and permeability
         to constitute a reservoir.

         "MBbls" means thousand barrels of oil.


         "Mcf" means thousand cubic feet of natural gas.


         "MMBbls" means million barrels of oil.

         "MMBtu" means million British thermal units, a unit of heat energy used
         to measure the amount of heat that can be generated by burning gas or
         oil.

         "MMcf" means million cubic feet of natural gas.

                                       17
<PAGE>

         "Net" means, when referring to wells or acres, the fractional ownership
         working interests held by us, either directly or through a subsidiary
         or other Polish enterprise in which we have an interest, multiplied by
         the gross wells or acres.

         "Proved reserves" means the estimated quantities of crude oil, gas and
         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, i.e.,
         prices and costs as of the date the estimate is made. "Proved reserves"
         may be developed or undeveloped.

         "PV-10 Value" means the estimated future net revenue to be generated
         from the production of proved reserves discounted to present value
         using an annual discount rate of 10.0%. These amounts are calculated
         net of estimated production costs and future development costs, using
         prices and costs in effect as of a certain date, without escalation and
         without giving effect to non property-related expenses, such G&A costs,
         debt service, future income tax expense or depreciation, depletion and
         amortization.

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

         "Tcf" means trillion cubic feet of natural gas.


--------------------------------------------------------------------------------
                            ITEM 3. LEGAL PROCEEDINGS
--------------------------------------------------------------------------------

         We are not a party to any material legal proceedings, and no material
legal proceedings have been threatened by us or, to the best of our knowledge,
against us.


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

         No matter was submitted to a vote of our security holders during the
fourth quarter of the fiscal year ended December 31, 2002.

                                       18
<PAGE>

                                     PART II

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

Price Range of Common Stock and Dividend Policy

         The following table sets forth for the periods indicated the high and
low closing prices for our common stock as quoted under the symbol "FXEN" on the
Nasdaq SmallCap Market:

                                                                Low       High
                                                                ---       ----
         2003:
           First Quarter (through March 20, 2003)...........   $2.60      $3.54

         2002:
           Fourth Quarter...................................    2.24       3.04
           Third Quarter....................................    1.83       2.99
           Second Quarter...................................    1.99       2.98
           First Quarter....................................    1.97       3.01

         2001:
           Fourth Quarter...................................    1.81       3.00
           Third Quarter....................................    2.55       3.20
           Second Quarter...................................    2.91       6.20
           First Quarter....................................    3.50       5.94

         We have never paid cash dividends on our common stock and do not
anticipate that we will pay dividends in the foreseeable future. We intend to
reinvest any future earnings to further expand our business. We estimate that,
as of March 20, 2003, we had approximately 4,100 stockholders.

         Our common stock is currently traded on the Nasdaq SmallCap Market
under the symbol FXEN.

Recent Sales of Unregistered Securities


         In August 2002, we granted to certain directors, executive officers and
employees options to purchase an aggregate of 551,000 shares of common stock at
$2.40 per share at any time on or before seven years after the date of grant,
including options granted to officers and directors as follows:

                                   Name                           Number
                                                                -----------
        David N. Pierce.........................................  85,000
        Andrew W. Pierce........................................  75,000
        Thomas B. Lovejoy.......................................  75,000
        Scott J. Duncan.........................................  75,000
        Jerzy B. Maciolek.......................................  75,000
        Peter L. Raven..........................................  10,000
        Clay Newton.............................................  10,000
                                                                 -------
            Total                                                405,000
                                                                 =======

In addition to the 405,000 options awarded to executive officers and directors,
we awarded an aggregate of 146,000 options to a total of 18 employees, each of
whom had been a regular, full-time employee of ours for more than one year.

                                       19
<PAGE>

         In June 2002, we issued to one unaffiliated person and one unaffiliated
entity an aggregate of 20,682 shares of common stock as payment for financial
advisory services rendered. On the date of these transactions, the market price
for our common stock was approximately $2.15. Each purchaser was an accredited
investor, was provided with our business and financial information, including
copies of our periodic reports as filed with the Securities and Exchange
Commission, and was provided with the opportunity to ask questions directly of
our executive officers.

         On March 13, 2003, we sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities to six unaffiliated
purchasers, raising a total of approximately $5.6 million after offering costs.
Each of the purchasers was an accredited investor who was provided with a
private placement memorandum detailing our business and financial information,
including copies of our periodic reports as filed with the Securities and
Exchange Commission, and who was provided with the opportunity to ask questions
directly of our executive officers. Each share of preferred stock is convertible
into one share of common stock and one warrant to purchase one share of common
stock at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The
preferred stock has a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.

         The net proceeds from the offering, plus our available cash, were used
to reduce our obligation to Rolls-Royce Power Ventures Limited, or RRPV, by
approximately $2.2 million (see discussion of RRPV note amendment below), and
have been allocated to partially reduce our obligation to POGC, fund ongoing
geological and geophysical costs in Poland, and support ongoing prospect
marketing and general and administrative costs.

         In each of the above transactions, the securities purchased were
restricted securities taken for investment. Certificates for all shares issued
in the such transactions bore a restrictive legend conspicuously on their face
and stop-transfer instructions were noted respecting such certificates on our
stock transfer records. Each of the foregoing transactions was effected in
reliance on the exemption from registration provided in Section 4(2) of the
Securities Act of 1933 as transactions not involving any public offering.

                                       20
<PAGE>

--------------------------------------------------------------------------------
                         ITEM 6. SELECTED FINANCIAL DATA
--------------------------------------------------------------------------------

         The following selected consolidated financial data for the five years
ended December 31, 2002, are derived from our audited financial statements and
notes thereto, certain of which are included in this report. The selected
consolidated financial data should be read in conjunction with our Consolidated
Financial Statements and the Notes thereto included elsewhere in this report:
<TABLE>
<CAPTION>

                                                                    Years Ended December 31,
                                             -------------------------------------------------------------------------
                                                2002          2001           2000           1999           1998
                                             ----------- ------------- -------------- --------------- ----------------
                                                                       (As Restated)(1)(As Restated)(1)(As Restated)(1)
                                                        (In thousands, except per share amounts)
<S>                                          <C>           <C>            <C>            <C>            <C>
Statement of Operations Data:
  Revenues:
    Oil and gas sales....................... $    2,209    $    2,229     $    2,521     $    1,554     $    1,124
    Oilfield services.......................        533         1,584          1,290            865            323
    Gain on sale of property interests......         --            --             --             --            467
                                             ----------    ----------     ----------     ----------     ----------
      Total revenues........................      2,742         3,813          3,811          2,419          1,914
                                             ----------    ----------     ----------     ----------     ----------
  Operating costs and expenses:
    Lease operating costs (2)...............      1,365         1,358          1,349            962          1,046
    Exploration costs (3)...................      1,541         6,544          7,389          3,053          2,127
    Proved property impairment (4)..........      1,038            --             --             --          5,885
    Oilfield services costs.................        540         1,301          1,084            642            240
    Depreciation, depletion and
      amortization..........................        618           662            386            494            672
    Amortization of deferred
      compensation (G&A)....................         55         1,078            652             --             --
    Variable stock option
      compensation (G&A)....................         --            --             --           (645)           645
    Apache Poland general and
      administrative costs..................         --           575            957             --             --
    General and administrative..............      2,440           883          2,654          2,962          2,663
                                             ----------    ----------     ----------     ----------     ----------
        Total operating costs and expenses..      7,597        12,401         14,471          7,468         13,278
                                             ----------    ----------     ----------     ----------     ----------

  Operating loss............................     (4,855)       (8,588)       (10,660)        (5,049)       (11,364)
                                             ----------    ----------     ----------     ----------     ----------

  Other income (expense):
    Interest and other income...............        119           543            417            377            442
    Interest expense........................     (1,189)         (331)            (2)            (7)            --
    Impairment of notes receivable..........         --           (34)            --             --             --
                                             ----------    ----------     ----------     ----------     ----------
        Total other income (expense)........     (1,070)          178            415            370            442
                                             ----------    ----------     ----------     ----------     ----------
  Net loss.................................. $   (5,925)   $   (8,410)    $  (10,245)    $   (4,679)    $  (10,922)
                                             ==========    ==========     ==========     ==========     ==========

  Basic and diluted net loss per share:
      Net loss.............................. $    (0.34)   $    (0.48)    $    (0.62)    $    (0.33)    $    (0.84)
                                             ==========    ==========     ==========     ==========     ==========

  Basic and diluted weighted average
    shares outstanding......................     17,641        17,673         16,435         14,199         12,979

                                                    - Continued -

                                       21
<PAGE>
<CAPTION>
                                                                    Years Ended December 31,
                                             -------------------------------------------------------------------------
                                                2002          2001           2000           1999           1998
                                             ----------- ------------- -------------- --------------- ----------------
                                                                                      (As Restated)(4)(As Restated)(4)
                                                                      (In thousands)
<S>                                          <C>           <C>            <C>            <C>            <C>
Cash Flow Statement Data:
  Net cash used in operating activities..... $   (2,162)   $   (3,248)    $   (6,082)    $   (2,984)    $   (3,091)
  Net cash provided by (used in)
    investing activities....................       (295)          326         (3,834)        (3,678)         1,066
  Net cash provided by (used in)
    financing activities....................          5         5,000          9,375          6,469           (674)

Balance Sheet Data:
  Working capital........................... $   (9,150)   $      558     $      616     $    5,459     $    3,965
  Total assets..............................      5,441         9,168         10,570         10,470          8,253
  Long-term debt............................         --         4,907             --             --             --
  Stockholders' equity......................     (4,869)          953          8,231          8,367          6,920
</TABLE>
------------------------


(1)  As a result of the restatement discussed in Note 19 to the Consolidated
     Financial Statements, the Company has applied variable stock option
     accounting to certain officer loans in 1998. As a result, the interest
     income of $64 and $134 recorded in 1998 and 1999, respectively, and the
     impairment charges of $666 and $738 recorded in 1999 and 2000,
     respectively, were reversed. In addition, compensation expense of $736 ($91
     of which is not related to the variable option plan and is recorded in
     general and administrative expenses) was recorded in 1998, $645 of which
     was reversed to income in 1999 due to a decrease in the stock price.
(2)  Includes lease operating expenses and production taxes.
(3)  Includes geophysical and geological costs, exploratory dry hole costs and
     nonproducing leasehold impairments.
(4)  Includes proved property write downs relating to our properties in the
     United States and Poland.


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

         The following discussion of our historical financial condition and
results of operations should be read in conjunction with Item 6. "Selected
Consolidated Financial Data," our Consolidated Financial Statements and related
Notes contained in this report.

Introduction


         As of December 31, 2002, we had approximately $700,000 of cash and cash
equivalents, a working capital deficit of approximately $9.2 million, and a
stockholders' deficit of approximately $4.9 million. In addition, we have a
remaining commitment of $5.4 million that must be spent by us (in addition to
payment of the $4.4 million to POGC, which is included in our accrued
liabilities at December 31, 2002), in order to complete our earning obligation
in our Fences project areas. These factors cause uncertainty about our ability
to continue as a going concern.

         Since December 31, 2002, we obtained $5.6 million in equity funding,
reached new terms respecting our Fences 1 obligations, extended our RRPV
obligation with revised terms and entered into a farmout agreement with
CalEnergy Gas under which it may provide cash and drilling funds of up to $10.6
million. Our primary obligations through the end of 2003 include $3.3 million
principal amount plus interest due RRPV at year end, $4.4 million plus interest
due POGC at year end, $5.4 million of Fences I work commitment, and
approximately $1.8 million for general, administrative and marketing expenses,
for a total of approximately $16.0 million, plus any geological and geophysical
costs we may wish to expend. Offsetting these amounts, we have $3.8 million in
available cash and may look forward to other sources of funds including $10.6
million of work and cash that may be realized under the CalEnergy Gas Farmout
Agreement, $0.6 million in accrued Kleka 11 production revenue, and an amount to
be determined (PV-10 value $1.1 million) for the future value of Kleka 11
production, for an approximate total of approximately $16.0 million. In
addition, we have the right to earn a 49% interest in the Fences II project area
and anticipate completing documentation soon for a 100% interest in the Fences
III project area. We believe we can arrange with industry participants to trade
a portion of our interest in these properties for drilling funds and cash
payments that will exceed our related acquisition or earning and any related
geological and geophysical costs.

                                       22
<PAGE>

         Despite these events, we cannot assure that we will be able to continue
or that the report of our auditors on our financial statements for the year
ended December 31, 2003, will not contain a qualifying paragraph about our
ability to continue as a going concern similar to the explanatory paragraph
regarding our financial statements for 2002 and previous years.


     Private Placement of Convertible Preferred Stock

         On March 13, 2003, we sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of $5.6
million after offering costs. Each share of preferred stock is convertible into
one share of common stock and one warrant to purchase one share of common stock
at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The
preferred stock has a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.

         The net proceeds from the offering, plus our available cash, were used
to reduce our obligation to RRPV (see discussion of RRPV note amendment below),
fund ongoing geological and geophysical costs in Poland, and support ongoing
prospect marketing and general and administrative costs.

     CalEnergy Gas Agreement

         In January 2003, we signed a farmout agreement with CalEnergy Gas
(Holdings) Ltd., an affiliate of MidAmerican Energy Holdings Company, for the
joint exploration of our Fences I project in Poland. Under the terms of the
agreement, CalEnergy Gas has the right, but not the obligation, to pay 100% of
the costs to drill an initial well, and by so doing, will earn a 24.5% interest
(50% of our interest) in that drilling prospect. Following the completion of the
initial well, CalEnergy Gas may elect to terminate the agreement or to drill a
second well. If CalEnergy Gas elects to drill a second well, it will pay us $1
million prior to drilling. CalEnergy Gas will pay 100% of the costs to drill a
second well to earn 24.5% interest in that prospect. Following the second well,
CalEnergy Gas has the option to acquire 24.5% (50% of our interest) of the
entire Fences project area by paying to us the sum of $10.6 million, less the
costs of drilling the first two wells and less the cost of any additional
geological and geophysical costs it has incurred on the Fences area. Any such
payment to us is pledged to RRPV, until its note, with a principal balance of
approximately $3.3 million, plus interest, has been satisfied in full. We expect
the net proceeds to us to be approximately $5.6 million before the end of 2003,
from which we will be obligated to pay RRPV.


         All of the costs related to our 49% interest in the project area that
are paid for by CalEnergy Gas will be credited against the remaining $5.4
million obligation under our $16.0 million work obligation to POGC (see below).
CalEnergy Gas has received consent from POGC concerning the transfer of our
working interest according to the agreement terms, and RRPV has committed to
permit the transfer, free of any lien or encumbrance, of 50% of our interest to
CalEnergy Gas. We expect drilling to commence in the second quarter of 2003.


     Fences I Settlement Agreement

         On April 11, 2000, we agreed to spend $16.0 million of exploration
costs on the Fences project areas to earn a 49% interest. When expenditures
exceed $16.0 million, POGC will pay its 51% share of further costs. Through the
end of 2001, we had paid $6.7 million towards the $16.0 million commitment. As
of December 31, 2001, we had accrued $2,678,477 of additional costs pertaining
to the Fences project areas.


         In late 2002, as part of our discussions with POGC concerning the
CalEnergy Gas agreement and the opportunity to participate with POGC in other
exploration projects, we reaffirmed our intent to fulfill the $16.0 million
commitment with POGC. In connection with this agreement and in order to clarify
uncertainties about the nature and timing of our obligation regarding the
balance of our $16.0 million commitment, we agreed to recognize in 2002, and pay
at a future date, an additional $2.3 million of costs related to prior
exploration activities in the Fences project areas to POGC, $1.6 million of
which will be credited towards the $16.0 million commitment. The 2002 amount
includes $704,000 in interest costs related to our prior liabilities to POGC,
$433,000 in drilling costs, $418,000 in pipeline costs, $502,000 in seismic
costs, and $250,000 related to foreign exchange adjustments.

                                       23
<PAGE>

         In addition, as part of our future payments towards the remaining
commitment, we have agreed to assign in 2003, as soon as is practicable, all of
our rights to the Kleka 11 well, including the amounts recorded as accounts
receivable for Kleka gas sales. Accordingly, at December 31, 2002, our
receivable from POGC in the amount of $606,986 was offset against the POGC
liability. The liability will be further offset in 2003 by the value of the
remaining gas reserves associated with the Kleka well, as determined by an
independent engineer under criteria to be agreed to. As of December 31, 2002, we
had estimated proved developed and proved undeveloped gas reserves of 1,374 and
2,836 million cubic feet of gas, respectively, for a total of 4,210 million
cubic feet of gas with an estimated net present value, discounted at 10%, of
approximately $1.1 million. We agreed to convey our interest in the Kleka 11
well in order to conserve cash while reducing the balance of our $16.0 million
commitment in view of our limited liquidity. Lastly, we agreed to begin accruing
interest on the past due amount to POGC. The interest rate in effect at December
31, 2002, was 12.8% per annum; the interest rate as of March 21, 2003, was
10.4%.


     Rolls-Royce Power Ventures

         In early 2003, we reached an agreement with RRPV to amend its 9.5%
Convertible Secured Note in the amount of $5.0 million (see Footnote 6 in the
financial statements). Our current liabilities at December 31, 2002, include the
$5.0 million principal balance, plus accrued interest of $392,000. The note is
secured by a lien on our Fences I and Wilga property interests and was repayable
in March 2003, unless converted to common stock at $5.00 per share or otherwise
amended.

         In March 2003, following our successful private placement of
convertible preferred stock, we paid $2.2 million to RRPV. In return, RRPV
extended the maturity date of the note to December 31, 2003. We have also agreed
to pay 40% of the gross proceeds of any subsequent equity or debt offering
concluded prior to the amended maturity date to RRPV. We also agreed to assign
our rights to payments under the CalEnergy Gas agreement to RRPV, except for
those amounts related to drilling the two wells. All such payments will be used
to offset the remaining principal and interest. In exchange for these payments,
RRPV agreed to release its lien on interests earned by CalEnergy Gas under its
agreement with us.

         The loan amendment contains other terms and conditions, including an
increase in the interest rate on the note from 9.5% to 12% per annum effective
March 9, 2003, an extension of the conversion period until December 31, 2003,
with the conversion price being changed from $5.00 per share to $3.42 per share,
and an extension fee payment of $100,000.

     Cost Reduction Measures


         In mid-2002, we recognized that it would likely require an extended
period to consummate a farmout transaction with our Fences I project and our
ability to raise additional equity/debt would be restricted until such an
arrangement was in place. We further recognized the importance of reducing our
overhead expenses to conserve cash while in discussions with potential
participants. Effective July 1, 2002, we undertook several measures to reduce
our ongoing expenses. We cut the salaries of all key employees by 50% and did
not replace employees who left the Company. We also reduced the level of
benefits available to all employees. We cut other areas of overhead expenses
where possible. In addition to our overhead reductions, we significantly reduced
the amount of money designated for ongoing seismic and other exploration costs.


     Summary

         Despite our financial condition, because of the events described above,
we believe that we are well-positioned to obtain additional funding and continue
as a going concern. There can be no assurance that we will be able to obtain
additional financing or successfully complete the necessary steps to enable us
to continue as a going concern. If we are unable to obtain sufficient funds to
satisfy our future cash requirements, we may be forced to curtail operations
further, dispose of assets, issue securities to meet obligations, or seek
extended payment terms from our creditors. Such events would materially and
adversely affect our financial position and results of operations and result in
the dilution of the interests of existing stockholders.

                                       24
<PAGE>

Critical Accounting Policies

     Oil and Gas Activities

         We follow the successful efforts method of accounting for our oil and
gas properties. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves. If an
exploratory well has not found proved reserves, these costs plus the costs of
drilling the well are expensed. The costs of development wells are capitalized,
whether productive or nonproductive. Geological and geophysical costs on
exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are considered not to be realizable. An impairment loss is recorded if
the net capitalized costs of proved oil and gas properties exceed the aggregate
undiscounted future net cash flows determined on a property-by-property basis.
The impairment loss recognized equals the excess of net capitalized costs over
the related fair value, determined on a property-by-property basis. As a result
of the foregoing, our results of operations for any particular period may not be
indicative of the results that could be expected over longer periods.


     Interests Held Under Oil and Gas Leases

         Statement of Financial Accounting Standards No. 141, Business
Combinations (FAS 141) and Statement of Financial Accounting Standards No. 142,
Goodwill and Intangible Assets (FAS 142) were issued by the Financial Accounting
Standards Board (FASB) in June 2001 and became effective for us on July 1, 2001,
and January 1, 2002, respectively. FAS 141 requires all business combinations
initiated after June 30, 2001, to be accounted for using the purchase method.
Additionally, FAS 141 requires companies to disaggregate and report separately
from goodwill certain intangible assets. FAS 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under FAS 142, goodwill and
certain other intangible assets are not amortized, but rather are reviewed
annually for impairment. One interpretation being considered relative to these
standards is that oil and gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves for
both undeveloped and developed leaseholds should be classified separately from
oil and gas properties, as intangible assets on our balance sheets. In addition,
the disclosures required by FAS 141 and 142 relative to intangibles would be
included in the notes to financial statements. Historically, we, like many other
oil and gas companies, have included these oil and gas mineral rights held under
lease and other contractual arrangements representing the right to extract such
reserves as part of the oil and gas properties, even after FAS 141 and 142
became effective.

         This interpretation of FAS 141 and 142 described above would only
affect our balance sheet classification of oil and gas leaseholds. Our results
of operations and cash flows would not be affected, since these oil and gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves would continue to be amortized in accordance
with accounting rules for oil and gas companies provided in Statement of
Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil
and Gas Producing Companies (FAS 19).

         At December 31, 2002, we had undeveloped leaseholds of approximately
$147,000 that would be classified under that interpretation on our balance sheet
as "intangible undeveloped leasehold" and developed leaseholds of an estimated
$7,000 that would be classified under that interpretation as "intangible
developed leaseholds" if we applied the interpretation currently being
considered.

         We will continue to classify our oil and gas mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further interpretive guidance
is provided.


     Oil and Gas Reserves

         Engineering estimates of our oil and gas reserves are inherently
imprecise and represent only approximate amounts because of the subjective
judgments involved in developing such information. There are authoritative
guidelines regarding the engineering criteria that have to be met before
estimated oil and gas reserves can be designated as "proved." Proved reserve

                                       25
<PAGE>

estimates are updated at least annually and take into account recent production
and technical information about each field. In addition, as prices and cost
levels change from year to year, the estimate of proved reserves also changes.
This change is considered a change in estimate for accounting purposes and is
reflected on a prospective basis in related depreciation rates.

