Back to GetFilings.com
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, 2000
Commission File Number: 0-25386
FX ENERGY, INC.
(Exact name of registrant as specified in its charter)
Nevada 87-0504461
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206, Salt Lake City, Utah 84106
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: Telephone (801) 486-5555
Telecopy (801) 486-5575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, Par Value $0.001
Preferred Stock Purchase Rights
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers in response
to Item 405 of Regulation S-K 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 15, 2001, the aggregate
market value of the voting and nonvoting common equity held by nonaffiliates of
the registrant was $89,217,000.
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 9, 2001,
FX Energy had outstanding 17,680,235 shares of its common stock, par value
$0.001.
DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy Statement in
connection with the 2001 Annual Meeting of Stockholders is incorporated by
reference in response to Part III of this Annual Report.
- --------------------------------------------------------------------------------
FX ENERGY, INC.
Form 10-K for the fiscal year ended December 31, 2000
- --------------------------------------------------------------------------------
Table of Contents
Item Page
- ----------- ------
Part I
-- Special Note on Forward-Looking Statements.................... 1
1. and 2. Business and Properties....................................... 2
3. Legal Proceedings............................................. 28
4. Submission of Matters to a Vote of Security Holders........... 28
Part II
5. Market for Common Equity and Related Stockholder Matters...... 29
6. Selected Consolidated Financial Data.......................... 30
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 32
7A. Qualitative and Quantitative Disclosure about Market Risk..... 40
8. Financial Statements and Supplementary Data................... 40
9. Changes and Disagreements with Accountants on Accounting
and Financial Disclosure................................. 40
Part III
10. Directors and Officers of Registrant.......................... 41
11. Executive Compensation........................................ 41
12. Security Ownership of Certain Beneficial Owners
and Management........................................... 41
13. Certain Relationships and Related Transactions................ 41
Part IV
14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K................................................. 42
-- Signature Page................................................ 49
-- Report of Independent Accountants............................ F-1
- --------------------------------------------------------------------------------
SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS
- --------------------------------------------------------------------------------
This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "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 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 future events that may result in the need for additional
capital;
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 future drilling and other exploration schedules and sequences
for various wells and other activities;
o uncertainties regarding future political, economic,
regulatory, fiscal, taxation and other policies in Poland;
o the cost of additional capital that we may require and
possible related restrictions on our future operating or
financing flexibility;
o our future ability to attract strategic partners to share the
costs of exploration, exploitation, development and
acquisition activities; and
o future plans and the financial and technical resources of
strategic partners.
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
- --------------------------------------------------------------------------------
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
- --------------------------------------------------------------------------------
Introduction
We are an independent oil and gas company focused on exploration,
development and production opportunities in the Republic of Poland. With the
help of our partners, we were the first western company to discover and produce
gas in Poland. We also hold rights to more oil and gas exploration acreage in
Poland than any other western company. Our ongoing activities are conducted
under strategic alliances with the Polish Oil and Gas Company, or POGC, and/or
Apache Corporation. These alliances allow us to utilize the operating and
technical personnel of those companies, gain access to geological and
geophysical data, manage our exploration risk and obtain other necessary support
in Poland.
We conduct exploration and development activities with our partner,
POGC, in the Fences project area in western Poland under an agreement signed in
2000, whereby we will earn a 49.0% interest by spending $16.0 million of
exploration costs to balance expenditures already made by POGC. In and near the
Fences project area, POGC has developed and refined two exploration models: one
model has resulted in four gas fields in the Rotliegendes trend associated with
the Poznan Depression in the Fences project area; the other model has resulted
in six gas fields in the Zechstein Reef trend associated with the Wolsztyn Block
immediately west of the Fences project area. All of these fields were developed
by POGC before our agreement started. Now, we are applying these two exploration
models to test several structures defined by 3-D seismic on those portions of
the Rotliegendes and Zechstein Reef trends located in the Fences project area.
The Kleka 11, our first exploratory well in the Fences project area,
discovered the Kleka East field and brings the number of fields in the
Rotliegendes trend to five. The Kleka 11 commenced producing in February 2001
and is currently producing at a rate of approximately 4 Mmcf per day into the
main POGC gas grid. The next exploratory well, the Mieszkow 1, reached planned
total depth structurally low to prognosis and is currently being sidetracked and
directionally drilled to a new bottom hole location. We anticipate following the
Mieszkow 1 with a development well in the same structure, if warranted, or with
exploratory wells based on the Zaniemysl or Donatowo 3-D seismic grids, which
are expected to be available for drill site selection in the second quarter of
2001.
We also conduct oil and gas exploration activities with Apache in four
project areas in Poland, which we refer to as the Apache Exploration Program.
During 2000, we and Apache completed a 2-D seismic data acquisition program
covering approximately 328 kilometers and drilled an exploratory well, the
Tuchola 108-2, in the Pomeranian project area. During January 2001, the Tuchola
108-2 tested at 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 test was
limited by the capacity of the surface equipment. The Tuchola 108-2 is currently
being completed.
Our immediate goal in the Apache Exploration Program is to determine
whether a trend of commercially productive Main Dolomite Reef fields exists in
the Pomeranian project area similar to the Main Dolomite Reef trend that
produces from a number of fields on the southern side of Poland's Permian Basin.
Accordingly, we will move the rig that drilled the Tuchola 108-2 to a location
(the Chojnice 108-6) three kilometers northwest of the Tuchola 108-2, where we
will test a Main Dolomite Reef target at a depth of approximately 2,500 meters.
We have also started a 2-D seismic acquisition program covering approximately
280 kilometers during the first half of 2001 to confirm a number of Main
Dolomite Reef leads that appear to be on trend with the Tuchola 108-2 discovery.
Under terms of the Apache Exploration Program, Apache will cover our 42.5% share
of costs to drill the Tuchola 108-2 and Chojnice 108-6 exploratory wells. We
will be responsible for our share of all further costs on the Pomeranian project
area.
2
During the balance of 2001, we expect to continue acquiring seismic and
drilling wells in the Fences project area with POGC and the Pomeranian project
area with Apache and POGC, in each case seeking to capitalize on successes in
identified geological trends. We also expect to advance our discussions with
POGC concerning the possible acquisition of an interest in producing properties.
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 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 are as follows:
Focus on Poland
We believe Poland is an attractive oil and gas exploration and
production opportunity because of its known productive basins, its limited oil
and gas exploration and development 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 3-D seismic-based exploration models that have been
refined since the mid-1990s in the Rotliegendes and Zechstein Reef trends in
western Poland. We are using these models to explore and develop the
Rotliegendes and Zechstein Reef trends in our Fences project area without
incurring the cost of developing those models. In addition, we believe the
Fences project area is well suited to debt funding. Accordingly, we are seeking
capital from power development companies, banks and other lenders to fund the
majority of development costs in the Fences project area. The recent Tuchola
108-2 discovery in the Main Dolomite Reef formation, if confirmed by additional
seismic and drilling, may give us a third such trend where we can apply mature
exploration models and where the criteria for project financing may be reached
at a relatively early stage. It also represents the successful use of financial
leverage directly resulting from Apache covering our share of costs for initial
exploratory wells under the Apache Exploration Program.
Reduce our Exploration Risk Profile
Historically, we have managed exploration risk by limiting capital
exposure. Now, we are also managing 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 POGC 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 Relationships
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
has granted us and Apache each the right to earn up to a one-third interest in
POGC-controlled acreage near our Lublin, Pomeranian and Carpathian project
areas. In turn, we and Apache have granted POGC an option to earn up to a
one-third interest in our Lublin, Pomeranian and Carpathian project areas. As
previously indicated, we signed an agreement during 2000 to participate with
POGC in the Fences project area, where POGC is the operator. In addition, we
have made proposals to participate in additional appraisal, development
3
or exploration projects with POGC. We believe that our relationship with POGC
will provide additional opportunities in Poland.
Apache Corporation
Apache is a leading independent exploration and production company
based in the United States with extensive operations in the United States,
Canada, Australia, Egypt, Poland and China. We and Apache have joint operating
agreements on our Pomeranian, Warsaw West, Lublin and Carpathian project areas
with Apache as operator. Apache does not participate in our Fences or Baltic
project areas. Under the terms of the Apache Exploration Program, Apache has
covered our share of the costs to drill the equivalent of nine exploratory wells
and to acquire over 1,661 kilometers of 2-D seismic data to date. During 2001,
Apache will cover our share of costs to drill the Chojnice 108-6, the tenth and
final carried exploratory well in Poland.
Rolls Royce Power Ventures
In March 2001, we signed an agreement with Rolls-Royce Power Ventures
Limited, or RRPV, London, England, that provides RRPV with an option on gas
supplies from our wells in Poland. The gas will be used to support the
development of a planned RRPV power project in Poland. While our agreement with
RRPV covers only a single planned power project, it is possible this arrangement
may grow to include other projects and expand into a strategic relationship.
Under the agreement, RRPV is providing us with $5.0 million to be used for
exploration and development of gas reserves in Poland. We do not expect RRPV to
require gas until 2002 or later. In the interim, we expect to sell our Polish
gas production to POGC under our existing gas sales agreement.
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, 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.
For the purposes of presenting information in this report, all gross
and net well and acreage positions in Poland assume the following:
o POGC does not exercise its rights to participate in the
portions of the areas controlled by us and Apache, except
where it has elected to participate with the interest
indicated prior to the date of this report; and
o We and Apache each will exercise our respective options to
participate in POGC-controlled acreage at 33.3% each.
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.
The Republic of Poland
The Republic of Poland, with a population of approximately 39 million
people, peacefully asserted its independence in 1989 and adopted a new
constitution that established 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 that is currently one of the
fastest growing in eastern Europe, with annual growth rates of approximately 5%
and estimated annual inflation rates ranging from 7.4% and 9.5% between 1998 and
2000.
Poland's international trade has also undergone significant progress.
Since 1989, Poland's economic ties have turned 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,
4
generating over one third of the country's total investment and acting as a
powerful restraint on unemployment. According to the Polish Foreign Investment
Agency, or PAIZ, cumulative foreign direct investment flows into Poland is
estimated to have aggregated approximately $43.0 billion through mid-2000,
including approximately $3.7 billion during the first half of 2000.
Since its relatively recent transition to a market economy and a
parliamentary democracy, Poland is continuing to experience significant economic
growth and political changes. Poland has developed and is refining legal 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.
Poland's legal framework and fiscal regime for oil and gas exploration
and production are attractive, as Poland has actively encouraged investment by
foreign companies to offset its own lack of sufficient capital to further
explore and develop the country's oil and gas resources. In July 1995, Poland's
Council of Ministers approved a program to restructure and privatize the Polish
petroleum sector. Under this plan, the Plock refinery has been privatized as a
publicly held company whose stock trades 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 1995, the Polish corporate income tax rate has been reduced 2%
per year to 30% for 2000 and 28% for 2001. Further reductions in the income tax
rate of 2% per year may be enacted down to a rate of 22%. Additional tax relief
may be available for certain qualifying capital investments that provide
deductions during the initial years of operation under certain circumstances.
