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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
Commission File Number: 0-25386
FX ENERGY, INC.
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(Exact name of registrant as specified in its charter)
Nevada 87-0504461
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206, Salt Lake City, Utah 84106
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(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 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. [ ]
State the aggregate market value of the voting and nonvoting common
equity held by nonaffiliates of the registrant. The aggregate market value shall
be computed by reference to the price at which the common equity was sold, or
the average bid and asked prices of such common equity, as of a specified date
within 60 days prior to the date of filing. As of March 29, 2002, the aggregate
market value of the voting and nonvoting common equity held by nonaffiliates of
the registrant was $50,466,608.
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 29,
2002, FX Energy had outstanding 17,628,235 shares of its common stock, par value
$0.001.
DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy Statement in
connection with the 2002 Annual Meeting of Stockholders is incorporated by
reference in response to Part III of this Annual Report.
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FX ENERGY, INC.
Form 10-K for the fiscal year ended December 31, 2001
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Table of Contents
Item Page
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Part I
-- Special Note on Forward-Looking Statements.................... 1
1. and 2. Business and Properties....................................... 2
3. Legal Proceedings............................................. 25
4. Submission of Matters to a Vote of Security Holders........... 25
Part II
5. Market for Common Equity and Related Stockholder Matters...... 26
6. Selected Consolidated Financial Data.......................... 27
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 29
7A. Qualitative and Quantitative Disclosure about Market Risk..... 38
8. Financial Statements and Supplementary Data................... 39
9. Changes and Disagreements with Accountants on Accounting and
Financial Disclosure........................................ 39
Part III
10. Directors and Officers of Registrant.......................... 40
11. Executive Compensation........................................ 40
12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 40
13. Certain Relationships and Related Transactions................ 40
Part IV
14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K................................................. 41
-- Signature Page................................................ 45
-- Report of Independent Accountants............................ F-1
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SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS
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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," "will," "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 partners
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 partners;
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, which may not occur
or which 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 as a result of various factors, including the
risk factors detailed in this report. The forward-looking statements included in
this report are made only as of the date of this report.
1
PART I
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ITEMS 1. AND 2. BUSINESS AND PROPERTIES
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INTRODUCTION
We are an independent oil and gas company focused on exploration,
development and production opportunities in the Republic of Poland. In the
company of our partner, the Polish Oil and Gas Company, or POGC, we were the
first western company to discover and produce gas in Poland. Our ongoing
activities in Poland are conducted under a strategic alliance with POGC. This
alliance allows us to utilize in-country operating and technical personnel, gain
access to geological and geophysical data and obtain other necessary support in
Poland. Also, in the United States, we produce oil in Montana and Nevada and
have an oilfield services company in Montana.
We are in the process of finalizing the formation of a joint stock
company, Plotki Gaz SA, or Plotki, in which we will hold a 49% ownership
interest and POGC will hold a 51% ownership interest. Plotki will be the first
joint stock company owned by POGC and an American company formed to conduct oil
and gas activities. We plan to utilize Plotki to conduct our joint operations in
the Fences project area. In addition, we believe there may be opportunities
through Plotki to expand the scope of our interest in Poland. The formation of
Plotki is consistent with the Polish government's announced goal to eventually
privatize POGC.
In the Fences project area in western Poland, our current area of
focus, we conduct exploration and production operations with POGC under an
agreement signed in 2000, whereby we will earn a 49.0% interest in the
exploration rights on approximately 300,000 acres (excluding already producing
fields and wells) by spending $16.0 million for new exploration. We have paid
$6.7 million in cash expenditures and have accrued $2.7 million of additional
costs as of December 31, 2001, towards the $16.0 million commitment.
The Fences project area lies at the southern edge of a Permian-age
basin in a geological province that produces gas from two main horizons: the
Zechstein Reef and the Rotliegendes. Before our Fences project area agreement
started, POGC had already developed approximately 2 Tcfe of gas reserves in the
aggregate from a number of producing fields in and near the Fences area.
Existing geological and geophysical data suggest these horizons have potential
for production in the central and southern portions of the Fences area. We have
embarked on a project to reprocess the abundant seismic data that already exists
covering the entire Fences area and that has not previously been processed with
modern geophysical techniques. We will conclude this project in mid-2002 and we
expect it to yield a number of "drill-ready" targets in the Rotliegendes and the
lower Permian. We plan to solicit industry support for drilling after completion
of our reprocessing project, if not earlier.
During the balance of 2002, we expect to continue our exploratory
activities in Poland by acquiring additional seismic data and drilling
exploratory wells, as warranted and as funding permits. We also expect to
advance our discussions with prospective industry partners with the potential of
providing funding and with POGC concerning the possible expansion of our joint
interests in Poland.
BUSINESS STRATEGY
Our business strategy remains focused on Poland, where we compensate
for our small size by leveraging the financial and technical resources of our
larger industry partners in what have become strategic relationships. We seek
the potential rewards of high potential exploration opportunities while
endeavoring to minimize our exposure to the risks normally associated with
exploration. The principal components of our business strategy follows.
2
Focus on Poland
We believe Poland is an attractive oil and gas exploration and
production opportunity because of its known productive areas that today remain
underexplored and underdeveloped, and its heavy dependence on oil and gas
imports. Poland's industrial infrastructure and fiscal regime favorable to
foreign investment reinforce the attractiveness of Poland.
Apply Technical and Financial Leverage
POGC has developed a 3-D seismic-based exploration model that has been
refined since the mid-1990s in the Zechstein Reef trend in western Poland. We
are applying modern geophysical techniques that were refined in the southern
North Sea on Rotliegendes reservoirs to the Rotliegendes play in Poland. We
believe the Fences project area has considerable potential for the successful
application of both approaches at relatively low risk. Accordingly, we are
seeking capital from industry partners, power development companies, banks and
other sources to fund the majority of our ongoing exploration and/or development
costs in the Fences project area.
The Tuchola 108-2 discovery in the Main Dolomite Reef formation may
give us a third such trend where we can develop or apply existing exploration
models. It also represents the successful use of financial leverage in that
Apache Corporation, or Apache, covered our share of costs for our first two
exploratory wells under the Apache Exploration Program.
Reduce our Exploration Risk Profile
Historically, we have managed exploration risk by limiting capital
exposure. We now hope to reduce the exploration risk by focusing on the use of
tested exploration models in known producing trends. The Fences project area
represents a relatively lower risk area because of its production history and
because we are able to use exploration models developed by others for this area.
The Main Dolomite Reef trend, if confirmed in the Pomeranian project area,
should also have a lower risk profile because of its similarity to the more
fully explored analog trend along the southern edge of Poland's Permian Basin.
STRATEGIC RELATIONSHIP WITH THE POLISH OIL AND GAS COMPANY
POGC is a fully integrated oil and gas company owned by the Treasury of
the Republic of Poland. Our strategic alliance with POGC provides us with access
to important exploration data as well as technical and operational support. POGC
is our partner in substantially all of our ongoing exploration activities in
Poland, including the Fences project area where POGC is the operator, Block 108
of the Pomeranian project area where we are the operator, and the Wilga project
area where Apache is the operator. In addition, we have made proposals to expand
the scope of our projects with POGC, utilizing Plotki. We believe that our
relationship with POGC will continue to provide additional opportunities in
Poland.
ASSUMPTIONS
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.
As discussed within this report, we have entered into arrangements with POGC and
Apache through which each company has separate rights to participate in various
activities and projects in Poland.
All historical production and test data about Poland, excluding wells
in which we have participated, have been derived from information furnished by
either POGC or the Polish Ministry of Environmental Protection, Natural
Resources and Forestry unless noted otherwise.
3
THE REPUBLIC OF POLAND
The Republic of Poland is located in eastern 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 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, or PAIZ, cumulative foreign
direct investment flow into Poland is estimated to have aggregated approximately
$49.4 billion from 1989 through 2000, including approximately $10.6 billion
during 2000. During 2001, Poland's gross domestic product grew by an estimated
2.5%, coupled with an estimated inflation rate of 5.5% and an estimated
unemployment rate of 16.5%.
Since its transition to a market economy and a parliamentary democracy,
Poland has experienced significant economic growth and political changes. Poland
has developed and is refining legal, tax and regulatory systems characteristic
of parliamentary democracies with interpretation and procedural safeguards to
ensure the rule of law. 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 and to facilitate interaction with
European Union members. Since 1995, the Polish corporate income tax rate has
been reduced 2.0% per year to 28.0% for 2001 and 2002. Further reductions in the
income tax rate of 2.0% per year may be enacted down to a rate of 22.0%.
Additional tax relief may be available for certain qualifying capital
investments that provide deductions during the initial years of operation under
certain circumstances.
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 and develop 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
by Western companies using Western capital in the oil and gas sector is
consistent with the approved privatization policy.
Since the 1850s, when oil was first commercially produced in Poland, in
excess of 122 MMBbls of oil and 2.6 Tcf of gas in the southeastern Carpathian
region and 24 MMBbls of oil and 2.3 Tcf of gas in the western Polish Permian
Basin trend have been produced to date. 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, drawn down over five years, 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:
Oil Gas
---------------------------------------------
Estimated proved reserves as of January 1, 2001..................114.9 MMBbls 5.1 Tcf
Estimated average production per day during 2000................10,000 Bbls per day 0.5 Bcf per day
Estimated average imports per day during 2000..................430,000 Bbls per day 0.8 Bcf per day
Estimated average share of energy consumed during 2000...........24.1% Total energy 10.5% Total energy
During 1998, Poland joined NATO and set an objective of joining the
European Union by 2003. 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
4
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 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.
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
We are actively seeking an industry partner to provide additional
capital needed to continue our ongoing activities in Poland. Due to our limited
financial resources, it is critical for us to obtain funding sufficient to
provide at least $9.3 million in order to complete our earning requirements in
the Fences project area. There is no contractual time limit pertaining to
completing our $16.0 million commitment.
Polish Exploration Rights
As of December 31, 2001, our oil and gas exploration rights in Poland
were comprised of the following gross acreage components:
Operator
----------------------------------------------- Total
FX Energy Apache POGC Acreage
--------------- --------------- --------------- ---------------
Project Area:
Fences(1)................................. -- -- 300,000 300,000
Pomeranian(2)............................. 2,200,000 -- -- 2,200,000
Wilga (3)................................. -- 250,000 -- 250,000
Baltic Project Area(4).................... 900,000 -- -- 900,000
--------------- --------------- --------------- ---------------
Total gross acreage..................... 3,100,000 250,000 300,000 3,650,000
=============== =============== =============== ===============
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(1) On April 11, 2000, we entered into an agreement with POGC to earn 49.0%
of POGC's 100% interest in the Fences 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 a 74% interest and POGC
owns a 26% interest.
(3) We own a 45% interest, Apache owns a 45% interest and POGC owns a 10%
interest in the Wilga project area.
(4) On March 7, 2002, the Baltic project area rights expired. We previously
owned 100% of the Baltic project area.
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 Project Area
Fences Project Area Exploration Agreement
On April 11, 2000, we agreed to spend $16.0 million of exploration
costs on the Fences project area to earn a 49.0% interest. When expenditures
exceed $16.0 million, POGC will pay its 51.0% share of further costs. To date,
we have paid $6.7 million towards the $16.0 million commitment, leaving a
remaining commitment of $9.3 million, including $2.7 million of costs accrued as
of December 31, 2001. The Fences project area consists of approximately 300,000
gross acres in a region of west central Poland encompassing significant portions
of two gas-producing horizons. Currently, we and POGC are in the process of
5
finalizing the formation of Plotki, a Joint Stock Company, to hold our 49%
ownership interest and POGC's 51% ownership interest in the Fences project area
as well as other possible projects involving POGC.
The Rotliegendes Area
During 2000, we drilled the Kleka 11, our first Rotliegendes target,
which is now producing at a rate of approximately 1.5 MMcf of gas per day.
Drilling operations on the next exploratory well, the Mieszkow 1, have been
suspended since April 2001 pending the reprocessing and reinterpretation of 3-D
seismic data. For 2001 financial reporting purposes, we classified the Mieszkow
1 as an exploratory dry hole.
Following the Kleka and Mieszkow operations, which had been scheduled
by POGC prior to our agreement to join in the Fences area, we have embarked on a
project to reprocess the abundant seismic data that already exists covering the
entire Fences area and that has not previously been processed with modern
geophysical techniques. We will complete this project in mid-2002 and expect it
will yield a number of targets in the Rotliegendes and the lower Permian that
warrant drilling. We plan to solicit industry support for drilling after
completion of our reprocessing project, if not earlier.
The Zechstein Reef Trend
In the Zechstein Reef trend, POGC has discovered gas in six Zechstein
Reef buildups (Koscian, Rensko, Bonikowo, Wielichowo, Ruchocice and Racot) in a
35-kilometer stretch along the Wolsztyn Block immediately west of the Fences
project area. Drilling on 3-D seismic data in the Zechstein Reef trend, POGC has
successfully completed 24 of 27 wells (89%) for production. This success rate is
attributable to specific 3-D processing techniques that POGC has developed to
identify these reefs. The Zechstein Reef trend appears to run approximately 45
kilometers inside the Fences project area before continuing to the southeast.
During 2001, we acquired an approximately 100 square kilometer 3-D seismic grid
in the Donatowo area in the western portion of the Fences project area. This 3-D
seismic grid covers several apparent Zechstein Reef buildups.
Apache Exploration Program
The Apache Exploration Program, now complete, consisted of various
agreements that were signed between 1997 and 2001. The initial primary terms of
the Apache Exploration Program included a commitment by Apache to cover our
share of costs to drill ten exploratory wells and to acquire 2,000 kilometers of
2-D seismic data to earn a 50.0% interest in our Lublin Basin and Carpathian
project areas. The project was later expanded to cover the Pomeranian and Warsaw
West project areas.