         Despite the inherent imprecision in these engineering estimates, these
estimates are used in determining depreciation expense and impairment expense
and in disclosing the supplemental standardized measure of discounted future net
cash flows relating to proved oil and gas properties. Depreciation rates are
determined based on estimated proved reserve quantities (the denominator) and
capitalized costs of producing properties (the numerator). Producing properties'
capitalized costs are amortized based on the units of oil or gas produced.
Therefore, assuming all other variables are held constant, an increase in
estimated proved reserves decreases our depreciation, depletion and amortization
expense. Also, estimated reserves are often used to calculate future cash flows
from our oil and gas operations, which serve as an indicator of fair value in
determining whether a property is impaired or not. The larger the estimated
reserves, the less likely the property is impaired.


Restatement

         As further discussed in Notes 1 and 19 to the consolidated financial
statements, we have restated the consolidated financial statements for the years
ended December 31, 2002, 2001 and 2000. The restatement decreased the net loss
for the year ended December 31, 2000, by $597,818, or $0.04 per share.
Additionally, the restatement reduced the accumulated deficit and increased the
cost basis of the treasury stock at December 31, 2002 and 2001, by $973,990.
This restatement was necessary to account for certain loans to officers in 1998
using variable stock option accounting and resulted in the reversal of interest
income and impairment charges originally recorded in 2000. All amounts in the
following discussion have been adjusted for these restatements as appropriate.


Results of Operations by Business Segment

         We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, general and administrative costs, or G&A, and other income
directly associated with their respective segments are detailed within the
following discussion. DD&A, G&A, amortization of deferred compensation (G&A),
interest income, other income, interest expense, impairment of notes receivable
from officers and other costs, which are not allocated to individual operating
segments for management or segment reporting purposes, are discussed in their
entirety following the segment discussion. A comparison of the results of
operations by business segment and the information regarding nonsegmented items
for the years ended December 31, 2002, 2001 and 2000, respectively, follows.
Further information concerning our business segments can be found in Note 13,
Business Segments, in the financial statements.

     Exploration and Production Segment

         A summary of the amount and percentage change, as compared to their
respective prior year period, for oil and gas revenues, average oil and gas
prices, oil and gas production volumes, and lifting costs per barrel and Mcf for
the years ended December 31, 2002, 2001 and 2000, is set forth in the following
table:
<TABLE>
<CAPTION>
                                                              For the year ended December 31,
                                         ----------------------------------------------------------------------------
                                                  2002                     2001                      2000
                                        ------------------------- ------------------------  -------------------------
                                            Oil          Gas         Oil          Gas          Oil          Gas
                                        ------------ ------------ ------------ ----------- ------------  ------------
<S>                                      <C>           <C>        <C>           <C>        <C>              <C>
Revenues..............................   $1,924,000    $ 285,000  $ 1,835,000   $ 394,000  $ 2,521,000      $     --
  Percent change versus prior year....        +4.9%       -27.7%       -28.0%       +100%       +62.2%

Average price (Bbls or Mcf)(1)........   $    21.19    $    1.58  $     19.41   $    1.58  $     26.14      $     --
  Percent change versus prior year....        +9.2%           --       -25.8%       +100%       +70.3%

Production volumes (Bbls or Mcf)......       90,817      180,407       94,522     249,661       96,416            --
  Percent change versus prior year....        -3.9%       -27.7%        -1.9%       +100%        -4.8%

Lifting costs per Bbls or Mcf(2)......   $    14.28    $    0.16  $     13.62   $     .16  $     12.13      $     --
  Percent change versus prior year....        +4.8%           --       +12.3%          --       +36.6%
</TABLE>
---------------------
(1) The contract price for gas during 2002 and 2001, prior to adjusting for
    actual physical content of Btu, was $2.02 per MMBtu.
(2) Lifting costs per barrel are computed by dividing the related lease
    operating expenses by the total barrels of oil produced after royalties.
    Lifting costs per Mcf of gas are computed by dividing the related lease
    operating expenses by the total Mcf of gas produced before royalties.
    Lifting costs do not include production taxes.


         Oil Revenues. Oil revenues were $1.9 million, $1.8 million and $2.5
million for the years ended December 31, 2002, 2001 and 2000, respectively.
Essentially all oil revenues during the three years were derived from our
producing properties in the United States. During these three years, oil
revenues fluctuated primarily due to volatile oil prices and the declining
production rates attributable to the natural production declines of our
producing properties. Oil revenues in 2002 increased from 2001 levels by

                                       26
<PAGE>

approximately $161,000 due to higher oil prices, offset by approximately $72,000
related to production declines. Oil revenues in 2001 decreased from 2000 levels
by approximately $636,000 due to lower oil prices and approximately $50,000
related to production declines.

         Gas Revenues. Our gas revenues are derived solely from our Polish
producing operations. Gas revenues were $285,000 and $394,000 for the years
ended December 31, 2002 and 2001, respectively. There were no gas revenues
during 2000. The Kleka 11, our first producing well in Poland, began producing
during February 2001. During 2002 and 2001, gas produced by the Kleka 11 was
sold to POGC based on U.S. dollar pricing at a fixed price under a five-year
contract, which may be terminated by giving POGC a 90-day written notice. The
decline in gas production from 2001 to 2002 is the result of the operator
choking back the well to avoid any increase in water production.

         Lease Operating Costs. Lease operating costs were $1.4 million for each
of the years ended December 31, 2002, 2001 and 2000. Operating costs rose
slightly from 2001 to 2002, as higher oil lifting costs offset lower oil and gas
production. Operating costs rose from 2000 levels in 2001 due to the
commencement of production from the Kleka well in Poland, as well as higher per
unit oil lifting costs offset by lower production taxes, 2002 operating costs
increased approximately $68,000 due to higher lifting costs, offset by
approximately $61,000 related to lower oil and gas production. The 2001
operating costs increased approximately $141,000 due to higher lifting costs and
approximately $17,000 related to higher oil and gas production, offset by a
reduction in production taxes of approximately $149,000.


         Exploration Costs. Our exploration efforts are focused in Poland, and
the expenses consist of geological and geophysical costs, or G&G costs,
exploratory dry holes and oil and gas leasehold impairments. Exploration costs
were $2.6 million, $6.5 million and $7.4 million for the years ended December
31, 2002, 2001 and 2000, respectively. Limited available capital in 2002 caused
us to sharply curtail our exploration activities in Poland. Subject to the
commencement of drilling activities under the CalEnergy Gas agreement and our
ability secure additional equity/debt financing, exploration costs will continue
to be curtailed in the near term.

         G&G costs were $1.0 million, $2.9 million and $4.7 million for the
years ended December 31, 2002, 2001 and 2000, respectively. During 2002, most of
our G&G costs were spent on reprocessing and further analyzing the seismic data
on the Fences I area. During 2001, we spent approximately $1.8 million on
acquiring 3-D seismic data in the Fences project areas, $552,000 acquiring and
analyzing 2-D seismic data on the Pomeranian project area, and granted stock
options valued at $36,000 to a Polish consultant. During 2000, we spent
approximately $2.1 million on acquiring 3-D seismic data in the Fences project
areas, approximately $477,000 on acquiring and analyzing 2-D seismic data on the
Lublin Basin, Pomeranian and Warsaw West project areas, and granted stock
options valued at approximately $81,000 to a Polish consultant. Under terms of
the Poland 2001 Agreement Credit, Apache covered our share of additional G&G
costs totaling $53,000 and $19,000 during 2001 and 2000, respectively.

         Exploratory dry-hole costs were $0, $3.1 million and $2.0 million for
the years ended December 31, 2002, 2001 and 2000, respectively. Due to our
capital limitations, we did not participate in any exploratory drilling in 2002.
During 2001, we incurred costs of $3.1 million pertaining to the Mieszkow 1 well
on the Fences project areas. In accordance with FASB No. 19, we have classified
the Mieszkow 1 as an exploratory dry hole for financial reporting purposes,
because further operations have been suspended since drilling, pending the
reprocessing and interpretation of 3-D seismic data in order to evaluate the
economic feasibility of additional drilling operations at the well site. During
2000, we drilled the Wilga 3 and Wilga 4 wells near our Wilga 2 discovery on the
Wilga project area, both of which were subsequently determined to be exploratory
dry holes. The two wells cost a net amount of $1.1 million and $900,000,
respectively, after Apache covered one-half of our 45% share of drilling costs
under terms of the Apache Exploration Program.


         Impairments of oil and gas properties were $1.5 million, $584,000 and
$674,000 for the years ended December 31, 2002, 2001 and 2000, respectively.
During 2002, we incurred an impairment of $509,000 in costs associated with the
Tuchola 108-2 well. A preliminary open-hole test in early January 2001 on the
well resulted in a flow rate of 9.5 MMcf of gas per day from the Main Dolomite
Reef formation at a depth between 2,535 meters and 2,595 meters. The flow rate
was limited by the capacity of the surface equipment. The well was subsequently
completed in an approximately 200 foot thick section of the Main Dolomite, but

                                       27
<PAGE>

has since been shut-in pending a pipeline connection. Constrained capital has
prevented us from drilling the additional appraisal and development wells and
building the necessary infrastructure, and FASB No. 19 requires well costs to be
impaired if after a year has passed, a determination that proved reserves have
been found cannot be made. We also recognized an impairment of $1.0 million in
costs associated with the Kleka 11 well, where lower production profiles caused
a downward revision in recoverable future reserves.


         During 2001, we incurred impairments of $525,000 for the Baltic project
area and $59,000 for the Warsaw West project area, both of which are located in
Poland in areas where we no longer have exploration plans. During 2000, we
incurred impairments of $674,000 for the Williston Basin in North Dakota, where
we also no longer have exploration plans. Impairments will vary from period to
period based on our determination that capitalized costs of unproved properties,
on a property-by-property basis, are not realizable.


         Apache Poland G&A Costs. Apache Poland G&A costs consist of our share
of direct overhead costs incurred by Apache in Poland in accordance with the
terms of the Apache Exploration Program. Apache Poland G&A costs were $0,
$575,000 and $957,000 for the years ended December 31, 2002, 2001 and 2000.
During mid-2001, we began to narrow the focus of our ongoing exploratory efforts
relating to the Apache Exploration Program by including only the Pomeranian and
Wilga project areas and discontinued our exploratory activities on the Lublin
Basin, Warsaw West and Carpathian project areas. Prior to July 1, 2000, Apache
covered all of our pro rata share of Apache Poland G&A costs. Effective July 1,
2000, we began paying approximately 35% of Apache Poland G&A costs, to be
adjusted as each of Apache's remaining drilling requirements were completed.
Apache has since completed its remaining drilling requirements, and we are now
responsible only for our 45% share of Apache Poland G&A costs relating to
ongoing, jointly conducted activities in the Wilga project area in Poland for
which Apache is the operator, subject to a preapproved annual budget. There were
no jointly conducted activities in the Wilga project area in 2002. In addition
to the above amounts, Apache covered our share of additional Apache Poland G&A
costs totaling $464,000 and $33,000 during 2001 and 2000, respectively, under
terms of the Poland 2001 Agreement Credit.


         Poland 2001 Agreement Credit. Under an amendment to the Apache
Exploration Program effective January 1, 2001, referred to as the Poland 2001
Agreement, Apache agreed to issue to us a credit that included Apache covering
$932,000 of our share of joint costs in Poland (other than carried costs) in
return for the release of Apache's commitment to cover our share of costs to
shoot 339 kilometers of 2-D seismic data in the Carpathian project area. During
2001 and 2000, we used the entire Poland 2001 Agreement Credit, as shown below:
<TABLE>
<CAPTION>
                                                                              Poland 2001 Agreement Credit
                                                                     -----------------------------------------------
                                                                          2001            2000           Total
                                                                     --------------- --------------- ---------------
         <S>                                                         <C>             <C>             <C>
         Cost category:
           Geological and geophysical costs......................... $      53,000   $      19,000   $      72,000
           Exploratory dry hole costs...............................        25,000          (3,000)         22,000
           Apache Poland general and administrative costs...........       464,000          33,000         497,000
           Leasehold costs..........................................            --          65,000          65,000
           Tuchola 108-2 completion costs...........................       276,000              --         276,000
                                                                      ------------    ------------   -------------
             Total..................................................  $    818,000    $    114,000   $     932,000
                                                                      ============    ============   =============
</TABLE>

         DD&A Expense - Producing Operations. DD&A expense for producing
properties was $281,000, $322,000 and $73,000 for the years ended December 31,
2002, 2001 and 2000, respectively. DD&A expense incurred during 2002 and 2001
includes approximately $205,000 and $258,000, respectively, or $1.03 per Mcf of
gas produced, associated solely with the Kleka 11 well that began producing in
Poland during February 2001. DD&A expense declined from 2001 to 2002 due to
reduced production from the well. There was no DD&A expense associated with
Poland during 2000. The DD&A rate per barrel for oil produced in the United
States was $0.89, $0.69 and $0.76 during 2002, 2001 and 2000, respectively. The
differences between the DD&A rates per barrel from year to year are primarily
the result of changes in oil reserve estimates computed as of December 31 of
each year.

                                       28
<PAGE>

     Oilfield Services Segment

         Oilfield Services Revenues. Oilfield services revenues were $0.5
million, $1.6 million and $1.3 million for the years ended December 31, 2002,
2001 and 2000, respectively. Oilfield services revenues increased from 2000 to
2001 due to improved market conditions and an increased emphasis on using our
oilfield servicing equipment for contract third-party services rather than
servicing company-owned properties. Conversely, the contract drilling industry
was significantly curtailed in the area where we operate in 2002, and our
revenues declined sharply as a result. Oilfield services revenues will continue
to fluctuate from period to period based on market demand, weather, the number
of wells drilled, downtime for equipment repairs, the degree of emphasis on
using our oilfield services equipment on our company-owned properties and other
factors.

         Oilfield Servicing Costs. Oilfield services costs were $0.5 million,
$1.3 million and $1.1 million for the years ended December 31, 2002, 2001 and
2000, respectively, or 100%, 82% and 84% of oilfield servicing revenues,
respectively. Oilfield services costs as a percentage of oilfield services
revenues were relatively flat during 2001, as compared to 2000. During 2002,
oilfield servicing costs were a higher percentage of oilfield services revenues,
as compared to 2001, due to increased maintenance and repair costs associated
with our oilfield servicing equipment. In general, oilfield servicing costs are
directly associated with oilfield services revenues. As such, oilfield services
costs will continue to fluctuate period to period based on the number of wells
drilled, revenues generated, weather, downtime for equipment repairs, the degree
of emphasis on using our oilfield services equipment on our company-owned
properties and other factors.

         DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $310,000, $308,000 and $247,000 for the years ended December 31, 2002, 2001
and 2000, respectively. We spent $116,000, $248,000 and $779,000 on upgrading
our oilfield servicing equipment during 2002, 2001 and 2000, respectively.

     Nonsegmented Items

         Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $55,000, $1.1 million and $652,000 during the years ended
December 31, 2002, 2001 and 2000, respectively. On April 5, 2001, we extended
the term of options to purchase 125,000 shares of our common stock that were to
expire during 2001 for a period of two years, with a one-year vesting period. On
August 4, 2000, we extended the term of options and warrants to purchase 678,000
shares of our common stock that were to expire during 2000 for a period of two
years, with a one-year vesting period. In accordance with FIN 44 "Accounting for
Certain Transactions involving Stock Compensation," we incurred noncash deferred
compensation costs of $1.8 million, including $219,000 for the April 5, 2001,
option extension and $1.6 million for the August 4, 2000, option extension, to
be amortized over their respective one-year vesting periods from the date of
extension. The deferred costs have all been amortized as of December 31, 2002.


         G&A Costs - Corporate. G&A costs were $2.4 million, $883,000, and $2.7
million for the years ended December 31, 2002, 2001 and 2000, respectively.
During 2001, G&A costs were $1.8 million lower than 2000 G&A costs, primarily
due to the Company writing off $1.7 million of compensation that was accrued as
of December 31, 2000. The accrued compensation consisted of bonus awards and
salary increases that were awarded but not paid due to our financial condition
prior to December 31, 2001. We wrote off the accrued compensation, which was
waived by each employee, in recognition of our inability to pay these amounts
within the foreseeable future. We have no obligation or intent to pay any of the
waived amounts in the future. Without the write-offs, G&A costs during 2001
would have been approximately $3.5 million. During 2002, in recognition of our
limited resources, we aggressively pursued the cost reduction measures described
earlier, resulting in costs lower than 2001, excluding the $1.7 million
write-off during that year, and actual 2000 costs.

         Interest and Other Income - Corporate. Interest and other income was
$119,000, $514,000 and $417,000 for the years ended December 31, 2002, 2001 and
2000, respectively. Our cash, cash equivalent and marketable debt securities
balances were $0.7 million, $3.2 million and $2.4 million as of December 31,
2002, 2001 and 2000, respectively. Lower cash balances and interest rates in
2002 and 2001 reduced our interest income in both years. During the years ended
December 31, 2002 and 2001, we recorded other income of $93,000 and $341,000,
respectively, pertaining to amortizing an option premium resulting from granting
RRPV an option to purchase gas from our properties in Poland.


                                       29
<PAGE>

         Interest Expense. Interest expense was $1.2 million, $331,000 and
$2,000 for the years ended December 31, 2002, 2001 and 2000, respectively.
During, 2002 and 2001, we recorded $93,000 and $341,000, respectively, of
imputed interest expense relating to our financing arrangement with RRPV. On
March 9, 2002, we began to accrue interest on the $5.0 million RRPV obligation
at an annual rate of 9.5%.


         Impairment of Notes Receivable. Impairment of notes receivable was $0,
$34,000, and $0 for the years ended December 31, 2002, 2001 and 2000,
respectively. In accordance with SFAS No. 114 "Accounting by Creditors for
Impairment of a Loan," the notes receivable carrying value must be adjusted at
the end of each reporting period to reflect the market value of the underlying
collateral. On November 8, 2000, a former employee exercised an option to
purchase 52,000 shares of our common stock at a price of $3.00 per share. The
former employee elected to pay for the cost of the exercise by signing a full
recourse promissory note with us for $156,000. Terms of the note receivable
included a three-year term with annual principal payments of $52,000 plus
interest accrued at 9.5%. On November 8, 2001, the former employee surrendered
52,000 shares of our common stock in return for cancellation of the note
receivable. We recorded a loss of $34,060 on the transaction and the acquisition
of 52,000 shares of common stock at a price of $2.63 per share, the closing
price of our stock on November 8, 2001.


         Income Taxes. We incurred net losses of $5.9 million, $8.4 million and
$10.8 million for the years ended December 31, 2002, 2001 and 2000,
respectively. SFAS No. 109 "Accounting for Income Taxes" requires that a
valuation allowance be provided if it is more likely than not that some portion
or all of a deferred tax asset will not be realized. Our ability to realize the
benefit of our deferred tax asset will depend on the generation of future
taxable income through profitable operations and the expansion of our
exploration and development activities. The market and capital risks associated
with achieving the above requirement are considerable, resulting in our
conclusion that a full valuation allowance be provided. Accordingly, we did not
recognize any income tax benefit in our consolidated statement of operations for
these years.

Liquidity and Capital Resources


         With insufficient revenues to cover our operating expenses to fund
further exploration, our greatest uncertainty is our shortage of capital and our
dependence on obtaining substantial amounts of external funding through the sale
of securities or an interest in our exploration projects in Poland. Our ability
to obtain such required funding is, to a substantial extent, dependent on the
interest of the securities markets and oil and gas industry generally in
international oil and gas exploration. Although we believe that there appears to
be growing securities markets and industry interest in financing international
oil and gas exploration, we cannot assure that this will enable us to obtain the
financing we require on acceptable terms or that such perceived trend, if we
accurately perceive it, may not become less favorable.

         As of December 31, 2002, we had approximately $700,000 of cash and cash
equivalents, a working capital deficit of approximately $9.2 million, and a
stockholders' deficit of approximately $4.9 million. In addition, we have a
remaining work commitment of $5.4 million that must be spent by us (in addition
to payment of the $4.4 million to POGC, which is included in our accrued
liabilities at December 31, 2002) in order to complete our earning obligation in
our Fences project areas. Our financial position as of December 31, 2002, raises
uncertainty about our ability to continue as a going concern.


                                       30
<PAGE>

         We have made significant progress in several areas toward improving our
liquidity and capital resources discussed in detail at the beginning of this
MD&A section. We raised $5.6 million from the recent sale of equity securities,
we extended the due dates on the RRPV note and the accrued liability to POGC, we
arranged to reduce our liability to POGC by the value of our interest in the
Kleka 11 well, and we signed a farmout agreement with CalEnergy Gas that, if
CalEnergy Gas fully earns half our interest in Fences I, will result in $10.6
million of work commitments performed and cash paid to us. In addition, we
recently obtained the right to earn a 49% interest in the Fences II project area
and anticipate completing documentation soon for a 100% interest in the Fences
III project area. We believe we can arrange with industry participants to trade
a portion of our interest in these properties for drilling funds and cash
payments that will exceed our related costs. Notwithstanding these measures,
there remains uncertainty about our ability to continue as a going concern, and
our auditor's report on our financial statements for the year ended December 31,
2003, may contain an explanatory paragraph about our ability to continue as a
going concern similar to the explanatory paragraph regarding our financial
statements for 2002 and previous years.

         To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities, and agreements with industry
participants that funded our share of costs in certain exploratory activities in
order to earn an interest in our properties. The continuation of our exploratory
efforts in Poland is dependent on our ability to raise additional capital or to
farm out our properties. The availability of such capital or farmouts will
affect the timing, pace, scope and amount of our future capital expenditures. If
we are unable to arrange farmouts for the Fences II and Fences II project areas,
or having done so, if the results of operations there are disappointing, or if
CalEnergy Gas's drilling program is unsuccessful, or if CalEnergy Gas elects not
to pursue that drilling program, or if other disappointing events should occur,
there can be no assurance that we will be able to secure additional participants
or obtain additional equity or debt financing. We may also not be able to
further reduce expenses or successfully complete other steps to continue as a
going concern. If we are unable to obtain sufficient funds to satisfy our future
cash requirements, we may be forced to curtail operations, dispose of assets, or
seek extended payment terms from our vendors. Such events would materially and
adversely affect our financial position and results of operations.