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. In the early 1990s, the World Bank lent Poland $250 million, drawn
down over five years, to fund the purchase of new exploration and drilling
equipment. Poland currently has estimated oil reserves of approximately 115.0
MMBbls of oil and imports, approximately 98% of its annual oil consumption
needs, primarily from countries of the former Soviet Union and the Middle East.
Poland also currently has estimated gas reserves of approximately 5.0 Tcf and
imports approximately more than 70% of its annual gas consumption needs,
primarily from countries of the former Soviet Union. Poland is about the size of
New Mexico and contains approximately 77.3 million acres. As of the date of this
report, we had exploration rights to approximately 14.4 million of those acres.
During 1999, Poland joined NATO and has 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. Currently, coal is the dominant
energy source, accounting for 94% of energy production and 65% of energy usage
in Poland as recently as 1998. Increased consumption of natural gas, as an
alternative to coal, is considered to be a key component in meeting the European
Union's strict environmental guidelines for its members. The demand for gas in
Poland is expected to double over the next ten years, primarily due to increased
economic growth and 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 by POGC.
5
Exploration, Development and Production Activities in Poland
Polish Exploration Rights
As of December 31, 2000, our oil and gas exploration rights in Poland
were comprised of the following gross acreage components:
POGC-Controlled Areas (1)
FX Energy ----------------------------------- Total Gross
Concessions (1) Concessions Exclusive Acreage
---------------- ----------------- ---------------- -----------------
(Rounded to the nearest 100,000 acre)
Project Area:
Fences (2)...................... -- 300,000 -- 300,000
Apache Exploration Program (3)
Lublin Basin.................. 3,300,000 600,000 -- 3,900,000
Carpathian.................... 1,400,000 200,000 1,300,000 2,900,000
Pomeranian.................... 2,200,000 -- 1,300,000 3,500,000
Warsaw West................... 2,900,000 -- -- 2,900,000
---------------- ----------------- ---------------- -----------------
Total....................... 9,800,000 800,000 2,600,000 13,200,000
---------------- ----------------- ---------------- -----------------
Baltic Project Area (4)......... 900,000 -- -- 900,000
---------------- ----------------- ---------------- -----------------
Total gross acreage........... 10,700,000 1,100,000 2,600,000 14,400,000
================ ================= ================ =================
- --------------------------
(1) In the Apache Exploration Program, POGC-controlled areas
include approximately 0.8 million acres of existing POGC
Concessions and approximately 2.6 million acres for which POGC
has been granted the exclusive right to obtain concessions by
the government of Poland. We and Apache each have separate
options to participate in the exploration of POGC-controlled
areas, with up to a one-third interest each. In turn, POGC has
an option to participate with up to a one-third interest,
determined on a block-by-block basis, in the exploration of
the FX Energy Concession portion of the respective areas. The
Warsaw West and the Baltic project areas are not subject to
POGC options.
(2) On April 11, 2000, we entered into an agreement with POGC to
earn a 49.0% interest in the Fences project area by spending
$16.0 million of exploration costs.
(3) We and Apache each have a 50.0% beneficial interest in all FX
Energy Concessions within the Apache Exploration Program.
(4) We own 100% of the Baltic project area.
As we continually 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. During
2000, we paid $6.7 million to POGC under this agreement, including approximately
$4.6 million for drilling activities and $2.1 million for 3-D seismic
activities. Upon completion of the Mieszkow 1 well and the 3-D seismic grids at
Donatowo and Zaniemysl, we will have expended a total of approximately $9.6
million, leaving a remaining commitment of approximately $6.4 million.
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 trends. The following description of POGC's prior activity in the
Rotliegendes trend associated with the Poznan Depression and in the Zechstein
Reef trend associated with the Wolsztyn Block indicates the success POGC has had
with exploration models that we are now using:
6
The Rotliegendes Trend
In the Rotliegendes trend associated with the Poznan Depression, POGC
has discovered four fields: Kaleje, Kleka, Radlin and Jarocin. Our recent Kleka
East discovery brings the number of fields in this trend to five; if successful,
the Mieszkow 1 well would raise the total to six fields. The Rotliegendes trend
continues for approximately 45 kilometers within the Fences project area.
Extensive drilling by POGC shows that reservoir quality is relatively uniform
throughout the Rotliegendes trend. All structural traps drilled by POGC to date
contain gas accumulations, with the size of the accumulation approximately
proportionate to the size of the structure. During the past two years, POGC has
acquired 3-D seismic data over the entire trend within the Fences project area,
except for a gap of approximately 100 square kilometers in the Zaniemysl area.
During 2000, we completed field acquisition of 3-D seismic to fill this gap.
During 2001, we intend to finish processing and interpreting the Zaniemysl 3-D
seismic grid and, if warranted, drill an exploratory well as funding permits.
Our first structural target in the Fences project area was Kleka East,
a 3-D seismic-defined Rotliegendes prospect approximately two kilometers
southeast of POGC's three well Kleka field. Our Kleka 11 well began producing in
February 2001 and is currently producing at a rate of approximately 4 Mmcf per
day. The next exploratory well, the Mieszkow 1, reached planned total depth
structurally low to prognosis and is currently being sidetracked and
directionally drilled to a new bottom hole location. During the second quarter
of 2001, we will evaluate the results of the Mieszkow 1 and the Zaniemysl 3-D
seismic grid to select sites for additional drilling.
The Zechstein Reef Trend
In the Zechstein Reef trend, POGC has discovered gas in six Zechstein
Reef buildups in a 35-kilometer stretch along the Wolsztyn Block immediately
west of the Fences project area. These fields consist of Koscian, Rensko,
Bonikowo, Wielichowo, Ruchocice and Racot. When drilling on 3-D seismic data in
the Zechstein Reef trend, every Zechstein Reef prospect POGC has drilled has
contained hydrocarbons, and 24 of 27 wells (89%) have been completed for
production. We believe this success rate is attributable to specific 3-D
processing techniques that POGC has developed to identify areas of probable
porosity within these reefs. The Zechstein Reef trend appears to run
approximately 45 kilometers inside the Fences project area before continuing to
the southeast.
We have completed field acquisition on 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 identified by 2-D seismic data acquired by POGC. As funding
permits, we will continue to acquire additional 3-D seismic data along the
Zechstein Reef trend in the Fences project area. During 2001, we intend to
finish processing and interpreting the Donatowo 3-D seismic grid and, if
warranted, drill an exploratory well as funding permits.
Apache Exploration Program
The Apache Exploration Program consists of various agreements that
govern our joint operations with Apache that were signed between 1997 through
early 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 initial terms
were later modified to allow the ten exploratory wells to be drilled anywhere in
Poland. As of December 31, 2000, Apache has, in effect, paid our share of costs
to drill an equivalent of nine exploratory wells (including two that were being
drilled as of December 31, 2000) and to acquire 1,661 kilometers of 2-D seismic
data.
7
The following table shows the detail and status of Apache's work
commitment as of December 31, 2000, as it pertains to exploratory drilling and
2-D seismic data acquisition:
Well Name or FX Energy's Carried
Kilometers Status of Apache Working Well
Project Area of 2-D Seismic Work Commitment Interest Count
----------------------------------- ----------------------- -------------------- ------------- -----------
Exploratory drilling:
Lublin Basin....................Czernic.277-2...........Fulfilled.................33.3% 1.0
Lublin Basin....................Poniatowa.317-1.........Fulfilled.................47.5 1.0
Lublin Basin....................Witkow.1................Fulfilled.................45.0 1.0
Lublin Basin....................Siedliska.2.............Fulfilled.................33.3 1.0
Lublin Basin....................Wilga.2.................Fulfilled.................45.0 1.0
Lublin Basin....................Wilga.3.................Fulfilled.(1).............45.0 0.5
Lublin Basin....................Wilga.4.................Fulfilled.(1).............45.0 0.5
Pomeranian......................Tuchola.108-2...........Unfulfilled.(2)...........42.5 1.0
Warsaw West.....................Annopol.254-1...........Unfulfilled.(2)...........50.0 1.0
Pomeranian .....................Chojnice.108-6..........Unfulfilled.(2)...........42.5 1.0
2-D Seismic data acquisition:
Pomeranian......................300.kilometers..........Fulfilled.(3).............50.0 0.4
Warsaw West.....................422.kilometers..........Fulfilled.(3).............50.0 0.6
Lublin Basin....................1,650.kilometers........Fulfilled.................50.0 --
Carpathian......................350.kilometers..........11.km.fulfilled.(4).......50.0 --
-----------
Total carried well count.................................................................... 10.0
===========
- ------------------------
(1) Apache agreed to cover one-half of our share of costs to drill
the Wilga 3 and 4 wells in exchange for the release of its
commitment to cover our share of costs to drill one
exploratory well in Poland.
(2) As of December 31, 2000, the Tuchola 108-2 and the Annopol
254-1 were in the process of being drilled. Drilling
operations on the Chojnice 108-6 are expected to commence
during the first half of 2001.
(3) Apache agreed to cover our share of costs to shoot 722
kilometers of 2-D seismic data in the Pomeranian and Warsaw
West project areas in exchange for the release of its
commitment to cover our share of costs to drill one
exploratory well in Poland.
(4) Effective January 1, 2001, we signed the Poland 2001 Agreement
with Apache, whereby we agreed to release Apache's remaining
commitment to pay for our 50.0% share of costs to shoot 339
kilometers of 2-D seismic data on the Carpathian project area.
In return, Apache agreed to issue us a credit of $932,000
against all outstanding and future invoices billed to us by
Apache pertaining to our joint operations in Poland. If our
actual share of costs to shoot the 339 kilometers of 2-D
seismic data on the Carpathian project area exceeds $932,000,
the excess will be covered by Apache.
Additional terms of the Apache Exploration Program include Apache
covering our share of costs for the following items:
o our 45.0% share of costs to perform a flow test, and if
warranted, complete the Wilga 2 well;
o all concession and usufruct fees in the Lublin Basin and
Carpathian project areas (approximately $855,000), which was
fulfilled by Apache during 2000; and
o all of Apache Poland general and administrative costs through
June 30, 2000. Thereafter, we are obligated to pay 35.0% of
Apache's monthly Polish general and administrative costs, to
be increased by 5.0% upon Apache completing each of its three
remaining drilling requirements, up to a maximum of 50.0%.
Effective with the completion of drilling operations on the
Tuchola 108-2, Annopol 254-1 and Chojnice 108-6 wells, we will
be obligated to pay 50.0% of Apache Poland general and
administrative costs.
The Apache Exploration Program also included an Area of Mutual Interest
Agreement, or AMI, between us and Apache, whereby each party was required to
offer the other a 50.0% interest in any new activity entered into by either
party within the AMI that included all of Poland, except for the Fences and
Baltic project areas, which began on January 1, 1999, and terminated on December
31, 2000. Apache is the operator of all areas controlled by us and Apache within
the acreage covered by the Apache Exploration Program.
8
Pomeranian Project Area
The 3.5 million acre Pomeranian project area is located in northwestern
Poland and consists of exploration rights on 2.2 million gross acres held by us
and Apache and options on 1.3 million gross acres controlled by POGC. We and
Apache have an option to participate, with up to a one-third interest each, in
the exploration of the POGC option acreage. In turn, POGC has the option to
participate in the exploration of the acreage we and Apache hold, with up to a
one-third interest, by participating in the first exploratory well on each
250,000 acre block.