As of December 31, 2001, Apache had completed all of its work
commitments applicable to the Apache Exploration Program. The following table
shows the results of each exploratory well drilled under terms of the Apache
Exploration Program, listed in the order the exploratory wells were drilled:
Effective
Carried
Project Area Well Name Result Interest
---------------------------------------------------------------------- ---------------------- -------------
Project Area:
Lublin Basin.................................Czernic.277-2.........Exploratory.dry.hole 33.3%
Lublin Basin.................................Poniatowa.317-1.......Exploratory.dry.hole 47.5
Lublin Basin.................................Witkow.1..............Exploratory.dry.hole 45.0
Lublin Basin.................................Siedliska.2...........Exploratory.dry.hole 33.3
Lublin Basin (Wilga).........................Wilga.2...............Discovery........ 45.0
Lublin Basin (Wilga).........................Wilga.3...............Exploratory.dry.hole 45.0
Lublin Basin (Wilga).........................Wilga.4...............Exploratory.dry.hole 45.0
Pomeranian...................................Tuchola.108-2.........Discovery........ 42.5
Warsaw West..................................Annopol.254-1.........Exploratory.dry.hole 50.0
Pomeranian ..................................Chojnice.108-6........Exploratory.dry.hole 42.5
6
As of the date of this report, the current status of our interest in
each project area within the Apache Exploration Program is as follows:
o Pomeranian project area. On November 28, 2001, Apache assigned
its interest in the Pomeranian project area to us. We are now
the operator and have a 100% interest in the Pomeranian
project area, except for Block 108, where we have a 74%
interest and POGC has a 26% interest. The Tuchola 108-2
discovery is located on Block 108. We have successfully
completed an extended flow test on the Tuchola 108-2 and are
currently assessing the potential for commercial production in
light of pipeline and facility expenditures that would be
required. The options we had pertaining to POGC acreage
adjacent to the Pomeranian project area have expired, as has
POGC's option to participate in the Pomeranian project area;
both may be renewed in the future.
o Lublin Basin project area. During 2001, we and Apache dropped
all of the remaining acreage in the Lublin Basin project area
except for Block 255 ("Wilga project area"), which contains
the Wilga 2 discovery. We have a 45.0% interest in Block 255,
which is operated by Apache. We and our partners have
successfully completed an extended flow test on the Wilga 2
and are currently assessing the potential for commercial
production in light of pipeline and facility expenditures that
would be required. The options we had pertaining to POGC
acreage adjacent to the Lublin Basin project area have
expired.
o Carpathian project area. During 2001, we assigned all of our
acreage in the Carpathian project area to Apache, including
the options pertaining to POGC controlled acreage nearby.
o Warsaw West project area. During 2001, we and Apache dropped
all of our acreage in the Warsaw West project area, where we
have no further exploration plans.
Pomeranian Project Area
The Pomeranian project area is located in northwestern Poland and
consists of exploration rights covering approximately 2.2 million gross acres
laying along the under-explored northern edge of the Permian Basin in
northwestern Poland. The Pomeranian project area is relatively unexplored and
has had little oil and gas production. In the past, POGC provided us and Apache
with existing seismic data and well logs and cores from the Pomeranian project
area for reprocessing and analysis. 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. During 2000, we and Apache acquired
approximately 328 kilometers of additional 2-D seismic data in the Pomeranian
project area and commenced drilling the Tuchola 108-2 to test the Main Dolomite
and other objectives. A preliminary open-hole test in early January 2001 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
flow rate was limited by the capacity of the surface equipment. The Tuchola
108-2 well was subsequently completed in an approximately 200 foot thick section
of the Main Dolomite. The Tuchola 108-2 discovery is the first confirmation on
the northern margin of the Permian Basin of a commercial accumulation in the
Main Dolomite Reef trend that produces on the southern margin from the BMB field
and other fields in Poland. During 2001, 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. Under terms of
the Apache Exploration Program, Apache covered our 42.5% share of cost to drill
the Tuchola 108-2 and the Chojnice 108-6. We were responsible for our 42.5%
share of costs to complete the Tuchola 108-2. During mid-2001, we conducted an
additional 2-D seismic program covering approximately 280 kilometers to confirm
a number of additional Main Dolomite Reef leads. During 2002, we intend to
farm-out part of our interest to an industry partner prior to conducting further
exploratory activities on the Pomeranian project area.
Lublin Basin and the Wilga Project Area
The Lublin Basin project area in central southeast Poland initially
consisted of exploration rights on approximately 5 million gross acres held by
us and Apache and options to participate in 600,000 acres controlled by POGC. We
have since dropped all of our Lublin Basin project acreage except for Block 255
7
("Wilga project area"), which contains approximately 250,000 acres and the Wilga
2 discovery. We have a 45.0% working interest in the Wilga project area.
From 1998 through 2000, Apache covered our cost to drill an equivalent
of seven exploratory wells in the Lublin Basin project area under terms of the
Apache Exploration Program. The Wilga 2, which was drilled on Block 255 during
2000, was a discovery and the other six wells were exploratory dry holes.
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
partners successfully completed an extended flow test on the Wilga 2 and are
currently assessing the potential for commercial production in light of pipeline
and facility expenditures that would be required. Under terms of the Apache
Exploration Program, Apache covered our costs to test and complete the Wilga 2.
The agreements covering the Wilga 2 also specify that each partner has the right
to propose that certain activities be undertaken and elect whether to
participate in such activities proposed by itself or others. If a partner elects
to not participate in such activities relating to the Wilga 2, the other
partners nevertheless have the right to proceed.
Baltic Project Area
The Baltic project area, which was our first exploration project area
in Poland, is located onshore in northern Poland near the Baltic Sea and
consisted of exploration rights covering approximately 2.1 million gross and net
acres in northern Poland. During 1997, we drilled two exploratory wells on the
Baltic project area. Both wells, the Gladysze 1-A and the Orneta 1, were
exploratory dry holes. On March 7, 2002, the Baltic project area's six-year
concession term expired. As of December 31, 2001, we had no capitalized costs
pertaining to the Baltic project area.
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 and to 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 and granted POGC oil and gas
exploration rights on the Fences project area. 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. 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, with a term of 30 years and so long thereafter as commercial
production continues. Upon the grant of the exploitation concession, the
concession owner may become obligated to pay a fee, to be negotiated within the
range of 0.01% to 0.05% of the market value of the estimated recoverable
reserves in place, payable in five equal annual installments. The concession
owner would also be required to pay a royalty on any production, the amount of
which will be set by the concession authority, within a range established on the
base royalty rate for the mineral being extracted. The base royalty rate for oil
and gas is 6.0%. This rate could be increased unilaterally to up to 10.0% (the
current statutory maximum base royalty rate) by the Council of Ministers. The
concession authority can set the royalty rate for any particular commercial
8
production in a range between 50.0% and 150.0% of the base royalty rate,
depending on the economic viability of such operation, but not to exceed the
statutory maximum rate. Therefore, with the current base rate of 6.0% for oil
and gas, the concession authority could establish the royalty rate between 3.0%
and 9.0%. If, however, the base rate were increased to 10.0%, the current
statutory maximum, the royalty rate would be between 5.0% and 15.0%. The royalty
rate could vary for different producing fields and could be changed from time to
time during the productive life of a field. Local governments will receive 60.0%
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 Project Area
The Fences 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 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.
When Plotki is formed, we and POGC will assign our respective 49.0% and
51.0% interests in the concession covering the Fences project area to Plotki as
capital contributions.
Pomeranian and Wilga Project Areas
For concessions controlled by us and/or Apache, each of the oil and gas
usufructs divides exploration rights into successive exploration periods
expiring in three and six years, respectively, after the grant of the last
concession agreements covered by the applicable usufruct. A number of
exploratory wells are required to be drilled during the first three-year and
second three-year exploration periods, a minimum amount of 2-D seismic data
acquisition must be completed and other expenditures must be made, all as set
forth in the applicable usufructs, in order to retain an interest in each
usufruct.
During each respective six-year exploration period, we are committed to
the following obligations in Poland, presented on a gross basis, to retain our
exploratory concession acreage, exclusive of the Fences project area:
Exploratory Drilling
Start of First ------------------------------------
Three-Year First Second
Whole Exploration Three-Year Three-Year 2-D Seismic Data
Blocks Period Period (1) Period (2) Acquisition (3)
---------------------------------- ---------------- ----------------- ------------------ ------------------
Project Area:
Wilga................. 1 08/08/97 1 well None 500 km
Pomeranian............ 10 12/31/98 1 well 2 wells 600 km
- ---------------------
(1) As of December 31, 2001, we had fulfilled our exploratory drilling
requirements for the first three-year exploration period on all
usufructs.
(2) We expect the Polish government to agree to count the Chojnice 108-6 as
one of the required wells during the second three-year exploration
period on the Pomeranian project area.
(3) As of December 31, 2001, we had fulfilled all 2-D seismic data
requirements on the Wilga and Pomeranian project areas.
As of December 31, 2001, all required usufruct/concession payments had
been made for each of the above project areas.
Plotki Gaz SA
As of the date of this report, we are in the process of finalizing the
formation of a joint stock company, Plotki Gaz SA, or Plotki, in which we will
hold a 49% ownership interest and POGC will hold a 51% ownership interest.
Plotki will be the first joint stock company owned by POGC and an American
company formed to conduct oil and gas activities. We plan to utilize Plotki to
conduct our joint operations in the Fences project area. In addition, we believe
9
there may be opportunities through Plotki to expand the scope of our
relationship with POGC. The formation of Plotki is consistent with the Polish
government's announced goal to eventually privatize POGC.
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 from the Kleka 11 well 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 1.5 MMcf of gas per day.
On March 9, 2001, we granted Rolls Royce Power Ventures, or RRPV, an
option exercisable until March 9, 2002, to enter into an agreement to purchase
up to 17 MMcf of gas per day from our wells in Poland, subject to availability.
During March 2002, RRPV elected not to exercise the option.
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 2001:
2001
-----------
Polish producing property data:
Average daily net gas production (Mcf)(1).............. 800
Average sales price per Mcf............................ $ 1.58
Average production costs per Mcf(2).................... $ 0.16
- -------------------------
(1) Consists solely of the Kleka 11 well, which began producing on February
22, 2001.
(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 and 1999.
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
10
average daily production, average working interest and net revenue interest for
our United States producing properties during 2001 follows:
Average Daily Production
(Bbls) Average Average
---------------------------- Working Net Revenue
Gross Net Interest Interest
------------- -------------- -------------- --------------------
United States producing properties:
Montana:
Cut Bank............................ 268 230 99.5% 85.7%
Bears Den........................... 15 6 48.0 39.2
Rattlers Butte...................... 20 1 6.3 5.1
------------- --------------
Total............................. 303 237
------------- --------------
Nevada:
Trap Spring......................... 10 2 21.6 20.0
Munson Ranch........................ 35 12 36.0 34.1
Bacon Flat.......................... 40 5 16.9 12.5
------------- --------------
Total............................. 85 19
------------- --------------
Total United States producing
properties................... 388 256
============= ==============
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 partner.
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
48.0% 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 partner.
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 36.0%. 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
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 2001, 2000 and 1999:
Years Ended December 31,
--------------------------------------
2001 2000 1999
----------- ----------- ------------
United States producing property data:
Average daily net oil production (Bbls).......................... 256 265 279
Average sales price per Bbl...................................... $ 19.41 $ 26.14 $ 15.35
Average production costs per Bbl(1).............................. $ 14.50 $ 13.99 $ 9.50
- -----------------------------
(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 years ended December 31, 2001, 2000 and 1999,
over 85.0% of our total oil sales were to CENEX, a regional refiner and
marketer. 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 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. During 1998, we
first started our oilfield servicing business in an effort to increase our
United States revenues, which had been declining due to the depressed oil prices
that had occurred throughout 1998. Since 1998, our oilfield services revenues
have grown from $322,000 in 1998 to $1.6 million in 2001.
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, 2001, of $12.66 per Bbl for oil in
the United States, $17.00 per Bbl for oil in Poland and $1.85 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 2001.
12
The following summary of proved reserve information as of December 31,
2001, represents estimates net to us only and should not be construed as exact:
United States Poland
----------------------------------------------------------------- Total
Oil PV-10 Value Oil Gas PV-10 Value PV-10 Value
---------- --------------------------- --------- --------------- ---------------
(MBbls) (In thousands) (MBbls) (MMcf) (In thousands) (In thousands)
Proved reserves:
Developed producing..... 1,075 $ 2,091 -- 2,167 $ 2,084 $ 4,175
Undeveloped............. 25 81 114 2,844 1,330 1,411
---------- ------------- ----------- --------- --------------- ---------------
Total................. 1,100 $ 2,172 114 5,011 $ 3,414 $ 5,586
========== =========================== ========= =============== ===============
DRILLING ACTIVITIES
The following table sets forth the exploratory wells that we drilled
during the years ended December 31, 2001, 2000 and 1999:
Years Ended December 31,
-------------------------------------------------------------------
2001 2000 1999
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- --------- ---------- --------- ----------
Discoveries:
United States....................... -- -- -- -- -- --
Poland.............................. 1.0 0.5 1.0 0.5 1.0 0.5
---------- ---------- --------- ---------- --------- ----------
Total............................. 1.0 0.5 1.0 0.5 1.0 0.5
---------- ---------- --------- ---------- --------- ----------
Exploratory dry holes:
United States....................... -- -- -- -- -- --
Poland.............................. 2.0 1.0 2.0 1.0 5.0 1.6
---------- ---------- --------- ---------- --------- ----------
Total............................. 2.0 1.0 2.0 1.0 5.0 1.6
---------- ---------- --------- ---------- --------- ----------
Total wells drilled................... 3.0 1.5 3.0 1.5 6.0 2.1
========== ========== ========= ========== ========= ==========
We did not drill any development wells during 2001, 2000 or 1999.
WELLS AND ACREAGE
As of December 31, 2001, our producing gross and net well count
consisted of the following:
Number of Wells
------------------------
Gross Net
----------- -----------
Well count:
United States(1).................................................................. 107.0 97.2
Poland(2)......................................................................... 1.0 0.5
----------- -----------
Total........................................................................... 108.0 97.7
=========== ===========
- -----------------------
(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.
13
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2001:
Developed Undeveloped
---------------------------- ----------------------------
Gross Net Gross Net
---------------------------- ----------------------------
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)
Fences project area (2)...................... 225 110 300,000 147,000
Wilga project area........................... 543 244 250,000 113,000
Pomeranian project area (3).................. -- -- 2,200,000 2,135,000
Baltic project area (4)...................... -- -- 900,000 900,000
------------- ------------- ------------- --------------
Total Polish acreage..................... 768 354 3,650,000 3,295,000
------------- ------------- ------------- --------------
Total Acreage.................................. 11,900 10,900 3,659,142 3,301,424
============= ============= ============= ==============
- ------------------
(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 area is attributable
to the Kleka 11 well only. The net acreage amount assumes we
spend $16.0 million of exploration expenditures to earn a 49%
interest.
(3) We own a 100% interest in the Pomeranian project area, except
for Block 108 (approximately 250,000 acres), where we own a
74% interest.
(4) The Baltic project area's concession term expired on
March 7, 2002.
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.
14
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
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.
15
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.
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, 2001, we had 31 employees, consisting of eight in
Salt Lake City, Utah; 20 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.
16
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.
RISK FACTORS
Our business is subject to a number of material risks, including the
following factors related directly and indirectly to our business activities in
the United States and Poland.
RISKS RELATING TO OUR BUSINESS
We currently have limited financial resources.
As of December 31, 2001, we had $3.2 million of cash and cash
equivalents, $559,000 of working capital and $5.0 million of long-term debt that
is due on or before March 9, 2003 (unless converted to restricted common stock
at $5.00 per share prior to March 9, 2003), coupled with a history of operating
losses. These matters raise substantial doubt about our ability to continue as a
going concern. In addition, we have a remaining commitment of $9.3 million that
must be spent by us in order to earn a 49.0% interest in the Fences project
area.