         We may seek to obtain additional funds for future capital investments
from strategic alliances with other energy or financial participants, the sale
of additional securities, project financing, sale of partial property interests,
or other arrangements, all of which may dilute the interest of our existing
stockholders or our interest in the specific project financed. We may change the
allocation of capital among the categories of anticipated expenditures depending
upon future events that we cannot predict. For example, we may change the
allocation of our expenditures based on the actual results and costs of future
exploration, appraisal, development, production, property acquisition and other
activities. In addition, we may have to change our anticipated expenditures if
costs of placing any particular discovery into production are higher, if the
field is smaller, or if the commencement of production takes longer than
expected.


         Working Capital (current assets less current liabilities). Our working
capital was $(9.2) million as of December 31, 2002, a decrease of $9.7 million
from December 31, 2001. In accordance with the terms of our RRPV loan agreement,
the entire principal amount of $5.0 million, plus accrued interest, was due on
March 9, 2003, unless RRPV earlier converted the loan to restricted common stock
at $5.00 per share, the market value of our common stock at the time the terms
with RRPV were finalized. Accordingly, the entire balance of the RRPV note,
along with interest accrued through December 31, 2002, is shown as a current
liability on the balance sheet. As discussed above, we reached an agreement with
RRPV to extend the maturity date of the loan until December 31, 2003.

         Our current liabilities also include $4.4 million of costs related to
our Fences project in Poland. In 2000, we agreed to spend $16.0 million of
exploration costs on this project area, which is owned and operated by POGC, in
order to earn a 49% interest. As of December 31, 2002, we have made cash
payments of approximately $6.7 million pertaining to the required $16.0 million,
in addition to the amount accrued at year-end.

         Operating Activities. We used net cash of $2.1 million, $3.1 million
and $6.1 million in our operating activities during 2002, 2001 and 2000,
respectively, primarily as a result of the net losses incurred in those years.
The declining use of cash in operations is also a reflection of a systematic
reduction in exploration costs, as our resources have become limited over time.

                                       31
<PAGE>

         Investing Activities. We used net cash of $295,000 in investing
activities during 2002, received net cash of $326,000 from our investing
activities during 2001, and used net cash of $3.9 million in investing
activities during 2000. During 2002, the bulk of cash used was for upgrading our
producing oil and gas properties and our well-servicing equipment. During 2001,
our capital expenditures for producing properties and well-servicing equipment
were offset by $1.3 million in maturing marketable debt securities. During 2000,
we spent $7.7 million on various additions to both proved and unproved
properties, and spent $779,000 on additions to oilfield servicing equipment. We
also received a net of $4.0 million net from transactions in marketable debt
securities.


         Financing Activities. We received net cash of $4,500, $5.0 million and
$9.4 million from our financing activities during 2002, 2001 and 2000,
respectively. During 2001, we received $5.0 million pertaining to our RRPV loan
and gas purchase option agreement. Also, during 2001, we acquired 52,000 shares
of common stock at a cost of $137,000 in a noncash transaction. During 2000, we
received net proceeds of $9.3 million ($10.4 million gross) from the private
placement of 2,969,000 shares of our common stock, and received $103,000 in cash
and $156,000 in the form of a full recourse promissory note secured by 52,000
shares of our common stock from the exercise of options and warrants to purchase
95,572 shares of our common stock. Also, during 2000, we acquired 233,340 shares
of treasury stock at a cost of $1,838,000 in a noncash transaction.


Contractual Obligations and Contingent Liabilities and Commitments

         The following is a summary of our significant contractual obligations
and commitments as of December 31, 2002 (in thousands):

         Contractual Obligations and Commitments      Due by December 31, 2003
                                                             (In thousands)


         Note Payable (RRPV).........................  $  5,000 plus interest(1)
         Fences I work commitment(2).................     5,400
         Cash payment to POGC(2).....................     4,400 plus interest
                                                       ----------------------
               Total.................................  $ 14,800 plus interest(1)
                                                       ======================

----------------------
(1) In March 2003, we paid RRPV $2.2 million, which reduced the balance due to
    approximately $3.3 million, plus interest.
(2) The Fences I work commitment and the cash payment to POGC are required in
    order for us to meet our commitment to earn a 49% interest in the Fences I
    project area.


         Our oil and gas drilling and production operations are subject to
hazards incidental to the industry that can cause severe damage to and
destruction of property and equipment, pollution or environmental damage and
suspension of operations, personal injury and loss of life. To lessen the
effects of these hazards, we maintain insurance of various types to cover our
United States operations and rely on the insurance or financial capabilities of
our exploration participants in Poland. These measures do not cover risks
related to violations of environmental laws or all other risks involved in oil
and gas exploration, drilling and production. We would be adversely affected by
a significant adverse event that is not fully covered by insurance or by our
inability to maintain adequate insurance in the future at rates we consider
reasonable.


Risk Factors

         The auditor's report on our financial statements for the year ended
December 31, 2002, contains an explanatory paragraph about our ability to
continue as a going concern. We have incurred substantial operating losses and
negative cash flows from operations since inception, and our obligations and
commitments for the year ending December 31, 2003, exceed the cash we have
available. These matters raise substantial doubt about our ability to continue
as a going concern.

                                       32
<PAGE>

         We continue to need additional financing to supplement our limited
financial resources and we may be unable to obtain it. We do not currently
generate sufficient revenues to cover our costs of operation, including our
exploration and general and administrative costs, and will continue to rely on
raising additional capital through attracting industry or financial
participants, raising additional equity, incurring additional debt, selling or
conveying interests in our assets in exchange for exploration funding, or
completing other arrangements. We may be unable to obtain additional financing,
further reduce expenses, or successfully complete other steps to meet our
obligations and commitments and continue as a going concern.

         Our success depends largely on our discovery of economic quantities of
oil or gas in Poland and we may be unable to do so. Our ability to obtain
additional financing and to continue as a going concern depends on the
exploration potential of our prospect areas, on the perception of prospective
funding sources or industry participants that our prospects have commercial
potential in view of related risks, and on our discovery of commercial
quantities of oil or gas in Poland.

         Factors outside our control may prevent us from establishing commercial
production or substantial reserves as a result of our exploration, appraisal and
development activities in Poland. Those factors include the following:

         o        our interpretations of geological and geophysical data may not
                  lead to oil or gas discoveries;

         o        future wells may not encounter commercial quantities of oil or
                  gas;

         o        there is no way to predict in advance of drilling and testing
                  whether any prospect will discover oil or gas in place or will
                  yield oil or gas in sufficient quantities to cover drilling or
                  completion costs or to be economically viable;

         o        one or more appraisal wells may be required to confirm the
                  commercial potential of an oil or gas discovery;

         o        we may continue to incur exploration costs in specific areas
                  even if initial appraisal wells are plugged and abandoned or,
                  if completed for production, do not result in production of
                  commercial quantities of oil or gas; and

         o        drilling operations may be curtailed, delayed or canceled as a
                  result of numerous factors, including operating problems
                  encountered during drilling, weather conditions, compliance
                  with governmental requirements, shortages or delays in the
                  delivery of equipment or availability of services and other
                  factors.

         We have had limited exploratory success in Poland and our efforts may
be unsuccessful in the future. We have participated in drilling 15 exploratory
wells in Poland, consisting of 12 exploratory dry holes, two that discovered
hydrocarbons in place, one of which was not completed, one of which was
completed for production but not placed into production and is considered
shut-in, and one that was placed into production. We have no retained interest
in production or reserves from the one discovery in Poland that was placed into
production, the Kleka 11 well in the Fences I project area, because we agreed to
convey it to POGC in order to reduce the balance of our commitment to earn an
interest in the Fences I project area. The shut-in Wilga 2 is located
approximately 19 kilometers from the nearest pipeline, and we have not
determined that the construction of pipeline and related production facilities
is economically feasible.

                                       33
<PAGE>

         We have limited control over our exploration and development activities
in Poland and may suffer delays or increased costs as a result. We rely to a
significant extent on the expertise and financial capabilities of POGC. The
failure of POGC to perform its obligations as operator in conducting drilling
and other field activities in all of our project areas, other than the
Pomeranian and Fences II project areas, may require that we take steps under our
agreement to become operator and perhaps advance POGC's share, if any, of costs
of proposed activities, which may delay our planned exploration or may result in
delays and increased costs. If we are unable to complete exploration, we may be
unable to earn an interest in the related project area or recover costs incurred
to date.

         In the Fences project areas, we have agreements with POGC but no
agreements with the governmental agencies owning the oil or gas rights. We
currently have no direct interest in the underlying agreements, licenses and
grants from the Polish agencies governing the exploration, exploitation,
development or production of acreage in the Fences project areas. We may be
unable to earn an interest in these project areas or recover costs incurred to
date if POGC should elect not to pursue activities on such acreage, should our
relationship with POGC deteriorate or terminate, or if the government agencies
should fail to fulfill the requirements of or elect to terminate any agreements,
licenses or grants pertaining to the Fences project area. If we do not pay POGC
$4.4 million by December 31, 2003, and complete the balance of our $5.4 million
work commitment in the Fences I project area, we would be required to relinquish
all interest in that area.

         The exploration models we are using may not improve our chances of
finding oil or gas in Poland. We will have to revise or replace these
exploration models as a guide to further exploration if ongoing drilling results
do not confirm their validity.

         We may encounter delays in placing our current or future discoveries
into production. The possible delays may include obtaining rights-of-way to
connect to the POGC pipeline system, construction permits, availability of
materials and contractors, the signing of an oil or gas purchase contract and
other factors. Such delays would correspondingly delay the commencement of cash
flow.

         We cannot accurately predict the size of exploration targets or foresee
all related risks. Notwithstanding the accumulation and study of 2-D and 3-D
seismic data, drilling logs, production information from established fields and
other data, our predictions are only preliminary geological estimates of the
forecasted volume and characteristics of possible reservoirs and are not an
estimate of reserves. We may require several test wells and long-term analysis
of test data and history of production to determine the oil or gas potential of
individual prospects.

         Privatization of POGC could affect our relationship and future
opportunities in Poland. The Polish government has commenced the privatization
of POGC by privatizing some of POGC's refining assets and has stated its intent
to privatize other segments of POGC. The timing of such privatization is unclear
and beyond our control. Privatization may result in new policies, strategies or
ownership that could make it more difficult, time-consuming and expensive for us
to work with POGC and may reduce or eliminate the availability of opportunities
with POGC in the future.

         Our loan agreement with Rolls-Royce Power Ventures Limited restricts
our flexibility. We have encumbered certain of our property interests in Poland
to secure repayment of the remaining $3.3 million balance, plus interest, due
Rolls-Royce Power Ventures by December 31, 2003. In addition, our agreements
with Rolls-Royce Power Ventures preclude us from incurring additional
indebtedness other than for operating costs or conveying or encumbering our
property interests in Poland without repaying the balance due Rolls-Royce Power
Ventures.

         The loss of key personnel could have an adverse impact on our
operations. We rely on our officers and key employees and their expertise,
particularly David N. Pierce, Chairman, President and Chief Executive Officer;
Thomas B. Lovejoy, Vice-Chairman and Chief Financial Officer; Andrew W. Pierce,
Vice-President and Chief Operating Officer; and Jerzy B. Maciolek,
Vice-President of Exploration. The loss of the services of any of these
individuals may materially and adversely affect our ability to obtain required
additional capital or complete our planned exploration program in Poland. We do
not maintain key-man insurance on any of our employees.

         Oil and gas price decreases and volatility could adversely affect our
operations and our ability to obtain financing. Oil and gas prices are subject
to wide fluctuations in response to a number of seasonal, geopolitical and
market factors. This volatility could make it more difficult to obtain funding
from external sources.

                                       34
<PAGE>

         Our insurance may not be adequate to protect us against numerous
operating risks. Our oil and gas activities are subject to industry hazards such
as blowouts, explosions, uncontrollable flows of oil, gas or well fluids, fires,
pollution, releases of toxic gas and other environmental hazards and risks.
These hazards can cause personal injury and loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage, and
suspension of operations. The general liability insurance we carry does not
cover all of our risks, may not be sufficient to pay the full amount of
potential liabilities, and may not be available in the future on reasonable
terms. The self-insurance provided by POGC, as operator of the Fences project
area, may not cover all casualties adequately. A significant casualty that is
not fully covered by insurance could expose us to financial loss well beyond our
ability to pay. Further, we may not be able to maintain adequate insurance in
the future at rates we consider reasonable.

         Polish laws, regulations and policies may be changed in ways that could
adversely impact our business. Our oil and gas activities in Poland are and will
continue to be subject to ongoing uncertainties and risks, including

         o        possible changes in government personnel and the development
                  of new administrative policies and practices;

         o        possible changes to the laws, regulations and policies
                  applicable to us or the oil and gas industry in Poland in
                  general;

         o        uncertainties as to whether the laws and regulations will be
                  applicable in any particular circumstance under Poland's
                  immature legal system;

         o        uncertainties as to the manner in which we may be able to
                  enforce our rights in Poland under its immature legal system;

         o        political instability and possible changes in government;

         o        changes in export and transportation tariffs;

         o        changes in local and national tax requirements; and

         o        expropriation or nationalization of private enterprises and
                  other risks arising out of foreign government sovereignty over
                  our acreage in Poland.

         Poland has a developing regulatory regime, regulatory policies and
interpretations that are relatively untested, making it difficult to evaluate
how the regulatory regime will affect our operations. Poland's regulations
governing exploration, development, production, marketing, transportation and
storage of oil and gas were promulgated relatively recently and are relatively
untested. Therefore, there is little or no administrative or enforcement history
or established practice that can aid us in evaluating how the regulatory regime
will affect our operations. It is possible that such governmental policies will
change or that new laws and regulations, administrative practices or policies or
interpretations of existing laws and regulations will restrict our proposed
activities or result in delays, increased costs, or decreased opportunities.

         Our activities are subject to rapidly changing environmental laws and
regulations that could result in additional costs to us or the imposition of
liability. Operations on our project areas are subject to environmental laws and
regulations in Poland that provide for restrictions and prohibitions on spills,
releases or emissions of various substances produced in association with oil and
gas exploration and development. We are required to prepare and obtain approval
of environmental impact assessments by governmental authorities in Poland prior
to commencing oil or gas production, transportation and processing functions. We
may not have complied with all applicable laws and regulations in drilling
wells, acquiring seismic data or completing other activities in Poland to date.
The cost of compliance with current regulations or any changes in environmental
regulations could require significant expenditures. Further, breaches of such
regulations may result in mitigation costs, adverse publicity, or the imposition
of fines and penalties, any of which may be material.

                                       35
<PAGE>

         Our stockholder rights plan and bylaws discourage unsolicited takeover
proposals and could prevent our stockholders from realizing a premium on our
common stock. The rights issued under the stockholder rights plan would cause
substantial dilution to a person or group that attempts to acquire us on terms
not approved in advance by our board of directors. In addition, our articles of
incorporation and bylaws contain provisions that may discourage unsolicited
takeover proposals that our stockholders may consider to be in their best
interests that include

         o        provisions that members of the board of directors are elected
                  and retire in rotation, and

         o        the ability of the board of directors to designate the terms
                  of, and to issue new series of, preferred shares.

Together, these provisions and our stockholder rights plan may discourage
transactions that otherwise could involve payment to our stockholders of a
premium over prevailing market prices for our common shares.

         Our common stock price has been and may continue to be extremely
volatile, which may make it difficult to obtain financing and may preclude our
investors from recovering their investment in our common stock. Our common stock
traded as low as $1.83 and as high as $3.04 during the fiscal year ended
December 31, 2002. This volatility may make it more difficult or more expensive
for us to obtain financing. Additionally, it may preclude our investors from
recovering their investment in our common stock at the time of their choosing,
or at all.


New Accounting Pronouncements

         In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." SFAS No. 143 is effective for us beginning January 1,
2003. The most significant impact of this standard to us will be a change in the
method of accruing for site restoration costs. Under SFAS No. 143, the fair
value of asset retirement obligations will be recorded as liabilities when they
are incurred, which are typically at the time the assets are installed. Amounts
recorded for the related assets will be increased by the amount of these
obligations. Over time, the liabilities will be accreted for the change in their
present value and the capitalized costs will be depreciated over the useful
lives of the related assets. We are currently evaluating the impact of adopting
SFAS No. 143.

         In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liabilities
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). This statement
requires that a liability for costs associated with an exit or disposal activity
be recognized and measured initially at fair value only when the liability is
incurred. SFAS No. 146 will be effective for exit or disposal activities that
are initiated after December 31, 2002.

         In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation Transition and Disclosure." This statement amends FASB
Statement No. 123, or SFAS No. 123, "Accounting for Stock-Based Compensation,"
to provide alternative methods of transition for an entity that voluntarily
changes to the fair value based method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the disclosure provisions of SFAS
No. 123 to require prominent disclosure in both annual and interim financial
statements about the effects on reported net income of an entity's accounting
policy decisions with respect to stock-based employee compensation. As we will
continue to account for stock-based compensation according to APB 25, adoption
of SFAS No. 148 will require us to provide prominent disclosures about the
effects of SFAS No. 123 on reported income and will require disclosure of these
affects in the interim financial statements as well. SFAS No. 148 is effective
for the financial statements for fiscal years ending after December 15, 2002,
and subsequent interim periods. We believe that the adoption of this standard
will have no material impact on our operating results and financial position.

                                       36
<PAGE>

         In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"),
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others, which expands on the accounting
guidance of Statements Nos. 5, 57, and 107 and incorporates without change the
provisions of FASB Interpretation No. 34, which is being superseded. This
interpretation requires a guarantor to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. In addition, guarantors are required to make significant
new disclosures, even if the likelihood of the guarantor making payments under
the guarantee is remote. The interpretation's disclosure requirements are
effective for the Company as of December 31, 2002. The recognition requirements
of FIN 45 are to be applied prospectively to guarantees issued or modified after
December 31, 2002. The Company has no significant guarantees and the adoption of
this interpretation did not have a material impact on the Company's financial
statements.

         In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),
Consolidation of Variable Interest Entities. The objective of this
interpretation is to provide guidance on how to identify a variable interest
entity and determine when the assets, liabilities, noncontrolling interests and
results of operations of a variable interest entity need to be included in a
company's consolidated financial statements. A company that holds variable
interests in an entity will need to consolidate the entity if the company's
interest in the variable interest entity is such that the company will absorb a
majority of the variable interest entity's expected losses and/or receive a
majority of the entity's expected residual returns, if they occur. The
provisions of this interpretation became effective upon issuance. As of December
31, 2002, the Company did not have any variable interest entities that will be
subject to FIN 46.

         We have reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on our results
of operations or financial position. Based on that review, we believe that none
of these pronouncements will have a significant effect on current or future
earnings or operations.

--------------------------------------------------------------------------------
                      ITEM 7A. QUANTITATIVE AND QUALITATIVE
                         DISCLOSURES ABOUT MARKET RISKS
--------------------------------------------------------------------------------

Price Risk

         Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.

         Our gas production in Poland is currently being sold to POGC based on
U.S. dollar pricing under a five-year contract that may be terminated by us with
a 90-day written notice. The limited volume and single source of our gas
production means we cannot assure uninterruptible production or production in
amounts that would be meaningful to industrial users, which may depress the
price we may be able to obtain. There is currently no competitive market for the
sale of gas in Poland. Accordingly, we expect that the prices we receive for the
gas we produce will be lower than would be the case in a competitive setting and
may be lower than prevailing western European prices, at least until a fully
competitive market develops in Poland.

         We currently do not engage in any hedging activities or have any
derivative financial instruments to protect ourselves against market risks
associated with oil and gas price fluctuations, although we may elect to do so
if we achieve a significant amount of production in Poland.

                                       37
<PAGE>

Foreign Currency Risk

         We have entered into various agreements in Poland, primarily in U.S.
dollars or the U.S. dollar equivalent of the Polish zloty. We conduct our
day-to-day business on this basis as well. The Polish zloty is subject to
exchange rate fluctuations that are beyond our control. We do not currently
engage in hedging transactions to protect ourselves against foreign currency
risks, nor do we intend to do so in the foreseeable future.

--------------------------------------------------------------------------------
               ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
--------------------------------------------------------------------------------

         Our financial statements, including the accountant's report, are
included beginning at page F-1 immediately following the signature page of this
report.


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

         We have not disagreed on any items of accounting treatment or financial
disclosure with our auditors.

                                       38
<PAGE>

                                    PART III

--------------------------------------------------------------------------------
           ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
--------------------------------------------------------------------------------


General

         Our articles of incorporation provide that the board of directors shall
be divided into three classes, with each class as equal in number as
practicable.

Executive Officers and Directors

         The following sets forth the name, age, term of directorship, and
principal business experience of each of our executive officers and director.

              Name                   Age                Position
              ----                   ---                --------
         David N. Pierce             57    President and Chairman of the Board
         Andrew W. Pierce            55    Vice-President, Chief Operating
                                             Officer and Director
         Thomas B. Lovejoy           67    Vice-Chairman, Chief Financial
                                             Officer and Director
         Jerzy B. Maciolek           53    Vice-President of International
                                             Exploration and Director
         Scott J. Duncan             54    Vice-President of Investor Relations,
                                             Secretary/Treasurer and Director
         Peter L. Raven              64    Director
         David L. Worrell            57    Director
         Arnold S. Grundvig, Jr.     54    Director


         David N. Pierce has served as our President and Chairman of the Board
of Directors since 1992. For over three years prior to 1992, Mr. Pierce was the
Vice-President and a director of our predecessor, Frontier Exploration Company,
which he co-founded with his brother, Andrew W. Pierce, in January 1989, and
which was acquired by us in 1992. Prior to founding Frontier Exploration
Company, Mr. Pierce served in executive capacities with privately held oil and
gas companies beginning in 1979. An attorney with over 25 years of experience in
natural resources, securities and international business law, Mr. Pierce is a
graduate of Princeton University and Stanford University Law School.

         Andrew W. Pierce has been our Vice-President, Chief Operating Officer
and a director since 1992. For over three years prior to 1992, he was the
President and a director of our predecessor, Frontier Exploration Company, which
he co-founded with his brother, David N. Pierce, in January 1989, and which was
acquired by us in 1992. Mr. Pierce has over 25 years of experience in oil and
gas exploration, drilling, production and leasing experience, with primary
management and line responsibility for drilling and completion activities in the
western United States.

         Thomas B. Lovejoy has served as our Vice-Chairman of the Board of
Directors since 1995 and as our Chief Financial Officer since 1999. From 1995 to
1999, he also provided consulting services to us. Between 1992 and 1999, Mr.
Lovejoy was the principal of Lovejoy & Associates, Inc., Greenwich, Connecticut,
which provided financial strategic advice respecting private placements, mergers
and acquisitions. From 1989 through 1992, he was the Managing Director and head
of natural resource, utility and mining groups of Prudential Securities, Inc.,
in New York City. From 1980 through 1988, he was the Managing Director and head
of the energy and natural resources group of Paine Webber, Inc. From 1993 to
2001, Mr. Lovejoy served as a director of Scaltech, Inc., Houston, Texas, a
processor of petroleum refinery oil waste. Mr. Lovejoy is a graduate of
Massachusetts Institute of Technology and Harvard Business School.