The Pomeranian project area lies along the under-explored northern edge
of the Permian Basin in northwestern Poland. To date, the Pomeranian project
area is relatively unexplored and has had no significant oil and gas production.
Geologic survey test wells previously drilled by the Polish government have
recorded oil and gas shows. POGC has made available to us and Apache the
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 an exploratory well, 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 is being 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.
The next well on the Pomeranian project area, the Chojnice 108-6, will
test the Main Dolomite at a depth of approximately 2,500 meters at a drill site
located approximately three kilometers northwest of the Tuchola 108-2. The
Chojnice 108-6 is expected to be drilled during the second quarter of 2001.
Drilling will commence as soon as the rig that drilled the Tuchola 108-2 can be
moved to the Chojnice 108-6 location. During 2001, a 2-D seismic program
covering approximately 280 kilometers will be conducted to confirm a number of
additional Main Dolomite Reef leads.
Under terms of the Apache Exploration Program, Apache is committed to
cover our 42.5% share of costs to drill the Tuchola 108-2 and Chojnice 108-6
exploratory wells. We will be responsible for our share of all other further
costs on the Pomeranian project area.
Warsaw West Project Area
The 2.9 million-acre Warsaw West project area is located in central
Poland. We and Apache each own a 50.0% interest in the Warsaw West project area.
POGC has no option to participate in the Warsaw West project area.
To date, there has been no oil or gas production from the Warsaw West
project area. During December 2000, we and Apache commenced drilling the Annopol
254-1 on the Warsaw West project area to test lower Permian and Carboniferous
objectives. The Annopol 254-1 was determined to be an exploratory dry hole in
February 2001. Under terms of the Apache Exploration Program, Apache covered our
50.0% share of costs to drill the Annopol 254-1. We and Apache are now currently
evaluating whether to acquire an additional 520 kilometers of 2-D seismic data
by November 2001 on the Warsaw West project area, in order to hold the Warsaw
West project area beyond the first three year exploration period.
Lublin Project Area
The 3.9 million-acre Lublin project area in central southeast Poland
consists of exploration rights on approximately 3.3 million gross acres held by
us and Apache and options to participate in 600,000 acres controlled by POGC. We
and Apache have an option to participate, with up to a one-third interest each,
in the exploration of the
9
POGC option acreage. In turn, POGC has the option to participate in the
exploration of the acreage that we and Apache hold, with up to a one-third
interest, by participating in the first exploratory well on each 250,000 acre
block.
The first four exploratory wells under the Apache Exploration Program,
all drilled within the Lublin project area prior to 2000, were exploratory dry
holes. In accordance with the terms of the Apache Exploration Program, Apache
covered our share of costs for each of the four wells. The fifth exploratory
well, Wilga 2, was a successful discovery. 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 at a depth of approximately 2,800
meters. We and Apache each have a 45.0% working interest and POGC has a 10.0%
working interest in the 250,000 acre block containing the Wilga 2 discovery. The
Wilga 2 well was followed by two offsets, the Wilga 3 and 4, which were
exploratory dry holes. During the first half of 2001, we and our partners plan
an extended flow test on the Wilga 2 to assess the potential for commercial
production in light of pipeline and facility expenditures that would be
required. Under terms of the Apache Exploration Program, Apache will cover 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.
The first three-year exploration period of a six-year exploration
period covering approximately 3.3 million acres held by us and Apache on the
Lublin project area expires during 2001. We anticipate relinquishing all of the
approximately 3.3 million acres on the Lublin project area, except for
approximately 250,000 acres, which covers Block 255 and includes the Wilga 2
discovery.
Carpathian Project Area
The 2.9 million acre Carpathian project area is located in southern
Poland and comprises exploration rights on 1.4 million gross acres held by us
and Apache and options on 1.5 million gross acres controlled by POGC. We and
Apache have an option to participate, with up to a one-third interest each, in
the exploration of the POGC option acreage. In turn, POGC has the option to
participate in the exploration of the acreage that we and Apache own, with up to
a one-third interest, by participating in the first exploratory well on each
250,000-acre block.
Oil and gas were first discovered in the Carpathian project area in
1854. A limited number of deep wells drilled in recent years by POGC evidence
additional possible reservoir potential within the area. Over the past few
years, there have been several new oil and gas discoveries in the Carpathian
region. Potential producing horizons within the Carpathian project area include
the Jurassic, Miocene, Cretaceous and Devonian. We and Apache have identified
several new leads in the Carpathian project area based on reprocessed existing
seismic data.
During 1999, we and Apache each elected to participate, with a 5.0%
interest each, in drilling the Andrychow 6 located within POGC-controlled
acreage on the Carpathian project area. The Andrychow 6, which was operated by
POGC, was determined to be an exploratory dry hole after testing a Devonian
formation yielded noncommercial results. Also, during 1999, we and Apache
commenced testing and recompletion operations on the Lachowice Farm-in, an
undeveloped gas discovery on a POGC concession located within the Carpathian
project area. Under terms of the agreement, we and Apache agreed to pay the
costs of testing three shut-in wells and, if warranted, additional wells and
production infrastructure in order to earn a one-third interest each in the
project. The test results from this project did not warrant constructing
gathering and processing facilities. On May 4, 2000, we and Apache each turned
the project back to POGC and terminated the Lachowice Farm-in.
The first three-year exploration period of a six-year exploration
period covering approximately 1.4 million acres held by us and Apache on the
Carpathian project area expires at the end of 2001. In order to begin the second
three year exploration period on the aforementioned acreage, we and Apache must
acquire at least 339 kilometers of 2-D seismic and commence drilling an
exploratory well by the end of 2001. We and Apache are currently evaluating
whether to continue exploration activities on the Carpathian project area.
10
Other Polish Project Areas
Baltic Project Area
The Baltic project area, which was our first exploration project area
in Poland, is located onshore near the Baltic Sea and consists of exploration
rights covering approximately 900,000 gross and net acres in northern Poland.
The Baltic project area is part of the Baltic Platform geological region that
covers the southeastern portion of the Baltic Sea, portions of the bordering
onshore areas of northern Poland and areas to the northeast in the Kaliningrad
district of Russia, Lithuania and Latvia. Approximately 34 onshore and offshore
fields have been discovered in the Baltic Platform. Industry sources report that
four of the largest fields in this region had produced an aggregate of over 150
MMBbls of high-grade oil through 1994.
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.
We hold a 100% interest in the Baltic project area and have no further work
commitments. We do not currently plan to conduct any exploratory activities on
the Baltic project area during 2001. However, recently reported Cambrian
successes in southern Kaliningrad near the Polish border, coupled with the
recent exploratory successes in our other project areas in Poland, may encourage
industry interest in participating with us on this project area in the future.
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 agreements that grant the holder the exclusive right to explore
for and 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. If a commercially
viable discovery is made in an exploration concession area, it is necessary for
the holder of the exploration concession license to obtain an exploitation
concession license for a specific term by then applying to the concession
authority and negotiating with local government authorities. The holder of a
usufruct and exploration and exploitation concession licenses must also acquire
rights to use the land from the surface owner.
The concession authority has granted us oil and gas exploration rights
on the Lublin, Carpathian, Pomeranian and Baltic project areas, granted Apache
oil and gas exploration rights on the Warsaw West project area and granted POGC
oil and gas exploration rights on the Fences project area and on POGC option
acreage. 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.
Fences Project Area
The Fences project area consists of portions of three oil and gas
exploration concessions (Koscian-Serem, Solec-Jarocin and Jaraczewo-Pogorzela
concessions) controlled by POGC. Three producing fields lie within the
concession boundaries (Radlin, Kleka and Kaleje), but are excluded from the
Fences project area.
11
The following table sets forth the exploration terms of each Fences
project area exploratory oil and gas concession:
Six-Year Exploration Period
---------------------------------- Optional
Beginning End Extension
---------------- ----------------- --------------
POGC concession:
Koscian-Serem........................................ 9/28/95 9/28/01 3 years
Solec-Jarocin........................................ 4/30/96 4/30/02 3 years
Jaraczewo-Pogorzela.................................. 11/19/96 11/19/02 3 years
We believe POGC has paid all required usufruct and concession fees and
completed all material work commitments to date for the three exploratory oil
and gas concessions included within the Fences project area.
Apache Exploration Program and the Baltic Project Area
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 (except in the Baltic project area), 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 have committed
to the following obligations in Poland, presented on a gross basis, to retain
our exploratory concession acreage, excluding the Fences project area, POGC
option acreage and POGC exclusive acreage:
Start of First Exploratory Drilling
Three Year ------------------------------------
Whole Exploration First Three Second Three 2-D Seismic Data
Blocks Period Year Period (1) Year Period (2) Acquisition (3)
---------------------------------- ---------------- ----------------- ------------------ ------------------
Project Area:
Lublin Basin:
Vistula (4)......... 8 08/08/97 1 well 1 well per block 500 km
Lublin Middle....... 7 06/30/98 2 wells 1 well per block 500 km
Block 298........... 1 06/30/98 1 well 2 wells 150 km
Kamarow............. 7 03/04/98 2 wells 1 well per block 500 km
Carpathian............ 12 12/31/98 1 well 2 wells 350 km
Pomeranian............ 10 12/31/98 1 well 2 wells 600 km
Warsaw West........... 13 11/13/98 1 well 2 wells 1,500 km
Baltic................ 3 03/07/96 1 well 1 well None
- -------------------
(1) As of December 31, 2000, we had fulfilled our exploratory
drilling requirements for the first three-year exploration
period on all usufructs except for Block 298 and Kamarow,
where we had previously drilled one exploratory well. We have
also participated in drilling four exploratory wells (Czernic
277-2, Siedliska 2, Witkow 1 and Andrychow 6) that were on
concessions controlled by POGC.
(2) In the Vistula, Lublin Middle and Kamarow usufructs, one
exploratory well must be drilled in each previously undrilled
block by the end of the second three-year exploration period
to retain the exploratory acreage within each particular
block.
(3) As of December 31, 2000, we had fulfilled all 2-D seismic data
requirements in the Vistula, Lublin Middle and Kamarow areas,
acquired 11 kilometers of 2-D seismic data in the Carpathian
project area, 328 kilometers of 2-D seismic data in the
Pomeranian project area and 480 kilometers of 2-D seismic data
in the Warsaw West project area. As of December 31, 2000, no
2-D seismic data had been acquired in Block 298. All 2-D
seismic data acquisition must be completed during the first
three-year exploration period, except for the Warsaw West
project area, which includes 1,000 kilometers of 2-D seismic
data in the first three-year exploration period and 500
kilometers in the second three-year exploration period.
(4) During 2000, we relinquished all of our Vistula acreage, with
the exception of the approximately 250,000 acre Block 255,
which includes the Wilga 2 discovery.
As of December 31, 2000, all required usufruct/concession payments had
been made in each of the above project areas, including $695,000 for the Lublin
Basin project area, $160,000 for the Carpathian project area,
12
$250,000 for the Pomeranian project area, $390,000 for the Warsaw West project
area and $149,000 for the Baltic project area. As of December 31, 2000, the only
outstanding usufruct/concession fee obligation was $15,666, the final payment
due under the Baltic project area usufruct, which was paid during February 2001.