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities and through agreements with
industry partners that funded our share of costs in certain exploratory
activities in order to earn an interest in our properties. As the date of this
report, we did not have a commitment from a third party to provide any
additional funding for our ongoing operations. The continuation of our
exploratory efforts in Poland is dependent on raising additional capital through
attracting an industry or financial partner, raising additional equity,
incurring additional debt, selling or farming out assets or completing other
arrangements. The availability of such capital will affect the timing, pace,
scope and amount of our future capital expenditures. There can be no assurance
that we will be able to obtain additional financing, 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.
Our success depends largely on our discovery of economic quantities of
oil or gas in Poland.
We currently have a limited amount of production in the United States
and Poland. 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 funds from external sources until we generate
sufficient revenue to cover these costs. Our exploration programs in Poland are
based on interpretations of geological and geophysical data. The factors listed
below, most of which are outside our control, may prevent us from establishing
additional commercial production or substantial reserves as a result of our
exploration, appraisal and development activities in Poland:
o We cannot assure that any future well will encounter
commercial quantities of oil or gas.
o There is no way to predict in advance of drilling and testing
whether any prospect encountering oil or gas 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.
17
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.
We have participated in drilling 15 exploratory wells in Poland,
including three exploratory successes (the Wilga 2, Kleka 11 and Tuchola 108-2),
and 12 exploratory dry holes as of the date of this report. In the Fences
project area, we have drilled one exploratory success (Kleka 11). In the Apache
Exploration Program, Apache has, in effect, covered our share of costs to drill
an equivalent of ten exploratory wells, including two exploratory successes
(Wilga 2 and Tuchola 108-2) and eight exploratory dry holes. We have also
drilled two exploratory dry holes in the Baltic project area and one in the
Carpathian project area. In addition to the aforementioned items, we
participated in testing and appraising two shut-in gas wells in the Lachowice
Farm-in that did not result in commercial production.
Of our three exploratory successes in Poland, only the Kleka 11 well is
currently producing. The Wilga 2 is located approximately 19 kilometers from the
nearest pipeline and the Tuchola 108-2 is located approximately five kilometers
from the nearest pipeline. We are currently assessing the potential for
commercial production, in light of pipeline and facility expenditures that would
be required, for the Wilga 2 and the Tuchola 108-2.
We have limited control over our exploration and development activities
in Poland.
We rely to a significant extent on the expertise and financial
capabilities of POGC. The failure of POGC to perform its obligations under
contracts with us may have a material adverse effect on us. In the future, we
may become even more reliant upon the operational expertise and financial
capabilities of our industry partners.
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 area,
where POGC is the operator. Upon the formation of Plotki, we and POGC have
agreed to assign our interests in the Fences project area to Plotki as a capital
contribution. Our program in the Fences project area would be adversely affected
if POGC should elect not to pursue activities on such acreage, does not assign
its interest in the Fences project area to Plotki, 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. In addition, should
our relationship with POGC deteriorate or terminate, our oil and gas activities
in Poland may be adversely affected.
During 2001, Apache completed all of its requirements under terms of
the Apache Exploration Program and now participates with us in Poland only on
our Wilga project area. We have limited control over the Wilga project area
because Apache is the operator.
We may not achieve the results anticipated in placing our current or
future discoveries into production.
We may encounter delays in commencing the production and the sale of
gas in Poland, including our recent gas discoveries and other possible future
discoveries. 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 and may
require us to obtain additional short-term financing pending commencement of
production. Further, we may design proposed surface and pipeline facilities
based on possible estimated results of additional drilling. We cannot assure
that additional drilling will increase reserves or production that will provide
an economic return for planned expenditures for facilities. We may have to
change our anticipated expenditures if costs of placing a particular discovery
into production are higher, if the project is smaller or if the commencement of
production takes longer than expected.
18
We cannot assure the exploration models we are using in Poland will
improve our chances of finding oil or gas in Poland.
We cannot assure the exploration models we, POGC or Apache have
developed will provide a useful or effective guide for selecting exploration
prospects and drilling targets. 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. These exploration models may be based on
incomplete or unconfirmed data and theories that have not been fully tested. The
seismic data, other technologies and the study of producing fields in the area
do not enable us to know conclusively prior to drilling that oil or gas will be
present in commercial quantities. We cannot assure that the analogies that we
draw from available data from other wells, more fully explored prospects or
producing fields will be applicable to our drilling prospects.
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, we
cannot predict accurately the oil or gas potential of individual prospects and
drilling targets or the related risks. Our predictions are only rough,
preliminary geological estimates of the forecasted volume and characteristics of
possible reservoirs and are not an estimate of reserves. In some cases, our
estimates may be based on a review of data from other exploration or producing
fields in the area that may not be similar to our exploration prospects. 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.
Our activities in Poland have benefited from our relationship with
POGC, which has provided us with exploration acreage, seismic data and
production data under our agreements. The Polish government has commenced the
privatization of POGC by selling 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 adversely affect our existing relationship
and agreements, as well as the availability of opportunities with POGC in the
future.
We have a history of operating losses and will require additional
capital in the future to fund our operations.
From our inception in January 1989 through December 31, 2001, we have
incurred cumulative net losses of approximately $48.0 million. We expect that
our exploration and production activities may continue to result in net losses
and that our accumulated deficit may increase. We anticipate that we may incur
losses through 2002 and possibly beyond, depending on whether our activities in
Poland and the United States result in sufficient revenues to cover related
operating expenses and G&A.
Until sufficient cash flow from operations can be obtained, we expect
we will need additional capital to fully fund our ongoing planned exploration,
appraisal, development and property acquisition programs in Poland. Obtaining
additional financing may dilute the interest of our existing stockholders or our
interest in the specific project being financed. We cannot assure that
additional funds could be obtained or, if obtained, would be on terms favorable
to us. In addition to planned activities in Poland, we may require additional
funds for general corporate purposes.
Our initial production in Poland is encumbered to secure repayment of a
$5.0 million loan due RRPV.
We have agreed to encumber most of our Polish property interests in
Poland and the related proceeds from gas sales to secure repayment of a $5.0
million loan from RRPV. The RRPV loan is due on March 9, 2003, including
interest accrued at 9.5% for one year. Unless converted to common stock at $5.00
per share, we will have to raise additional capital to pay back the loan. The
loan will have to be repaid notwithstanding the level of production from our
19
producing properties, our other cash requirements or the potentially greater
financial return from other expenditures. In addition, our agreements with RRPV
contain financial and operating covenants that are customary for transactions of
this nature, including limitations on additional indebtedness. Our agreement
with RRPV also specifies usual and customary events of default. If the loan is
not repaid timely or a default occurs, RRPV would have the right to obtain
possession of our encumbered Polish property interests.
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 us. We have entered into
employment agreements with Mr. David Pierce, Mr. Andrew Pierce, Mr. Maciolek and
other key executives. We do not maintain key man insurance on any of our
employees.
The price we receive for gas we sell will likely be lower than
free-market gas prices in western Europe.
The limited volume and single source of our 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. Similarly, there is no established market relationship
between gas prices in short-term and long-term sales agreements. The
availability of abundant quantities of gas from former members of the Soviet
Union and the low cost of electricity from coal-fired generating facilities may
also tend to depress gas prices in Poland.
Oil and gas price decreases and volatility could adversely affect our
operations and our ability to obtain financing.
Oil and gas prices have been and are likely to continue to be volatile
and subject to wide fluctuations in response to the following factors:
o the market and price structure in local markets;
o changes in the supply of and demand for oil and gas;
o market uncertainty;
o political conditions in international oil and gas producing
regions;
o the extent of production and importation of oil and gas into
existing or potential markets;
o the level of consumer demand;
o weather conditions affecting production, transportation and
consumption;
o the competitive position of oil or gas as a source of energy,
as compared with coal, nuclear energy, hydroelectric power and
other energy sources;
o the availability, proximity and capacity of gathering systems,
pipelines and processing facilities;
o the refining and processing capacity of prospective oil or gas
purchasers;
o the effect of government regulation on the production,
transportation and sale of oil and gas; and
o other factors beyond our control.
We have not entered into any agreements to protect us from price
fluctuations and may not do so in the future.
20
Our industry is subject to numerous operating risks. Insurance may not
be adequate to protect us against all these risks.
Our oil and gas drilling and production operations are subject to
hazards incidental to the industry. These hazards include blowouts, cratering,
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. To lessen the effects of these hazards, we maintain insurance of
various types to cover our United States operations. We cannot assure that the
general liability insurance of $9.0 million carried by us or the $25.0 million
carried by Apache, as the operator of the Wilga project area, can continue to be
obtained on reasonable terms. POGC, as operator of the Fences project area, is
self-insured. We do not plan to purchase well control insurance on wells we
drill in the Fences project area and may elect not to purchase such insurance on
wells drilled in other areas in Poland as well. The current level of insurance
does not cover all of the risks involved in oil and gas exploration, drilling
and production. Where additional insurance coverage does exist, the amount of
coverage may not be sufficient to pay the full amount of such liabilities. We
may not be insured against all losses or liabilities that may arise from all
hazards because such insurance is unavailable at economic rates, because of
limitations on existing insurance coverage or other factors. For example, we do
not maintain insurance against risks related to violations of environmental
laws. We would be adversely affected by a significant adverse event that is not
fully covered by insurance. Further, we cannot assure that we will be able to
maintain adequate insurance in the future at rates we consider reasonable.
RISKS RELATING TO CONDUCTING BUSINESS IN POLAND
Polish laws, regulations and policies may be changed in ways that could
adversely impact our business.
Our oil and gas exploration, development and production activities in
Poland are and will continue to be subject to ongoing uncertainties and risks,
including:
o possible changes in government personnel, the development of
new administrative policies and practices and political
conditions in Poland that may affect the administration of
agreements with governmental agencies or enterprises;
o possible changes to the laws, regulations and policies
applicable to us and our partners 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;
o uncertainties as to whether we will be able to enforce our
rights in Poland;
o uncertainty as to whether we will be able to demonstrate, to
the satisfaction of the Polish authorities, our, POGC's and
Apache's compliance with governmental requirements respecting
exploration expenditures, results of exploration,
environmental protection matters and other factors;
o the inability to recover previous payments to the Polish
government made under the exploration rights or any other
costs incurred respecting those rights if we were to lose or
cancel our exploration and exploitation rights at any time;
o political instability and possible changes in government;
o export and transportation tariffs;
o local and national tax requirements;
o expropriation or nationalization of private enterprises and
other risks arising out of foreign government sovereignty over
our acreage in Poland; and
o possible significant delays in obtaining opinions of local
authorities or satisfying other governmental requirements in
connection with a grant of an exploitation concession.
21
Poland has a developing regulatory regime, regulatory policies and
interpretations.
Poland has a developing regulatory regime governing exploration and
development, production, marketing, transportation and storage of oil and gas.
These provisions were recently promulgated 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 materially and adversely
affect our activities in Poland. For example, Poland's laws, policies and
procedures may be changed to conform to the minimum requirements that must be
met before Poland is admitted as a full member of the European Union.
Our oil and gas operations are subject to rapidly changing
environmental laws and regulations that could negatively impact our
operations.
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. Additionally, if significant quantities of gas
are produced with oil, regulations prohibiting the flaring of gas may inhibit
oil production. In such circumstances, the absence of a gas gathering and
delivering system may restrict production or may require significant
expenditures to develop such a system prior to producing oil and gas. We may be
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 and our partners cannot assure that we have complied with all
applicable laws and regulations in drilling wells, acquiring seismic data or
completing other activities in Poland to date. The Polish government may adopt
more restrictive regulations or administrative policies or practices. 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 the imposition of fines and penalties, any of which
may be material. These environmental costs could have a material adverse effect
on our financial condition or results of operations in the future.
Certain risks of loss arise from our need to conduct transactions in
foreign currency.
The amounts in our agreements relating to our activities in Poland are
normally expressed and payable in United States dollars or equivalent Polish
zloty. Conversions between United States dollars and Polish zloty are made on
the date amounts are paid or received. In the future, our financial results and
cash flows in Poland may be affected by fluctuations in exchange rates between
the Polish zloty and the United States dollar. We have not hedged our foreign
currency activities in the past and do not plan to do so. Currencies used by us
may not be convertible at satisfactory rates. In addition, the official
conversion rates between United States and Polish currencies may not accurately
reflect the relative value of goods and services available or required in
Poland. Further, inflation may lead to the devaluation of the Polish zloty.
Under Poland's Foreign Exchange Law, prior to making transfers of
nonresident income (such as dividends, interest, rent) abroad, a bank generally
must be furnished with documents evidencing title for the payment, as well as
with a certificate issued by the Polish tax authorities confirming the
expiration of tax liability in Poland or a foreign exchange permit releasing the
transferor from this obligation. If the income to be transferred is not subject
to taxation in Poland, a written declaration to this effect may be sufficient.
Given that the Foreign Exchange Law has come into effect recently and
no detailed rules and regulations under it have been issued to date by the
Polish authorities, the interpretation of the law's provisions will remain
subject to considerable uncertainty in the near term.
22
RISKS RELATED TO AN INVESTMENT IN OUR COMMON STOCK
Our stockholder rights plan and bylaws discourage unsolicited takeover
proposals and could prevent our stockholders from realizing a premium
on our common stock.
We have a stockholder rights plan that may have the effect of
discouraging unsolicited takeover proposals. 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.
Our common stock has traded as low as $1.97 and as high as $3.01
between January 1, 2001, and the date of this report. Some of the factors
leading to this volatility include:
o the timing and availability of capital from industry or
financial sources;
o the potential sale by us of newly issued common stock to raise
capital or by existing stockholders of restricted securities;
o changes in stock market analysts' recommendations regarding
us, other oil and gas companies or the oil and gas industry in
general;
o price and volume fluctuations in the general securities
markets that are unrelated to our results of operations;
o the investment community's view of companies with assets and
operations outside the United States in general and in Poland
in particular;
o actions or announcements by POGC that may affect us;
o the outcome of individual wells or the timing of exploration
efforts in Poland;
o prevailing world prices for oil and gas; and
o the potential of our current and planned activities in Poland.
Our common stock is currently traded on the Nasdaq National Market
under the symbol FXEN. Due to the recent decline in the share price of our
common stock and our operating losses, we could fail to meet the Nasdaq National
Market's minimum listing requirements and, as a result, our common stock could
be de-listed. If our stock were de-listed from Nasdaq, there would likely be a
substantial reduction in the liquidity of any investment in our common stock.
De-listing could also reduce the ability of holders of our common stock to
purchase or sell shares as quickly and as inexpensively as they have done
historically. This lack of liquidity also makes it more difficult for us to
raise capital in the future. There can be no assurance that an active trading
market will be sustained in the future.
23
OIL AND GAS TERMS
The following terms have the indicated meaning when used in this
Report:
"Bbl" means barrel of oil.
"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.
"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. "Mcf" means one cubic foot of natural gas.
"MMcf" means million cubic feet of natural gas.
"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. "Tcfe" means an
equivalent of a trillion cubic feet of natural gas.
24
- --------------------------------------------------------------------------------
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, 2001.