                                       39
<PAGE>

         Jerzy B. Maciolek has been our Vice-President of International
Exploration and a director since 1996. He was initially employed by us in
September 1995 as a geologist. Mr. Maciolek has been instrumental in our
exploration efforts in Poland. Mr. Maciolek is also currently a member of the
advisory board of the Polish Oil and Gas Company. Prior to becoming our
employee, he was a private consultant for over five years, including consulting
on exploration projects in the western United States, the hydrocarbon potential
of Poland and Kazakhstan, and developing applied integrated geophysical
interpretations over gold mines in Nevada, California and Mexico. During that
time, he provided consulting services to us as well as to others. Mr. Maciolek
is a graduate of the Mining and Metallurgy Academy in Krakow, Poland.

         Scott J. Duncan has served as our Vice-President for Investor
Relations, Secretary/Treasurer and a director since May 1993. Mr. Duncan
provided services to us as a financial consultant from our inception in 1992
through April 1993, when he became a full-time employee. Prior to becoming a
consultant with the Company, he was an executive and director of several small
businesses in Salt Lake City, Utah. Mr. Duncan is a graduate of the University
of Utah School of Business.

         Peter L. Raven has been a director since March 1996. Mr. Raven retired
in 1992 after serving in various positions with Ultramar, PLC, London, England,
a fully integrated oil and gas company, and its U.K. and American held
subsidiaries, including Chief Financial Officer of Ultramar, PLC and President
of American Ultramar (1988-1992) and Executive Vice-President (1985-1988). Mr.
Raven is a graduate of the Downside School in England, the Institute of
Chartered Accountants, and the Harvard Business School Advanced Management
Program. Mr. Raven is a member of our Audit and Compensation Committees. Mr.
Raven resigned as a director effective August 15, 2003.

         David L. Worrell is the founder and has served as the President of
David Worrell Associates, a commercial real estate consulting and development
firm with emphasis on the hospitality industry, from 1990 through 1997 and 1999
through the present. Mr. Worrell served in 1998 as Senior Vice President,
Development, for Homestead Village, Inc., a New York Stock Exchange listed
lodging company. From 1993 through 1997, Mr. Worrell was the Chief Executive
Officer and from 1998 through the present has been the Chairman of Subway Russia
Franchising Company, the exclusive master franchisee of the Subway Sandwich Shop
restaurant concept in Russia. From 1981 through 1990, Mr. Worrell was Managing
Director, Vice President and Director of Development for MAT Associates, a
national real estate developer specializing in hotel and related commercial
development. Prior to 1981, Mr. Worrell was a practicing attorney in the areas
of real estate acquisition and development and international transactions. A
graduate of Stanford Graduate School of Business, Stanford Law School, and
Cornell University, Mr. Worrell is a member of our Audit and Compensation
Committees.

         Arnold S. Grundvig, Jr. is the President and Chief Financial Officer of
A-Systems Corporation, a developer of accounting software, a position he has
held since 1993. From 1990 to 1992, Mr. Grundvig served as Controller for Weider
Health & Fitness, a sports nutrition company, and Schiff Vitamin, a nutrition
enhancement company. From 1985 to 1989, he served as a Financial Analyst for
Petro Source Corporation, a crude oil trading firm. From 1983 to 1985, Mr.
Grundvig worked as an independent turn-around consultant. From 1977 to 1983, he
worked for First Interstate Bank (now Wells Fargo Bank) as Manager of the Credit
Department and as a Commercial Loan officer. From 1971 to 1977, he served as a
Financial Analyst for Dun & Bradstreet, Inc., a commercial credit rating bureau.
A graduate of Phoenix University (MBA) and the University of Utah, Mr. Grundvig
is a member of our Audit and Compensation committees.

Technical Advisory Panel

         In February 2003, we formed a Technical and Industry Advisory Panel to
advise and consult with management in connection with our activities in Poland.
Panel members, who serve at the pleasure of the board of directors, consist of
the following:

         Richard Hardman CBE, 67, has been engaged principally as Exploration
Advisor since February 2003. From January 2002 through January 2003, Mr. Hardman
acted as Advisor on Exploration to the Chief Executive Officer of Enterprise Oil
and worked in an advisory capacity to Neptune Oil and Gas. Between 1983 and
January 2002, Mr. Hardman served in various executive capacities with Amerada

                                       40
<PAGE>

Hess, a worldwide, integrated oil and gas firm. Based in London, he was Vice
President of Worldwide Exploration between May 1998 and May 2001 and Exploration
Advisor thereafter until January 2002. Over a career spanning more than 40
years, Mr. Hardman has worked in oil and gas exploration as a geologist in
Libya, Kuwait, Columbia, Norway and the North Sea. He has served as Chairman of
the Petroleum Society of Great Britain, President of the Geological Society of
London, as the European member of the Advisory Counsel of the American
Association of Petroleum Geologists, and is currently Chairman of APPEX, a
farmout fair organization based in London. He was made a Commander of the
British Empire in New Year Honours List of 1998 for services to the oil
industry.

         Philip Gardner, 54, has been engaged principally as a technical and
commercial advisor since the beginning of April 2003. Mr. Gardner has been the
director of PG Upstream Energy Consultants, Ltd. since March 2003, and was
self-employed as an independent energy consultant from January 2003 through
March 2003. Previously, Mr. Gardner worked between January 1974 and December
2002 in international oil and gas exploration and production as a geologist and
manager in the North Sea, United States, Libya, Australia, Indonesia, Egypt and
Poland for Conoco, Inc. / ConocoPhillips, a fully integrated, worldwide energy
company based in Houston, Texas. Most recently, Mr. Gardner was Poland Upstream
Branch Manager between November 2000 and December 2002, and for five years
previously, Manager Exploration Skills and Resources, both for Conoco U.K. Ltd.,
which became Conoco Phillips UK Ltd. in November 2002.

         Steven McTiernan, 52, has been the principal of Sandown Energy
Consultants Limited, London, since September 2001. He has over 30 years of
diverse oil and gas industry and investment banking experience. He has held
engineering and management positions with Abu Dhabi Petroleum, British
Petroleum, Amoco and Mesa Petroleum. He spent 17 years with The Chase Manhattan
Bank where he was Senior Vice President and Global Energy Executive based in New
York until 1996. He was then appointed Global Head of Oil and Gas Investment
Banking at NatWest Markets. From May 1998 until September 2001, he was Head of
Energy for CIBC World Markets in London. He was appointed a Director of Tullow
Oil plc, a large independent oil and gas exploration and production company
headquartered in London, in February 2002. Mr. McTiernan advised us in
connection with our recent agreement with CalEnergy Gas for the Fences I project
area.

Section 16(a) Beneficial Ownership Reporting Compliance

         Section 16(a) of the Securities Exchange Act of 1934, as amended,
requires our directors and executive officers, and persons who own more than 10%
of a registered class of our equity securities, to file with the Securities and
Exchange Commission initial reports of ownership and reports of changes in
ownership of our equity securities. Officers, directors and greater than 10%
stockholders are required to furnish us with copies of all Section 16(a) forms
they file.

         Based solely upon a review of Forms 3, 4 and 5 and amendments thereto
furnished to us during or respecting our last fiscal year ended December 31,
2002, no person who, at any time during the most recent fiscal year, was a
director, officer, beneficial owner of more than 10% of any class of our equity
securities, or any other person known to be subject to Section 16 of the
Exchange Act failed to file, on a timely basis, reports required by Section
16(a) of the Securities Exchange Act, with the following exceptions: Reports on
Form 5 for David N. Pierce, Thomas B. Lovejoy, Jerzy B. Maciolek, Scott J.
Duncan, Peter L. Raven, and Clay Newton were filed February 19, 2003, which was
five days beyond the required date. We have been informed that the reports were
prepared and placed with an overnight courier in time for timely filing, but
that transportation interruption related to the Presidents' Day storm of 2003
resulted in late delivery.


--------------------------------------------------------------------------------
                         ITEM 11. EXECUTIVE COMPENSATION
--------------------------------------------------------------------------------

         The information from the definitive proxy statement for the 2003 annual
meeting of stockholders under the caption "Election of Directors: Executive
Compensation" is incorporated herein by reference.

                                       41
<PAGE>

--------------------------------------------------------------------------------
          ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                   MANAGEMENT AND RELATED STOCKHOLDER MATTERS
--------------------------------------------------------------------------------

Principal Stockholders

         The following table sets forth, as of April 24, 2003, the name and
shareholdings of each person who owns of record, or was known by us to own
beneficially, 5% or more of the common stock currently outstanding; the name and
shareholdings of each director; and the shareholdings of all executive officers
and directors as a group. Unless otherwise indicated, all shares consist of
common stock, and all such shares are owned beneficially and of record by the
named person or group. Options include only those exercisable within 60 days of
the table date:
<TABLE>
<CAPTION>
                                                      Principal Stockholders, Officers and Directors
                                        ---------------------------------------------------------------------------
                                                  Nature of Ownership                Percentage of Ownership(1)
                                        ----------------------------------------- ---------------------------------
                                          Common                                  Common
           Beneficial Owner               Stock       Options(2)     Total(3)      Stock    Options(2)    Total
--------------------------------------- ------------- ------------- ------------- ---------- ----------- ----------
<S>                                     <C>           <C>           <C>           <C>        <C>         <C>
David N. Pierce(4)...................    86,550        785,000       871,550       0.5%       4.2%        4.7%
Andrew W. Pierce.....................    57,103        760,001       817,104       0.3        4.1         4.4
Thomas B. Lovejoy(5).................   527,367        360,001       887,368       3.0        2.0         4.9
Jerzy B. Maciolek....................        --        410,001       410,001       0.0        2.3         2.3
Scott J. Duncan(6)...................   153,500        250,001       403,501       0.9        1.4         2.2
Peter L. Raven.......................    40,000         38,001        78,001       0.2        0.2         0.4
David L. Worrell(7)..................    32,000             --        32,000       0.2         --         0.2
Arnold S. Grundvig, Jr...............        --             --            --        --         --          --
                                        -------       ---------     ---------     ---        ----        ----
All executive officers and
  directors as a group (8 persons)...   896,520       2,603,005     3,499,525     5.1%       14.2%       19.1%
                                        =======       =========     =========     ===        ====        ====
</TABLE>
-------------------------
(1)  Calculations of total percentages of ownership outstanding for each
     individual assume the exercise of currently vested options held by that
     individual to which the percentage relates. Percentages calculated for
     totals of all executive officers and directors as a group assume the
     exercise of all vested options held by the indicated group.
(2)  These vested options give the holders the right to acquire shares of common
     stock at prices ranging from $2.40 to $10.25 per share with various
     expiration dates ranging from April 2003 to August 2009.
(3)  Except as otherwise noted, shares are owned beneficially and of record, and
     such record stockholder has sole voting, investment and dispositive power.
(4)  Includes 50,000 shares held by David N. Pierce as custodian for minor
     children, 14,000 shares held by Mr. Pierce's wife, Mary Phillips, and 2,000
     shares held by Mary Phillips as custodian for minor children,. Mr. Pierce
     is deemed to hold or share voting and dispositive power over all of such
     shares.
(5)  Includes 41,000 shares held in trust for the benefit of Thomas B. Lovejoy's
     children, 104,500 shares held in Mr. Lovejoy's IRA account, 10,000 shares
     held by Mr. Lovejoy's spouse's IRA account, 200,000 shares held by Lovejoy
     & Associates, Inc. (of which Mr. Lovejoy is sole owner), and 17,500 shares
     owned by Lovejoy & Associates Profit Sharing Plan. Mr. Lovejoy is deemed to
     hold dispositive power over all of such shares.
(6)  Includes 125,000 shares held by Scott J. Duncan jointly with his wife,
     Cathy H. Duncan; 6,500 shares held solely by Cathy H. Duncan; and 22,000
     shares held by Cathy Duncan as custodian for minor children. Mr. Duncan is
     deemed to hold or share voting and dispositive power over all of such
     shares.
(7)  Includes 20,000 shares held by David L. Worrell jointly with his wife,
     Julianne Shedd Worrell, and 5,000 shares held solely by Julianne Shedd
     Worrell. Mr. Worrell is deemed to hold or share dispositive power over all
     of such shares.

                                       42
<PAGE>

Equity Compensation Plans
<TABLE>
<CAPTION>
                                                                                       Number of Securities
                                                                                       Remaining Available
                                      Number of Securities                             for Future Issuance
                                       To Be Issued upon        Weighted-Average           under Equity
                                          Exercise of          Exercise Price of        Compensation Plans
                                      Outstanding Options,    Outstanding Options,    (excluding securities
           Plan Category              Warrants and Rights     Warrants and Rights      reflected in column (a))
                                              (a)                     (b)                        (c)
                                     ----------------------- ----------------------- -----------------------
<S>                                        <C>                       <C>                     <C>
Equity compensation plans
  approved by security holders.....        3,299,017                 $5.21                   350,983
Equity compensation plans not
  approved by security holders.....        1,245,000                  3.27                        --
                                           ---------                  ----                   -------
      Total                                4,544,017                  4.68                   350,983
                                           =========                  ====                   =======
</TABLE>

         Since inception, we have issued options pursuant to stock option and
award plans that have been adopted by the board of directors and approved by the
stockholders. As of December 31, 2002, we had outstanding options to purchase an
aggregate of 3,299,017 shares under plans that have been approved by the
stockholders. In addition, from time to time, the Board of Directors has
authorized the issuance of options, warrants and convertible securities under
arrangements that have not been submitted to the stockholders for approval. This
includes compensatory options granted to employees, consultants, officers,
directors and others. As of December 31, 2002, there was an aggregate of 350,983
shares reserved for issuance under currently outstanding options, warrants and
convertible securities not submitted to the stockholders for approval.

         In addition to the specific provisions noted below, all such
outstanding options, warrants and convertible securities provide for
antidilution adjustments to the number of shares issuable and the exercise or
conversion price in the event of any stock split, stock dividend or
recapitalization of the common stock of the Company; restrict transfer; require
the Company to reserve for issuance that number of shares issuable on exercise
or conversion; require notice to the holder prior to certain extraordinary
corporate events; require payment of the exercise price of options and warrants
in cash plus such other type of consideration as specifically noted; are fully
vested and exercisable unless otherwise indicated; and contain other similar
miscellaneous items.

         Early in the Company's history, in June 1994, the Company granted to
David N. Pierce and Andrew W. Pierce, founders, executive officers and
directors, options to purchase 500,000 shares each at $3.00 per share,
exercisable at any time within 10 years. These options are currently fully
vested and contain terms providing that, in the event of a change of control of
the Company and at the election of the optionee, in consideration of the
cancellation of the unexercised options, the Company will pay to the optionee an
amount equal to the number of unexercised options multiplied by the amount by
which the fair market value of the common stock as of the date preceding the
date of the change of control exceeded the option exercise price. The grants of
these options were not the result of arm's-length negotiations. The Company has
agreed to register under the Securities Act of 1933 the issuance of the common
stock on exercise of these options, at its cost, in certain circumstances. The
options may be exercised by the payment of cash or delivery of shares of common
stock already owned.

         In August 1995, the Company granted to Thomas B. Lovejoy, then the
principal of a financial consultant to the Company and now an officer and
director, options to purchase an aggregate of 350,000 shares of common stock at
$3.00 per share, originally expiring August 1, 2000, with respect to 150,000
shares, August 1, 2001, with respect to 100,000 shares, and August 1, 2002, with
respect to 100,000 shares. The expiration dates of the options previously
expiring in 2000 and 2001 were each extended for two years. The Company has
agreed to register the issuance or resale of the common stock issuable upon
exercise of this option in certain circumstances.

         The Company granted to an outside consultant options to purchase 20,000
shares at $8.25 per share in 1997 and 30,000 shares at $7.375 per share in 1999.
The Company has agreed to register the issuance and resale of the common stock
issuable on the exercise of the option to purchase 20,000 shares granted in 1997
in certain circumstances. The options to purchase 30,000 shares granted in 1999
vest one third per year after the anniversary date of the grant, are exercisable

                                       43
<PAGE>

for a period of seven years after the date of vesting, and are exercisable by
delivering common stock owned by the optionee for over six months or a
promissory note on terms acceptable to the Board of Directors.

         In September 1997, the Company issued to one executive officer and
director and one employee seven-year options to purchase 10,000 shares each at
an exercise price of $7.25 per share. The options are currently fully vested.
The Company has agreed to register issuance of the common stock issuable on
exercise of these options in certain circumstances.

         The Company has granted to a consultant in Poland options to purchase
25,000 shares at $4.0625 per share on October 18, 2000, and at $2.44 per share
on November 12, 2001. Each option vests one third per year after the date of
grant and is exercisable for a period of seven years after the date of vesting.
The options may be exercised by the delivery of a promissory note in a form
satisfactory to the Board of Directors, by the delivery of common stock owned by
the optionee for over six months, or in such other form as the Board of
Directors may deem appropriate.


--------------------------------------------------------------------------------
             ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
--------------------------------------------------------------------------------

         The Company has engaged Clay Newton to provide financial consulting
services from time to time. During 2002, the Company paid Mr. Newton $6,210 for
such services. Additionally in 2002, but prior to his appointment as a director,
Mr. Newton was paid a consulting fee of $9,840 for conducting a pre-appointment
review of the Company's accounting and reporting practices and policies.
Although Mr. Newton resigned as a director on March 31, 2003, he is expected to
continue to provide financial consulting services in 2003. Except for Mr.
Newton's engagement as a consultant prior to his appoint as a director, the
foregoing transactions were not the result of arm's length negotiations.


--------------------------------------------------------------------------------
                        ITEM 14. CONTROLS AND PROCEDURES
--------------------------------------------------------------------------------

         Disclosure controls are procedures that are designed with an objective
of ensuring that information required to be disclosed in our periodic reports
filed with the SEC, such as this Annual Report on Form 10-K, is recorded,
processed, summarized and reported within the time periods specified by the SEC.
Disclosure controls are also designed with an objective of ensuring that such
information is accumulated and communicated to our management, including the
Chief Executive Officer and Chief Financial Officer, in order to allow timely
consideration regarding required disclosures.

         The evaluation of our disclosure controls by the Chief Executive
Officer and Chief Financial Officer included a review of the controls'
objectives and design, the operation of the controls, and the effect of the
controls on the information presented in this Annual Report. Our management,
including the Chief Executive Officer and Chief Financial Officer, does not
expect that disclosure controls can or will prevent or detect all errors and all
fraud, if any. A control system, no matter how well designed and operated, can
provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Also, projections of any evaluation of the disclosure
controls and procedures to future periods are subject to the risk that the
disclosure controls and procedures may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

         Based on their review and evaluation as of a date within 90 days of the
filing of this Form 10-K, and subject to the inherent limitations all as
described above, our Chief Executive Officer and Chief Financial Officer have
concluded that our disclosure controls and procedures (as defined in Rules
13a-14 and 15d-14 under the Securities Exchange Act of 1934) are effective. They
are not aware of any significant changes in our disclosure controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.

                                       44
<PAGE>

                                     PART IV

--------------------------------------------------------------------------------
              ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
                               REPORTS ON FORM 8-K
--------------------------------------------------------------------------------

(a)      The following documents are filed as part of this report or
         incorporated herein by reference.

         1. Financial Statements. See the following beginning at page F-1:

                                                                           Page
                                                                          ------

             Report of Independent Accountants.........................     F-1
             Consolidated Balance Sheets as of December 31, 2002
               and 2001................................................     F-2
             Consolidated Statements of Operations for each of the
               Three Years Ended December 31, 2002, 2001 and 2000,
               respectively............................................     F-3
             Consolidated Statements of Cash Flows for each of the
               Three Years Ended December 31, 2002, 2001 and 2000,
               respectively............................................     F-5
             Consolidated Statements of Stockholders' Equity (Deficit)
               for each of the Three Years Ended December 31, 2002, 2001
               and 2000, respectively..................................     F-6
             Notes to the Consolidated Financial Statements............     F-7

         2.   Supplemental Schedules. The Financial Statement schedules have
              been omitted because they are not applicable or the required
              information is otherwise included in the accompanying Financial
              Statements and the notes thereto.