During 2001, the first three-year exploration period expires for the
Lublin Middle, Block 298, Kamarow, Carpathian, Pomeranian and Warsaw West
usufructs. We intend to relinquish all acreage pertaining to the Lublin project
area usufructs that expire during 2001. We are evaluating all other usufructs
expiring during 2001 to elect whether to relinquish or retain the acreage under
each usufruct and begin the second three-year exploration period.
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
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 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.
Polish Production, Transportation and Marketing
Poland has crude oil pipelines traversing the country and a network of
gas pipelines serving major metropolitan, commercial, industrial areas 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 under a
five-year contract that may be terminated by us with a 90-day written notice.
We have granted RRPV an option exercisable until March 2002, to enter
into an agreement to purchase up to 17 Mmcf of gas per day from our wells in
Poland, subject to availability. The gas will be used to support the development
of a planned RRPV power project. Contract prices will be adjustable during the
term of the agreement, based in part on the domestic price of electricity. Gas
will be delivered at the POGC pipeline connection, and RRPV will be responsible
for transportation costs. RRPV will be required to take at least 80% of the gas
it agrees to purchase. We may sell to others gas we produce in excess of the
reserves required to supply the RRPV contract.
Domestic Properties
Producing Properties
We currently produce oil domestically 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
13
average daily production, average working interest and net revenue interest for
our domestic producing properties during 2000 follows:
Average Daily Production
(Bbls) Average Average
---------------------------- Working Net Revenue
Gross Net Interest Interest
------------- -------------- -------------- --------------------
Domestic producing properties:
Cut Bank.............................. 269 231 99.5% 85.7%
Bears Den............................. 24 10 48.0 39.2
Rattlers Butte........................ 30 2 6.3 5.1
Trap Spring........................... 12 2 21.6 20.0
Munson Ranch.......................... 43 15 36.0 34.1
Bacon Flat............................ 43 5 16.9 12.5
------------- --------------
Total............................... 421 265
============= ==============
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 104 producing oil wells, 18 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.
Domestic Marketing and Production
The following table sets forth our average net daily oil production,
average sales price and average production costs associated with our domestic
oil production during the periods indicated:
Years Ended December 31,
--------------------------------------
2000 1999 1998
----------- ----------- ------------
Domestic producing property data:
Average daily net oil production (Bbls).......................... 265 279 315
Average sales price per Bbl...................................... $ 26.14 $ 15.35 $ 9.78
Average production costs per Bbl(1).............................. $ 13.99 $ 9.50 $ 9.11
- -------------------
(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, 2000, 1999 and 1998,
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.
14
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.
During 2000, we purchased an idle drilling rig, which was subsequently converted
to a workover rig, cementing equipment and other associated oilfield equipment
costing approximately $250,000 in an effort to expand our oilfield services
business to take advantage of the current shortage of oilfield services. We now
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 that we utilize in our oilfield
services business. We started our oilfield services business in 1998, in an
effort to increase our domestic revenues, which had declined due to depressed
oil prices during 1998. Our oilfield services revenues have grown from $322,000
in 1998 to $1.3 million in 2000.
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, 2000 of $21.33 per bbl for oil in the
United States and $2.09 per MMbtu for 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." Our
proved reserve estimates are subject to continuing revisions as additional
information becomes available or assumptions change.
Estimates of our proved domestic 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 2000.
The following summary of proved reserve information as of December 31,
2000, represents estimates net to us only and should not be construed as exact:
Domestic Poland
---------------------------- ---------------------------- Total
Oil PV-10 Value Gas PV-10 Value PV-10 Value
----------- --------------- ----------- --------------- ---------------
(MBbls) (In thousands) (Mmcf) (In thousands) (In thousands)
Proved reserves:
Developed producing......... 1,161 $ 4,505 -- $ -- $ 4,505
Undeveloped................. 59 404 2,381 2,511 2,915
----------- --------------- ----------- --------------- ---------------
Total..................... 1,220 $ 4,909 2,381 $ 2,511 $ 7,420
=========== =============== =========== =============== ===============
Proved undeveloped Polish gas reserves in the above table relate to the
Kleka 11 well only, which was drilled during 2000 and commenced production
during February 2001.
Drilling Activities
The following table sets forth the exploratory wells that we drilled
during the years ended December 31, 2000, 1999 and 1998. We did not drill any
development wells during 2000, 1999 or 1998:
15
Years Ended December 31,
-------------------------------------------------------------------
2000 1999 1998
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- --------- ---------- --------- ----------
Discoveries:
Poland.............................. 1.0 0.5 1.0 0.5 -- --
Domestic............................ -- -- -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total............................. 1.0 0.5 1.0 0.5 -- --
--------------------- --------- ---------- --------- ----------
Exploratory dry holes:
Poland.............................. 2.0 1.0 5.0 1.6 -- --
Domestic............................ -- -- -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total............................. 2.0 1.0 5.0 1.6 -- --
---------- ---------- --------- ---------- --------- ----------
Total wells drilled................... 3.0 1.5 6.0 2.1 -- --
========== ========== ========= ========== ========= ==========
As of December 31, 2000, there were three exploratory wells that were
being drilled in Poland and are excluded from the above table: the Tuchola 108-2
(an exploratory success during January 2001; 42.5% working interest); Annopol
254-1 (exploratory dry hole during February 2001; 50.0% working interest) and
Mieszkow 1 (still drilling at the date of this report; 49.0% working interest).
Wells and Acreage
As of December 31, 2000, we had 118 gross and 109 net producing oil
wells, all of which are located in Montana and Nevada. As of December 31, 2000,
we did not have any producing wells in Poland.
16
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2000:
Developed Undeveloped
---------------------------- ----------------------------
Gross Net Gross Net
---------------------------- ----------------------------
Domestic:
North Dakota................................. -- -- 12,688 12,688
Montana...................................... 10,732 10,418 1,150 1,057
Nevada....................................... 400 128 37 16
------------- ------------- ------------- --------------
Total..................................... 11,132 10,546 13,875 13,761
------------- ------------- ------------- --------------
Poland: (1)
Apache Exploration Program (2)
Lublin Basin............................... -- -- 3,300,000 1,650,000
Carpathian................................. -- -- 1,400,000 700,000
Pomeranian................................. -- -- 2,200,000 1,100,000
Warsaw West................................ -- -- 2,900,000 1,450,000
------------- ------------- ------------- --------------
Total.................................... -- -- 9,800,000 4,900,000
------------- ------------- ------------- --------------
Baltic project area.......................... -- -- 900,000 900,000
Fences project area (3)...................... 225 110 300,000 147,000
------------- ------------- ------------- --------------
Total Polish acreage..................... 225 110 11,000,000 5,947,000
------------- ------------- ------------- --------------
Total Acreage.................................. 11,357 10,656 11,013,875 5,960,761
============= ============= ============= ==============
- ------------------
(1) All undeveloped Polish acreage is rounded to the nearest
100,000 acres.
(2) Gives effect to 50.0% beneficial ownership of Apache in the
Lublin Basin, Carpathian, Pomeranian and Warsaw West areas in
our joint exploration arrangements with Apache under the
Apache Exploration Program. Does not give effect to options on
POGC-controlled areas containing approximately 0.6 million
acres in the Lublin Basin area, 1.5 million acres in the
Carpathian area and 1.3 million acres in the Pomeranian area
under the POGC option agreements.
(3) Developed acreage in the Fences project area is attributable
to the Kleka 11 well only.
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.
17
Domestic
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.
18
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 is operated
under 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 domestic 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 domestic
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, 2000, we had 34 employees, consisting of eight in
Salt Lake City, Utah; 23 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.
19
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, but
not limited to, the following factors related directly and indirectly to our
business activities in the United States and Poland:
Risks Relating to our Business
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; and
o drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, including operating problems
encountered during drilling, weather conditions, compliance
with governmental requirements, shortages or delays in the
delivery of equipment or availability of services and other
factors.
We have had limited exploratory success in Poland.
We have participated in drilling 14 exploratory wells in Poland,
including three exploratory successes (the Wilga 2, Kleka 11 and Tuchola 108-2),
ten exploratory dry holes and one exploratory well that is currently drilling
(Mieszkow 1) as of the date of this report. In the Fences project area, we have
drilled one exploratory success and are currently drilling another exploratory
well. In the Apache Exploration Program, Apache has, in effect, covered our
share of costs to drill an equivalent of nine exploratory wells, including two
exploratory successes and seven 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, 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 has yet to be completed for production. During the first
half of 2001, we and our partners plan an extended flow test on the Wilga 2 to
assess the potential for commercial production, in light of pipeline and
facility expenditures that would be required. The Tuchola 108-2 is
20
located approximately five kilometers from the nearest pipeline and is currently
being tested and completed for production.
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 our strategic partners, POGC and Apache. The failure of either
POGC or Apache to perform its obligations under contracts with us would most
likely have a material adverse effect on us. In particular, we have prepared our
exploration budget through 2002 based on the participation of and funding to be
provided by Apache and POGC. In the future, we may become even more reliant upon
the operational expertise and financial capabilities of our strategic partners.
Apache has worldwide oil and gas interests outside of Poland in which we do not
participate. Apache is only committed to drilling one additional well in Poland
under the Apache Exploration Program. If Apache's separately held interests
should become more promising to Apache than interests held with us in Poland,
Apache may focus its efforts, funds, expertise and other resources elsewhere. In
addition, should our relationship with POGC or Apache deteriorate or terminate,
our oil and gas activities in Poland may be adversely affected.
Although we have rights to participate in exploration and development
activities on some POGC-controlled acreage, we have no right to initiate such
activities. Further, we have no interest in the underlying agreements, licenses
and grants from the Polish agencies governing the exploration, exploitation,
development or production of acreage controlled by POGC. Thus, our program in
Poland involving POGC-controlled acreage would be adversely affected if POGC
should elect not to pursue activities on such acreage, if the relationship
between us, POGC or Apache should deteriorate or terminate or if POGC or the
government agencies should fail to fulfill the requirements of or elect to
terminate such agreements, licenses or grants.
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 establish additional 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.
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
21
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 may require additional
capital in the future to fund our operations.
From our inception in January 1989 through December 31, 2000, we have
incurred cumulative net losses of $40.0 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
2001 and possibly beyond, depending on whether our activities in Poland and the
United States result in sufficient revenues to cover related operating expenses.
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. Outside of
the $5.0 million of financing we received from RRPV during March 2001, we have
no current arrangement for any such additional financing, but may seek required
funds from the issuance of additional debt or equity securities, project
financing, strategic alliances or other arrangements. Although we are currently
negotiating with commercial lenders to establish a credit facility, we can offer
no assurances that we will be able to obtain financing on acceptable or
favorable terms. 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 a portion of our gas reserves in Poland and
the related proceeds from gas sales to secure repayment of a $5.0 million loan
from RRPV. If RRPV elects to buy gas we produce in Poland, the loan will be
repayable over eight years. If RRPV elects not to buy our gas, the loan will be
repayable in March 2003, unless converted to common stock. Unless converted to
common stock, the loan will have to be repaid notwithstanding the level of
production from our 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 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
22
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.