25
PART II
- --------------------------------------------------------------------------------
ITME 5. MARKET FOR 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 National Market:
Low High
----------- -----------
2002:
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
2000:
Fourth Quarter.............................. 3.19 4.81
Third Quarter............................... 3.28 5.69
Second Quarter.............................. 4.44 8.31
First Quarter............................... 5.13 7.94
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 29, 2002, we had approximately 4,200 stockholders.
Our common stock is currently traded on the Nasdaq National Market
under the symbol FXEN. Due to the recent decline in the share price of our
common stock and our operating losses, we could fail to meet the Nasdaq National
Market's minimum listing requirements and, as a result, our common stock could
be de-listed. Nasdaq National Market listing requirements include a series of
financial tests relating to net tangible assets, market value of public float,
number of market makers and stockholders, and maintaining a minimum bid price
for the Company's share price of $3.00. The accompanying consolidated financial
statements indicate that we will not meet the net tangible assets test and the
market capitalization test as of December 31, 2001. As a result, we may seek to
have our stock traded on the Nasdaq SmallCap Market, or it could be de-listed.
If our stock were de-listed from Nasdaq, there would likely be a substantial
reduction in the liquidity of any investment in our common stock. De-listing
could also reduce the ability of holders of our common stock to purchase or sell
shares as quickly and as inexpensively as they have done historically. This lack
of liquidity also would make it more difficult for us to raise capital in the
future. There can be no assurance that an active trading market will be
sustained in the future.
26
- --------------------------------------------------------------------------------
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
- --------------------------------------------------------------------------------
The following selected consolidated financial data of FX Energy, Inc.
and its subsidiaries for the five years ended December 31, 2001, are derived
from the audited financial statements and notes thereto of FX Energy, Inc. and
its subsidiaries, 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:
Years Ended December 31,
---------------------------------------------------------------
2001 2000 1999 1998 1997
----------- ------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales....................... $ 2,229 $ 2,521 $ 1,554 $ 1,124 $ 2,040
Oilfield services....................... 1,584 1,290 865 323 496
Gain on sale of property interests...... -- -- -- 467 272
----------- ------------ ------------ ------------ ------------
Total revenues........................ 3,813 3,811 2,419 1,914 2,808
----------- ------------ ------------ ------------ ------------
Operating costs and expenses:
Lease operating costs (1)............... 1,358 1,349 962 1,046 1,239
Exploration costs (2)................... 6,544 7,389 3,053 2,127 5,314
Proved property impairment (3).......... -- -- -- 5,885 --
Oilfield services costs................. 1,301 1,084 642 240 329
Depreciation, depletion and
amortization.......................... 662 386 494 672 635
Amortization of deferred
compensation (G&A).................... 1,078 652 -- -- --
Apache Poland general and
administrative costs.................. 575 957 -- -- --
General and administrative.............. 883 2,654 2,962 2,572 2,566
----------- ------------ ------------ ------------ ------------
Total operating costs and expenses.. 12,401 14,471 8,113 12,542 10,083
----------- ------------ ------------ ------------ ------------
Operating loss............................ (8,588) (10,660) (5,694) (10,628) (7,275)
----------- ------------ ------------ ------------ ------------
Other income (expense):
Interest and other income............... 543 557 511 506 662
Interest expense........................ (331) (2) (7) -- (83)
Impairment of notes receivable.......... (34) (738) (666) -- --
----------- ------------ ------------ ------------ ------------
Total other income (expense)........ 178 (183) (162) 506 579
----------- ------------ ------------ ------------ ------------
Net loss before extraordinary gain........ (8,410) (10,843) (5,856) (10,122) (6,696)
Extraordinary gain...................... -- -- -- -- 3,076
----------- ------------ ------------ ------------ ------------
Net loss.................................. $ (8,410) $ (10,843) $ (5,856) $ (10,122) $ (3,620)
=========== ============ ============ ============ ============
Basic and diluted net loss per share:
Net loss before extraordinary gain...... $ (0.48) $ (0.66) $ (0.41) $ (0.78) $ (0.53)
Extraordinary gain...................... -- -- -- -- 0.24
----------- ------------ ------------ ------------ ------------
Net loss.............................. $ (0.48) $ (0.66) $ (0.41) $ (0.78) $ (0.29)
=========== ============ ============ ============ ============
Basic and diluted weighted average
shares outstanding...................... 17,673 16,435 14,199 12,979 12,597
- Continued -
27
Years Ended December 31,
---------------------------------------------------------------
2001 2000 1999 1998 1997
----------- ------------ ------------ ------------ ------------
(In thousands)
Cash Flow Statement Data:
Net cash used in operating
activities ............................. $ (3,248) $ (6,082) $ (2,984) $ (3,091) $ (2,402)
Net cash provided by (used in)
investing activities ................... 326 (3,834) (3,678) 1,066 (3,110)
Net cash provided by (used in)
financing activities.................... 5,000 9,375 6,469 (674) 1,679
Balance Sheet Data:
Working capital........................... $ 558 $ 616 $ 5,459 $ 3,965 $ 8,494
Total assets.............................. 9,168 10,570 10,470 8,253 18,555
Long-term debt............................ 4,907 -- -- -- --
Stockholders' equity...................... 953 8,231 8,367 6,920 17,612
- --------------------
(1) Includes lease operating expenses and production taxes.
(2) Includes geophysical and geological costs, exploratory dry hole costs
and nonproducing leasehold impairments.
(3) Includes proved property write down relating to our producing
properties in the United States.
28
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
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 AND CRITICAL ACCOUNTING POLICIES
We are an independent energy company with activities concentrated
within the oil and gas industry. In Poland, we have projects involving the
exploration and exploitation of oil and gas with POGC and Apache. In the United
States, we produce oil from fields in Montana and Nevada and have an oilfield
services company in northern Montana that performs contract drilling and well
servicing operations.
We conduct substantially all of our exploration and development
activities in Poland jointly with others and, accordingly, recorded amounts for
our activities in Poland reflect only our proportionate interest in these
activities.
Our results of operations may vary significantly from year to year
based on the factors discussed in "Risk Factors" and on other factors such as
our exploratory and development drilling success. Therefore, the results of any
one year may not be indicative of future results.
Oil and Gas Activities
We follow the successful efforts method of accounting for our oil and
gas properties in both the United States and Poland. 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, 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
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. 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.
Oil and Gas Reserves
Engineering estimates of FX Energy's 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 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.
29
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, 2001, 2000 and 1999, respectively follows.
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, 2001, 2000 and 1999, is set forth in the following
table:
For the year ended December 31,
---------------------------------------------------------------------------------
2001 2000 1999
--------------------------- -------------------------- --------------------------
Oil Gas Oil Gas Oil Gas
-------------- ------------ ------------- ------------ ------------- ------------
Revenues............................ $ 1,835,000 $ 394,000 $ 2,521,000 $ -- $ 1,554,000 $ --
Percent change versus prior year.. -28.0% +100% +62.2%
Average price (Bbls or Mcf)(1)...... $ 19.41 $1.58 $ 26.14 $ -- $ 15.35 $ --
Percent change versus prior year.. -25.8% +100% +70.3%
Production volumes (Bbls or Mcf).... 94,522 249,661 96,416 -- 101,275
Percent change versus prior year.. -1.9% +100% -4.8%
Lifting costs per Bbls or Mcf(2).... $ 13.62 $ .16 $ 12.13 $ -- $ 8.88 $ --
Percent change versus prior year.. +12.3% +100% +36.6%
- --------------------
(1) The contract price for gas during 2001 prior to adjusting for actual
physical content of British thermal units, or 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 $1.8 million, $2.5 million and $1.6
million for the years ended December 31, 2001, 2000 and 1999, respectively.
During 2001, we received $19,000 of oil revenues from Poland pertaining to the
production test performed on the Wilga 2. All other oil revenues for 2001, 2000
and 1999 were derived solely from our producing properties in the United States.
During these three years, the oil revenues from our United States producing
properties fluctuated primarily due to volatile oil prices, the degree of
maintenance performed and the declining production rates attributable to the
natural production declines of our producing properties.
Gas Revenues. Our gas revenues are derived solely from our Polish
producing operations. Gas revenues were $394,000 during the year ended December
31, 2001. There were no gas revenues during 2000 and 1999. The Kleka 11, our
first producing well in Poland, began producing during February 2001. During
2001, gas produced by the Kleka 11 was sold to POGC based on U.S. dollar pricing
under a five-year contract, which may be terminated by giving POGC a 90-day
written notice. Also, during 2001, there were no gas revenues pertaining to the
Wilga 2 or the Tuchola 108-2, as the gas produced during the production tests
for each of the wells was flared. The Wilga 2 and the Tuchola 108-2 are
currently shut-in, pending the construction of pipelines and production
facilities.
30
Lease Operating Costs. Our lease operating costs consist of normal
recurring lease operating expenses and production taxes. Lease operating costs
were $1.4 million, $1.3 million and $962,000 for the years ended December 31,
2001, 2000 and 1999, respectively, or $14.50, $13.99 and $9.50, respectively,
per barrel of oil produced and $0.16 per Mcf of gas produced during the year
ended December 31, 2001.
Lease operating expenses, or LOE, were $1.3 million, $1.2 million and
$899,00 for the years ended December 31, 2001, 2000 and 1999, respectively. LOE
incurred during 2001 include $42,000, or $0.16 per Mcf of gas produced based on
a 49% working interest, pertaining solely to the Kleka 11 well that began
producing in Poland during February 2001. There were no LOE associated with
Poland during 2000 and 1999. During 2001, in the United States, we plugged and
abandoned ten inactive wells on the Cut Bank Sand Unit, our principal producing
property in Montana, at a total cost of approximately $82,000. During 2000, in
the United States, we plugged and abandoned ten inactive wells on the Cut Bank
Sand Unit at a total cost of approximately $92,000. During 1999, in the United
States, we performed only routine maintenance on our producing properties and
deferred workovers in an effort to control operating costs due to the low oil
prices that prevailed throughout most of 1999.
Production taxes are solely attributable to our United States oil
production. Production taxes were $29,000, $179,000 and $63,000 for the years
ended December 31, 2001, 2000 and 1999, respectively. Production tax legislation
in the state of Montana, as revised during 1999, contains provisions whereby the
production tax rate for stripper wells was decreased to be as low as 0.5%
coupled with provisions that would increase the production tax rate to as high
as 12.8% for an entire calendar quarter in the event West Texas Intermediate
crude oil, or WTI, exceeded $30.00 per barrel for an entire quarter. During
2001, 2000 and 1999, WTI exceeded $30.00 only during the third and fourth
quarters of 2000. As a result, production taxes were substantially higher during
2000 as compared to 2001 and 1999. Production taxes averaged approximately 1.6%,
7.1% and 4.1% of oil revenues during the years ended December 31, 2001, 2000 and
1999, respectively.
DD&A Expense - Producing Operations. DD&A expense for producing
properties was $322,000, $73,000 and $51,000 for the years ended December 31,
2001, 2000 and 1999, respectively. DD&A expense incurred during 2001 includes
approximately $258,000, or $1.03 per Mcf of gas produced, associated solely with
the Kleka 11 well that began producing in Poland during February 2001. The
capital costs pertaining to the Kleka 11 that were included in the DD&A
calculation for the year ended December 31, 2001, include our 49.0% share of
costs and POGC's 51.0% share of costs, which we paid as part of our commitment
to earn a 49.0% working interest in the Fences project area. There was no DD&A
expense associated with Poland during 2000 and 1999. The DD&A rate per barrel
for oil produced in the United States was $0.69, $0.76 and $0.50 during 2001,
2000 and 1999, 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, 2001, 2000 and 1999, respectively.
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 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 utilized the entire Poland 2001 Agreement Credit, as shown
below:
Poland 2001 Agreement Credit
-----------------------------------------------
2001 2000 Total
--------------- --------------- ---------------
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
=============== =============== ===============
31
Exploration Costs. Our exploration costs consist of geological and
geophysical costs, or G&G costs, exploratory dry holes and nonproducing
leasehold impairments. Exploration costs were $6.5 million, $7.4 million and
$3.1 million for the years ended December 31, 2001, 2000 and 1999, respectively.
During 1999, we incurred G&G costs totaling $31,000 relating to our discontinued
gold exploration in Poland, all of which is excluded from the following
discussion of each component of exploration costs because mining is not a
reportable segment.
G&G costs were $2.9 million, $4.7 million and $1.9 million for the
years ended December 31, 2001, 2000 and 1999, respectively. During 2001, we
spent approximately $1.8 million on acquiring 3-D seismic data in the Fences
project area, $552,000 acquiring and analyzing 2-D seismic data on the
Pomeranian project area and granted 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 area, 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. During 1999, we spent approximately $310,000
reprocessing 2-D seismic data on the Pomeranian and Warsaw West project areas,
granted stock options valued at approximately $119,000 to a Polish consultant
and spent approximately $374,000 evaluating potential property acquisitions from
POGC. From January 1, 1999, through December 31, 2001, we spent an average
amount of approximately $1.2 million annually relating to analyzing seismic data
and the wages and associated expenses for employees and consultants directly
engaged in geological and geophysical activities. Subject to available funding,
G&G costs are expected to continue at current or higher levels as we further our
exploratory efforts in Poland.
Exploratory dry hole costs were $3.1 million, $2.0 million and $1.0
million for the years ended December 31, 2001, 2000 and 1999, respectively.
During 2001, we incurred costs of $3.1 million pertaining to the Mieszkow 1 on
the Fences project area. In accordance with FASB No. 19, we have classified the
Mieszkow 1 as an exploratory dry hole for financial reporting purposes, because
drilling operations have been suspended since April 2001 pending the
reprocessing and interpretation of 3-D seismic data in order to evaluate the
continuation of drilling operations and the need for additional funding. 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 costing a net amount of $1.1 million and $900,000, respectively, after
Apache covered one-half of our 45.0% share of drilling costs under terms of the
Apache Exploration Program. During 1999, we participated in drilling three
exploratory dry holes in Poland. Two of these wells, the Siedliska 2 and Witkow
1, were carried exploratory wells under the Apache Exploration Program. As such,
Apache covered all of our pro rata share of drilling costs for both wells. We
paid $99,000 for a 5.0% interest in the Andrychow 6 well, an exploratory dry
hole on the Carpathian project area. On the Lachowice Farm-in, we spent $869,000
to recomplete one shut-in well and test another shut-in well, both of which were
noncommercial. Also, during 1999, we spent $33,000 associated with the Gladysze
1-A, an exploratory dry hole drilled on the Baltic project area during 1997.
Under terms of the Poland 2001 Agreement Credit, Apache covered $22,000 of
additional exploratory costs incurred by us during 2001 and 2000, including
$6,000 for the Wilga 3, $2,000 for the Wilga 4 and $14,000 for the Lachowice 7.