         3.   Exhibits. The following exhibits are included as part of this
              report:
<TABLE>
<CAPTION>
            SEC
 Exhibit    Reference
 Number*      Number                               Title of Document                                  Location
----------  ----------- ------------------------------------------------------------------------- -----------------
<S>            <C>      <C>                                                                       <C>
 Item 3.                Articles of Incorporation and Bylaws
----------  ----------- ------------------------------------------------------------------------- -----------------
   3.01         3       Restated and Amended Articles of  Incorporation                           Incorporated by
                                                                                                  Reference(1)
   3.02         3       Bylaws                                                                    Incorporated by
                                                                                                  Reference(2)

Item 4.                 Instruments Defining the Rights of Security Holders
----------  ----------- ------------------------------------------------------------------------- -----------------
   4.01         4       Specimen Stock Certificate                                                Incorporated by
                                                                                                  Reference(2)
   4.02         4       Form of Designation of Rights, Privileges, and Preferences of Series A    Incorporated by
                          Preferred Stock                                                         Reference(3)
   4.03         4       Form of Rights Agreement dated as of April 4, 1997, between FX Energy,    Incorporated by
                          Inc. and Fidelity Transfer Corp.                                        Reference(3)

   4.04         4       Form of Designation of Rights, Privileges, and Preferences of 2003        Incorporated by
                          Series Convertible Preferred Stock                                      Reference(13)
   4.05         4       Specimen Stock Certificate for 2003 Series Convertible Preferred Stock    Incorporated by
                                                                                                  Reference(13)



                                       45
<PAGE>
<CAPTION>
            SEC
 Exhibit    Reference
 Number*      Number                               Title of Document                                  Location
----------  ----------- ------------------------------------------------------------------------- -----------------
<S>            <C>      <C>                                                                       <C>
Item 10.                Material Contracts
----------  ----------- ------------------------------------------------------------------------- -----------------
  10.05         10      Mining Usufruct Agreement between the State Treasury of the Republic of   Incorporated by
                          Poland and Lubex Petroleum Company Sp. z o.o. dated December 20,        Reference(4)
                          1996, relating to concession blocks 255 and others (Wilga)
  10.10         10      Mining Usufruct Agreement between the State Treasury of the Republic of   Incorporated by
                          Poland and FX Energy Poland Sp. z o.o. and Partners, commercial         Reference(5)
                          partnership, dated October 30, 1997, related to concession blocks 85,
                          86, 87, 88, 89, 105,108, 109, 129 and 149 in northwestern Poland
                          (Pomeranian)
  10.26         10      Frontier Oil Exploration Company 1995 Stock Option and Award Plan**       Incorporated by
                                                                                                  Reference(6)
  10.27         10      Form of FX Energy, Inc. 1996 Stock Option and Award Plan**                Incorporated by
                                                                                                  Reference(4)
  10.28         10      Form of FX Energy, Inc. 1997 Stock Option and Award Plan**                Incorporated by
                                                                                                  Reference(7)
  10.29         10      Form of FX Energy, Inc. 1998 Stock Option and Award Plan**                Incorporated by
                                                                                                  Reference(7)
  10.30         10      Employment Agreements between FX Energy, Inc. and each of David Pierce    Incorporated by
                          and Andrew Pierce, effective January 1, 1995**                          Reference(2)
  10.31         10      Amendments to Employment Agreements between FX Energy, Inc. and each of   Incorporated by
                          David Pierce and Andrew Pierce, effective May 30, 1996**                Reference(8)
  10.32         10      Form of Stock Option with related schedule (D. Pierce and A. Pierce)**    Incorporated by
                                                                                                  Reference(2)
  10.33         10      Form of Stock Option granted to D. Pierce and A. Pierce**                 Incorporated by
                                                                                                  Reference(2)
  10.34         10      Form of Non-Qualified Stock Option with related schedule**                Incorporated by
                                                                                                  Reference(6)
  10.39         10      Employment Agreement between FX Energy, Inc. and Jerzy B. Maciolek**      Incorporated by
                                                                                                  Reference(8)
  10.40         10      Addendum to Employment Agreement between FX Energy, Inc. and Jerzy B.     Incorporated by
                          Maciolek**                                                              Reference(9)
  10.41         10      Second Addendum to Employment Agreement between FX Energy, Inc. and       Incorporated by
                          Jerzy B. Maciolek**                                                     Reference(9)
  10.42         10      Employment Agreement between FX Energy, Inc. and Scott J. Duncan**        Incorporated by
                                                                                                  Reference(9)
  10.43         10      Form of Indemnification Agreement between FX Energy, Inc. and certain     Incorporated by
                          directors, with related schedule**                                      Reference(4)
  10.44         10      Form of Option granted to executive officers and directors, with          Incorporated by
                          related schedule**                                                      Reference(4)
  10.52         10      Form of Indemnification Agreement between FX Energy, Inc. and certain     Incorporated by
                          directors, with related schedule**                                      Reference(7)

                                       46
<PAGE>
<CAPTION>
            SEC
 Exhibit    Reference
 Number*      Number                               Title of Document                                  Location
----------  ----------- ------------------------------------------------------------------------- -----------------
<S>            <C>      <C>                                                                       <C>
  10.53         10      Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic    Incorporated by
                          Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I     Reference(10)
                          Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to
                          Fences project area
  10.55         10      Option extensions with related schedules**                                Incorporated by
                                                                                                  Reference(11)
  10.57         10      US$5,000,000 9.5% Convertible Secured Note dated as of March 9, 2001      Incorporated by
                                                                                                  Reference(12)
  10.58         10      Form of Pledge Agreement FX Energy Poland Sp. z o.o. and Rolls Royce      Incorporated by
                          Power Ventures Limited dated March 9, 2001, and related schedules       Reference(12)

  10.59         10      Sales / Purchase Agreement Special Provisions between Plains Marketing    Incorporated by
                        Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002           Reference(13)
  10.60         10      Form of Non-Qualified Stock Option awarded August 14, 2002, with          Incorporated by
                        related schedule**                                                        Reference(13)
  10.61         10      Description of compensation arrangement with Thomas B. Lovejoy and        Incorporated by
                        outside directors**                                                       Reference(13)
  10.62         10      Agreement Regarding Cooperation within the Poznan Area (Fences II)        Incorporated by
                        entered into January 8, 2003, by and between Polskie Gornictwo Naftowe    Reference(13)
                        i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.
  10.63         10      Settlement Agreement Regarding the Fences Area entered into January 8,    Incorporated by
                        2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and     Reference(13)
                        FX Energy Poland Sp. z o.o.
  10.64         10      Farmout Agreement Entered into by and between FX Energy Poland            Incorporated by
                        Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. Covering the "Fences   Reference(13)
                        Area" in the Foresudetic Monocline made as of January 9, 2003
  10.65         10      Letter Agreement between Rolls-Royce Power Ventures Limited and FX        Incorporated by
                        Energy, Inc. dated February 6, 2003                                       Reference(13)
  10.66         10      Amendment Agreement No. 1 to 9.5% Convertible Secured Note between FX     Incorporated by
                        Energy, Inc. and Rolls-Royce Power Ventures Limited dated March 10, 2003  Reference(13)


Item 21                 Subsidiaries of the Registrant
----------  ----------- ------------------------------------------------------------------------- -----------------
  21.01         21      Schedule of Subsidiaries                                                  Incorporated by
                                                                                                  Reference(9)

Item 23                 Consents of Experts and Counsel
----------  ----------- ------------------------------------------------------------------------- -----------------

  23.01         23      Consent of PricewaterhouseCoopers LLP, independent accountants            Attached
  23.02         23      Consent of Larry D. Krause, Petroleum Engineer                            Incorporated by
                                                                                                  Reference(13)
  23.03         23      Consent of Troy-Ikoda Limited, Petroleum Engineers                        Incorporated by
                                                                                                  Reference(13)

                                       47
<PAGE>
<CAPTION>
            SEC
 Exhibit    Reference
 Number*      Number                               Title of Document                               Location
----------  ----------- ------------------------------------------------------------------------- -----------------
<S>            <C>      <C>                                                                       <C>
Item 31                 Rule 13a-14(a)/15d14(a) Certifications
----------  ----------- ------------------------------------------------------------------------- -----------------
  31.01         31      Certification of Chief Executive Officer Pursuant to Rule 13a-14          Attached

  31.02         31      Certification of Chief Financial Officer Pursuant to Rule 13a-14          Attached

Item 32                 Section 1350 Certifications
----------  ----------- ------------------------------------------------------------------------- -----------------
  32.01         32      Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section    Attached
                        1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
                        2002

  32.02         32      Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section    Attached
                        1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
                        2002
----------  ----------- ------------------------------------------------------------------------- -----------------

</TABLE>
---------------------------
*    All exhibits are numbered with the number preceding the decimal indicating
     the applicable SEC reference number in Item 601 and the number following
     the decimal indicating the sequence of the particular document. Omitted
     numbers in the sequence refer to documents previously filed as an exhibit,
     but no longer required.
**   Identifies each management contract or compensatory plan or arrangement
     required to be filed as an exhibit, as required by Item 15(a)(3) of Form
     10-K.

(1)  Incorporated by reference from the proxy statement respecting the 1997
     annual meeting of stockholders.
(2)  Incorporated by reference from the registration statement on Form SB-2, SEC
     File No. 33-88354-D.
(3)  Incorporated by reference from the report on Form 8-K dated April 4, 1997.
(4)  Incorporated by reference from the annual report on Form 10-KSB for the
     year ended December 31, 1996.
(5)  Incorporated by reference from the quarterly report on Form 10-QSB for the
     quarter ended September 30, 1997.
(6)  Incorporated by reference from the quarterly report on Form 10-Q for the
     quarter ended September 30, 1995.
(7)  Incorporated by reference from the annual report on Form 10-K for the year
     ended December 31, 1999.
(8)  Incorporated by reference from the registration statement on Form S-1, SEC
     File No.333-05583.
(9)  Incorporated by reference from the annual report on Form 10-KSB for the
     year ended December 31, 1997.
(10) Incorporated by reference from the quarterly report on Form 10-Q for the
     quarter ended March 31, 2000.
(11) Incorporated by reference from the quarterly report on Form 10-Q for the
     quarter ended September 30, 2000.
(12) Incorporated by reference from the annual report on Form 10-K for the year
     ended December 31, 2000.
(13) Incorporated by reference from the annual report on Form 10-K for the
     period ended December 31, 2002.


(b)      Reports on Form 8-K.

         During the quarter ended December 31, 2002, we filed the following item
on Form 8-K:

                    Date of Event Reported             Item(s) Reported
                  ---------------------------  --------------------------------
                       October 28, 2002              Item 5. Other Events

                                       48
<PAGE>

--------------------------------------------------------------------------------
                                   SIGNATURES
--------------------------------------------------------------------------------

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


Dated:  October 8, 2003                FX ENERGY, INC. (Registrant)


                                       By: /s/ David N. Pierce
                                          -------------------------------------
                                          David N. Pierce
                                          President and Chief Executive Officer



Dated: October 8, 2003                     /s/ Thomas B. Lovejoy
                                          -------------------------------------
                                          Thomas B. Lovejoy
                                          Chief Financial Officer

                                       49
<PAGE>

<PAGE>

                       [PricewaterhouseCoopers LLP Logo]



                        REPORT OF INDEPENDENT ACCOUNTANTS





To the Stockholders and Board of Directors
of FX Energy, Inc. and its subsidiaries:


In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of cash flows and of stockholders' equity
present fairly, in all material respects, the financial position of FX Energy,
Inc., and its subsidiaries (the "Company") at December 31, 2002 and 2001, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2 to the
consolidated financial statements, the Company has suffered recurring losses and
negative cash flows from operations that raise substantial doubt about its
ability to continue as a going concern. Management's plans in regard to these
matters are also described in Note 2. The consolidated financial statements do
not include any adjustments that might result from the outcome of this
uncertainty.

As explained in Notes 1 and 19 to the consolidated financial statements, the
Company has restated its financial statements for the years ended December 31,
2002, 2001 and 2000.


/s/ PricewaterhouseCoopers LLP

Salt Lake City, Utah
March 13, 2003, except for the last
sentence of Note 11 and Notes 18 and 19
for which the date is October 1, 2003

                                      F-1
<PAGE>
<TABLE>
<CAPTION>
                                                FX ENERGY, INC. AND SUBSIDIARIES
                                                   Consolidated Balance Sheets
                                                As of December 31, 2002 and 2001


                                                                                                2002              2001
                                                                                          ---------------     --------------
<S>                                                                                       <C>                 <C>
ASSETS

Current assets:
    Cash and cash equivalents............................................................ $       705,012     $    3,157,427
    Receivables:
        Accrued oil sales................................................................         238,236            478,857
        Joint interest and other receivables.............................................          36,893             49,075
    Inventory............................................................................          84,262             87,260
    Other current assets.................................................................          95,726             95,004
                                                                                          ---------------     --------------
            Total current assets.........................................................       1,160,129          3,867,623
                                                                                          ---------------     --------------

Property and equipment, at cost:
    Oil and gas properties (successful efforts method):
        Proved...........................................................................       4,754,377          4,789,252
        Unproved.........................................................................         154,261            655,523
    Other property and equipment.........................................................       3,683,226          3,587,433
                                                                                          ---------------     --------------
        Gross property and equipment.....................................................       8,591,864          9,032,208
    Less accumulated depreciation, depletion and amortization............................      (4,685,487)        (4,090,293)
                                                                                          ---------------     --------------
            Net property and equipment...................................................       3,906,377          4,941,915
                                                                                          ---------------     --------------

Other assets:
    Certificates of deposit..............................................................         356,500            356,500
    Deposits.............................................................................          18,072              2,789
                                                                                          ---------------     --------------
            Total other assets...........................................................         374,572            359,289
                                                                                          ---------------     --------------

Total assets............................................................................. $     5,441,078     $    9,168,827
                                                                                          ===============     ==============



                                                           -Continued-

                         The accompanying notes are an integral part of these consolidated financial statements

                                                               F-2
<PAGE>
<CAPTION>
                                                FX ENERGY, INC. AND SUBSIDIARIES
                                                   Consolidated Balance Sheets
                                                As of December 31, 2002 and 2001
                                                           -Continued-


                                                                                                2002              2001
                                                                                          ---------------     --------------
                                                                                                   (As Restated)
<S>                                                                                       <C>                 <C>
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

Current liabilities:
    Accounts payable..................................................................... $       376,264     $      492,306
    Accrued liabilities..................................................................       4,933,393          2,816,561
    Note payable.........................................................................       5,000,000                 --
                                                                                          ---------------     --------------
            Total current liabilities....................................................      10,309,657          3,308,867

Long-term debt:
    Note payable.........................................................................              --          4,906,916
                                                                                          ---------------     --------------

            Total liabilities............................................................      10,309,657          8,215,783
                                                                                          ---------------     --------------

Commitments (Note 7)

Stockholders' equity (deficit):
    Preferred stock, $.001 par value, 5,000,000 shares authorized as of
        December 31, 2002 and 2001; no shares outstanding................................              --                 --
    Common stock, $.001 par value, 100,000,000 shares authorized as of December 31,
        2002 and 2001; 17,651,917 and 17,913,575 shares issued as of December 31, 2002
        and 2001, respectively...........................................................          17,652             17,914
    Treasury stock, at cost, 0 and 233,340 shares as of December 31, 2002 and
        2001, respectively...............................................................              --         (1,883,805)
    Deferred compensation from stock option modifications................................              --            (54,688)
    Additional paid in capital...........................................................      48,075,035         49,910,078
    Accumulated deficit..................................................................     (52,961,266)       (47,036,455)
                                                                                          ---------------     --------------
            Total stockholders' equity (deficit).........................................      (4,868,579)           953,044
                                                                                          ---------------     --------------
Total liabilities and stockholders' equity (deficit)..................................... $     5,441,078     $    9,168,827
                                                                                          ===============     ==============


                         The accompanying notes are an integral part of these consolidated financial statements

                                                                 F-3
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                FX ENERGY, INC. AND SUBSIDIARIES
                                              Consolidated Statements of Operations
                                      For the years ended December 31, 2002, 2001 and 2000


                                                                             2002               2001              2000
                                                                        ----------------  -----------------  ----------------
Revenues:                                                                                                     (As Restated)
<S>                                                                     <C>               <C>                <C>
    Oil and gas sales.................................................. $     2,208,916   $     2,229,064    $     2,520,779
    Oilfield services..................................................         533,438         1,583,811          1,290,055
                                                                        ---------------   ---------------    ---------------
        Total revenues.................................................       2,742,354         3,812,875          3,810,834
                                                                        ---------------   ---------------    ---------------

Operating costs and expenses:
    Lease operating expenses...........................................       1,365,454         1,358,304          1,348,399
    Geological and geophysical costs...................................       1,030,660         2,909,270          4,679,391
    Exploratory dry hole costs.........................................              --         3,051,334          2,034,206
    Impairment of oil and gas properties...............................       1,547,860           583,855            674,158
    Oilfield services costs............................................         539,783         1,300,713          1,084,129
    Depreciation, depletion and amortization...........................         617,937           661,644            385,807
    Amortization of deferred compensation (G&A)........................          54,688         1,077,547            652,489
    Apache Poland general and administrative costs.....................              --           575,303            956,936
    Other general and administrative costs (G&A).......................       2,440,528           882,985          2,654,430
                                                                        ---------------   ---------------    ---------------
        Total operating costs and expenses.............................       7,596,910        12,400,955         14,469,945
                                                                        ---------------   ---------------    ---------------

Operating loss.........................................................      (4,854,556)       (8,588,080)       (10,659,111)
                                                                        ---------------   ---------------    ---------------

Other income (expense):
    Interest and other income..........................................         118,961           542,824            416,721
    Interest expense...................................................      (1,189,216)         (330,816)            (2,422)
    Impairment of notes receivable.....................................              --           (34,060)                --
                                                                        ---------------   ---------------    ---------------
        Total other income (expense)...................................      (1,070,255)          177,948            414,299
                                                                        ---------------   ---------------    ---------------

Net loss..............................................................  $    (5,924,811)  $    (8,410,132)   $   (10,244,812)
                                                                        ===============   ===============    ===============

Basic and diluted net loss per share................................... $        (0.34)   $        (0.48)    $         (0.62)
                                                                        ===============   ===============    ===============

Basic and diluted weighted average number of shares
    Outstanding........................................................      17,641,335        17,672,684         16,435,436
                                                                        ===============   ===============    ===============


                         The accompanying notes are an integral part of these consolidated financial statements

                                                                  F-4
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                FX ENERGY, INC. AND SUBSIDIARIES
                                              Consolidated Statements of Cash Flows
                                      For the years ended December 31, 2002, 2001 and 2000


                                                                             2002               2001              2000
                                                                        ----------------  -----------------  ----------------
                                                                                                               (As Restated)
<S>                                                                     <C>               <C>                 <C>
Cash flows from operating activities:
    Net loss........................................................... $    (5,924,811)  $    (8,410,132)    $  (10,244,812)
    Adjustments to reconcile net loss to net cash used in
      Operating activities:
            Depreciation, depletion and amortization...................         617,937           661,644            385,807
            Impairment of oil and gas properties.......................       1,547,860           583,855            674,158
            Impairment of notes receivable.............................              --            34,060                 --
            Accrued interest income from notes receivable..............              --           (14,820)                --
            Gain (loss) on property dispositions.......................              --           (28,864)                --
            Exploratory dry hole costs.................................              --         3,051,334          2,034,206
            Common stock and stock options issued for services.........          44,000            35,653             80,813
            Amortization of deferred compensation (G&A)................          54,688         1,077,547            652,489
    Increase (decrease) from changes in working capital items:
        Receivables....................................................         252,803          (101,280)            74,496
        Inventory......................................................           2,998               660            (21,559)
        Other current assets...........................................            (722)          (14,691)            45,693
        Accounts payable and accrued liabilities.......................       1,243,345          (122,696)           236,757
                                                                        ---------------   ---------------     --------------
            Net cash used in operating activities......................      (2,161,902)       (3,247,730)        (6,081,952)
                                                                        ---------------   ---------------     --------------

Cash flows from investing activities:
    Additions to oil and gas properties................................        (161,195)         (754,500)        (6,988,314)
    Additions to other property and equipment..........................        (118,535)         (245,414)          (812,340)
    Net change in other assets.........................................         (15,283)               --                 --
    Proceeds from sale of property interests...........................              --            44,040                 --
    Purchase of marketable debt securities.............................              --                --         (6,314,990)
    Proceeds from marketable debt securities...........................              --         1,281,993         10,282,000
                                                                        ---------------   ---------------     --------------
        Net cash provided by (used) in investing activities............        (295,013)          326,119         (3,833,644)
                                                                        ---------------   ---------------     --------------

Cash flows from financing activities:
    Proceeds from loan and gas purchase option agreement...............              --         5,000,000                 --
    Proceeds from issuance of common stock, net of offering costs......              --                --          9,272,453
    Proceeds from exercise of stock options and warrants...............           4,500                --            102,944
                                                                        ---------------   ---------------     --------------
        Net cash provided by financing activities......................           4,500         5,000,000          9,375,397
                                                                        ---------------   ---------------     --------------

Net increase or (decrease) in cash and cash equivalents................      (2,452,415)        2,078,389           (540,199)
Cash and cash equivalents at beginning of year.........................       3,157,427         1,079,038          1,619,237
                                                                        ---------------   ---------------     --------------
Cash and cash equivalents at end of year............................... $       705,012   $     3,157,427     $    1,079,038
                                                                        ===============   ===============     ==============


                         The accompanying notes are an integral part of these consolidated financial statements

                                                                  F-5
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                FX ENERGY, INC. AND SUBSIDIARIES
                                    Consolidated Statement of Stockholders' Equity (Deficit)
                                      For the years ended December 31, 2002, 2001 and 2000


                                Common Stock                Notes and      Notes    Deferred    Additional
                            -------------------  Treasury    Interest   Receivable Compensation   Paid in  Accumulated      Total
                                      Par Value    Stock    Receivable  From Stock   from        Capital    Deficit    Stockholders'
                              Shares  $.001 Per     (As        from       Option  Stock Option     (As        (As          Equity
                              Issued    Share     Restated)  Officers    Exercise Modifications  Restated)  Restated)     (Deficit)
                            ----------- ------- ----------- ---------- ---------- ------------- ---------- ----------- -------------
<S>                         <C>        <C>       <C>       <C>         <C>        <C>        <C>          <C>          <C>
Balance as of
 December 31, 1999..........14,849,003 $14,849 $(1,747,045)$(2,036,385)       --          -- $40,516,941  $(28,381,511)$  8,366,849
  Sale of common stock, net
   of offering costs........ 2,969,000   2,969         --           --        --          --   9,269,484            --    9,272,453
  Exercise of stock options
   and warrants.............   243,572      44         --           --        --          --     102,900            --      102,944
  Interest on notes
   receivable...............        --      --         --     (140,359)       --          --     140,359            --           --
  Expiration of variable
   stock option plan........        --      --         --    2,176,744        --          --  (2,176,744)           --           --
  Recourse note from stock
   option exercise..........    52,000      52         --           -- $(156,000)         --     155,948            --           --
  Deferred compensation
   from stock option
   modifications............        --      --         --           --        -- $(1,565,974)  1,565,974            --           --
  Amortization of deferred
   compensation.............        --      --         --           --        --     652,489          --            --      652,489
  Options issued for
   services.................        --      --         --           --        --          --      80,813            --       80,813
  Net loss for year.........        --      --         --           --        --          --          --   (10,244,812) (10,244,812)
                            ---------- ------- ----------- ----------- --------- ----------- -----------  ------------ ------------
Balance as of
 December 31, 2000..........17,913,575  17,914 (1,747,045)          --  (156,000)   (913,485) 49,655,675   (38,626,323)   8,230,736
  Interest on notes
   receivable...............        --      --         --           --   (14,820)         --          --            --      (14,820)
  Impairment of notes
   receivable...............        --      --         --           --    34,060          --          --            --       34,060
  52,000 shares tendered
   for payment of notes
   receivable and accrued
   interest.................        --      --   (136,760)          --   136,760          --          --            --           --
  Deferred compensation
   from stock option
   modifications............        --      --         --           --        --    (218,750)    218,750            --           --
  Amortization of deferred
   compensation.............        --      --         --           --        --   1,077,547          --            --    1,077,547
  Options issued for
   services.................        --      --         --           --        --          --      35,653            --       35,653
  Net loss for year.........        --      --         --           --        --          --          --    (8,410,132)  (8,410,132)
                            ---------- ------- ----------- ----------- --------- ----------- -----------  ------------ ------------
Balance as of
 December 31, 2001..........17,913,575  17,914 (1,883,805)          --        --     (54,688) 49,910,078   (47,036,455)     953,044
  Retirement of treasury
   stock....................  (285,340)   (285) 1,883,805           --        --          --  (1,883,520)           --           --
  Amortization of deferred
   compensation.............        --      --         --           --        --      54,688          --            --       54,688
  Common stock  issued for
   services.................    20,682      20         --           --        --          --      43,980            --       44,000
  Exercise of stock options.     3,000       3         --           --        --          --       4,497            --        4,500
  Net loss for year.........        --      --         --           --        --          --          --    (5,924,811)  (5,924,811)
                            ---------- ------- ----------- ----------- --------- ----------- -----------  ------------ ------------
Balance as of
 December 31, 2002..........17,651,917 $17,652 $       --  $        -- $      -- $        -- $48,075,035  $(52,961,266)$ (4,868,579)
                            ========== ======= =========== =========== ========= =========== ===========  ============ ============


                         The accompanying notes are an integral part of these consolidated financial statements.