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 domestic 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 Apache Exploration Program, 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
23
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.
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.
24
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
zlotys. Conversions between United States dollars and Polish zlotys 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.
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.
25
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 $2.88 and as high as $10.13
during intra-day trading between January 1, 1999, and the date of this report.
Some of the factors leading to this volatility include:
o the outcome of
individual wells or the timing of exploration efforts in Poland;
o the potential sale by us of newly issued common stock to raise
capital or by existing stockholders of restricted securities;
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 or Apache that may affect us;
o prevailing world prices for oil and gas;
o the potential of our current and planned activities in Poland;
and
o changes in stock market analysts' recommendations regarding
us, other oil and gas companies or the oil and gas industry in
general.
We may encounter additional exploration failures in Poland that will
adversely affect the trading prices for our common stock.
26
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 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, which 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. "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 which 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.
27
- --------------------------------------------------------------------------------
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, 2000.
28
PART II
- --------------------------------------------------------------------------------
ITEM 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
---------- ----------
2001:
First Quarter (through March 15, 2001)................. $ 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
1999:
Fourth Quarter........................................ $ 4.00 $ 7.00
Third Quarter.......................................... 6.31 9.43
Second Quarter......................................... 4.13 7.00
First Quarter.......................................... 4.00 9.75
On March 15, 2001, the closing price per share of our common stock on
the Nasdaq National Market was $5.32.
The market price for our common stock has been volatile in the past and
could fluctuate significantly in response to the results of specific exploration
and development activities, variations in quarterly operating results,
fluctuations in oil and gas prices and changes in recommendations by securities
analysts. In addition, the securities markets regularly experience significant
price and volume fluctuations that are often unrelated or disproportionate to
the results of operations of particular companies. In particular, securities
such as the common stock of companies doing substantially all of their business
in emerging market countries such as Poland are, to varying degrees, influenced
by economic and market conditions in other emerging market countries. Although
economic conditions are different in each country, investors' reactions to
developments in one country may affect the securities of issuers doing business
in other countries, including Poland. There can be no assurance that the trading
price of our common stock would not be adversely affected by events elsewhere,
especially in emerging market countries. These broad fluctuations may adversely
affect the market price of our common stock.
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 15, 2001, we had approximately 4,200 stockholders.
29
- --------------------------------------------------------------------------------
ITEM 6. SELECTED CONSOLIDATED FINANCILA DATA
- --------------------------------------------------------------------------------
The following selected consolidated financial data of FX Energy, Inc.
and its subsidiaries for the five years ended December 31, 2000, 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,
---------------------------------------------------------------
2000 1999 1998 1997 1996
------------ ------------ ------------ ------------ -----------
(In thousands, except per share amounts)
Statement of Operations Data
Revenues:
Oil sales............................. $ 2,521 $ 1,554 $ 1,124 $ 2,040 $ 2,346
Oilfield services revenues............ 1,290 865 323 496 75
Gain on sale of property interests.... -- -- 467 272 --
------------ ------------ ------------ ------------ -----------
Total revenues...................... 3,811 2,419 1,914 2,808 2,421
------------ ------------ ------------ ------------ -----------
Operating costs and expenses:
Lease operating costs (1)............. 1,349 962 1,046 1,239 1,225
Exploration costs (2)................. 7,389 3,053 2,127 5,314 3,716
Impairments (3)....................... -- -- 5,885 -- --
Oilfield services..................... 1,084 642 240 329 154
Depreciation, depletion and
amortization........................ 386 494 672 635 558
General and administrative............ 2,654 2,962 2,572 2,566 1,715
Apache Poland general and
administrative...................... 957 -- -- -- --
Amortization of deferred
compensation........................ 652 -- -- -- --
------------ ------------ ------------ ------------ -----------
Total operating costs and expenses 14,471 8,113 12,542 10,083 7,368
------------ ------------ ------------ ------------ -----------
Operating loss.......................... (10,660) (5,694) (10,628) (7,275) (4,947)
------------ ------------ ------------ ------------ -----------
Other income (expense):
Interest and other income............. 557 511 506 662 370
Interest expense...................... (2) (7) -- (83) (333)
Impairment of notes receivable from
officers............................ (738) (666) -- -- --
------------ ------------ ------------ ------------ -----------
Total other income (expense)...... (183) (162) 506 579 37
------------ ------------ ------------ ------------ -----------
Net loss before extraordinary gain...... (10,843) (5,856) (10,122) (6,696) (4,910)
------------ ------------ ------------ ------------ -----------
Extraordinary gain.................... -- -- -- 3,076 --
------------ ------------ ------------ ------------ -----------
Net loss................................ $ (10,843) $ (5,856) $ (10,122) $ (3,620) $ (4,910)
============ ============ ============ ============ ===========
Basic and diluted net loss per share:
Net loss before extraordinary gain.... $ (0.66) $ (0.41) $ (0.78) $ (0.53) $ (0.49)
Extraordinary gain.................... -- -- -- 0.24 --
------------ ------------ ------------ ------------ -----------
Net loss............................ $ (0.66) $ (0.41) $ (0.78) $ (0.29) $ (0.49)
============ ============ ============ ============ ===========
Basic and diluted weighted average
shares outstanding.................... 16,435 14,199 12,979 12,597 10,018
- Continued -
30
Years Ended December 31,
---------------------------------------------------------
2000 1999 1998 1997 1996
---------- ----------- ---------- ---------- -----------
(In thousands)
Cash Flow Statement Data
Net cash used in operating activities (4)............. $ (6,082) $ (2,984) $ (3,091) $ (2,402) $ (3,496)
Net cash provided by (used in) investing activities (4) (3,834) (3,678) 1,066 (3,110) (7,160)
Net cash provided by (used in) financing activities... 9,375 6,469 (674) 1,679 18,259
December 31,
---------------------------------------------------------
2000 1999 1998 1997 1996
---------- ----------- ---------- ---------- -----------
(In thousands)
Balance Sheet Data
Working capital....................................... $ 616 $ 5,459 $ 3,965 $ 8,494 $ 13,843
Total assets.......................................... 10,570 10,470 8,253 18,555 22,994
Long-term debt........................................ -- -- -- -- 1,500
Stockholders' equity.................................. 8,231 8,367 6,920 17,612 20,908
- -----------------
(1) Includes lease operating expenses and production taxes.
(2) Includes geophysical and geological costs, exploratory dry hole costs
and nonproducing leasehold impairments.
(3) Includes domestic proved property write down.
(4) The years ended December 31, 1999, 1998, 1997 and 1996, have been
adjusted to include exploratory dry hole costs in investing activities
rather than as a component of operating activities.
31
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
We are an independent energy company engaged in the exploration,
development and production of oil and gas from properties located in the United
States and Poland. Through the end of 2000, all of our production revenue has
been from our United States producing properties. In the western United States,
we produce oil from fields in Montana and Nevada and have an oilfield services
company in northern Montana and oil and gas exploration prospects in several
western states.
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.
We follow the successful efforts method of accounting for our oil and
gas properties. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves. If an
exploratory well has not found proved reserves, 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.
We have reviewed all 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.
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.
Mining, which consisted solely of gold exploration on our Sudety project area in
Poland, has been discontinued and is excluded from the following discussion.
Depreciation, depletion and amortization costs, or DD&A, and general and
administrative costs, or G&A, directly associated with their respective segments
are detailed within the following discussion. Amortization of deferred
compensation, interest income, other income, officer loan impairment 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 information regarding nonsegmented items for the years ended
December 31, 2000, 1999 and 1998 follows:
32
Exploration and Production Segment
A summary of the amount and percentage change, as compared to their
respective prior year period, for oil revenues, average oil prices, production
volumes and lifting costs per barrel for the years ended December 31, 2000, 1999
and 1998, is set forth in the following table:
Year Ended December 31,
------------------------------------------------------
2000 1999 1998
----------------- ----------------- -----------------
Oil revenues...................................... $2,521,000 $1,554,000 $1,124,000
Percent change versus prior year................ +62.2% +38.3%
Average oil price................................. $26.14 $15.35 $9.78
Percent change versus prior year................ +70.3% +57.0%
Production volumes (Bbls)......................... 96,416 101,275 114,909
Percent change versus prior year................ -4.8% -11.9%
Lifting costs per barrel (1)...................... $12.13 $8.88 $8.41
Percent change versus prior year................ +36.6% +5.5%
- ------------------------
(1) Lifting costs per barrel are computed by dividing lease
operating expenses by the total barrels of oil produced.
Oil Revenues. Oil revenues were $2.5 million, $1.6 million and $1.1
million for the years ended December 31, 2000, 1999 and 1998, respectively.
During these three years, our oil revenues fluctuated primarily due to volatile
oil prices, the degree of maintenance performed and declining production rates
attributable to the natural production declines of our producing properties.
Gain on Sale of Property Interests. There was no gain on sale of
property interests for the years ended December 31, 2000 and 1999. We recognized
a gain on sale of property interests of $467,000 during the year ended December
31, 1998. During 1998, Apache paid us $500,000 in initial cash consideration
relating to its participation in our Carpathian project area, which was offset
by $33,000 of associated costs. The amount of gain on sale of property interests
will continue to vary from year to year, depending on the timing of completed
deals and the amount of up-front cash consideration, if any.
Lease Operating Costs. Our lease operating costs consist of normal
recurring lease operating expenses and production taxes. Lease operating costs
were $1.3 million, $962,000 and $1.0 million for the years ended December 31,
2000, 1999 and 1998, respectively, or $13.99, $9.50 and $9.11, respectively, per
barrel of oil produced.
Lease operating expenses were $1.2 million, $899,000 and $966,000 for
the years ended December 31, 2000, 1999 and 1998, respectively. During 2000, we
plugged and abandoned ten inactive wells at a total cost of approximately
$92,000 on the Cut Bank Sand Unit, our principal producing property, and
incurred substantially more maintenance and repair costs as we completed work
that had been postponed due to low oil prices during prior years. As a result,
lifting costs per barrel were $12.13 during 2000, an increase of $3.25 as
compared to the same period on 1999. During 1999 and 1998, we performed only
routine maintenance on our producing properties and deferred workovers in an
effort to control operating costs due to low oil prices. Lifting costs per
barrel were relatively flat during 1999 and 1998, amounting to $8.88 and $8.41
per barrel, respectively.
Production taxes were $179,000, $63,000 and $80,000 for the years ended
December 31, 2000, 1999 and 1998, respectively, or 7.1%, 4.1% and 7.0% of oil
revenues, respectively. During 1999, the state of Montana passed legislation to
reduce the production tax rate to as low as 0.5% for stripper oil wells. The
legislation also included a provision whereby the production tax rate would
increase to as much as 12.8% for stripper wells if the average price of west
Texas intermediate crude oil, or WTI, exceeded $30 per barrel during any
calendar quarter. In the event the average price of WTI exceeded $30 per barrel,
the higher tax rate would apply to all production during the then-current
calendar quarter. During the third and fourth quarters of 2000, the average
price of WTI exceeded $30 per barrel, resulting in a higher effective production
tax rate during 2000, as compared to 1999. During 1999, production taxes
decreased to an average of approximately 4.1% of annual oil revenues, as
compared to 7.0% during 1998,
33
primarily due to the reduction in the production tax rate on stripper wells in
Montana and the average price of WTI not exceeding $30 per barrel during any
quarter of 1999. The change in the amount of production taxes from year to year
is directly attributable to the combination of fluctuating of oil prices,
production tax rate changes and the amount of oil produced.