Nonproducing leasehold impairments were $584,000, $674,000 and $93,000
for the years ended December 31, 2001, 2000 and 1999, respectively. During 2001,
we incurred nonproducing leasehold 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 a nonproducing leasehold impairment $674,000 for the Williston
Basin in North Dakota, where we also no longer have exploration plans. During
1999, we incurred a nonproducing leasehold impairment of $72,000 for the
Lachowice Farm-in, which was deemed noncommercial after recompleting a shut-in
well and testing another shut-in well yielded noncommercial results, and $21,000
pertaining to a prospect in Nevada where we also no longer have exploration
plans. Nonproducing leasehold 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.
32
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 $575,000
and $957,000 for the years ended December 31, 2001 and 2000. There were no
Apache Poland G&A costs during the year ended December 31, 1999. 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 35.0% of Apache Poland G&A costs, to be
adjusted as each of Apache's remaining drilling requirements are completed, up
to a maximum of 50.0%. Apache has since completed its remaining drilling
requirements, and we are now responsible for our entire 50.0% share of Apache
Poland G&A costs relating to ongoing, jointly conducted activities in Poland for
which Apache is the operator, subject to a preapproved annual budget. 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.
Other income - E&P. Other income for our E&P segment was $29,000 during
the year ended December 31, 2001. There was no other income for our E&P segment
during 2000 and 1999. During 2001, we sold the working interest in our
nonproducing Ryckman Creek prospect located in Wyoming for $44,000, for which we
had associated costs of $15,000.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $1.6
million, $1.3 million and $865,000 for the years ended December 31, 2001, 2000
and 1999, respectively. During each year from 1999 through 2001, oilfield
services revenues increased each year due to improved market conditions and an
increasing emphasis on utilizing the Company's oilfield servicing equipment for
contract third-party services rather than servicing company-owned properties.
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 utilizing our oilfield services
equipment on our company-owned properties and other factors.
Oilfield Servicing Costs. Oilfield services costs were $1.3 million,
$1.1 million and $642,000 for the years ended December 31, 2001, 2000 and 1999,
respectively, or 82.0%, 84.0% and 74.2% 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 2000,
oilfield servicing costs were a higher percentage of oilfield services revenues,
as compared to 1999, 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 utilizing our oilfield services equipment on our company-owned
properties and other factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $308,000, $247,000 and $334,000 for the years ended December 31, 2001, 2000
and 1999, respectively. We spent $248,000, $779,000 and $138,000 on upgrading
our oilfield servicing equipment during 2001, 2000 and 1999, respectively. DD&A
expense was $61,000 higher during 2001, as compared to 2000, primarily due to
capital additions incurred during 2000 being depreciated during all of 2001.
DD&A expense was $87,000 lower during 2000, as compared to 1999, primarily due
to prior year capital additions becoming fully depreciated during 2000.
Nonsegmented Items
DD&A Expense - Corporate. DD&A expense for corporate activities was
$32,000, $66,000 and $109,000 for the years ended December 31, 2001, 2000 and
1999, respectively. We spent $6,000, $33,000 and $19,000 during 2001, 2000 and
1999, respectively, on software, hardware and office equipment utilized
primarily for corporate purposes. DD&A expense for corporate activities was
progressively lower year to year, primarily due to assets purchased in prior
years becoming fully depreciated in subsequent years.
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $1.1 million and $652,000 during the years ended December 31,
2001 and 2000, respectively. There was no amortization of deferred compensation
during 1999. On April 5, 2001, we extended the term of options to purchase
125,000 shares of the Company's common stock that were to expire during 2001 for
33
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.
G&A Costs - Corporate. G&A costs were $883,000, $2.7 million and $3.0
million for the years ended December 31, 2001, 2000 and 1999, respectively.
During 2001, G&A costs were $1.8 million lower, as compared to 2000, primarily
due to the Company writing off $1.7 million of compensation that was accrued as
of December 31, 2000. During 2000, G&A costs were $307,000 lower, as compared to
the same period of 1999, primarily due to lower payroll and associated costs.
Subject to available funding, we expect to incur future G&A costs at levels
similar to that of 2000 and 1999, or higher, in future periods as we continue
our presence in Poland.
Interest and Other Income - Corporate. Interest and other income was
$514,000, $557,000 and $512,000 for the years ended December 31, 2001, 2000 and
1999, respectively. Our cash, cash equivalent and marketable debt securities
balances were $3.2 million, $2.4 million and $6.9 million as of December 31,
2001, 2000 and 1999, respectively. The average cash and marketable securities
balances during 2001, 2000, and 1999 were relatively constant from year to year.
However, due to lower interest rates during 2001, we earned interest income of
$185,000, as compared to $531,000 and $499,000 during 2000 and 1999,
respectively. Accrued interest income associated with notes receivable was
$15,000, $140,000 and $134,000 during 2001, 2000 and 1999, respectively. Also,
during the year ended December 31, 2001, we recorded other income of $341,000
pertaining to amortizing an option premium resulting from granting RRPV an
option to purchase gas from our properties in Poland, and recorded other
miscellaneous items totaling $27,000.
Interest Expense. Interest expense was $331,000, $2,000 and $8,000 for
the years ended December 31, 2001, 2000 and 1999, respectively. During, 2001, we
recorded $341,000 of imputed interest expense relating to our financing
arrangement with RRPV and $2,000 for the short-term financing of oilfield
services equipment. Also, during 2001, we capitalized $12,000 of interest costs
pertaining to completing the Tuchola 108-2. During 2000, we incurred $2,000 of
interest expense relating to financing the purchase of five pickups used in our
Montana operations with one-year notes. During 1999, we incurred $8,000 of
interest expense primarily relating to the settlement of an audit by the
Blackfeet Tribe pertaining to the Cut Bank Field.
Impairment of Notes Receivable. Impairment of notes receivable was
$34,000, $738,000 and $666,000 for the years ended December 31, 2001, 2000 and
1999, 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. Also during 2000, two of our officers
surrendered collateral shares to us in return for the cancellation of the notes
receivable from those officers that were outstanding on December 28, 2000. The
officers' notes included principal and interest of $2.2 million reduced by a
cumulative impairment allowance of $1.4 million based on the market value of
233,340 shares of the our common stock held as collateral. As a result of the
transaction, we recorded the acquisition of 233,340 shares of treasury stock at
a cost of $773,000.
Income Taxes. We incurred net losses of $8.4 million, $10.8 million and
$5.9 million for the years ended December 31, 2001, 2000 and 1999, 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.
34
LIQUIDITY AND CAPITAL RESOURCES
General. Historically, we have relied primarily on proceeds from the
issuance of debt securities and the sale of our common stock to fund our
operating and investing activities. During 2001, we received $5.0 million under
the terms of our $5.0 million loan agreement and gas purchase option agreement
with RRPV. During 2000 and 1999, we received net proceeds of $9.3 million and
$7.1 million, respectively, from the sale of our common stock in private
transactions.
Working Capital. We had working capital of $559,000, $616,000 and $5.5
million as of December 31, 2001, 2000 and 1999, respectively. During 2001, we
used $3.2 million in our operating activities, received $326,000 from our
investing activities and received $5.0 million from our financing activities.
During 2000, we used $6.1 million in our operating activities, used $3.9 million
in our investing activities and received $9.4 million from our financing
activities. During 1999, we used $3.0 million in our operating activities, used
$3.7 million in our investing activities and received $6.5 million from our
investing activities. A detailed discussion regarding our cash flows from our
operating, investing and financing activities during 2001, 2000 and 1999
follows.
Operating Activities. We used net cash of $3.2 million, $6.1 million
and $3.0 million in our operating activities during 2001, 2000 and 1999,
respectively, primarily as a result of the net losses incurred in those years.
During 2001, 2000 and 1999, we spent $3.0 million, $6.4 million and $3.4
million, respectively, on operating activities exclusive of changes in working
capital items. Net changes in working capital items increased cash used in
operating activities by $238,000 during 2001 and decreased cash used in
operating activities by $335,000 and $450,000 during 2000 and 1999,
respectively.
Investing Activities. We received net cash of $326,000 from our
investing activities during 2001 and used net cash of $3.9 million and $3.7
million in investing activities during 2000 and 1999, respectively. During 2001,
we spent $333,000 on additions to proved properties, spent $422,000 on unproved
properties, spent $239,000 on upgrading our oilfield servicing equipment, spent
$6,000 on corporate assets, received $44,000 from the sale of a partial property
interest, received a $1,000 credit for exploratory dry holes drilled in prior
years and received $1.3 million from maturing marketable debt securities. Also,
during 2001, Apache covered $276,000 of our share of additional completion costs
pertaining to the Tuchola 108-2 in accordance with terms of the Poland 2001
Agreement Credit. During 2000, we spent $2.0 million on exploratory dry holes,
spent $2.6 million on additions to proved properties, spent $2.3 million on
additions to unproved properties, spent $779,000 on additions to oilfield
servicing equipment, spent $33,000 on corporate assets, spent $6.3 million on
purchasing marketable debt securities and received $10.3 million from maturing
or sold marketable debt securities. Also, during 2000, Apache covered $65,000 of
our share of leasehold costs pertaining to the Pomeranian and Warsaw West
project areas in accordance with terms of the Poland 2001 Agreement Credit.
During 1999, we spent $1.0 million on exploratory dry holes, spent $603,000 on
additions to properties, equipment and other assets, received $6,000 from the
sale of property interests, spent $6.6 million on purchasing marketable debt
securities and received $4.3 million from maturing or sold marketable debt
securities.
Financing Activities. We received net cash of $5.0 million, $9.4
million and $6.5 million from our financing activities during 2001, 2000 and
1999, 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 $773,000 in a noncash transaction.
During 1999, we advanced $598,000 to two officers, received net proceeds of $7.1
million ($7.2 million gross) from a private placement of 1,792,500 shares of
common stock and $13,000 from the exercise of options on 2,000 shares of our
common stock.
35
Carried Costs. In the past, our industry partners have provided a
substantial amount of the capital required under our exploration agreements with
them. For instance, in 1997, Apache committed to cover our share of certain
specific costs of the Apache Exploration Program in Poland, originally estimated
to cost $60.0 million gross (approximately $30.0 million net) in order to earn
an interest equal to ours in several of our Polish project areas. As of the end
of 2001, Apache had completed all of the primary earning requirements of the
Apache Exploration Program, which included the following principal items that
were completed between 1997 and 2001:
o up-front cash payments to us totaling $950,000;
o our share of costs to drill the equivalent of ten exploratory
wells (two of which were new discoveries and eight were
exploratory dry holes);
o our share of costs to shoot the equivalent of 2,000 kilometers
of 2-D seismic data;
o our share of leasehold costs in the Lublin Basin and
Carpathian project areas during the first three years of a
six-year exploration period; and
o our share of Apache Poland G&A through June 30, 2000.
Other industry partners have previously covered approximately $2.9
million of our share of costs in other projects during the last six years.
CAPITAL REQUIREMENTS
General. As of December 31, 2001, we had $3.2 million of cash and cash
equivalents, $559,000 of working capital and $5.0 million of long-term debt that
is due on or before March 9, 2003 (unless converted to restricted common stock
at $5.00 per share prior to March 9, 2003), coupled with a history of operating
losses. These matters raise substantial doubt about our ability to continue as a
going concern. In addition, we have a remaining commitment of $9.3 million that
must be spent by us in order to earn a 49.0% interest in the Fences project
area.
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities and through agreements with
industry partners that funded our share of costs in certain exploratory
activities in order to earn an interest in our properties. As of the date of
this report, we did not have a commitment from a third party to provide any
additional funding for our ongoing operations. The continuation of our
exploratory efforts in Poland is dependent on raising additional capital through
attracting an industry or financial partner, raising additional equity,
incurring additional debt, selling or farming out assets or completing other
arrangements. The availability of such capital will affect the timing, pace,
scope and amount of our future capital expenditures. There can be no assurance
that we will be able to obtain additional financing, 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.
Fences Project Area. On April 11, 2000, we agreed to spend $16.0
million of exploration costs on the Fences project area located in southeast
Poland that is owned and operated by POGC, in order to earn a 49.0% interest.
After we complete our $16.0 million commitment, POGC will begin bearing its
51.0% share of further costs. Currently, we are finalizing the formation of
Plotki Gaz SA, a joint stock company through which we and POGC will conduct our
ongoing exploration activities on the Fences project area under terms of the
$16.0 million commitment.
As of December 31, 2001, we had paid cash expenditures of approximately
$6.7 million pertaining to our $16.0 million commitment, including $2.4 million
on the Kleka 11, $2.2 million on the Mieszkow 1 and $2.1 million on 3-D seismic
data acquisition in two separate surveys, all of which was paid during 2000.
During 2001, we did not make any cash expenditures pertaining to the $16.0
million commitment. At December 31, 2001, we had accrued $2.7 million of costs
incurred during 2001 on the Fences project area, including $880,000 for the
Mieszkow 1 and $1.8 million for 3-D seismic data acquisition. Upon formation of
Plotki, we anticipate assigning to an outside partner a portion of the project
interests we convey to Plotki, in consideration of the partner's assumption of
all, or a portion of, our remaining obligation to earn an interest in the Fences
project area, including payment of the $2.7 million accrued costs at December
31, 2001. During 2002, we may commence drilling one or more additional
exploratory wells at a gross cost of approximately $2.8 million each, as
warranted and as funding permits.
Pomeranian Project Area. During 2001, we and our partners completed and
tested the Tuchola 108-2, at a cost of approximately $1.8 million gross
($773,000 net), and completed data acquisition on an approximately $1.1 million
gross ($509,000 net) 2-D seismic program covering approximately 281 kilometers
to confirm Main Dolomite Reef leads on regional 2-D seismic data. During 2002,
we intend to farm-out part of our interest to an industry partner prior to
conducting further exploratory activities on the Pomeranian project area.
Wilga Project Area. During 2001, we and our partners completed and
tested the Wilga 2. Under terms of the Apache Exploration Program, Apache
covered our 45.0% share of costs to complete and test the Wilga 2. We and our
partners are now assessing and evaluating the pipeline and facility expenditures
that will be required to commence production from the Wilga 2.
Other. As a result of the completion of the Apache Exploration Program
and our limited financial resources, we have dropped our exploration acreage
pertaining to the Lublin Basin project area (except for Wilga project area on
Block 255, which contains the Wilga 2 discovery and approximately 250,000
acres), the Carpathian project area, the Warsaw West project area and the Baltic
project area. During 2001, we wrote off all of our capitalized unproved property
costs associated with the aforementioned items, which consisted solely of
$59,000 for the Warsaw West project area and $525,000 for the Baltic project
36
area. Under terms of the Apache Exploration Program, Apache carried the majority
of our share of capital and exploratory expenditures incurred from 1997 through
the end of 2001 relating to the Lublin Basin, Carpathian and Warsaw West project
areas. During 2002, we expect to incur minimal exploration expenditures on our
operations in the United States.