                                                                   F-6
</TABLE>
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements


Note 1:  Summary of Significant Accounting Policies

         Restatement

As further discussed in Note 19 to the consolidated financial statements, the
Company has determined that certain adjustments are required to restate the
consolidated financial statements for the years ended December 31, 2002, 2001
and 2000. All amounts in the accompanying footnotes have been adjusted for this
restatement as appropriate.

         Organization

FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively
referred to hereinafter as the "Company") is an independent energy company with
activities concentrated within the upstream oil and gas industry. In Poland, the
Company has projects involving the exploration and exploitation of oil and gas
prospects with the Polish Oil and Gas Company ("POGC") and other industry
partners. In the United States, the Company produces oil from fields in Montana
and Nevada and has an oilfield services company in northern Montana that
performs contract drilling and well servicing operations.

         Principles of Consolidation

The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries and the Company's undivided interests in Poland.
All significant inter-company accounts and transactions have been eliminated in
consolidation. At December 31, 2002, the Company owned 100% of the voting common
stock or other equity securities of its subsidiaries.

         Cash Equivalents

The Company considers all highly-liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents.

         Concentration of Credit Risk

The majority of the Company's receivables are within the oil and gas industry,
primarily from the purchasers of its oil and gas, fees generated from oilfield
services and its industry partners. The receivables are not collateralized. To
date, the Company has experienced minimal bad debts, and has no allowance for
doubtful accounts at December 31, 2002 and 2001. The majority of the Company's
cash and cash equivalents is held by three financial institutions in Utah,
Montana and New York.

         Inventory

Inventory consists primarily of tubular goods and production related equipment
and is valued at the lower of average cost or market.

                                      F-7
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -



         Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and
gas operations. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether an individual well has found proved reserves.
If it is determined that an exploratory well has not found proved reserves, or
if the determination that proved reserves have been found cannot be made within
one year, the costs of the well are expensed. The costs of development wells are
capitalized whether productive or nonproductive. Geological and geophysical
costs on exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are not considered to be realizable. Depletion, depreciation and
amortization ("DD&A") of capitalized costs of proved oil and gas properties is
provided on a property-by-property basis using the unit-of-production method.
The computation of DD&A takes into consideration dismantlement, restoration and
abandonment costs and the anticipated proceeds from equipment salvage. The
estimated dismantlement, restoration and abandonment costs are expected to be
substantially offset by the estimated residual value of lease and well
equipment. Effective January 1, 2003 under SFAS 143, the carrying amount of
assets will be increased by their respective retirement obligations. An
impairment loss is recorded if the net capitalized costs of proved oil and gas
properties exceed the aggregate undiscounted future net revenues determined on a
property-by-property basis. The impairment loss recognized equals the excess of
net capitalized costs over the related fair value determined on a
property-by-property basis. Gains and losses are recognized on sales of entire
interests in proved and unproved properties. Sales of partial interests are
generally treated as a recovery of costs and any resulting gain or loss is
recorded as other income.

         Other Property and Equipment

Other property and equipment, including oilfield servicing equipment, is stated
at cost. Depreciation of other property and equipment is calculated using the
straight-line method over the estimated useful lives (ranging from 3 to 40
years) of the respective assets. The costs of normal maintenance and repairs are
charged to expense as incurred. Material expenditures that increase the life of
an asset are capitalized and depreciated over the estimated remaining useful
life of the asset. The cost of other property and equipment sold, or otherwise
disposed of, and the related accumulated depreciation are removed from the
accounts and any gain or loss is reflected in current operations.

The historical cost of other property and equipment, presented on a gross basis
with accumulated depreciation, is summarized as follows:
<TABLE>
<CAPTION>

                                                                                    December 31,            Estimated
                                                                             ----------------------------  Useful Life
                                                                                 2002           2001        (in years)
                                                                             -------------  -------------  -------------
                                                                                   (In thousands)
         <S>                                                                 <C>            <C>               <C>
         Other property and equipment:
             Oilfield servicing equipment................................... $      2,824   $     2,730          6
             Trucks.........................................................          262           262          5
             Building.......................................................           96            96          40
             Office equipment and furniture.................................          501           499        3 to 6
                                                                             ------------   -----------
             Total cost                                                             3,863         3,587
                                                                             ============   ===========
             Accumulated depreciation                                              (2,819)       (2,502)
                                                                             ============   ===========
                 Net property and equipment................................. $        864   $     1,085
                                                                             ============   ===========

                                      F-8
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


         Supplemental Disclosure of Cash Flow Information

Non-cash investing and financing transactions not reflected in the consolidated
statements of cash flows include the following:
<CAPTION>
                                                                                           Year Ended December 31,
                                                                                     ----------------------------------
                                                                                       2002         2001        2000
                                                                                     ----------  ----------  ----------
                                                                                           (In thousands) (As Restated)
         <S>                                                                         <C>         <C>         <C>
         Non-cash investing transactions:
             Additions to properties included in current liabilities................ $      851  $      999  $       --
             Non-cash consideration received from the sale of equipment.............         --          --          23
                                                                                     ----------  ----------  ----------
                 Total.............................................................. $      851  $      999  $       23
                                                                                     ==========  ==========  ==========
         Non-cash financing transactions:
             Shares tendered for payment of notes receivable and accrued interest... $       --  $      137  $    1,838
                                                                                     ----------  ----------  ----------
             Recourse note receivable from stock option exercise....................         --          --         156
                                                                                     ----------  ----------  ----------
                 Total.............................................................. $       --  $      137  $    1,994
                                                                                     ==========  ==========  ==========

Supplemental disclosure of cash paid for interest and income taxes:
<CAPTION>
                                                                                           Year Ended December 31,
                                                                                     -----------------------------------
                                                                                        2002         2001        2000
                                                                                     ----------  ----------- -----------
                                                                                                (In thousands)
         <S>                                                                         <C>         <C>         <C>
         Supplemental disclosure:
             Cash paid during the year for interest................................  $        1  $        2  $        2
             Cash paid during the year for income taxes............................          --          --          --
</TABLE>

         Revenue Recognition

Revenues associated with oil and gas sales are recorded when the title passes
and are net of royalties. Oilfield service revenues are recognized when the
related service is performed.

         Stock-Based Compensation

The Company accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board ("APB") Opinion No. 25
and related interpretations. Nonemployee stock-based compensation is accounted
for using the fair value method in accordance with SFAS No. 123 "Accounting for
Stock-based Compensation."

                                      F-9
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


As of December 31, 2002, the Company had 5,544,017 options outstanding under
stock option and award plans as well as from other individual grants. The
Company applies APB Opinion No. 25 and related interpretations in accounting for
options granted under the stock option and award plans and for other option
agreements. Had compensation cost for the Company's options been determined
based on the fair value at the grant dates consistent with SFAS No. 123, the
Company's net loss and loss per share would have been increased to the pro forma
amounts indicated in the following table:
<TABLE>
<CAPTION>
                                                                                 2002           2001           2000
                                                                             -------------  -------------  -------------
                                                                              (In thousands, except per share amounts)
                                                                                                           (As Restated)
         <S>                                                                 <C>             <C>           <C>
         Net loss:
         Net loss, as reported.............................................. $    (5,925)    $    (8,410)  $    (10,245)
         Add: stock-based employee compensation expense included in
           reported net loss, net of related tax effects....................          55           1,078            652
         Less: Total stock-based employee compensation expense
           determined under the fair value based method for all awards,
           net of related tax effects                                             (1,125)         (1,515)        (1,890)
                                                                             -----------     -----------   ------------
              Pro forma net loss............................................ $    (6,995)    $    (8,847)  $    (11,483)
                                                                             ===========     ===========   ============
         Basic and diluted net loss per share:
              As reported................................................... $     (0.34)    $     (0.48)  $      (0.62)
              Pro forma.....................................................       (0.40)          (0.50)         (0.70)
</TABLE>

The effects of applying SFAS No. 123 are not necessarily representative of the
effects on the reported net income or loss for future years.

The fair value of each option granted to employees and consultants during 2002,
2001 and 2000 is estimated on the date of grant using the Black-Scholes option
pricing model. The following weighted-average assumptions were utilized for the
Black-Scholes valuation: (1) expected volatility of 90% for 2002, 78% to 83% for
2001 and 80% to 87% for 2000; (2) expected lives ranging from four to seven
years; (3) risk-free interest rates at the date of grant ranging from 3.26% to
4.24%; and, (4) dividend yield of zero for each year.

         Income Taxes

Deferred income taxes are provided for the difference between the tax basis of
an asset or liability and its reported amount in the financial statements. Such
difference may result in taxable or deductible amounts in future years when the
reported amount of the asset or liability is recovered or settled, respectively.

         Reclassifications

Certain balances in the 2001 and 2000 financial statements have been
reclassified to conform to the current year presentation. These changes had no
effect on total assets, total liabilities, stockholders' equity or net loss.

         Foreign Operations

The Company's investments and operations in Poland are comprised of U.S. Dollar
expenditures.

         Use of Estimates

The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates with regard to the consolidated financial statements
include the unaudited estimates of proved oil and gas reserve quantities and the
related future net cash flows.

                                      F-10
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


         Net Loss Per Share

Basic earnings per share is computed by dividing the net loss by the weighted
average number of common shares outstanding. Diluted earnings per share is
computed by dividing the net loss by the sum of the weighted average number of
common shares and the effect of dilutive unexercised stock options and warrants
and convertible preferred stock.

Outstanding options and warrants as of December 31, 2002, 2001 and 2000 were as
follows:

                                                    Options and
                                                     Warrants      Price Range
                                                   ------------ ----------------
         Balance sheet date:
           December 31, 2002.......................  5,544,017   $1.50 - $10.25
           December 31, 2001.......................  5,785,585   $1.50 - $10.25
           December 31, 2000.......................  4,572,917   $1.50 - $10.25

The Company had a net loss in 2002, 2001 and 2000. The above options and
warrants were not included in the computation of diluted earnings per share for
2002, 2001 or 2000 because the effect would have been antidilutive.

Note 2:  Liquidity and Capital Resources

The accompanying consolidated financial statements have been prepared assuming
the Company will continue as a going concern and do not include any adjustments
to reflect the possible future effects on the recoverability of assets and
liquidation of liabilities that may result from this uncertainty. The Company
has incurred substantial operating losses and negative cash flows from
operations since inception and had an accumulated deficit of approximately $54
million at December 31, 2002. These matters raise substantial doubt about the
Company's ability to continue as a going concern. To date, the Company has
financed its operations principally through the sale of equity securities,
issuance of debt securities and through agreements with industry partners that
funded the Company's share of costs in certain exploratory activities in order
to earn an interest in the Company's properties.

As of December 31, 2002, the Company had $705,012 of cash and cash equivalents,
negative working capital of $(9,149,528) including debt due to Rolls Royce Power
Ventures ("RRPV") with a principal amount of $5.0 million due on or before March
9, 2003. In addition, the Company has agreed to spend $16.0 million of
exploration costs on the Fences I project area to earn a 49.0% interest. Through
the end of 2002, the Company had paid $6.7 million towards the $16.0 million
commitment, leaving a remaining cash commitment to POGC of $9.3 million.

Subsequent to December 31, 2002, the Company has amended its loan agreement with
RRPV (see Note 6) and raised approximately $5.6 million through the sale of its
convertible preferred stock (see Note 17). In addition, the Company entered into
a Farmout Agreement with CalEnergy Gas whereby CalEnergy Gas has the right, but
not the obligation, to earn a 24.5% interest (50% of the Company's interest) in
the Fences I project area by spending a total of $10.6 million, including the
cost to drill two wells plus certain cash payments to the Company, all to be
completed by December 15, 2003. CalEnergy Gas also has the right to terminate
participation after each of the first two wells. However, if CalEnergy Gas
completes all the earning requirements, the work performed and payments will
exceed the Company's remaining obligations to POGC to complete its earning
requirements in the Fences I project area.

The Company's long-term success or failure is largely dependent on the outcome
of its exploration, production and acquisition activities in Poland. The
Company's ability to continue its ongoing oil and gas activities in Poland is
dependent on accessing additional capital directly or through further farmouts.
The availability of such capital will effect the timing, pace, scope and amount
of the Company's future capital expenditures. There can be no assurance the
Company will be able to obtain additional financing, reduce expenses or
successfully complete other steps to continue as a going concern. If the Company

                                      F-11
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


is unable to obtain sufficient funds to satisfy its cash requirements, it may be
forced to curtail operations, dispose of assets or seek extended payment terms
from its vendors. Such events would materially and adversely affect the
Company's financial position and results of operations.

Note 3:  Investment in Marketable Debt Securities

The Company follows the provisions of SFAS No. 115 "Accounting for Certain
Investments in Debt and Equity Securities." The Company's marketable debt
securities with remaining contractual maturities of less than twelve months are
classified as available for sale. The Company had no investment in debt and
equity securities at December 31, 2002.

Note 4:  Performance Bond Deposits

As of December 31, 2002 and 2001, the Company had a replacement bond to a
federal agency in the amount of $463,000, which was collateralized by
certificates of deposit totaling $231,500. In addition, there are certificates
of deposit totaling $125,000 covering performance bonds in other states.

Note 5:  Accrued Liabilities

The Company's accrued liabilities as of December 31, 2002 and 2001 were
comprised of the following:

                                                         December 31,
                                                  ----------------------------
                                                      2002           2001
                                                  -------------  -------------
                                                          (In thousands)
         Accrued liabilities:
             Exploratory dry hole costs.........  $        880   $        880
             Drilling costs.....................           433             --
             Seismic costs......................         1,859          1,798
             Pipeline costs.....................           502             --
             Interest payable, POGC.............           704             --
             Interest payable, RRPV.............           392             --
             Other costs........................           163            139
                                                  ------------   ------------
                 Total..........................  $      4,933   $      2,817
                                                  =============  =============

Note 6:  Notes Payable

On March 9, 2001, the Company signed a $5.0 million, 9.5% loan agreement and gas
purchase option agreement with RRPV. The proceeds from the loan were used for
exploration and development of additional gas reserves in Poland. The loan was
interest free for the first year. In consideration for the loan and not charging
interest for the first year, the Company granted RRPV an option to purchase up
to 17 Mmcf of gas per day from the Company's properties in Poland, subject to
availability, exercisable on or before March 9, 2002. The option to purchase gas
from the Company's Polish properties was not exercised by RRPV. In accordance
with the loan agreement, the entire principal amount plus accrued interest is
due on or before March 9, 2003, unless RRPV elects to convert the loan to
restricted common stock at $5.00 per share, the market value of the Company's
common stock at the time the terms with RRPV were finalized, on or before March
9, 2003. As collateral for the loan, the Company granted RRPV a lien on most of
the Company's Polish property interests.

For financial reporting purposes, the Company imputed interest expense for the
first year at 9.5%, or $433,790, to be amortized ratably over the one-year
interest free period beginning March 9, 2001 and recorded an option premium of
$433,790 pertaining to granting RRPV an option to purchase gas from the
Company's properties in Poland, to be amortized ratably to other income over the
one-year option period.

In March, 2003, following a private placement of convertible preferred stock,
the Company paid $2.2 million to RRPV. In return, RRPV extended the maturity
date of the note to December 31, 2003. The Company has also agreed to pay 40% of

                                      F-12
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


the gross proceeds of any subsequent equity or debt offering concluded prior to
the amended maturity date to RRPV. The Company also agreed to assign its rights
to payments under the CalEnergy Gas agreement to RRPV, except for those amounts
relating to the two wells required to be drilled under the agreement. All such
payments will be used to offset the remaining principal and interest. In
exchange for these payments, RRPV agreed to release its lien on interests earned
by CalEnergy Gas under its agreement with the Company.

The loan amendment contains other terms and conditions, including an increase in
the interest rate on the note from 9.5% to 12% per annum effective March 9,
2003, an extension of the conversion period until December 31, 2003, with the
conversion price being changed from $5.00 per share to $3.42 per share, the
market price of the Company's stock when RRPV agreed to extend the payment date,
and an extension fee payment of $100,000. In accordance with EITF 98-5,
"Accounting for Convertible Securities with Beneficial Conversion Features or
Contingently Adjustable Conversion Ratios," no charge to income will be recorded
as a result of the reduction in conversion price as the new conversion price
does not result in any intrinsic value.

Note 7:  Commitments

         Fences I Project Area

On April 11, 2000, the Company signed an agreement with POGC under which the
Company will earn a 49.0% working interest in approximately 265,000 gross acres
in west central Poland (the "Fences I" project area) by spending $16.0 million
for agreed drilling, seismic acquisition and other related activities.

During 2000, the Company paid $6,689,432 to POGC under the agreement, including
$4,586,063 for drilling activities and $2,103,369 for 3-D seismic activities,
leaving a remaining commitment of $9,310,568. During 2002 and 2001, the Company
did not make any additional cash payments to POGC relating to this agreement. As
of December 31, 2001, the Company had accrued $2,678,477 of additional costs
pertaining to the Fences project area $16.0 million commitment, including
$880,121 for drilling activities and $1,798,356 for 3-D seismic activities.

During 2002, the Company reaffirmed its intent to fulfill its $16 million
commitment with POGC. In connection with this agreement, the Company agreed to
recognize and pay at a future date an additional $2,306,627 of costs related to
prior exploration activities in the Fences I area to POGC, $1,602,902 of which
will be credited towards the $16 million commitment. The $2,306,627 is recorded
as an accrued liability, net of accounts receivable from POGC, at December 31,
2002. The 2002 amount includes $703,725 in interest costs related to the
Company's prior liabilities to POGC, $432,875 in drilling costs, $417,653 in
seismic costs, $502,244 in pipeline costs, and $250,130 related to foreign
exchange adjustments. As part of its future payment, the Company agreed to
assign in 2003 all of its right to the Kleka well, including the amounts
recorded as accounts receivable for Kleka gas sales. Accordingly, at December
31, 2002, the Company's account receivable from POGC in the amount of $606,986
was offset against the POGC liability. The Company further agreed to begin
accruing interest on the past due amount to POGC. The interest rate in effect at
December 31, 2002 was 12.8%. The interest rate changed on January 1, 2003, to
10.4%.

         Apache Exploration Program

The Apache Exploration Program ("AEP") consists of various agreements signed
between the Company and Apache Corporation ("Apache") during 1997 through 2001.
Apache Poland general and administrative ("G&A") costs consist of the Company's
share of direct overhead costs incurred by Apache in Poland in accordance with
the terms of the AEP. Apache Poland G&A costs were $0, $575,000 and $957,000 for
the years ended December 31, 2002, 2001 and 2000, respectively. The initial
primary terms of the Apache Exploration Program included a commitment by Apache
to cover the Company's share of costs to drill ten exploratory wells, to acquire
2,000 kilometers of 2-D seismic and cover the Company's share of other specified
costs to earn a fifty-percent interest in the Company's Lublin Basin and
Carpathian project areas. As of December 31, 2000, Apache had completed all of
its requirements under the terms of the Apache Exploration Program.

                                      F-13
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


Note 8:  Income Taxes

The Company recognized no income tax benefit from the losses generated during
2002, 2001 and 2000. The components of the net deferred tax asset as of December
31, 2002 and 2001 are as follows:
<TABLE>
<CAPTION>
                                                                                                   December 31,
                                                                                            ----------------------------
                                                                                                2002           2001
                                                                                            -------------  -------------
                                                                                                   (In thousands)
         <S>                                                                                <C>            <C>
         Deferred tax liability:
             Property and equipment basis differences...................................... $       (370)  $       (349)
         Deferred tax asset:
             Net operating loss carryforwards:
                 United States.............................................................       12,475         12,174
                 Poland....................................................................        4,224          3,893
             Oil and gas properties........................................................        1,795          1,218
             Options issued for services...................................................          610            143
             Other.........................................................................           10             10
             Valuation allowance...........................................................      (18,744)       (17,089)
                                                                                            ------------   ------------
                 Total..................................................................... $         --   $         --
                                                                                            ============   ============
<CAPTION>
The change in the valuation allowance during 2002, 2001 and 2000 is as follows:

                                                                                       Year Ended December 31,
                                                                             ---------------------------------------------
                                                                                 2002           2001            2000
                                                                             -------------  -------------  ---------------
                                                                                            (In thousands)
                                                                                              (Restated)      (Restated)
          <S>                                                                <C>             <C>           <C>
          Valuation allowance:
             Balance, beginning of year..................................... $   (17,089)    $   (15,590)  $    (12,600)
             Decrease due to property and equipment basis differences.......        (577)            136            109
             Increase due to net operating loss.............................        (632)         (1,956)        (2,931)
             Other..........................................................        (446)            321           (168)
                                                                             -----------     -----------   ------------
                 Total...................................................... $   (18,744)    $   (17,089)  $    (15,590)
                                                                             ===========     ===========   ============
</TABLE>

SFAS No. 109 "Accounting for Income Taxes" requires that a valuation allowance
be provided if it is more likely than not that some portion or all of a deferred
tax asset will not be realized. The Company's ability to realize the benefit of
its deferred tax asset will depend on the generation of future taxable income
through profitable operations and expansion of the Company's oil and gas
producing activities. The risks associated with that growth requirement are
considerable, resulting in the Company's conclusion that a full valuation
allowance be provided at December 31, 2002 and 2001.

         United States NOL

At December 31, 2002, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $33,446,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and 14,697,000 expires subsequent to 2018. The utilization of the NOL
carryforwards against future taxable income in the United States may become
subject to an annual limitation if there is a change in ownership. The NOL
carryforwards in the United States include $6,326,000 relating to tax deductions
resulting from the exercise of stock options. The tax benefit from adjusting the
valuation allowance related to this portion of the NOL carryforward will be
credited to additional paid-in capital.