DD&A Expense - Producing Operations. DD&A expense for producing
properties was $73,000, $51,000 and $231,000 for the years ended December 31,
2000, 1999 and 1998, respectively, or $0.76, $0.50 and $2.01 per barrel,
respectively. The increase in DD&A expense of $0.26 per barrel during 2000, as
compared to the same period of 1999, is primarily attributed to a 456,000 barrel
decrease in the amount of estimated proved reserves as of December 31, 1999, as
compared to December 31, 1998. The decrease in DD&A expense of $1.51 during
1999, as compared to the December 31, 1998, is directly attributable to the $5.9
million write-down of our domestic proved developed oil and gas properties
during 1998, which resulted in a substantially lower depreciable property basis
during 1999, as compared to 1998.
Domestic Proved Property Impairment. There were no domestic proved
property impairments for the years ended December 31, 2000 or 1999. For the year
ended December 31, 1998, we incurred a domestic proved developed property
impairment of $5.9 million due to low oil prices experienced during 1998,
coupled with forecasted continuation of depressed oil prices and our decision to
focus our limited resources on Poland. As of December 31, 1998, the estimated
net present value for our domestic proved properties was approximately $472,000,
consisting solely of proved developed reserves. In accordance with SFAS No. 121
"Accounting for the Impairment of Long-Lived Assets and for the Long-Lived
Assets To Be Disposed of," we recorded total impairment expense of $5.9 million
for the year ended December 31, 1998, which represented the difference between
the net book value of our domestic proved developed properties and the related
fair value, determined on a property-by-property basis, as of December 31, 1998.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs, or G&G, exploratory dry holes and nonproducing leasehold
impairments. Exploration costs were $7.4 million, $3.1 million and $2.1 million
for the years ended December 31, 2000, 1999 and 1998, respectively. G&G costs of
$31,000 and $29,000 incurred during the years ended December 31, 1999 and 1998,
respectively, relate to our discontinued gold exploration in Poland, which is
excluded from the following discussion of each component of exploration costs.
G&G costs were $4.7 million, $1.9 million and $2.1 million during the
years ended December 31, 2000, 1999 and 1998, respectively. During 2000, we
spent approximately $2.1 million on acquiring 3-D seismic data in the Fences
project area, approximately $477,000 on acquiring 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. 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. During 1998, we incurred
approximately $400,000 of cost relating to our share of the Lublin project area
2-D seismic data acquisition program with Apache and $75,000 relating to a
geological and geophysical study. From January 1, 1998, through December 31,
2000, we spent an average amount of approximately $1.6 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 $2.0 million, $1.0 million and $17,000
for the years ended December 31, 2000, 1999 and 1998, respectively. During 2000,
we drilled the Wilga 3 and Wilga 4 wells near our Wilga 2 discovery on the
Lublin Basin 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 costs to drill
the Wilga 3 and Wilga 4 wells 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 costs for both wells. We retained and paid for a 5.0% interest in
the Andrychow 6 well, an exploratory dry hole on the Carpathian project area,
which cost $99,000. On the Lachowice Farm-in, we spent $869,000 to recomplete
one
34
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. During
1998, we participated in drilling two exploratory dry holes, the Czernic 277-2
and the Poniatowa 317-1, on the Lublin project area in Poland. Both wells were
carried exploratory wells under the Apache Exploration Program. As such, Apache
covered all of our pro rata share of costs for both wells. All of the
exploratory dry hole costs recorded during 1998 were associated with wells
drilled prior to 1998.
Nonproducing leasehold impairments were $674,000 and $93,000 for the
years ended December 31, 2000 and 1999, respectively. There were no nonproducing
leasehold impairments during the year ended December 31, 1998. During 2000, we
incurred a nonproducing leasehold impairment $674,000 relating to the Williston
Basin in North Dakota, where we no longer have exploration plans. During 1999,
we incurred a nonproducing leasehold impairment of $72,000 relating to the
Lachowice Farm-in, which was 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 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.
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 $957,000
for the year ended December 31, 2000. There were no Apache Poland G&A costs
during the years ended December 31, 1999, and 1998. 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%. In addition to the $957,000 of Apache Poland G&A we
paid during 2000, Apache covered approximately $34,000 of Apache Poland G&A
costs incurred by us during the second half of 2000 under an amendment to the
Apache Exploration Program effective January 1, 2001, referred to as the Poland
2001 Agreement, whereby Apache agreed to issue us a credit of $923,000 against
any outstanding invoices as of December 31, 2000, as well as any future costs
billed by Apache in return for the release of its commitment to cover our share
of costs to shoot 339 kilometers of 2-D seismic data in the Carpathian project
area. The annual budgeted amount of Apache Poland G&A costs is subject to
advance joint approval.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $1.3
million, $865,000 and $323,000 for the years ended December 31, 2000, 1999 and
1998, respectively. During 2000, oilfield services revenues were $425,000 higher
than the same period of 1999, primarily due to improved market conditions as a
result of higher oil prices. During all of 2000 and 1999, we focused our
oilfield servicing equipment on third-party contract oilfield services in an
effort to increase our domestic revenues rather than utilizing it on our
company-owned properties. During 1998, our oilfield services revenues consisted
of $323,000 from third-party contract oilfield services work conducted in the
third and fourth quarters as we began to shift the primary focus of utilizing
our oilfield servicing equipment to third-party contract work rather than work
performed on company-owned properties. Oilfield services revenues will continue
to fluctuate year to year based on market demand, the number of wells drilled,
downtime for equipment repairs, the degree of emphasis on utilizing our oilfield
servicing equipment on our company-owned properties and other factors.
Oilfield Servicing Costs. Oilfield servicing costs were $1.1 million,
$642,000 and $240,000 for the years ended December 31, 2000, 1999 and 1998,
respectively, or 84.0%, 74.2% and 74.4% of oilfield servicing revenues,
respectively. During 2000, oilfield servicing costs were a higher percentage of
oilfield services revenues, as compared to 1999 and 1998, due to higher than
normal maintenance and repair costs associated with our oilfield servicing
equipment. During 1999, oilfield servicing costs as a percentage of oilfield
services revenues, were relatively flat as compared to the same period of 1998.
In general, oilfield servicing costs are directly associated with oilfield
services revenues. As such, oilfield servicing costs will continue to fluctuate
year to year based on revenues generated, market demand, the number of wells
drilled, downtime for equipment repairs, the degree of emphasis on utilizing our
oilfield servicing equipment on our company-owned properties and other factors.
35
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $247,000, $334,000 and $322,000 for the years ended December 31, 2000, 1999
and 1998, respectively. We spent $779,000, $138,000 and $156,000 on upgrading
our oilfield servicing equipment during 2000, 1999 and 1998, respectively. DD&A
expense was $87,000 lower during 2000, as compared to 1999, due to prior year
capital additions becoming fully depreciated during 2000. DD&A expense was
$12,000 higher during 1999, as compared to 1998, due to prior year capital
additions being depreciated for an entire year.
Nonsegmented Items
DD&A Expense - Corporate. DD&A expense for corporate activities was
$66,000, $110,000 and $118,000 for the years ended December 31, 2000, 1999 and
1998, respectively. We spent $33,000, $20,000 and $85,000 during 2000, 1999 and
1998, 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 coupled with a lesser amount of asset additions
in the ensuing years.
G&A Costs. G&A costs were $2.7 million, $3.0 million and $2.6 million
for the years ended December 31, 2000, 1999 and 1998, respectively. 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. During 1999, G&A costs were $390,000
higher, as compared to the same period of 1998, primarily due to higher payroll
and other related costs associated with our increasing emphasis on expanding our
activities in Poland. Subject to available funding, G&A costs are expected to be
at current or higher levels in future periods as we expand our presence in
Poland.
Amortization of Deferred Compensation. Amortization of deferred
compensation was $652,000 for the year ended December 31, 2000. There was no
amortization of deferred compensation during the years ended December 31, 1999
and 1998. 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
deferred compensation cost of $1.6 million, including $1.2 million covering the
intrinsic value applicable to officers and employees and $378,000 covering the
fair market value calculated using the Black-Scholes model for a consultant, to
be amortized to expense over the one-year vesting period.
Interest and Other Income. Interest and other income were $557,000,
$512,000 and $506,000 for the years ended December 31, 2000, 1999 and 1998,
respectively. Our cash, cash equivalent and marketable debt securities balances
were $2.4 million, $6.9 million and $4.7 million as of December 31, 2000, 1999
and 1998, respectively. The average cash and marketable securities balances
during 2000, 1999, and 1998 were relatively constant from year to year. We
earned interest income of $531,000, $499,000 and $492,000 during 2000, 1999 and
1998, respectively. Accrued interest income associated with officers' notes
receivable was $140,000, $134,000 and $64,000 during 2000, 1999 and 1998,
respectively.
Interest Expense. Interest expense was $2,000 and $8,000 for the years
ended December 31, 2000 and 1999. We had no interest expense for the year ended
December 31, 1998. 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. During the three years ended December 31, 2000, 1999 and 1998,
we had no long-term debt.
Officer Loan Impairment. Officer loan impairment was $738,000 and
$666,000 for the years ended December 31, 2000 and 1999, respectively. There was
no officer loan impairment for the year ended December 31, 1998. In accordance
with SFAS No. 114 "Accounting by Creditors for Impairment of a Loan," the notes
receivable from officers carrying value was $773,000 as of December 28, 2000,
including principal and interest of $2.2 million reduced by an impairment
allowance of $1.4 million based on the market value of 233,340 shares of the our
common stock held as collateral. On December 28, 2000, the officers surrendered
the collateral shares to us in return for the
36
cancellation of the notes receivable from officers and we recorded the resulting
acquisition of 233,340 shares of treasury stock at a cost of $773,000.
Income Taxes. We incurred net losses of $10.8 million, $5.9 million and
$10.1 million for the years ended December 31, 2000, 1999 and 1998,
respectively, which can be carried forward to offset future taxable income. 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.
Net Loss. We incurred net losses of $10.8 million, $5.9 million and
$10.1 million for the years ended December 31, 2000, 1999 and 1998,
respectively. The net loss in 2000 was due principally to $7.4 million of
exploration costs, an officer loan impairment of $738,000 and $2.7 million of
G&A costs. The net loss in 1999 was due principally to $3.1 million of
exploration costs, an officer loan impairment of $666,000 and $3.0 million of
G&A costs. The net loss in 1998 was due principally to $2.1 million of
exploration costs, a domestic proved property impairment of $5.9 million and
$2.6 million of G&A costs.
Liquidity and Capital Resources
Historically, we have relied primarily on proceeds from the sale of our
common stock to fund our operating and investing activities. During March 2001,
we signed a $5.0 million loan agreement with RRPV to partially fund our planned
ongoing activities in Poland during 2001. 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. We also benefit from funds provided by our
industry partners, primarily Apache.