We may obtain funds for future capital investments from strategic
alliances with other energy or financial partners, 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.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board (FASB) issued
Statements of Financial Accounting Standards ("SFAS") No. 141 "Business
Combinations" and SFAS No. 142 "Goodwill and Other Intangible Assets." Under
SFAS No. 141, the purchase method of accounting must be used for business
combinations initiated after June 30, 2001. Under SFAS No. 142 (effective for us
beginning January 1, 2002), goodwill and certain intangibles are no longer
amortized but will be subject to annual impairment tests. The adoption of these
new standards did not have a significant impact on our financial statements.
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 initial 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 August 2001, the FASB issued SFAS No. 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 is effective for
fiscal years beginning after December 15, 2001, and interim periods within those
fiscal years. We adopted this statement on January 1, 2002. This statement
addresses financial accounting and reporting for the impairment or disposal of
long-lived assets. Although SFAS No. 144 supersedes SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets To Be Disposed
Of," it retains the fundamental provisions of SFAS No. 121 for the recognition
and measurement of the impairment for long-lived assets. The adoption of this
new standard did not have a significant impact on our financial statements.
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.
37
- --------------------------------------------------------------------------------
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
- --------------------------------------------------------------------------------
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. During 2001, we sold oil produced during the Wilga 2
production test to a third party under a short-term contract that has since been
terminated. Commercial production from the Wilga 2 will not commence until after
the associated facilities and pipeline that may be constructed are completed.
Currently, we do not have a contract to sell future oil production from the
Wilga 2. The limited volume of our oil and 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 are able to obtain. There is
currently no competitive market for the sale of oil or gas in Poland.
Accordingly, we expect that the prices we receive for the oil and 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. Similarly, there is no established market
relationship between oil and gas prices in short-term and long-term sales
agreements. The availability of abundant quantities of oil and gas from outside
Poland and the low cost of electricity from coal-fired generating facilities may
also tend to depress oil and gas prices in Poland.
We currently do not engage in any hedging or trading 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
in the future if we achieve a significant amount of production in Poland. See
"Items 1. and 2. Business and Properties: Risk Factors."
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. The exchange rates for
the Polish Zloty were 3.96, 4.13 and 4.14 per U.S. dollar as of December 31,
2001, 2000 and 1999, respectively.
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.
38
- --------------------------------------------------------------------------------
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 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.
39
PART III
- --------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2002 annual
meeting of stockholders under the caption "Election of Directors: Executive
Officers, Directors and Nominees" and "Compliance with Section 16(a) of the
Exchange Act" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2002 annual
meeting of stockholders under the caption "Election of Directors: Executive
Compensation" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2002 annual
meeting of stockholders under the caption "Election of Directors: Security
Ownership of Certain Beneficial Owners and Management" is incorporated herein by
reference.
- --------------------------------------------------------------------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2002 annual
meeting of stockholders under the caption "Election Of Directors: Certain
Relationships and Related Transactions" is incorporated herein by reference.
40
PART IV
- --------------------------------------------------------------------------------
ITEM 14. 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, 2001 and 2000.... F-2
Consolidated Statements of Operations for each of the Three
Years Ended December 31, 2001, 2000 and 1999, respectively.... F-3
Consolidated Statements of Cash Flows for each of the Three
Years Ended December 31, 2001, 2000 and 1999, respectively.... F-5
Consolidated Statements of Stockholders' Equity for each of
the Three Years Ended December 31, 2001, 2000 and 1999,
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:
SEC
Exhibit Reference
Number Number Title of Document Location
- ---------- ----------- -------------------------------------------------------------------------- -----------------
Item 3. Articles of Incorporation and Bylaws
- --------------------------------------------------------------------------------------------------
3.1 3 Restated and Amended Articles of Incorporation Incorporated by
Reference(1)
3.2 3 Bylaws Incorporated by
Reference(2)
Item 4. Instruments Defining the Rights of Security Holders
- --------------------------------------------------------------------------------------------------
4.1 4 Specimen Stock Certificate Incorporated by
Reference(2)
4.2 4 Form of Designation of Rights, Privileges, and Preferences of Series A Incorporated by
Preferred Stock Reference(3)
4.3 4 Form of Rights Agreement dated as of April 4, 1997, between FX Energy, Incorporated by
Inc. and Fidelity Transfer Corp. Reference(3)
41
SEC
Exhibit Reference
Number Number Title of Document Location
- ---------- ----------- -------------------------------------------------------------------------- -----------------
Item 10. Material Contracts
- --------------------------------------------------------------------------------------------------
10.5 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, 1996, Reference(4)
relating to concession blocks 255, 275, 295, 316, 336, 337 and 338
(Lublin)
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)
10.11 10 Option Agreement dated July 18, 1997, between Polish Oil and Gas Incorporated by
Company, FX Energy, Inc. and Apache Overseas, Inc. Reference(5)
10.12 10 Participation Agreement dated effective as of April 16, 1997, between Incorporated by
Apache Overseas, Inc. and FX Energy, Inc. pertaining to the Lublin Reference(6)
Concessions
10.13 10 Letter Agreement dated February 27, 1998, between FX Energy, Inc. and Incorporated by
Apache Overseas, Inc. regarding modification to all agreements for Reference(7)
acreage in Poland under established area of mutual interest
10.15 10 Participation Option Agreement dated effective February 27, 1998, Incorporated by
between FX Energy, Inc. and Apache Overseas, Inc. pertaining to the Reference(7)
Pomeranian Concession
10.16 10 Prospect Agreement between Apache Poland Sp. z o.o. and FX Energy Poland Incorporated by
Sp. z o.o. dated April 17, 1998 Reference(8)
10.24 10 Agreement between Apache Overseas, Inc. and FX Energy, Inc. dated Incorporated by
effective January 1, 1999, pertaining to oil and gas operations in Reference(9)
Poland
10.26 10 Frontier Oil Exploration Company 1995 Stock Option and Award Plan* Incorporated by
Reference(10)
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(9)
10.29 10 Form of FX Energy, Inc. 1998 Stock Option and Award Plan* Incorporated by
Reference(9)
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(11)
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)
42
SEC
Exhibit Reference
Number Number Title of Document Location
- ---------- ----------- -------------------------------------------------------------------------- -----------------
10.34 10 Form of Non-Qualified Stock Option with related schedule* Incorporated by
Reference(10)
10.35 10 Letter Agreement dated effective August 3, 1995, between Lovejoy Incorporated by
Associates, Inc. and FX Energy, Inc. re: Financial Consulting Reference(10)
Engagement*
10.36 10 Letter Agreement dated effective August 3, 1995, between Lovejoy Incorporated by
Associates, Inc. and FX Energy, Inc. re: Indemnification Reference(10)
10.37 10 Non-Qualified Stock Option granted to Thomas B. Lovejoy* Incorporated by
Reference(10)
10.38 10 Letter Agreement dated effective December 31, 1997, between FX Energy, Incorporated by
Inc. and Lovejoy Associates, Inc. re: Extension of Consulting Reference(7)
Engagement*
10.39 10 Employment Agreement between FX Energy, Inc. and Jerzy B. Maciolek* Incorporated by
Reference(11)
10.40 10 Addendum to Employment Agreement between FX Energy, Inc. and Jerzy B. Incorporated by
Maciolek* Reference(7)
10.41 10 Second Addendum to Employment Agreement between FX Energy, Inc. and Incorporated by
Jerzy B. Maciolek* Reference(7)
10.42 10 Employment Agreement between FX Energy, Inc. and Scott J. Duncan* Incorporated by
Reference(7)
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 related Incorporated by
schedule* Reference(4)
10.52 10 Form of Indemnification Agreement between FX Energy, Inc. and certain Incorporated by
directors, with related schedule Reference(9)
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(12)
Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to
Fences project area
10.54 10 Agreement effective as of January 1, 2000, between FX Energy, Inc. and Incorporated by
Apache Overseas, Inc. Reference(13)
10.55 10 Option extensions with related schedules Incorporated by
Reference(13)
10.56 10 Poland 2001 Agreement dated as of January 1, 2001, between Apache Incorporated by
Overseas, Inc. and FX Energy, Inc. Reference(14)
10.57 10 US$5,000,000 9.5% Convertible Secured Note dated as of March 9, 2001 Incorporated by
Reference(14)
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(14)
43
SEC
Exhibit Reference
Number Number Title of Document Location
- ---------- ----------- -------------------------------------------------------------------------- -----------------
Item 21 Subsidiaries of the Registrant
- --------------------------------------------------------------------------------------------------
21.1 Schedule of Subsidiaries Incorporated by
Reference(7)
Item 23 Consents of Experts and Counsel
- --------------------------------------------------------------------------------------------------
23.1 23 Consent of PricewaterhouseCoopers LLP, independent accountants This Filing
23.2 23 Consent of Larry D. Krause, Petroleum Engineer This Filing
23.3 23 Consent of Troy-Ikoda Limited, Petroleum Engineers This Filing
- -----------------------
* Identifies each management contract or compensatory plan or arrangement
required to be filed as an exhibit.
(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 report on Form 8-K dated August 6, 1997.
(7) Incorporated by reference from the annual report on Form 10-KSB for the
year ended December 31, 1997.
(8) Incorporated by reference from the report on Form 8-K dated April 20, 1998.
(9) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 1999.
(10) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended September 30, 1995.
(11) Incorporated by reference from the registration statement on Form S-1, SEC
File No.333-05583.
(12) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended March 31, 2000.
(13) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended September 30, 2000.
(14) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 2000.
(b) Reports on Form 8-K.
During the quarter ended December 31, 2001, we filed the following
items on Form 8-K:
Date of Event Reported Item(s) Reported
--------------------------- -------------------------------------
October 3, 2001 Item 9. Regulation FD Disclosure
44
- --------------------------------------------------------------------------------
SIGNATURES
- --------------------------------------------------------------------------------
In accordance with Section 13 or 15(d) of the Exchange Act, the
registrant has caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
Dated: April 15, 2002. FX ENERGY, INC. (Registrant)
David N. Pierce, President and
Chief Executive Officer
In accordance with the Exchange Act, this report has been signed below
by the following persons on behalf of the registrant and in the capacities and
on the date indicated.
Dated: April 15, 2002
/s/ David N. Pierce
-----------------------------------------------------
David N. Pierce, Director and President
(Principal Executive Officer)
/s/ Andrew W. Pierce
-----------------------------------------------------
Andrew W. Pierce, Director and Vice President
(Principal Operations Officer)
/s/ Jerzy B. Maciolek
-----------------------------------------------------
Jerzy B. Maciolek, Director and Vice President
International Exploration
/s/ Thomas B. Lovejoy
-----------------------------------------------------
Thomas B. Lovejoy, Director, Chief Financial Officer
and Vice Chairman (Principal Financial Officer)
/s/ Scott J. Duncan
-----------------------------------------------------
Scott J. Duncan, Director, Vice President
Investor Relations and Secretary (Principal
Accounting Officer)
/s/ Peter L. Raven
-----------------------------------------------------
Peter L. Raven, Director
/s/ Dennis B. Goldstein
-----------------------------------------------------
Dennis B. Goldstein, Director
45
PRICEWATERHOUSECOOPERS
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, 2001 and 2000, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Salt Lake City, Utah
March 13, 2002
F-1
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2001 and 2000
2001 2000
----------------- ----------------
ASSETS
Current assets:
Cash and cash equivalents............................................................ $ 3,157,427 $ 1,079,038
Investment in marketable debt securities............................................. -- 1,281,993
Receivables:
Accrued oil sales................................................................ 478,857 250,954
Joint interest and other receivables............................................. 49,075 175,698
Inventory............................................................................ 87,260 87,920
Other current assets................................................................. 95,004 80,313
----------------- ----------------
Total current assets......................................................... 3,867,623 2,955,916
----------------- ----------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved........................................................................... 4,789,252 4,318,056
Unproved......................................................................... 655,523 3,031,863
Other property and equipment......................................................... 3,587,433 3,333,791
----------------- ----------------
Gross property and equipment..................................................... 9,032,208 10,683,710
Less accumulated depreciation, depletion and amortization............................ (4,090,293) (3,428,649)
----------------- ----------------
Net property and equipment................................................... 4,941,915 7,255,061
----------------- ----------------
Other assets:
Certificates of deposit.............................................................. 356,500 356,500
Deposits............................................................................. 2,789 2,789
----------------- ----------------
Total other assets........................................................... 359,289 359,289
----------------- ----------------
Total assets............................................................................. $ 9,168,827 $ 10,570,266
================= ================
-Continued-
The accompanying notes are an integral part of these consolidated financial statements
F-2
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2001 and 2000
-Continued-
2001 2000
----------------- ----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable..................................................................... $ 492,306 $ 598,926
Accrued liabilities.................................................................. 2,816,561 1,740,604
----------------- ----------------
Total current liabilities.................................................... 3,308,867 2,339,530
Long-term debt:
Note payable......................................................................... 4,906,916 --
----------------- ----------------
Total liabilities............................................................ 8,215,783 2,339,530
----------------- ----------------
Commitments (Note 7)
Stockholders' equity:
Preferred stock, $.001 par value, 5,000,000 shares authorized as of
December 31, 2001 and 2000; no shares outstanding................................ -- --
Common stock, $.001 par value, 100,000,000 shares authorized as of December 31,
2001 and 2000; 17,913,575 shares issued as of December 31, 2001 and 2000......... 17,914 17,914
Treasury stock, at cost, 285,340 and 233,340 shares as of December 31, 2001 and
2000, respectively............................................................... (909,815) (773,055)
Note receivable from stock option exercise........................................... -- (156,000)
Deferred compensation from stock option modifications................................ (54,688) (913,485)
Additional paid in capital........................................................... 49,910,078 49,655,675
Accumulated deficit.................................................................. (48,010,445) (39,600,313)
----------------- ----------------
Total stockholders' equity................................................... 953,044 8,230,736
----------------- ----------------
Total liabilities and stockholders' equity............................................... $ 9,168,827 $ 10,570,266
================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---------------- ----------------- ----------------
Revenues:
Oil and gas sales.................................................. $ 2,229,064 $ 2,520,779 $ 1,554,474
Oilfield services.................................................. 1,583,811 1,290,055 864,689
---------------- ----------------- ----------------
Total revenues................................................. 3,812,875 3,810,834 2,419,163
---------------- ----------------- ----------------
Operating costs and expenses:
Lease operating expenses........................................... 1,329,505 1,169,478 899,258
Production taxes................................................... 28,799 178,921 63,141
Geological and geophysical costs................................... 2,909,270 4,679,391 1,959,422
Exploratory dry hole costs......................................... 3,051,334 2,034,206 1,001,433
Impairment of oil and gas properties............................... 583,855 674,158 92,605
Oilfield services costs............................................ 1,300,713 1,084,129 641,871
Depreciation, depletion and amortization........................... 661,644 385,807 494,052
Amortization of deferred compensation (G&A)........................ 1,077,547 652,489 --
Apache Poland general and administrative costs..................... 575,303 956,936 --
Other general and administrative costs (G&A)....................... 882,985 2,654,430 2,961,878
---------------- ----------------- ----------------
Total operating costs and expenses............................. 12,400,955 14,469,945 8,113,660
---------------- ----------------- ----------------