         Polish NOL

As of December 31, 2002, the Company had NOL carryforwards in Poland totaling
approximately $11,324,600, including $882,262, $1,925,220 and $5,734,913
generated in 2002, 2001 and 2000, respectively. The NOL carryforwards may be

                                      F-14
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


carried forward five years in Poland. However, no more than fifty-percent of the
NOL carryforwards for any given year may be applied against Polish income in
succeeding years.

The domestic and foreign components of our net loss are as follows:
<TABLE>
<CAPTION>
                                                                                      Year Ended December 31,
                                                                             -------------------------------------------
                                                                                 2002           2001           2000
                                                                             -------------  -------------  -------------
                                                                                    (In thousands)        (As Restated)
             <S>                                                             <C>            <C>            <C>
             Domestic....................................................... $     (3,570)  $     (1,585)  $     (3,697)
             Foreign........................................................       (2,355)        (6,825)        (6,548)
                                                                             ------------   ------------   ------------
                 Total...................................................... $     (5,925)  $     (8,410)  $    (10,245)
                                                                             ============   ============   ============
</TABLE>

Note 9:  Private Placement of Common Stock

During 2000, the Company completed a private placement of 2,969,000 shares of
common stock that resulted in net proceeds of $9,272,453 ($10,391,500 gross).
The proceeds from this placement were used to partially fund ongoing exploration
and development activities in Poland and for general corporate purposes.

Note 10:  Stock Options and Warrants

         Equity Compensation Plans

The Company's equity compensation consists of annual Stock Option and Award
Plans that are each subject to approval by the Board of Directors and are
subsequently presented for approval by the shareholders at each of the Company's
annual meetings. As of the date of this report, no options had been issued under
the 2002 Stock Option and Award Plan.

The following table summarizes information regarding the Company's stock option
and award plans as of December 31, 2002:
<TABLE>
<CAPTION>
                                                                                              Weighted      Number of
                                                                             Number of        Average         Shares
                                                                               Shares         Exercise      Available
                                                                             Authorized       Price of      for Future
                                                                             Under Plan     Outstanding      Issuance
                                                                                               Shares
                                                                            -------------  --------------- -------------
          <S>                                                                 <C>          <C>                 <C>
          Equity compensation plans approved by shareholders:
            1995 Stock Option and Award Plan................................     500,000   $         8.38            --
            1996 Stock Option and Award Plan................................     500,000             6.65        14,500
            1997 Stock Option and Award Plan................................     500,000             7.79        57,400
            1998 Stock Option and Award Plan................................     500,000             6.46        12,000
            1999 Stock Option and Award Plan................................     500,000             4.40         5,333
            2000 Stock Option and Award Plan................................     600,000             2.44        31,750
            2001 Stock Option and Award Plan................................     600,000             2.40       230,000
                                                                            -------------  --------------- -------------
              Total.........................................................   3,700,000   $         6.09       350,983
                                                                            =============  =============== =============
</TABLE>

The above table excludes 1,195,000 options that have been granted outside of
shareholder approved option plans.

All stock option and award plans are administered by a committee (the
"Committee") consisting of the board of directors or a committee thereof. At its
discretion, the Committee may grant stock, incentive stock options ("ISOs") or
non-qualified options to any employee, including officers. In addition to the
options granted under the stock option plans, the Company also issues
non-qualified options outside the stock option plans. The granted options have
terms ranging from five to seven years and vest over periods ranging from the
date of grant to three years. Under terms of the stock option award plans, the
Company may also issue restricted stock. The Company has not issued any stock
awards through the date of this report under the terms of the above stock option
and award plans.

                                      F-15
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -
<TABLE>
<CAPTION>
The following table summarizes fixed option activity for 2002, 2001 and 2000:

                                                  2002                       2001                       2000
                                        --------------------------  ------------------------  -------------------------
                                                        Weighted                  Weighted                   Weighted
                                                        Average                   Average                    Average
                                         Number of      Exercise    Number of     Exercise     Number of     Exercise
                                           Shares        Price        Shares       Price        Shares        Price
                                        -------------  -----------  -----------  -----------  ------------  -----------
       <S>                                 <C>         <C>           <C>         <C>            <C>         <C>
       Fixed Options Outstanding:
           Beginning of year.........      4,785,585   $      4.87   4,322,917   $      5.15    3,896,501   $      5.25
           Granted...................        551,000          2.40     501,750          2.44      501,750          4.06
           Exercised.................         (3,000)         1.50          --            --      (75,000)         3.00
           Canceled..................       (114,568)         6.00     (33,082)         5.00         (334)         8.63
           Expired...................       (675,000)         2.61      (6,000)         5.75           --           --
                                        -------------               -----------               ------------
               End of year...........      4,544,017   $      4.68   4,785,585   $      4.87    4,322,917   $      5.15
                                        =============               ===========               ============

       Exercisable at year-end.......      3,515,867   $      5.41   3,669,356   $      5.28    2,744,183   $      5.61
                                        =============               ===========               ============
</TABLE>

The weighted average fair value per share of options granted during 2002, 2001
and 2000 was $1.80, $1.16 and $2.56, respectively. The above table excludes
shares that would be issued to RRPV should they exercise the option to convert
their debt to stock as described in Note 6.

The following table summarizes information about fixed stock options outstanding
as of December 31, 2002:
<TABLE>
<CAPTION>
                                                     Outstanding                                 Exercisable
                                ------------------------------------------------------  -------------------------------
                                                  Weighted Average
                                  Number of           Remaining           Weighted        Number of        Weighted
                Exercise           Options        Contractual Life        Average          Options         Average
              Price Range        Outstanding         (in years)        Exercise Price    Exercisable    Exercise Price
         --------------------------------------  --------------------  ---------------  --------------  ---------------
         <S>                        <C>                 <C>            <C>                  <C>         <C>
         $1.50 - $3.00.........     2,155,750           3.70           $                    1,284,923   $
                                                                                 2.72                            2.93
         $4.06 - $6.75.........     1,288,100           3.68                     5.37       1,130,777            5.55
         $7.25 - $10.25........     1,100,167           1.87                     8.51       1,100,167            8.51
                                ---------------  --------------------  ---------------  --------------  ---------------
                Total..........     4,544,017           3.25           $         4.87       3,515,867   $        5.52
                                ===============  ====================  ===============  ==============  ===============
</TABLE>

The above table excludes shares that would be issued to RRPV should they
exercise the option to convert their debt to 1,000,000 shares of stock as
described in Note 6.

         Warrants

The following table summarizes changes in outstanding and exercisable warrants
during 2002, 2001 and 2000:
<TABLE>
<CAPTION>
                                             2002                         2001                         2000
                                  ---------------------------  ---------------------------- ---------------------------
                                   Number of       Price        Number of       Price        Number of       Price
                                    Shares         Range          Shares        Range         Shares         Range
                                  ------------ --------------  ------------ --------------- ------------ --------------
          <S>                        <C>       <C>                 <C>      <C>                <C>       <C>
          Warrants outstanding:
              Beginning of year...   100,000   $      3.00         250,000  $3.00 - $6.90      270,572   $1.65 - $6.90
          Exercised...............        --            --              --             --      (20,572)           1.65

              Expired.............  (100,000)  $      3.00        (150,000) $        6.90           --              --
                                  ------------                 -------------                ------------
                  End of year.....        --   $        --         100,000  $        3.00      250,000   $3.00 - $6.90
                                  ============                 =============                ============
</TABLE>

         Option and Warrant Extensions

On August 5, 2001, the Company extended the term of options and warrants to
purchase 125,000 shares of the Company's common stock that were to expire during
2001 for a period of two years, with a one-year vesting period. In accordance

                                      F-16
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


with FIN 44 "Accounting for Certain Transactions Involving Stock Compensation,"
the Company incurred deferred compensation costs of $218,750 applicable to an
officer and a non-officer, to be amortized to expense over the one-year vesting
period.

On August 4, 2000, the Company extended the term of options and warrants to
purchase 678,000 shares of the Company's common stock that were to expire during
2000 for a period of two years, with a one-year vesting period. The Company
incurred deferred compensation costs of $1,565,974, including $1,188,332
covering the intrinsic value applicable to officers and employees and $377,642
covering the fair market value calculated using the Black-Scholes model for a
consultant, which was amortized to expense over the one-year vesting period.
These options have now expired.

         Note Receivable from Stock Option Exercises

On November 8, 2000, a former employee exercised an option to purchase 52,000
shares of the Company's common stock at a price of $3.00 per share. The former
employee elected to pay for the cost of the exercise by signing a full recourse
promissory note with the Company for $156,000. Terms of the note receivable
included a three-year term with annual principal payments of $52,000 plus
interest accrued at 9.5%. On November 8, 2001, the former employee surrendered
52,000 shares of the Company's common stock in return for cancellation of the
note receivable. The Company recorded a loss of $34,060 on the transaction and
the acquisition of 52,000 shares of common stock as treasury stock at a price of
$2.63 per share, the closing price of the Company's stock on November 8, 2001.

Note 11:  Related Party Transactions

         Notes Receivable from Officers

On February 17, 1998, two of the Company's officers exercised options to
purchase 300,000 shares of the Company's common stock at $1.50 per share that
were scheduled to expire on May 6, 1998. The officers paid for the cost of
exercising the options by utilizing a contractual bonus of $100,000 each issued
to them during 1997 and signing a full recourse note payable to the Company for
$125,000 each with interest accrued at 7.7%. On April 10, 1998, in consideration
of the agreement of the two officers to not sell the Company's common stock in
market transactions, the Company agreed to advance the officers, on a
non-recourse basis, additional funds to cover their tax liabilities and other
considerations. As of December 31, 1999, the officers had been advanced a total
amount of $1,837,920. On December 28, 2000, the officers surrendered the
collateralized shares to the Company in return for the cancellation of the notes
receivable from officers and the Company cancelled the notes receivable with a
corresponding reduction in additional paid-in capital (See Note 19).

                                      F-17
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


Note 12:  Quarterly Financial Data (Unaudited)

Summary quarterly information for 2002 and 2001 is as follows:
<TABLE>
<CAPTION>
                                                                           Quarter Ended
                                             ---------------------------------------------------------------------------
                                               December 31        September 30          June 30           March 31
                                             -----------------  -----------------  ------------------ ------------------
                                                              (In thousands, except per share amounts)
         <S>                                 <C>                <C>                <C>                <C>
         2002:
             Revenues....................... $           708    $            977   $           607    $           450
             Net operating loss.............          (2,833)               (271)             (751)            (1,000)
             Net loss.......................          (3,664)               (373)             (870)            (1,018)

             Basic and diluted net loss per
              common share.................  $         (0.21)   $          (0.02)  $         (0.05)   $         (0.06)

         2001:
             Revenues....................... $           635    $          1,174   $         1,363    $           641
             Net operating loss.............          (3,254)             (1,283)           (1,855)            (2,196)
             Net loss.......................          (3,251)             (1,195)           (1,807)            (2,157)

             Basic and diluted net loss per
               common share................. $         (0.19)   $          (0.07)  $         (0.10)   $         (0.12)
</TABLE>

The net operating loss for the fourth quarter of 2002 includes $1,547,860 in
property impairment costs, and $703,725 and $502,244 in interest and seismic
costs, respectively, incurred in connection with a revision of the Company's
agreement with POGC relative to the Fences I project area. The net operating
loss for the fourth quarter of 2001 includes $3,048,137 in dry hole costs and
$525,355 in property impairment costs.

Note 13:  Business Segments

The Company operates within two business segments of the oil and gas industry:
exploration and production ("E&P") and oilfield services. The Company's revenues
associated with its E&P activities are comprised of oil sales from its producing
properties in the United States and oil and gas sales from its producing
properties in Poland. Over 85.0% of the Company's oil sales in the United States
were to Cenex during 2000, 2001 and the first half of 2002. During the second
half of 2002, over 85% of the Company's oil sales were to Plains Marketing
Canada, LP. During 2002 and 2001, all of the Company's oil and gas sales in
Poland were to POGC. There were no oil and gas sales in Poland during 2000. The
Company believes the purchasers of its oil and gas production could be replaced,
if necessary, without a loss in revenue. E&P operating costs are comprised of:
(1) exploration costs (geological and geophysical costs, exploratory dry holes,
non-producing leasehold impairments and Apache Poland G&A costs (in 2000)), and,
(2) lease operating costs (lease operating expenses and production taxes).
Substantially all exploration costs are related to the Company's operations in
Poland. Substantially all lease operating costs are related to the Company's
domestic production.

The Company's revenues associated with its oilfield services segment are
comprised of contract drilling and well servicing fees generated by the
Company's oilfield servicing equipment in Montana. Oilfield servicing costs are
comprised of direct costs associated with its oilfield services.

DD&A directly associated with a respective business segment is disclosed within
that business segment. The Company does not allocate current assets, corporate
DD&A, general and administrative costs, amortization of deferred compensation,
interest income, interest expense, impairment of notes receivable from officers,
other income or other expense to its operating business segments for management
and business segment reporting purposes. All material inter-company transactions
between the Company's business segments are eliminated for management and
business segment reporting purposes.

                                      F-18
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


Information on the Company's operations by business segment for 2002, 2001 and
2000 is summarized as follows:
<TABLE>
<CAPTION>
                                                                                                2002
                                                                             -------------------------------------------
                                                                                              Oilfield
                                                                                 E&P          Services        Total
                                                                             -------------  -------------  -------------
                                                                                           (In thousands)
         <S>                                                                 <C>            <C>            <C>
         Operations summary:
             Revenues(1).................................................... $      2,209   $       533    $      2,742
             Cash operating costs...........................................       (2,396)         (540)         (2,936)
             Non-cash operating costs.......................................       (1,545)           --          (1,545)
                                                                             ------------   -----------    ------------
                 Operating income or (loss) before DD&A expense.............       (1,732)           (7)         (1,739)
              DD&A expense..................................................         (281)         (310)           (591)
                                                                             ------------   -----------    ------------
              Operating loss................................................ $     (2,013)  $      (317)   $     (2,330)
                                                                             ============   ===========    ============
         Identifiable net property and equipment:
             Unproved properties -  Poland.................................. $        146   $        --    $        146
             Unproved properties - Domestic.................................            8            --               8
             Proved properties - Poland.....................................        1,931            --           1,931
             Proved properties - Domestic...................................          957            --             957
             Equipment and other............................................           --           791             791
                                                                             ------------   -----------    ------------
                 Total...................................................... $      3,042   $       791    $      3,833
                                                                             ============   ===========    ============

         Net Capital Expenditures:

             Property and equipment(2)                                       $      1,012   $       116    $      1,128
                                                                             ------------   -----------    ------------

                 Total...................................................... $      1,012   $       116    $      1,128
                                                                             ============   ===========    ============
---------------------
(1)      E&P revenues include $1,924,000 generated in the United States and
         $285,000 generated in Poland.
(2)      E&P includes $418,000 of pipeline costs, $586,000 of proved property
         additions and $8,000 of unproved property additions.
<CAPTION>

                                                                                                2001
                                                                             -------------------------------------------
                                                                                              Oilfield
                                                                                 E&P          Services        Total
                                                                             -------------  -------------  -------------
                                                                                           (In thousands)
         <S>                                                                  <C>           <C>            <C>
         Operations summary:
             Revenues (1)...................................................  $     2,229)  $     1,584    $      3,813
             Cash operating costs...........................................       (5,751)       (1,300)         (7,051)
             Non-cash operating costs (2)...................................       (2,727)           --          (2,727)
                                                                              -----------   -----------    ------------
                 Operating income or (loss) before DD&A expense.............       (6,249)          284          (5,965)
              DD&A expense..................................................         (322)         (308)           (630)
                                                                              -----------   -----------    ------------

              Operating loss................................................  $    (6,571)  $       (24)   $     (6,595)
                                                                              ===========   ===========    ============

         Identifiable net property and equipment:
             Unproved properties -  Poland..................................  $       648   $        --    $        648
             Unproved properties - Domestic.................................            8            --               8
             Proved properties - Poland.....................................        2,324            --           2,324
             Proved properties - Domestic...................................          877            --             877
             Equipment and other............................................           --           985             985
                                                                              -----------   -----------    ------------
                 Total......................................................  $     3,857   $       985    $      4,842
                                                                              ===========   ===========    ============
         Net Capital Expenditures:
             Property and equipment(3)......................................  $     1,745   $       248    $      1,993
                                                                              -----------   -----------    ------------
                 Total......................................................  $     1,745   $       248    $      1,993
                                                                              ===========   ===========    ============
</TABLE>
----------------------
(1)      E&P revenues include $1,815,000 generated in the United States and
         $414,000 generated in Poland.
(2)      E&P includes accrued exploratory dry hole costs of $880,000, accrued
         3-D seismic costs of $1,799,000, stock options issued for services
         valued at $36,000, a $572,000 credit pertaining to reversing accrued
         compensation and an impairment charge of $584,000 for unproved Polish
         properties.
(3)      E&P includes a $894,000 of exploratory dry hole costs, $320,000 of
         proved property additions and $531,000 of unproved property additions.

                                      F-19
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -
<TABLE>
<CAPTION>
                                                                                                2000
                                                                             -------------------------------------------
                                                                                              Oilfield
                                                                                 E&P          Services        Total
                                                                             -------------  -------------  -------------
                                                                                           (In thousands)
         <S>                                                                 <C>            <C>             <C>
         Operations summary:
             Revenues........................................................$     2,521    $     1,290     $    3,811
             Cash operating costs............................................     (8,710)        (1,084)        (9,794)
             Non-cash operating costs (1)....................................       (983)            --           (983)
                                                                             -----------    -----------     ----------
                 Operating income or (loss) before DD&A expense..............     (7,172)           206         (6,966)
             DD&A expense....................................................        (73)          (247)          (320)
                                                                             -----------    -----------     ----------
             Operating loss..................................................$    (7,245)   $       (41)    $   (7,286)
                                                                             ===========    ===========     ==========

         Identifiable net property and equipment:
             Unproved properties -  Poland (2)...............................$     3,014    $        --     $    3,014
             Unproved properties - Domestic..................................         18             --             18
             Proved properties - Poland......................................      2,429             --          2,429
             Proved properties - Domestic....................................        623             --            623
             Equipment and other.............................................         --          1,045          1,045
                                                                             -----------    -----------     ----------
                 Total.......................................................$     6,084    $     1,045     $    7,129
                                                                             ===========    ===========     ==========
         Net Capital expenditures:
             Property and equipment (3)......................................$     6,988    $       780     $    7,768
                                                                             -----------    -----------     ----------
                 Total.......................................................$     6,988    $       780     $    7,768
                                                                             ===========    ===========     ==========
</TABLE>
--------------------
(1)      E&P includes stock options valued at $81,000 issued to a Polish citizen
         for consulting services, accrued bonuses of $228,000 and a
         non-producing property impairment of $674,000.
(2)      E&P includes $2,157,000 relating to the Mieszkow 1, which was in the
         process of being drilled as of December 31, 2000 and was subsequently
         determined to be an exploratory dry hole during 2001.
(3)      E&P includes $2,034,000 of costs that were reclassed to exploratory dry
         hole expense, $2,631,000 of proved property additions and $2,323,000 of
         unproved property additions.

A reconciliation of the segment information to the consolidated totals for 2002,
2001 and 2000 follows:
<TABLE>
<CAPTION>
                                                                                 2002           2001           2000
                                                                             -------------  -------------  -------------
                                                                                           (In thousands)
         <S>                                                                 <C>            <C>            <C>
         Revenues:
           Reportable segments...............................................$      2,742   $      3,813   $      3,811

           Non-reportable segments...........................................          --             --             --
                                                                             ------------   ------------   ------------
            Total revenues...................................................$      2,742   $      3,813   $      3,811
                                                                             ============   ============   ============
         Operating loss:
           Reportable segments...............................................$     (2,333)   $    (6,595)   $    (7,286)
           Expense or (revenue) adjustments:
             Corporate DD&A expense..........................................         (27)           (32)           (66)
             Amortization of deferred compensation (G&A).....................         (55)        (1,078)          (652)
             General and administrative expenses.............................      (2,440)          (883)        (2,654)
             Other...........................................................          --             --             (1)
                                                                             ------------   ------------   ------------
               Total net operating loss......................................$     (4,855)  $     (8,588)  $    (10,659)
                                                                             ============   ============   ============
         Net property and equipment:
           Reportable segments...............................................$      3,833   $      4,842   $      7,129
           Corporate assets..................................................          73            100            126
                                                                             ------------   ------------   ------------
            Net property and equipment.......................................$      3,906   $      4,942   $      7,255
                                                                             ============   ============   ============
         Property and equipment capital expenditures:
           Reportable segments...............................................$      1,128   $      1,993   $      7,768
           Corporate assets..................................................           2              6             33
                                                                             ------------   ------------   ------------
            Net property and equipment capital expenditures..................$      1,130   $      1,999   $      7,801
                                                                             ============   ============   ============

                                      F-20
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


Note 14:  Disclosure about Oil and Gas Properties and Producing Activities (unaudited)

         Capitalized Oil and Gas Property Costs

Capitalized costs relating to oil and gas exploration and production activities
as of December 31, 2002 and 2001 are summarized as follows:
<CAPTION>


                                                                         United States       Poland           Total
                                                                        --------------- ---------------  ---------------
                                                                                        (In thousands)
         <S>                                                            <C>             <C>              <C>
         December 31, 2002:
             Proved properties......................................... $       2,360   $       2,394    $        4,754
             Unproved properties.......................................             8             146               154
                                                                        -------------   -------------    --------------
               Total gross properties..................................         2,368           2,540             4,908
             Less accumulated depreciation, depletion and amortization.        (1,404)           (462)           (1,866)
                                                                        -------------   -------------    --------------

                    Total.............................................. $         964   $       2,078    $        3,042
                                                                        =============   =============    ==============

         December 31, 2001:
             Proved properties......................................... $       2,208   $       2,581    $        4,789
             Unproved properties.......................................             8             648               656
                                                                        --------------- ---------------  ---------------
               Total gross properties..................................         2,216           3,229             5,445
             Less accumulated depreciation, depletion and amortization.        (1,331)           (257)           (1,588)
                                                                        -------------   -------------    --------------
                    Total.............................................. $         885   $       2,972    $        3,857
                                                                        =============   =============    ==============
</TABLE>

         Results of Operations

Results of operations are reflected in Note 13, Business Segments. There is no
tax provision as the Company is not subject to any federal or local income taxes
due to its operating losses. Total production costs for 2002, 2001 and 2000 were
$1,365,454, $1,358,304 and $1,348,399, respectively.