Working Capital. We had working capital of $616,000, $5.5 million and
$4.0 million as of December 31, 2000, 1999 and 1998, respectively. Working
capital as of December 31, 2000, was $4.8 million lower, as compared to the end
of 1999, primarily due to a net loss of $10.8 million during 2000, which was
partially offset by net proceeds of $9.3 million from a private placement of
2,969,000 shares of our common stock. Working capital as of December 31, 1999,
was $1.5 million higher, as compared to the end of 1998, primarily due to net
proceeds of $7.1 million from the private placement of 1,792,500 shares of our
common stock, which was partially offset by a $5.9 million net loss during 1999.
Operating Activities. We used net cash of $6.1 million, $3.0 million
and $3.1 million in our operating activities during 2000, 1999 and 1998,
respectively, primarily as a result of the net losses incurred in those years.
During 2000, 1999 and 1998, we spent $6.4 million, $3.4 million and $4.0
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 $335,000 $450,000 and $869,000 during 2000, 1999 and
1998, respectively.
Investing Activities. We used net cash of $3.9 million and $3.7 million
in investing activities during 2000 and 1999, respectively. During 1998, we
received net cash from investing activities of $1.1 million. During 2000, we
spent $2.0 million on exploratory dry holes, $2.6 million on additions to proved
properties, $2.3 million on additions to unproved properties, $779,000 on
additions to oilfield servicing equipment, $33,000 on corporate assets, $6.3
million on purchasing marketable debt securities and received $10.3 million from
maturing or sold marketable debt securities. During 1999, we spent $1.0 million
on exploratory dry holes, $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. During 1998, we spent $17,000 on
exploratory dry holes, $441,000 on additions to properties, equipment and other
assets, received $513,000 of proceeds from the sale of property interests and
equipment, spent $6.6 million on purchasing marketable debt securities and
received $7.6 million from maturing or sold marketable debt securities.
37
Financing Activities. We received net cash of $9.4 million and $6.5
million from our financing activities during 2000 and 1999, respectively. During
1998, we used net cash of $674,000 in our financing activities. 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 common stock.
During 1998, we advanced $840,000 to officers and received $166,000 in cash and
a full recourse note receivable of $250,000 from the exercise of options and
warrants to purchase 382,622 shares of our common stock.
In the past, our strategic partners have provided a substantial amount
of the capital required under our exploration agreements with them. We
anticipate they may continue to do so in the future. For instance, in 1997,
Apache committed to cover our share of an exploration program in Poland
originally estimated to cost $60.0 million gross (approximately $30.0 million
net). Based on the original estimate, Apache had spent approximately of $48.0
million of those gross costs through December 31, 2000. As of December 31, 2000,
Apache had a remaining commitment to cover our share of approximately $5.1
million of net costs in Poland, comprised primarily of the following items:
o our share of costs to drill three exploratory wells (two of
which were drilling as of December 31, 2000);
o the first $818,000 of costs (other than carried costs)
incurred after December 31, 2000;
o our 45.0% share of costs to flow test and, if warranted,
complete the Wilga 2 for production; and
o 15.0% (to be reduced by 5.0% as each of the three remaining
exploratory wells are drilled) of Apache's G&A in Poland,
computed on a monthly basis.
Other industry partners have previously covered approximately $2.9
million of our share of costs in other projects during the last five years.
Capital Requirements
General. As of December 31, 2000, we had approximately $2.4 million of
cash, cash equivalents and marketable debt securities with no long-term debt. We
believe this amount, along with the proceeds of a $5.0 million loan agreement we
signed during March 2001 with RRPV, the remaining Apache carried costs and
positive cash flow generated from our E&P and oilfield services segments, will
be sufficient to cover our minimum exploration and operating commitments during
2001. We have initiated discussions with commercial lenders and other gas
purchasers for possible project funding related to our recent discoveries in
Poland as well as possible other future discoveries. In order to fully fund or
accelerate our current planned exploration and development activities, we will
need additional capital. The timing, pace, scope and amount of our capital
expenditures are largely dependent on the availability of capital.
RRPV Financing. In March 2001, we signed a $5.0 million 9.5%
convertible note with RRPV. The proceeds are to be used for exploration and
development of additional gas reserves in Poland. In consideration for the loan,
we granted RRPV an option to purchase up to 17 Mmcf per day of gas we produce in
Poland. If RRPV elects to buy gas we produce in Poland, the loan will be
repayable over eight years. If RRPV elects not to buy our gas, the loan will be
repayable in March 2003 unless converted to restricted common stock at $5.00 per
share, subject to adjustment in certain circumstances. As security for the loan,
we have granted RRPV a lien on a portion of our gas reserves in Poland.
Fences Project Area. We have agreed to spend $16.0 million of
exploration costs on the Fences project area to earn a 49.0% interest. To date,
we have paid approximately $6.7 million of this commitment, including $2.4
million to drill the Kleka 11, $2.2 million of drilling costs relating to the
Mieszkow 1 and $2.1 million to commence two separate 3-D seismic data surveys.
After we complete our $16.0 million commitment, POGC will begin bearing
38
its 51.0% share of further costs. During 2001, we expect to spend approximately
$1.7 million to finish processing the Zaniemysl and Donatowo 3-D seismic grids,
$1.2 million on Mieskow 1 and approximately $2.8 million each on one or more
additional exploratory wells, as warranted and as funding permits.
Apache Exploration Program. During most of 2001, we expect that a
substantial portion of our share of costs relating to the Apache Exploration
Program will be covered by Apache. We have elected to utilize our tenth and
final well carry on the Chojnice 108-6, an exploratory well on the Pomeranian
project area, where we have a 42.5% working interest. In addition, Apache must
cover the first $818,000 of costs we incur during 2001 (other than carried
costs) relating to our joint activities with Apache in Poland and the portion of
Apache Poland G&A that is attributable to the uncompleted portion of Apache's
ten exploratory well work commitment.
During 2001, on the Pomeranian project area, we plan to participate in
an approximately $1.2 million gross 2-D seismic program covering approximately
280 kilometers to confirm Main Dolomite Reef leads on regional 2-D seismic data
and drill one or more exploratory wells (including the Chojnice 108-6), costing
approximately $2.8 million gross each to drill and complete, as warranted and as
funding permits.
During the first half of 2001, on the Lublin project area, Apache will
cover our 45.0% share of costs for an extended flow test on the Wilga 2 well
and, if warranted, completion of the well for production. The Wilga 2 extended
flow test will assess the potential for commercial production in light of
pipeline and facility expenditures that would be required.
On the Warsaw West project area, we and Apache are currently evaluating
whether to acquire an additional 520 kilometers of 2-D seismic data by November
2001, in order to fulfill the remaining work commitment required for the first
three year exploration period on the Warsaw West project area usufruct.
On the Carpathian project area, we and Apache are currently evaluating
whether to acquire an additional 339 kilometers of 2-D seismic data and commence
drilling an exploratory well by the end of 2001, in order to fulfill the
remaining work commitments required for the first three year exploration period
on the usufruct.
Other. If we have the opportunity to participate in additional
appraisal, development or exploration projects with POGC, we may be required to
obtain additional capital. We expect to incur minimal exploration expenditures
on our Baltic project area in Poland during 2001. Similarly, we expect to incur
minimal exploration, appraisal and development expenditures on our domestic
operations during 2001.
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. We may obtain funds for
future capital investments from the sale of additional securities, project
financing, sale of partial property interests, strategic alliances with other
energy or financial partners or other arrangements, all of which may dilute the
interest of our existing stockholders or our interest in the specific project
financed.
39
- --------------------------------------------------------------------------------
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
- --------------------------------------------------------------------------------
Market Risk
Our major market risk exposure continues to be the price we receive for
our production. Realized pricing is primarily driven by the prevailing worldwide
price of oil applicable to the United States, and the domestic price of gas in
Poland, subject to gravity, energy content and other adjustments for the actual
oil and gas sold. Historically, oil and gas prices have been volatile and
unpredictable. Price volatility relating to our domestic oil production and
Polish gas production is expected to continue into the future. See "Items 1. and
2. Business and Properties: Risk Factors."
We do not engage in any hedging activities to protect ourselves against
market risks associated with oil and gas price fluctuations, although we may
elect to do so if we achieve a significant amount of production in Poland. We
currently do not have any derivative financial instruments.
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 4.13, 4.14 and 3.51 per U.S. dollar as of December 31,
2000, 1999 and 1998, 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.
- --------------------------------------------------------------------------------
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.
40
PART III
- --------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2001 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 2001 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 2001 annual
meeting of stockholders under the caption "ELECTION OF DIRECTORS: Security
Ownership of Certain Beneficial Owners and Management" is incorporated herein by
reference.
As of December 31, 2000, we had options and warrants that were issued
and outstanding to purchase an aggregate of up to 4,572,917 shares of common
stock at exercise prices ranging from $1.50 to $10.25 per share, with a weighted
average exercise price of $5.16 per share. Of those warrants and options,
3,462,200 shares of common stock are issuable on the exercise of options held by
our officers and directors at exercise prices ranging from $1.50 to $10.25 per
share, with a weighted average exercise price of $4.87 per share, including
options to purchase 2,284,207 shares that are not fully vested. The existence of
such warrants and options may prove to be a hindrance to future financing by us,
and the exercise of such warrants and options may further dilute the interests
of all other stockholders. The possible future resale of common stock issuable
on the exercise of such warrants and options could adversely affect the
prevailing market price of our common stock. Further, the holders of options and
warrants may exercise them at a time when we would otherwise be able to obtain
additional equity capital on terms more favorable to us.
- --------------------------------------------------------------------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2001 annual
meeting of stockholders under the caption "ELECTION OF DIRECTORS: Certain
Relationships and Related Transactions" is incorporated herein by reference.