Operating loss......................................................... (8,588,080) (10,659,111) (5,694,497)
---------------- ----------------- ----------------
Other income (expense):
Interest and other income.......................................... 542,824 557,080 511,636
Interest expense................................................... (330,816) (2,422) (7,997)
Impairment of notes receivable..................................... (34,060) (738,177) (665,512)
---------------- ----------------- ----------------
Total other income (expense)................................... 177,948 (183,519) (161,873)
---------------- ----------------- ----------------
Net loss............................................................... $ (8,410,132) $ (10,842,630) $ (5,856,370)
================ ================= ================
Basic and diluted net loss per share................................... $ (0.48) $ (.66) $ (.41)
================ ================= ================
Basic and diluted weighted average number of shares
outstanding........................................................ 17,672,684 16,435,436 14,198,724
================ ================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-4
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2001, 2000 and 1999
2001 2000 1999
---------------- ----------------- ----------------
Cash flows from operating activities:
Net loss........................................................... $ (8,410,132) $ (10,842,630) $ (5,856,370)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization................... 661,644 385,807 494,052
Impairment of oil and gas properties....................... 583,855 674,158 92,605
Impairment of notes receivable............................. 34,060 738,177 665,512
Accrued interest income from notes receivable.............. (14,820) (140,359) (134,295)
Gain on sale of property interests......................... (28,864) -- --
Exploratory dry hole costs................................. 3,051,334 2,034,206 1,001,433
Common stock and stock options issued for services......... 35,653 80,813 302,687
Amortization of deferred compensation (G&A)................ 1,077,547 652,489 --
Increase (decrease) from changes in working capital items:
Receivables.................................................... (101,280) 74,496 (100,044)
Inventory...................................................... 660 (21,559) 1,966
Other current assets........................................... (14,691) 45,693 (59,953)
Accounts payable and accrued liabilities....................... (122,696) 236,757 608,285
---------------- ----------------- ----------------
Net cash used in operating activities...................... (3,247,730) (6,081,952) (2,984,122)
---------------- ----------------- ----------------
Cash flows from investing activities:
Additions to oil and gas properties................................ (754,500) (6,988,314) (1,224,688)
Additions to other property and equipment.......................... (245,414) (812,340) (137,094)
Net change in other assets......................................... -- -- (2,789)
Proceeds from sale of property interests........................... 44,040 -- 6,000
Purchase of marketable debt securities............................. -- (6,314,990) (6,617,089)
Proceeds from marketable debt securities........................... 1,281,993 10,282,000 4,298,000
---------------- ----------------- ----------------
Net cash provided by (used) in investing activities............ 326,119 (3,833,644) (3,677,660)
---------------- ----------------- ----------------
Cash flows from financing activities:
Proceeds from loan and gas purchase option agreement............... 5,000,000 -- --
Notes receivable from officers..................................... -- -- (597,563)
Proceeds from issuance of common stock, net of offering costs...... -- 9,272,453 7,053,552
Proceeds from exercise of stock options and warrants............... -- 102,944 13,250
---------------- ----------------- ----------------
Net cash provided by financing activities...................... 5,000,000 9,375,397 6,469,239
---------------- ----------------- ----------------
Net increase or (decrease) in cash and cash equivalents................ 2,078,389 (540,199) (192,543)
Cash and cash equivalents at beginning of year......................... 1,079,038 1,619,237 1,811,780
---------------- ----------------- ----------------
Cash and cash equivalents at end of year............................... $ 3,157,427 $ 1,079,038 $ 1,619,237
================ ================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
For the years ended December 31, 2001, 2000 and 1999
Common Stock Notes and Notes Deferred
------------------- Interest Receivable Compensation
Par Value Receivable From Stock from Additional Total
Shares $.001 Per Treasury from Option Stock Option Paid in Accumulated Stockholders'
Issued Share Stock Officers Exercise Modifications Capital Deficit Equity
---------- ------- --------- ----------- ---------- ------------- ----------- ------------ ------------
December 31, 1998.......13,054,503 $13,055 $ -- $(1,304,527) $ -- $ -- $31,112,861 $(22,901,313)$ 6,920,076
Sale of common stock,
net of offering costs. 1,792,500 1,792 -- -- -- -- 7,051,760 -- 7,053,552
Exercise of stock
options and warrants.. 2,000 2 -- -- -- -- 13,248 -- 13,250
Advances to officers... -- -- -- (597,563) -- -- -- -- (597,563)
Interest on notes
receivable............ -- -- -- (134,295) -- -- -- -- (134,295)
Impairment of notes
receivable from
officers.............. -- -- -- 665,512 -- -- -- -- 665,512
Options issued for
services.............. -- -- -- -- -- -- 302,687 -- 302,687
Net loss for year...... -- -- -- -- -- -- -- (5,856,370) (5,856,370)
---------- ------- ----------- ------------------------------------- ------------ --------------------------
Balance as of
December 31, 1999......14,849,003 14,849 -- (1,370,873) -- -- 38,480,556 (28,757,683) 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.. 95,572 96 -- -- -- -- 258,848 -- 258,944
Interest on notes
receivable............ -- -- -- (140,359) -- -- -- -- (140,359)
Impairment of notes
receivable from
officers.............. -- -- -- 738,177 -- -- -- -- 738,177
233,340 shares tendered
for payment of notes
receivable and accrued
interest.............. -- -- (773,055) 773,055 -- -- -- -- --
Recourse note from
stock option exercise. -- -- -- -- (156,000) -- -- -- (156,000)
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...... -- -- -- -- -- -- -- (10,842,630) (10,842,630)
--------- ------- ----------- ------------------------------------- ------------ --------------------------
Balance as of
December 31, 2000......17,913,575 17,914 (773,055) -- (156,000) (913,485) 49,655,675 (39,600,313) 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 $(909,815) $ -- $ -- $ (54,688) $49,910,078 $(48,010,445)$ 953,044
========== ======= =========== ===================================== ============ =========================
The accompanying notes are an integral part of these consolidated financial statements
F-6
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
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 Apache Corporation
("Apache"). 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, 2001, 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. 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.
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, 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.
F-7
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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. 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. (Note 14)
Other Property and Equipment
Other property and equipment, including oilfield servicing equipment, are 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
before accumulated depreciation, is summarized as follows:
December 31, Estimated
---------------------------- Useful Life
2001 2000 (in years)
------------- ------------- -------------
(In thousands)
Other property and equipment:
Oilfield servicing equipment................................... $ 2,730 $ 2,509 6
Trucks......................................................... 262 236 5
Building....................................................... 96 95 40
Office equipment and furniture................................. 499 494 3 to 6
------------- -------------
Total.......................................................$ 3,587 $ 3,334
============= =============
Supplemental Disclosure of Cash Flow Information
Non-cash investing and financing transactions not reflected in the consolidated
statements of cash flows include the following:
Year Ended December 31,
-----------------------------------
2001 2000 1999
---------- ----------- -----------
(In thousands)
Non-cash investing transactions:
Additions to properties included in current liabilities................ $ 999 $ -- $ 63
Non-cash consideration received from the sale of equipment............. -- 23 --
---------- ----------- -----------
Total.............................................................. $ 999 $ 23 $ 63
========== =========== ===========
Non-cash financing transactions:
Shares tendered for payment of notes receivable and accrued interest... $ 137 $ 773 $ --
Recourse note receivable from stock option exercise.................... -- 156 --
---------- ----------- -----------
Total.............................................................. $ 137 $ 929 $ --
========== =========== ===========
Supplemental disclosure of cash paid for interest and income taxes:
Year Ended December 31,
-----------------------------------
2001 2000 1999
---------- ----------- -----------
(In thousands)
Supplemental disclosure:
Cash paid during the year for interest................................ $ 2 $ 2 $ 8
Cash paid during the year for income taxes............................ -- -- --
F-8
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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."
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 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.
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, 2001, 2000 and 1999 were as
follows:
Options and
Warrants Price Range
----------- ----------------
Balance sheet date:
December 31, 2001................... 5,885,585 $1.50 - $10.25
December 31, 2000................... 4,572,917 $1.50 - $10.25
December 31, 1999................... 4,167,073 $1.50 - $10.25
The Company had a net loss in 2001, 2000 and 1999. The above options and
warrants were not included in the computation of diluted earnings per share for
2001, 2000 or 1999 because the effect would have been antidilutive.
F-9
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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 $48.0 million at
December 31, 2001. 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 the date of this report, the Company
did not have a commitment from a third party to provide any additional funding
for its ongoing operations.
As of December 31, 2001, the Company had $3,157,427 of cash and cash
equivalents, working capital of $558,756 and long term debt with a principal
amount of $5.0 million due on or before March 9, 2003. The Company believes that
its cash position, along with positive cash flow generated from its United
States E&P and United States oilfield services segments, will be sufficient to
cover the Company's minimum operating commitments during 2002, excluding
$2,678,477 of accrued costs pertaining to its Fences project area in Poland.
During 2002, management hopes to enter into a farm-out arrangement with an
industry partner under which the partner will pay the $2,678,477 of accrued
costs, in addition to the remaining $6,632,091 of the Company's $16 million work
commitment that has yet to be incurred. There is no assurance that the Company
will be able to successfully complete such a farm-out . In addition, in order to
sustain positive cash balances without raising additional capital in 2002,
overhead costs will have to be reduced substantially.
On March 9, 2001, the Company signed a $5.0 million, 9.5% loan agreement and gas
purchase option agreement with Rolls Royce Power Ventures ("RRPV"), which is due
on or before March 9, 2003, unless before March 9, 2003 RRPV elects to convert
the loan to restricted common stock at $5.00 per share. The loan was interest
free for the first year. RRPV did not exercise its option to purchase gas from
the Company's Polish properties. Unless RRPV elects to convert the loan to
restricted common stock at $5.00 per share prior to March 9, 2003, the Company
must raise additional capital to pay off the principal amount of the loan plus
accrued interest. As collateral for the loan, the Company granted RRPV a lien on
most of its Polish property interests.
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. 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 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." At December 31, 2000, the Company's
marketable debt securities were classified as available for sale, consisted of
corporate bonds with remaining contractual maturities of less than twelve
months, and had a carrying amount that approximated market value.
F-10
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 4: Performance Bond Deposits
As of December 31, 2001 and 2000, 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, 2001 and 2000 were composed
of the following:
December 31,
----------------------------
2001 2000
------------- -------------
(In thousands)
Accrued liabilities:
Compensation costs................... $ -- $ 1,388
Contractual bonus.................... -- 300
Exploratory dry hole costs........... 880 --
Seismic costs........................ 1,798 --
Other costs.......................... 139 53
------------- -------------
Total............................ $ 2,817 $ 1,741
============= =============
Effective December 31, 2001, the Company's employees waived their entitlements
to all unpaid compensation and contractual bonus costs as of that date in an
effort to conserve the Company's capital. Accordingly, there are no outstanding
accrued compensation or accrued contractual bonus amounts as of December 31,
2001.
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 Rolls Royce Power Ventures ("RRPV"). The proceeds
from the loan are to be 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, 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.
As of December 31, 2001, the Company had received $5.0 million from RRPV under
this arrangement. 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 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.
Note 7: Commitments
Fences 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 300,000 gross acres
in west central Poland (the "Fences" project area) by spending $16.0 million for
agreed drilling, seismic acquisition and other related activities.
F-11
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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 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.
Apache Exploration Program
The Apache Exploration Program consists of various agreements signed between the
Company and Apache during 1997 through 2001. 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.
Employment Agreements
Effective January 1, 1995, the Company entered into three-year employment
agreements with David N. Pierce and Andrew W. Pierce, each of whom is an officer
and director. In the event of termination of employment resulting from a change
in control of the Company not approved by the Board of Directors, each of the
two officers would be entitled to a termination payment equal to 150% of his
annual salary at the time of termination and the value of previously granted
employee benefits, including stock options and stock awards. The terms of such
employment agreements are automatically extended for an additional year on the
anniversary date of each such agreement.
On July 1, 1996, the Company entered into a three-year employment agreement with
Jerzy B. Maciolek, an officer of the Company. In the event the employment
contract is terminated by the Company, other than for cause, or by Mr. Maciolek
for cause or because of a change in control of the Company, Mr. Maciolek is
entitled to a termination payment equal to any accrued but unpaid salary,
unreimbursed expenses, benefits, and his salary for the remaining term of the
employment agreement. Additionally, all options held by Mr. Maciolek shall
immediately vest and not be forfeited. The employment agreement is automatically
extended for an additional one year upon each anniversary date of the effective
date unless otherwise terminated pursuant to the terms thereof.
Note 8: Income Taxes
The Company recognized no income tax benefit from the losses generated during
2001, 2000 and 1999. The components of the net deferred tax asset as of December
31, 2001 and 2000 are as follows:
December 31,
----------------------------
2001 2000
------------- -------------
(In thousands)
Deferred tax liability:
Property and equipment basis differences...................................... $ (349) $ (213)
Deferred tax asset:
Net operating loss carryforwards:
United States............................................................. 12,174 11,340
Poland.................................................................... 3,893 2,771
Oil and gas properties........................................................ 1,218 1,218
Impairment of notes receivable from officers.................................. -- 523
Options issued for services................................................... 143 143
Other......................................................................... 10 331
Valuation allowance........................................................... (17,089) (16,113)
------------- -------------
Total..................................................................... $ -- $ --
============= =============
F-12
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The change in the valuation allowance during 2001, 2000 and 1999 is as follows:
Year Ended December 31,
-------------------------------------------
2001 2000 1999
------------- ------------- -------------
(In thousands)
Valuation allowance:
Balance, beginning of year..................................... $ (16,113) $ (12,848) $ (10,685)
Decrease due to property and equipment basis differences....... 136 109 4
Increase due to net operating loss............................. (1,956) (2,931) (1,989)
Other.......................................................... 844 (443) (178)
------------- ------------- -------------
Total...................................................... $ (17,089) $ (16,113) $ (12,848)
============= ============= =============
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, 2001 and 2000.
United States NOL
At December 31, 2001, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $32,637,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and 13,888,000 expires subsequent to 2017. 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, 2001, the Company had NOL carryforwards in Poland totaling
approximately $10,438,340, including $1,925,220 $5,734,913 and $2,778,207
generated in 2001, 2000 and 1999, respectively. The NOL carryforwards may be
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.
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 December 31, 2001, all prior year Stock Option and Award
Plans had issued the maximum allowed options, except for the Company's 2000
Stock Option and Award Plan, which had outstanding options to purchase 412,585
shares out of a maximum total of 600,000 authorized shares. As of December 31,
2001, The Company has submitted the 2001 Stock Option and Award Plan, which
includes a maximum of 600,000 options, for shareholder approval at the 2002
annual shareholders' meeting. As of the date of this report, no options had been
issued under the 2001 Stock Option and Award Plan.