                                      F-21
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


         Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities
during 2002, 2001 and 2000, whether capitalized or expensed, are summarized as
follows:
<TABLE>
<CAPTION>
                                                                        United States       Poland           Total
                                                                        -------------   -------------    --------------
                                                                                        (In thousands)
         <S>                                                            <C>             <C>              <C>
         Year ended December 31, 2002:
             Acquisition of properties:
                 Proved..............................................   $          --   $          --    $           --
                 Unproved............................................              --               8                 8
             Exploration costs.......................................              --           1,031             1,031
             Development costs.......................................             153             851             1,004
                                                                        -------------   -------------    --------------
                 Total...............................................   $         153   $       1,890    $        2,043
                                                                        =============   =============    ==============

         Year ended December 31, 2001:
             Acquisition of properties:
                 Proved..............................................   $          --   $          --    $           --
                 Unproved............................................              --             525               525
             Exploration costs.......................................              --           6,542             6,542
             Development costs.......................................             319               2               321
                                                                        -------------   -------------    --------------
                 Total...............................................   $         319   $       7,069    $        7,388
                                                                        =============   =============    ==============

         Year ended December 31, 2000:
             Acquisition of properties:
                 Proved..............................................   $          --   $          --    $           --
                 Unproved............................................              --              21                21
             Exploration costs (1)...................................             692          11,200            11,892
             Development costs.......................................             202              --               202
                                                                        -------------   -------------    --------------
                 Total...............................................   $         894   $      11,221    $       12,115
                                                                        =============   =============    ==============
-------------------
(1)      Includes $2,429,000 relating to the Kleka 11, which was categorized as
         proved property as of December 31, 2000.

         Impairment of Oil and Gas Properties

o The Company has recorded impairment charges in its E&P segment related to oil
and gas properties as follows:
<CAPTION>
                                                            2002             2001              2000
                                                          ---------        -------           -------
                 <S>                                      <C>              <C>               <C>
                 Proved...........................        1,038,362             --                --
                 Unproved.........................          509,498        583,855           674,158
                                                          ---------        -------           -------
                   Total..........................        1,547,860        583,855           674,158
                                                          =========        =======           =======
</TABLE>

         Exploratory dry hole costs

During 2001, for financial reporting purposes, the Company classified the
Mieszkow 1 as an exploratory dry hole, and recorded exploratory dry hole costs
of $3,051,871, including cash expenditures of $2,171,750 and accrued costs of
$880,121. During 2000, the Company recorded exploratory dry hole costs of
$1,060,589 for the Wilga 3 well and $973,617 for the Wilga 4 well.

                                      F-22
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


Note 15:  Summary Oil and Gas Reserve Data (Unaudited)

         Estimated Quantities of Proved Reserves

Proved reserves are the estimated quantities of crude oil which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reserves under existing economic and operating
conditions. The Company's proved oil and gas reserve quantities and values are
based on estimates prepared by independent reserve engineers in accordance with
guidelines established by the Securities and Exchange Commission. Operating
costs, production taxes and development costs were deducted in determining the
quantity and value information. Such costs were estimated based on current costs
and were not adjusted to anticipate increases due to inflation or other factors.
No price escalations were assumed and no amounts were deducted for general
overhead, depreciation, depletion and amortization, interest expense and income
taxes. The proved reserve quantity and value information is based on the
weighted average price on December 31, 2002 of $25.00 per bbl for oil in the
United States and $2.60 per MCF of gas in Poland. The determination of oil and
gas reserves is based on estimates and is highly complex and interpretive, as
there are numerous uncertainties inherent in estimated quantities and values of
proved reserves, projecting future rates of production and timing of development
expenditures. The estimates are subject to continuing revisions as additional
information becomes available or assumptions change.

Estimates of the Company's proved domestic reserves were prepared by Larry
Krause Consulting, an independent engineering firm in Billings, Montana.
Estimates of the Company's proved Polish reserves were prepared by Troy-Ikoda
Limited, an independent engineering firm in the United Kingdom. The following
unaudited summary of proved developed reserve quantity information represents
estimates only and should not be construed as exact:
<TABLE>
<CAPTION>
                                                                  Crude Oil                       Natural Gas
                                                       -------------------------------- --------------------------------
                                                       United States        Poland      United States        Poland
                                                       ---------------  --------------- ---------------  ---------------
                                                        (in thousand barrels of oil)      (In millions of cubic feet)
         <S>                                                   <C>                <C>              <C>           <C>
         Proved Developed Reserves:
           December 31, 2002................................   1,015               --              --             1,374
           December 31, 2001................................   1,075               --              --             2,167
           December 31, 2000................................   1,161               --              --                --
<CAPTION>
The following unaudited summary of proved developed and undeveloped reserve
quantity information represents estimates only and should not be construed as
exact:

                                                                  Crude Oil                       Natural Gas
                                                       -------------------------------- --------------------------------
                                                       United States        Poland      United States        Poland
                                                       ---------------  --------------- ---------------  ---------------
                                                        (in thousand barrels of oil)      (In millions of cubic feet)
         <S>                                                 <C>                 <C>              <C>           <C>
         December 31, 2002:
             Beginning of year.......................         1,100               114              --            5,010
             Extensions or discoveries...............            --                --              --               --
             Revisions of previous estimates.........            33                --              --             (620)
             Production..............................           (91)               --              --             (180)
                                                       ---------------  --------------- ---------------  ---------------

                 End of year.........................         1,042               114              --            4,210
                                                       ===============  =============== ===============  ===============
         December 31, 2001:
             Beginning of year.......................         1,220                --              --            2,381
             Extensions or discoveries...............            --               114              --            2,844
             Revisions of previous estimates.........           (26)               --              --               35
             Production..............................           (94)               --              --             (250)
                                                       ---------------  --------------- ---------------  ---------------
                 End of year.........................         1,100               114              --            5,010
                                                       ===============  =============== ===============  ===============
         December 31, 2000:
             Beginning of year.......................         1,080                --              --               --
             Extensions and discoveries..............            --                --              --            2,381
             Revisions of previous estimates.........           236                --              --               --
             Production..............................           (96)               --              --               --
                                                       ===============  =============== ===============  ===============
                 End of year.........................         1,220                --              --            2,381
                                                       ===============  =============== ===============  ===============
</TABLE>
                                      F-23
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


         Standardized Measure of Discounted Future Net Cash Flows ("SMOG") and
         Changes Therein Relating to Proved Oil Reserves

Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities."
Certain information concerning the assumptions used in computing the valuation
of proved reserves and their inherent limitations are discussed below. The
Company believes such information is essential for a proper understanding and
assessment of the data presented. The assumptions used to compute the proved
reserve valuation do not necessarily reflect the Company's expectations of
actual revenues to be derived from those reserves nor their present worth.
Assigning monetary values to the reserve quantity estimation process does not
reduce the subjective and ever-changing nature of such reserve estimates.
Additional subjectivity occurs when determining present values because the rate
of producing the reserves must be estimated. In addition to errors inherent in
predicting the future, variations from the expected production rates also could
result directly or indirectly from factors outside the Company's control, such
as unintentional delays in development, environmental concerns and changes in
prices or regulatory controls. The reserve valuation assumes that all reserves
will be disposed of by production. However, if reserves are sold in place,
additional economic considerations also could affect the amount of cash
eventually realized. Future development and production costs are computed by
estimating expenditures to be incurred in developing and producing the proved
oil reserves at the end of the period, based on period-end costs and assuming
continuation of existing economic conditions. A discount rate of 10.0% per year
was used to reflect the timing of the future net cash flows. The discounted
future net cash flows for the Company's Polish reserves are based on a gas and
condensate sales contracts the Company has with POGC.

The components of SMOG are detailed below:
<TABLE>
<CAPTION>
                                                                        United States       Poland           Total
                                                                        --------------- ---------------  ---------------
                                                                                        (In thousands)
         <S>                                                            <C>             <C>              <C>
         December 31, 2002:
             Future cash flows........................................  $      26,049   $      10,964    $      37,013
             Future production costs..................................        (16,254)           (455)         (16,709)
             Future development costs.................................           (115)         (1,800)          (1,915)
             Future income tax expense................................             --              --               --
                                                                        --------------- ---------------  ---------------
             Future net cash flows....................................          9,680           8,709           18,389
             10% annual discount for estimated timing of cash flows...         (4,300)         (3,869)          (8,169)
                                                                        --------------- ---------------  ---------------
             Discounted net future cash flows.........................  $        5,380  $       4,840    $      10,220
                                                                        =============== ===============  ===============
         December 31, 2001:
             Future cash flows........................................  $      13,922   $       7,749    $      21,671
             Future production costs..................................         (9,464)           (425)          (9,889)
             Future development costs.................................            (73)         (1,390)          (1,463)
             Future income tax expense................................             --              --               --
                                                                        --------------- ---------------  ---------------
             Future net cash flows....................................          4,385           5,934           10,319
             10% annual discount for estimated timing of cash flows...         (2,213)         (2,520)          (4,733)
                                                                        --------------- ---------------  ---------------
                                                                        --------------- ---------------  ---------------
             Discounted net future cash flows.........................  $        2,172  $       3,414    $        5,586
                                                                        =============== ===============  ===============
         December 31, 2000:
             Future cash flows........................................  $      26,025   $       3,532    $      29,557
             Future production costs..................................        (16,216)           (476)         (16,692)
             Future development costs.................................           (195)             --             (195)
             Future income tax expense................................             --              --               --
                                                                        --------------- ---------------  ---------------
             Future net cash flows....................................          9,614           3,056           12,670
             10% annual discount for estimated timing of cash flows...         (4,705)           (545)          (5,250)
                                                                        --------------- ---------------  ---------------
                                                                        --------------- ---------------  ---------------
             Discounted net future cash flows.........................  $       4,909   $       2,511    $        7,420
                                                                        =============== ===============  ===============
</TABLE>
                                      F-24
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -

<TABLE>
<CAPTION>
The principal sources of changes in SMOG are detailed below:

                                                                                      Year Ended December 31,
                                                                             -------------------------------------------
                                                                                 2002           2001           2000
                                                                             -------------  -------------  -------------
                                                                                           (In thousands)
         <S>                                                                   <C>           <C>            <C>
         SMOG sources:
             Balance, beginning of year..............................         $    5,586    $     7,420    $      5,460
             Sale of oil and gas produced, net of production costs...               (843)          (871)         (1,172)
             Net changes in prices and production costs..............              4,890         (2,241)           (159)
             Extensions and discoveries, net of future costs.........                 --          1,330           2,511
             Changes in estimated future development costs...........               (251)          (686)            (53)
             Previously estimated development costs incurred during
                 the year............................................                586            321             202
             Revisions in previous quantity estimates................                270             59             (31)
             Accretion of discount...................................                559            742             546
             Net change in income taxes..............................                 --             --              --
             Changes in rates of production and other................               (577)          (488)            116
                                                                              ----------    -----------    ------------
                 Balance, end of year................................         $   10,220    $     5,586    $      7,420
                                                                              ==========    ===========    ============
</TABLE>

Note 16:  New Accounting Pronouncements

In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement
Obligations." SFAS No. 143 is effective for the Company beginning January 1,
2003. The most significant impact of this standard to the Company will be a
change in the method of accruing for site restoration costs. Under SFAS No. 143,
the fair value of asset retirement obligations will be recorded as liabilities
when they are incurred, which are typically at the time the assets are
installed. Amounts recorded for the related assets will be increased by the
amount of these obligations. Over time the liabilities will be accreted for the
change in their present value and the initial capitalized costs will be
depreciated over the useful lives of the related assets. The Company is
evaluating the impact of adopting No. SFAS 143.

In June 2002, the FASB issued Statement No. 146 ("SFAS 146"), "Accounting for
Costs Associated with Exit or Disposal Activities." SFAS 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liabilities
Recognition for Certain employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). This Statement
requires that a liability for costs associated with an exit or disposal activity
be recognized and measured initially at fair value only when the liability is
incurred. SFAS 146 will be effective for exit or disposal activities that are
initiated after December 31, 2002. Management believes that the adoption of this
standard will have no material impact on the Company's operating results and
financial position.

In December 2002, the FASB issued Statement No. 148 ("SFAS 148"), "Accounting
for Stock-Based Compensation Transition and Disclosure." This Statement amends
FASB Statement No. 123 ("SFAS 123"); "Accounting for Stock-Based Compensation,"
to provide alternative methods of transition for an entity that voluntarily
changes to the fair value based method of accounting for stock-based employee
compensation. In addition, SFAS 148 amends the disclosure provisions of SFAS 123
to require prominent disclosure in both annual and interim financial statements
about the effects on reported net income of an entity's accounting policy
decisions with respect to stock-based employee compensation. As FX Energy will
continue to account for stock-based compensation according to APB 25, adoption
of SFAS 148 will require FX Energy to provide prominent disclosures about the
effects of SFAS 123 on reported income and will require disclosure of these
affects in the interim financial statements as well. SFAS 148 is effective for
the financial statements for fiscal years ending after December 15, 2002 and
subsequent interim periods. Management believes that the adoption of this
standard will have no material impact on the Company's operating results and
financial position.

                                      F-25
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others, which expands on the accounting guidance
of Statements No. 5, 57, and 107 and incorporates without change the provisions
of FASB Interpretation No. 34, which is being superseded. This Interpretation
requires a guarantor to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing the guarantee. In
addition, guarantors are required to make significant new disclosures, even if
the likelihood of the guarantor making payments under the guarantee is remote.
The Interpretation's disclosure requirements are effective for the Company as of
December 31, 2002. The recognition requirements of FIN 45 are to be applied
prospectively to guarantees issued or modified after December 31, 2002. The
Company has no significant guarantees and the adoption of this interpretation
did not have a material impact on the Company's financial statements.

In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"), Consolidation
of Variable Interest Entities. The objective of this interpretation is to
provide guidance on how to identify a variable interest entity and determine
when the assets, liabilities, noncontrolling interests and results of operations
of a variable interest entity need to be included in a company's consolidated
financial statements. A company that holds variable interests in an entity will
need to consolidate the entity if the company's interest in the variable
interest entity is such that the company will absorb a majority of the variable
interest entity's expected losses and/or receive a majority of the entity's
expected residual returns, if they occur. The provisions of this interpretation
became effective upon issuance. As of December 31, 2002, the Company did not
have any variable interest entities that will be subject to FIN 46.

The Company has reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on its results
of operations or financial position. Based on that review, the Company believes
that none of these pronouncements will have a significant effect on current or
future earnings or operations.

Note 17:  Subsequent Events

         Private Placement of Convertible Preferred Stock

On March 13, 2003, the Company sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of $5.6
million after offering costs. Each share of preferred stock is convertible into
one share of common stock and one warrant to purchase one share of common stock
at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The
preferred stock has a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.

The net proceeds from the offering, plus the Company's available cash, were used
to reduce the obligation to RRPV, fund ongoing geological and geophysical costs
in Poland, and to support ongoing prospect marketing and general and
administrative costs.

         Amendment of RRPV Note Payable

In March, 2003, following the private placement of convertible preferred stock,
the Company paid $2.2 million to RRPV. In return, RRPV extended the maturity
date of the note to December 31, 2003. The Company has also agreed to pay 40% of
the gross proceeds of any subsequent equity or debt offering concluded prior to
the amended maturity date to RRPV. The Company also agreed to assign its rights
to payments under the CalEnergy Gas agreement to RRPV, except for those amounts
relating to the two wells required to be drilled under the agreement. All such
payments will be used to offset the remaining principal and interest. In
exchange for these payments, RRPV agreed to release its lien on interests earned
by CalEnergy Gas under its agreement with the Company.

The loan amendment contains other terms and conditions, including an increase in
the interest rate on the note from 9.5% to 12% per annum effective March 9,
2003, an extension of the conversion period until December 31, 2003, with the
conversion price being changed from $5.00 per share to $3.42 per share, and an
extension fee payment of $100,000.

                                      F-26
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


Note 18: Interests Held Under Oil and Gas Leases

Statement of Financial Accounting Standards No. 141, Business Combinations (FAS
141) and Statement of Financial Accounting Standards, No. 142, Goodwill and
Intangible Assets (FAS 142) were issued by the Financial Accounting Standards
Board (FASB) in June 2001 and became effective for us on July 1, 2001 and
January 1, 2002, respectively. FAS 141 requires all business combinations
initiated after June 30, 2001, to be accounted for using the purchase method.
Additionally, FAS 141 requires companies to disaggregate and report separately
from goodwill certain intangible assets. FAS 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under FAS 142, goodwill and
certain other intangible assets are not amortized, but rather are reviewed
annually for impairment. One interpretation being considered relative to these
standards is that oil and gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves for
both undeveloped and developed leaseholds should be classified separately from
oil and gas properties, as intangible assets on our balance sheets. In addition,
the disclosures required by FAS 141 and 142 relative to intangibles would be
included in the notes to financial statements. Historically, we, like many other
oil and gas companies, have included these oil and gas mineral rights held under
lease and other contractual arrangements representing the right to extract such
reserves as part of the oil and gas properties, even after FAS 141 and 142
became effective.

This interpretation of FAS 141 and 142 described above would only affect our
balance sheet classification of oil and gas leaseholds. Our results of
operations and cash flows would not be affected, since these oil and gas mineral
rights held under lease and other contractual arrangements representing the
right to extract such reserves would continue to be amortized in accordance with
accounting rules for oil and gas companies provided in Statement of Financial
Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas
Producing Companies (FAS 19).

At December 31, 2002, we had undeveloped leaseholds of approximately $147,000
that would be classified under that interpretation on our balance sheet as
"intangible undeveloped leasehold" and developed leaseholds of an estimated
$7,000 that would be classified under that interpretation as "intangible
developed leaseholds" if we applied the interpretation currently being
considered.

We will continue to classify our oil and gas mineral rights held under lease and
other contractual rights representing the right to extract such reserves as
tangible oil and gas properties until further interpretive guidance is provided.

Note 19:  Restatement

In October 2003, the Company determined that it needed to revise its previous
accounting treatment for certain loans made to officers in 1998. These loans
were made to facilitate the exercise of stock options by these officers and were
collateralized by 233,340 shares of Company stock. The Company previously
accounted for these loans in accordance with SFAS No. 114, "Accounting by
Creditors for Impairment of a Loan" and recognized impairment charges in 1999
and 2000 based on the market value of the collateral shares. The Company also
recognized interest income on the loans. In December 2000, the officers
transferred the collateral shares to the Company in payment of the loans and
accrued interest, and the adjusted loan balance was recorded by the Company as
treasury stock. The Company has determined that the officer loans should have
been accounted for as a deemed purchase of treasury stock and the granting of a
variable stock option in accordance with EITF 95-16, "Accounting for Stock
Compensation Arrangements with Employer Loan Features under APB Opinion No. 25."
Under variable stock option accounting, the Company would have recognized
increases or decreases in compensation expense based on the market value of the
Company's stock. In addition, the Company would not have recorded interest
income on the loans or impairment charges related to the loans. Because a
portion of the shares deemed to have been purchased were acquired through the
exercise of stock options and had not been owned for at least six months, the
Company also would have recorded a compensation charge of $90,000 related to
those shares, reflecting the difference between the purchase price and the
original option exercise price for those shares.

Overall, the adjustments recorded to reflect the revised accounting described
above decreased the net loss for the year ended December 31, 2000, by $597,818
(composed of the reversal of the impairment charge of $738,177 offset by the
reversal of interest income of $140,359), or $0.04 per share. The adjustments
also reduced the accumulated deficit at December 31, 2000, by $973,990 (composed
of the aforementioned $597,818, plus the reversal of impairment charges of
$665,512, offset by a previously unrecorded compensation charge of $90,875 and
the reversal of interest income of $198,465, all associated with prior years)
and increased the cost basis of treasury stock by the same amount. This treasury
stock was retired against additional paid-in-capital in August 2002.

                                      F-27
<PAGE>

                        FX ENERGY, INC. AND SUBSIDIARIES
                 Notes to the Consolidated Financial Statements
                                 - Continued -


The following sets forth the effects of the revision made to the Company's
consolidated statements of operations for the year ended December 31, 2000, and
the consolidated balance sheets at December 31, 2002 and 2001. These revisions
had no effect on the Company's net cash used in operating activities, net cash
provided by (used in) investing activities or net cash provided by financing
activities for the year ended December 31, 2000.
<TABLE>
<CAPTION>
        Year ended December 31, 2000
        Consolidated Statements of Operations
                                                                       ---------------       ----------------
                                                                          As Reported           As Restated
                                                                       ---------------       ----------------
        <S>                                                            <C>                   <C>
        Revenues                                                       $     3,810,834       $      3,810,834
        Operating expenses                                                  14,469,945             14,469,945
                                                                       ---------------       ----------------
        Operating loss                                                     (10,659,111)           (10,659,111)
        Other income (expense)
            Interest income                                                    557,080                416,721
            Interest expense                                                    (2,422)                (2,422)
            Impairment of notes receivable from officers                      (738,177)                     -
                                                                       ---------------       ----------------
                Total other income (expense)                                  (183,519)               414,299
                                                                       ---------------       ----------------
        Net loss                                                       $   (10,842,630)      $    (10,244,812)
                                                                       ===============       ================
        Basic and diluted net loss per share                           $         (0.66)      $          (0.62)
                                                                       ===============       ================


        December 31, 2001
        Stockholders' equity
                                                                           As Reported          As Restated
                                                                       ---------------       ----------------
        Common stock                                                   $        17,914       $         17,914
        Treasury stock                                                        (909,815)            (1,883,805)
        Deferred compensation from stock option exercise                       (54,688)               (54,688)
        Additional paid in capital                                          49,910,078             49,910,078
        Accumulated deficit                                                (48,010,445)           (47,036,455)
                                                                       ---------------       ----------------
              Total stockholders' equity                               $       953,044       $        953,044
                                                                       ===============       ================

        December 31, 2002
        Stockholders' deficit

                                                                          As Reported           As Restated
                                                                       ---------------       ----------------
        Common stock                                                   $        17,652       $         17,652
        Additional paid in capital                                          49,049,025             47,984,160
        Accumulated deficit                                                (53,935,256)           (52,870,391)
                                                                       ---------------       ----------------
              Total stockholders' deficit                              $    (4,868,579)      $     (4,868,579)
                                                                       ===============       ================

</TABLE>
                                      F-28

<PAGE>