F-13
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The following table summarizes information regarding the Company's stock option
and award plans as of December 31, 2001:
Weighted
Average Number of
Number of Exercise Shares
Shares Price of Available
Authorized Outstanding for Future
Under Plan Shares Issuance
------------- --------------- -------------
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 --
1997 Stock Option and Award Plan............................... 500,000 7.79 --
1998 Stock Option and Award Plan............................... 500,000 6.46 --
1999 Stock Option and Award Plan............................... 500,000 4.40 --
2000 Stock Option and Award Plan................................ 600,000 2.44 187,415
------------- --------------- -------------
Total......................................................... 3,100,000 $ 6.09 187,415
============= =============== =============
Equity compensation plans presented for approval by shareholders:
2001 Stock Option and Award Plan................................ 600,000 $ -- 600,000
------------- --------------- -------------
Total......................................................... 600,000 $ -- 600,000
============= =============== =============
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.
As of December 31, 2001, the Company had 5,785,585 options outstanding under the
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:
2001 2000 1999
------------- ------------- -------------
(In thousands, except per share amounts)
Net loss:
As reported................................................... $ (8,410) $ (10,843) $ (5,856)
Pro forma..................................................... (9,925) (12,733) (7,930)
Basic and diluted net loss per share:
As reported................................................... $ (0.48) $ (0.66) $ (0.41)
Pro forma..................................................... (0.56) (0.77) (0.56)
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 2001,
2000 and 1999 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 78.1% to 82.7% for 2001,
79.8% to 86.6% for 2000 and 80.5% for 1999; (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.
F-14
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The following table summarizes fixed option activity for 2001, 2000 and 1999:
2001 2000 1999
-------------------------- ------------------------ -------------------------
Weighted Weighted Weighted
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Shares Price Shares Price Shares Price
------------- ----------- ----------- ----------- ------------ -----------
Fixed Options Outstanding:
Beginning of year......... 4,322,917 $ 5.15 3,896,501 $ 5.25 3,413,667 $ 5.18
Granted................... 501,750 2.44 501,750 4.06 521,000 5.87
Exercised................. -- -- (75,000) 3.00 (2,000) 6.63
Canceled.................. (33,082) 5.00 (334) 8.63 (36,166) 7.92
Expired................... (6,000) 5.75 -- -- -- --
------------- ----------- ------------
End of year........... 4,785,585 $ 4.87 4,322,917 $ 5.15 3,896,501 $ 5.25
============= =========== ============
Exercisable at year-end....... 3,669,356 $ 5.28 2,744,183 $ 5.61 2,872,681 $ 4.66
============= =========== ============
The weighted average fair value per share of options granted during 2001, 2000
and 1999 was $1.16, $2.56 and $3.61, respectively. The above table excludes
RRPV's option to purchase 1,000,000 shares of stock as described in Note 6.
The following table summarizes information about fixed stock options outstanding
as of December 31, 2001:
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
-------------------------------------- -------------------- --------------- -------------- ---------------
$1.50 - $3.00......... 2,298,750 5.24 $ 2.76 1,678,000 $ 2.84
$4.06 - $6.75......... 1,366,169 4.64 5.41 880,690 5.84
$7.25 - $10.25........ 1,120,666 2.85 8.52 1,110,666 8.53
--------------- -------------------- --------------- -------------- ---------------
Total.......... 4,785,585 4.22 $ 4.87 3,669,356 $ 5.28
=============== ==================== =============== ============== ===============
The above table excludes RRPV's option to purchase 1,000,000 shares of stock as
described in Note 6.
Warrants
The following table summarizes changes in outstanding and exercisable warrants
during 2001, 2000 and 1999:
2001 2000 1999
--------------------------- --------------------------- ---------------------------
Number of Price Number of Price Number of Price
Shares Range Shares Range Shares Range
------------ -------------- ------------ -------------- ------------ --------------
Warrants outstanding:
Beginning of year... 250,000 $3.00 - $6.90 270,572 $1.65 - $6.90 270,572 $1.65 - $6.90
Exercised........... -- -- (20,572) 1.65 -- --
Expired............. (150,000) $ 6.90 -- -- -- --
-------- ------- -------
End of year....... 100,000 $ 3.00 250,000 $3.00 - $6.90 270,572 $1.65 - $6.90
======== ======= =======
The 100,000 warrants outstanding as of December 31, 2001 are scheduled to expire
on August 3, 2002.
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
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.
F-15
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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.
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 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. The carrying value of the notes receivable from officers
was $773,055 as of December 28, 2000, including principal of $1,837,920 and
accrued interest of $338,824, which was reduced by an impairment allowance of
$1,403,689 based on the market value of 233,340 shares of the Company's common
stock held as collateral. 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 recorded 233,340 shares of treasury
stock at a cost of $773,055.
Note 12: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2001 and 2000 is as follows:
Quarter Ended
---------------------------------------------------------------------------
December 31 September 30 June 30 March 31
----------------- ----------------- ------------------ ------------------
(In thousands, except per share amounts)
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)
2000:
Revenues....................... $ 965 $ 1,251 $ 925 $ 670
Net operating loss............. (3,646) (3,370) (2,778) (865)
Net loss....................... (3,548) (3,788) (2,771) (736)
Basic and diluted net loss per
common share................. $ (.22) $ (.21) $ (.18) $ (.05)
F-16
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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. During 2001, 2000 and 1999, over 85.0% of the Company's
oil sales in the United States were to one purchaser located in Montana. During
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 and 1999. 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), 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.
Information on the Company's operations by business segment for 2001, 2000 and
1999 is summarized as follows:
2001
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
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
============= ============= =============
- ---------------------
(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 $531,000 of unproved property additions.
F-17
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
2000
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues........................................................$ 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
============= ============= =============
- ----------------------
(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 $2,323,000 of
unproved property additions.
1999
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues........................................................$ 1,554 $ 865 $ 2,419
Cash operating costs (1)........................................ (3,500) (642) (4,142)
Non-cash operating costs (2).................................... (484) -- (484)
------------- ------------- -------------
Operating income or (loss) before DD&A expense.............. (2,430) 223 (2,207)
DD&A expense.................................................... (51) (334) (385)
------------- ------------- -------------
Operating loss..................................................$ (2,481) $ (111) $ (2,592)
============= ============= =============
Identifiable net property and equipment:
Unproved properties - Poland...................................$ 691 $ -- $ 691
Unproved properties - Domestic.................................. 692 -- 692
Proved properties - Domestic.................................... 494 -- 494
Equipment and other............................................. -- 581 581
------------- ------------- -------------
Total.......................................................$ 1,877 $ 581 $ 2,458
============= ============= =============
Net Capital Expenditures:
Property and equipment (3)......................................$ 1,386 $ 138 $ 1,524
------------- ------------- -------------
Total.......................................................$ 1,386 $ 138 $ 1,524
============= ============= =============
- ------------------------
(1) Excludes $31,000 of exploratory costs relating to the Company's gold
concessions in Poland, which is a discontinued segment.
(2) E&P includes stock options valued at $119,000 issued to a Polish
citizen for consulting services, accrued bonuses of $344,000 and
$21,000 non-producing leasehold impairment comprised of costs incurred
prior to 1999.
(3) E&P includes $1,073,000 of costs that were reclassed to expense,
including $1,001,000 of exploratory dry hole costs and $72,000 of
non-producing property impairments, and, $81,000 of proved property
additions and $232,000 of unproved property additions.
F-18
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
A reconciliation of the segment information to the consolidated totals for 2001,
2000 and 1999 follows:
2001 2000 1999
------------- ------------- -------------
(In thousands)
Revenues:
Reportable segments...............................................$ 3,813 $ 3,811 $ 2,419
Non-reportable segments........................................... -- -- --
------------- ------------- -------------
Total revenues...................................................$ 3,813 $ 3,811 $ 2,419
============= ============= =============
Operating loss:
Reportable segments...............................................$ (6,595) $ (7,286) $ (2,592)
Expense or (revenue) adjustments:
Non-reportable segments......................................... -- -- (31)
Corporate DD&A expense.......................................... (32) (66) (109)
Amortization of deferred compensation (G&A)..................... (1,078) (652) --
General and administrative expenses............................. (883) (2,654) (2,962)
Other........................................................... -- (1) --
------------- ------------- -------------
Total net operating loss......................................$ (8,588) $ (10,659) $ (5,694)
============= ============= =============
Net property and equipment:
Reportable segments...............................................$ 4,842 $ 7,129 $ 2,458
Corporate assets.................................................. 100 126 91
------------- ------------- -------------
Net property and equipment.......................................$ 4,942 $ 7,255 $ 2,549
============= ============= =============
Property and equipment capital expenditures:
Reportable segments...............................................$ 1,993 $ 7,768 $ 1,524
Corporate assets.................................................. 6 33 19
------------- ------------- -------------
Net property and equipment capital expenditures..................$ 1,999 $ 7,801 $ 1,543
============= ============= =============
Note 14: Disclosure about Oil and Gas Properties and Producing Activities
Capitalized Oil and Gas Property Costs
Capitalized costs relating to oil and gas exploration and production activities
as of December 31, 2001 and 2000 are summarized as follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
December 31, 2001:
Proved properties..........................................$ 2,208 $ 2,581 $ 4,789
Unproved properties........................................ 8 648 656
--------------- --------------- ---------------
Total gross properties................................... 2,216 3,229 5445
Less accumulated depreciation, depletion and amortization.. (1,331) (257) (1,588)
--------------- --------------- ---------------
Total...............................................$ 885 $ 2,972 $ 3,857
=============== =============== ===============
December 31, 2000:
Proved properties..........................................$ 1,889 $ 2,429 $ 4,318
Unproved properties........................................ 18 3,014 3,032
--------------- --------------- ---------------
Total gross properties................................... 1,907 5,443 7,350
Less accumulated depreciation, depletion and amortization.. (1,266) -- (1,266)
--------------- --------------- ---------------
Total...............................................$ 641 $ 5,443 $ 6,084
=============== =============== ===============
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 2001, 2000 and 1999 were
$1,358,304, $1,348,399 and $962,399, respectively.
F-19
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities
during 2001, 2000 and 1999, whether capitalized or expensed, are summarized as
follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
Year ended December 31, 2001:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
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
=============== =============== ===============
Year ended December 31, 1999:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
Unproved............................................... 1 230 231
Exploration costs.......................................... 38 3,016 3,054
Development costs.......................................... 82 -- 82
--------------- --------------- ---------------
Total..................................................$ 121 $ 3,246 $ 3,367
=============== =============== ===============
- --------------------
(1) Includes $2,429,000 relating to the Kleka 11, which was categorized as
proved property as of December 31, 2000.
Impairment of Unproved Oil and Gas Properties
During 2001, the Company recorded an impairment expense of $583,855 for areas in
Poland where it has no further exploration plans ($525,355 for the Baltic
project area and $58,500 for the Warsaw West project area). During 2000, the
Company recorded an impairment expense of $674,158 relating to the Williston
Basin in North Dakota, where it also has no further exploration plans. During
1999, the Company recorded an impairment expense of $93,000.
Exploratory dry hole costs
During 2001, for financial reporting purposes, the Company classified the
Mieszkow 1 as an exploratory dry hole. The Company recorded exploratory dry hole
costs of $3,051,871 pertaining to the Mieszkow 1, including cash expenditures of
$2,171,750 and accrued costs of $880,121. Since April 2001, drilling operations
on the Mieszkow 1 have been suspended pending the reprocessing and
interpretation of 3-D seismic in order to evaluate the continuation of drilling
operations.
Sale of Partial Property Interest
During 2001, the Company sold a 100% working interest in its Ryckman Creek
prospect located in Wyoming for $44,040 and retained a 2% over-riding royalty
interest. The Company recognized a gain of $28,864 on the transaction, which was
recorded as other income.
F-20
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, 2001 of $12.66 per bbl for oil in the
United States, $17.00 for oil in Poland and $1.85 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, and 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:
Crude Oil Natural Gas
-------------------------------- --------------------------------
United States Poland United States Poland
--------------- --------------- --------------- ---------------
(in thousand barrels of oil) (In millions of cubic feet)
Proved Developed Reserves:
December 31, 2001........................ 1,075 -- -- 2,167
December 31, 2000........................ 1,161 -- -- --
December 31, 1999........................ 1,080 -- -- --
F-21
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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)
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
=============== =============== =============== ===============
December 31, 1999:
Beginning of year...................... 1,535 -- -- --
Revisions of previous estimates........ (354) -- -- --
Production............................. (101) -- -- --
--------------- --------------- --------------- --------------
End of year........................ 1,080 -- -- --
=============== =============== =============== ===============
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.
F-22
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The components of SMOG are detailed below:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
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
=============== =============== ===============
December 31, 1999:
Future cash flows..........................................$ 24,229 $ -- $ 24,229
Future production costs.................................... (15,240) -- (15,240)
Future development costs................................... (105) -- (105)
Future income tax expense.................................. -- -- --
--------------- --------------- ---------------
Future net cash flows ..................................... 8,884 -- 8,884
10% annual discount for estimated timing of cash flows..... (3,424) -- (3,424)
--------------- --------------- ---------------
Discounted net future cash flows...........................$ 5,460 $ -- $ 5,460
=============== =============== ===============
The principal sources of changes in SMOG are detailed below:
Year Ended December 31,
-------------------------------------------
2001 2000 1999
------------- ------------- -------------
(In thousands)
SMOG sources:
Balance, beginning of year......................................$ 7,420 $ 5,460 $ 472
Sale of oil and gas produced, net of production costs........... (871) (1,172) (592)
Net changes in prices and production costs...................... (2,241) (159) 5,032
Extensions and discoveries, net of future costs................. 1,330 2,511 --
Changes in estimated future development costs................... (686) (53) (6)
Previously estimated development costs incurred during
the year.................................................... 321 202 82
Revisions in previous quantity estimates........................ 59 (31) (1,650)
Accretion of discount........................................... 742 546 47
Net change in income taxes...................................... -- -- --
Changes in rates of production and other........................ (488) 116 2,075
------------- ------------- -------------
Balance, end of year........................................$ 5,586 $ 7,420 $ 5,460
============= ============= =============
Note 16: New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (FASB) issued Statements
of Financial Accounting Standards ("SFAS") No. 141 "Business Combinations" and
SFAS No. 142 "Goodwill and Other Intangible Assets." Under SFAS No. 141, the
purchase method of accounting must be used for business combinations initiated
after June 30, 2001. Under SFAS No. 142 (effective for the Company beginning
January 1, 2002) goodwill and certain intangibles are no longer amortized but
F-23
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
will be subject to annual impairment tests. The adoption of these new standards
did not have a significant impact on the Company's financial statements.
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 August 2001, the FASB issued SFAS No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS No. 144 is effective for fiscal years
beginning after December 15, 2001, and interim periods within those fiscal
years. The Company adopted this statement on January 1, 2002. This statement
addresses financial accounting and reporting for the impairment or disposal of
long-lived assets. Although SFAS No. 144 supersedes SFAS No. 121 "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," it retains the fundamental provisions of SFAS No. 121 for the recognition
and measurement of the impairment for long-lived assets. The adoption of this
new standard did not have a significant impact on the Company's financial
statements.
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.
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