41
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, 2000
and 1999............................................... F-2
Consolidated Statements of Operations for each of
the three years ended December 31, 2000, 1999 and
1998, respectively..................................... F-3
Consolidated Statements of Cash Flows for each of
the three years ended December 31, 2000, 1999 and
1998, respectively..................................... F-5
Consolidated Statements of Stockholders' Equity for
each of the three years ended December 31, 2000,
1999 and 1998, 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(11)
3.2 3 Bylaws Incorporated by
Reference(1)
Item 4. Instruments Defining the Rights of Security Holders
-----------------------------------------------------------------------------------
4.1 4 Specimen Stock Certificate Incorporated by
Reference(1)
4.2 4 Form of Designation of Rights, Privileges, and Preferences Incorporated by
of Series A Preferred Stock Reference(14)
4.3 4 Form of Rights Agreement dated as of April 4, 1997, Incorporated by
between FX Energy, Inc. and Fidelity Transfer Corp. Reference(14)
42
SEC
Exhibit Reference
Number Number Title of Document Location
---------- ----------- ------------------------------------------------------------ -----------------
Item 10. Material Contracts
-----------------------------------------------------------------------------------
10.1 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and Frontier Poland Exploration Reference(3)
and Producing Company, Sp. z o.o. dated August 22, 1995,
relating to Blocks 51, 52, 71, 72, 91, 92, 93, 111, 112
and 113 (Baltic)
10.2 10 Amendment No. 1 to Mining Usufruct Agreement dated August Incorporated by
15, 1996 (Baltic) Reference(4)
10.3 10 Amendment No. 2 to Mining Usufruct Agreement dated August Incorporated by
22, 1996 (Baltic) Reference(15)
10.4 10 Form of concession dated December 20, 1995, relating to Incorporated by
Baltic Concessions granted pursuant to the Mining Reference(5)
Usufruct Agreement dated August 15, 1996, with related
schedule
10.5 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and Lubex Petroleum Company Sp. z Reference(10)
o.o. dated December 20, 1996, relating to concession
blocks 255, 275, 295, 316, 336, 337 and 338 (Lublin)
10.6 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and Apache Poland Sp. z o.o. and Reference(12)
FX Energy Poland Sp. z o.o. (East), commercial
partnership dated October 14, 1997, related to
concession blocks 257, 258, 277, 278, 297, 317 and 318
(Lublin)
10.7 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and Apache Poland Sp. z o.o. and Reference(12)
FX Energy Poland Sp. z o.o. (East), commercial
partnership dated October 14, 1997, related to
concession block 298 (Lublin)
10.8 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and Apache Poland Sp. z o.o. and Reference(12)
FX Energy Poland Sp. z o.o. (East), commercial
partnership dated October 14, 1997, related to
concession blocks 319, 320, 339, 340, 340A, 359, 360,
360A, 379, 380 and 380A (Lublin)
10.9 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and FX Energy Poland Sp. z o.o. Reference(12)
(East) and Gasex Production Company Sp. z o.o.,
commercial partnership, dated October 14, 1997, related
to concession blocks 410, 411, 412, 413, 414, 415, 430,
431, 432, 433, 452 and 453 (Western Carpathian)
43
SEC
Exhibit Reference
Number Number Title of Document Location
---------- ----------- ------------------------------------------------------------ -----------------
10.10 10 Mining Usufruct Agreement between the State Treasury of Incorporated by
the Republic of Poland and FX Energy Poland Sp. z o.o. Reference(12)
and Partners, commercial 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 Incorporated by
and Gas Company, FX Energy, Inc. and Apache Overseas, Reference(12)
Inc.
10.12 10 Participation Agreement dated effective as of April 16, Incorporated by
1997, between Apache Overseas, Inc. and FX Energy, Inc. Reference(13)
pertaining to the Lublin Concessions
10.13 10 Letter Agreement dated February 27, 1998, between FX Incorporated by
Energy, Inc. and Apache Overseas, Inc. regarding Reference(15)
modification to all agreements for acreage in Poland
under established area of mutual interest
10.14 10 Participation Agreement dated effective February 27, 1998, Incorporated by
between FX Energy, Inc. and Apache Overseas, Inc. Reference(15)
pertaining to the Western Carpathian Concession
10.15 10 Participation Option Agreement dated effective Incorporated by
February 27, 1998, between FX Energy, Inc. and Apache Reference(15)
Overseas, Inc. pertaining to the Pomeranian Concession
10.16 10 Prospect Agreement between Apache Poland Sp. z o.o. and FX Incorporated by
Energy Poland Sp. z o.o. dated April 17, 1998 Reference(18)
10.17 10 Option Agreement dated effective as of February 2, 1998, Incorporated by
between POGC, FX Energy, Inc. and Apache Overseas, Inc. Reference (15)
pertaining to the Western Carpathian Concessions
10.18 10 Option Agreement dated March 5, 1998, effective as of Incorporated by
April 16, 1997, between FX Energy, Inc., Apache Reference(17)
Overseas, Inc. and POGC, relating to FX Energy's
Carpathian Area Concessions.
10.19 10 Option Agreement between FX Energy Poland Sp. z o.o. and Incorporated by
POGC dated effective May 20, 1998, relating to Reference(19)
Pomeranian Concessions
10.20 10 Agreement dated October 21, 1996, between Sudety Mining Incorporated by
Company Sp. z o.o. and the State Treasury of the Reference(9)
Republic of Poland, for the establishment of the mining
usufruct for the purpose of gold exploration in the
Sudety Concessions
10.21 10 Earn-In and Exploration Letter of Intent dated June 13, Incorporated by
1997, between FX Energy, Inc. and Homestake Mining Reference(12)
Company of California
44
SEC
Exhibit Reference
Number Number Title of Document Location
---------- ----------- ------------------------------------------------------------ -----------------
10.22 10 Form of Mining Usufruct Agreement between the State Incorporated by
Treasury of the Republic of Poland and FX Energy Poland Reference(15)
Sp. z o.o. Commercial Partnership, dated October 16,
1997, relating to Sudety Concession blocks 43, 63, 64,
65, with related schedule.
10.23 10 Earn-in, Exploration, and Joint Venture Agreement between Incorporated by
Homestake Mining Company of California and FX Energy, Reference(15)
Inc., effective December 31, 1997, regarding exploration
for precious metals in the Republic of Poland (Sudety)
10.24 10 Agreement between Apache Overseas, Inc. and FX Energy, Incorporated by
Inc. dated effective January 1, 1999, pertaining to oil Reference(20)
and gas operations in Poland
10.25 10 Agreement on Cooperation in the Lachowice Area between Incorporated by
POGC, Apache Overseas, Inc., Apache Poland, Sp. Z o.o., Reference(20)
FX Energy, Inc. and FX Energy Poland Sp. Z o.o. dated
February 26, 1999
10.26 10 Frontier Oil Exploration Company 1995 Stock Option and Incorporated by
Award Plan* Reference(4)
10.27 10 Form of FX Energy, Inc. 1996 Stock Option and Award Plan* Incorporated by
Reference(10)
10.28 10 Form of FX Energy, Inc. 1997 Stock Option and Award Plan* Incorporated by
Reference(20)
10.29 10 Form of FX Energy, Inc. 1998 Stock Option and Award Plan* Incorporated by
Reference(20)
10.30 10 Employment Agreements between FX Energy, Inc. and each of Incorporated by
David Pierce and Andrew Pierce, effective January 1, Reference(1)
1995*
10.31 10 Amendments to Employment Agreements between FX Energy, Incorporated by
Inc. and each of David Pierce and Andrew Pierce, Reference(8)
effective May 30, 1996*
10.32 10 Form of Stock Option with related schedule (D. Pierce and Incorporated by
A. Pierce)* Reference(1)
10.33 10 Form of Stock Option granted to D. Pierce and A. Pierce* Incorporated by
Reference(1)
10.34 10 Form of Non-Qualified Stock Option with related schedule* Incorporated by
Reference(4)
10.35 10 Letter Agreement dated effective August 3 , 1995, between Incorporated by
Lovejoy Associates, Inc. and FX Energy, Inc. re: Reference(4)
Financial Consulting Engagement*
45
SEC
Exhibit Reference
Number Number Title of Document Location
---------- ----------- ------------------------------------------------------------ -----------------
10.36 10 Letter Agreement dated effective August 3, 1995, between Incorporated by
Lovejoy Associates, Inc. and FX Energy, Inc. re: Reference(4)
Indemnification
10.37 10 Non-Qualified Stock Option granted to Thomas B. Lovejoy* Incorporated by
Reference(4)
10.38 10 Letter Agreement dated effective December 31, 1997, Incorporated by
between FX Energy, Inc. and Lovejoy Associates, Inc. re: Reference(15)
Extension of Consulting Engagement*
10.39 10 Employment Agreement between FX Energy, Inc. and Jerzy B. Incorporated by
Maciolek* Reference(8)
10.40 10 Addendum to Employment Agreement between FX Energy, Inc. Incorporated by
and Jerzy B. Maciolek* Reference(15)
10.41 10 Second Addendum to Employment Agreement between FX Energy, Incorporated by
Inc. and Jerzy B. Maciolek* Reference(15)
10.42 10 Employment Agreement between FX Energy, Inc. and Scott J. Incorporated by
Duncan* Reference(15)
10.43 10 Form of Indemnification Agreement between FX Energy, Inc. Incorporated by
and certain directors, with related schedule* Reference(10)
10.44 10 Form of Option granted to executive officers and Incorporated by
directors, with related schedule* Reference(10)
10.45 10 Memorandum of Understanding regarding officer loans Incorporated by
(reformed June 19, 1998) Reference(16)
10.46 10 Limited Recourse Promissory Note of David N. Pierce in the Incorporated by
amount of $950,954 (reformed June 19, 1998) Reference(16)
10.47 10 Pledge and Security Agreement between FX Energy, Inc. and Incorporated by
David N. Pierce (reformed June 19, 1998) Reference(16)
10.48 10 Agreement To Hold Collateral between FX Energy, Inc. and Incorporated by
David N. Pierce and Kruse, Landa & Maycock, as agent to Reference(16)
hold collateral (reformed June 19, 1998)
10.49 10 Limited Recourse Promissory Note of Andrew W. Pierce in Incorporated by
the amount of $769,924 (reformed June 19, 1998) Reference(16)
10.50 10 Pledge and Security Agreement between FX Energy, Inc. and Incorporated by
Andrew W. Pierce (reformed June 19, 1998) Reference(16)
10.51 10 Agreement To Hold Collateral between FX Energy, Inc. and Incorporated by
Andrew W. Pierce and Kruse, Landa & Maycock, as agent to Reference(16)
hold collateral (reformed June 19, 1998)
10.52 10 Form of Indemnification Agreement between FX Energy, Inc. Incorporated by
and certain directors, with related schedule Reference(20)
46
SEC
Exhibit Reference
Number Number Title of Document Location
---------- ----------- ------------------------------------------------------------ -----------------
10.53 10 Agreement on Cooperation in Exploration of Hydrocarbons on Incorporated by
Foresudetic Monocline dated April 11, 2000, between Reference(22)
Polskie Gornictwo Naftowe I 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 Incorporated by
Energy, Inc. and Apache Overseas, Inc. Reference(23)
10.55 10 Option extensions with related schedules Incorporated by
Reference(24)
10.56 10 Poland 2001 Agreement dated as of January 1, 2001, between This Filing
Apache Overseas, Inc. and FX Energy, Inc.
10.57 10 US$5,000,000 9.5% Convertible Secured Note dated as of This Filing
March 9, 2001
10.58 10 Form of Pledge Agreement FX Energy Poland Sp. z o.o. and This Filing
Rolls Royce Power Ventures Limited dated March 9, 2001
and related schedules
Item 21 Subsidiaries of the Registrant
-----------------------------------------------------------------------------------
21.1 Schedule of Subsidiaries Incorporated by
Reference(15)
Item 23 Consents of Experts and Counsel
-----------------------------------------------------------------------------------
23.1 23 Consent of PricewaterhouseCoopers LLP, independent This Filing
accountants
23.2 23 Consent of Larry D. Krause, Petroleum Engineer This Filing
23.3 23 Consent of Troy-Ikoda Limited, Petroleum Engineers This Filing
- --------------------------------
Incorporated by reference notes:
* Identifies each management contract or compensatory plan or
arrangement required to be filed as an exhibit.
(1) Incorporated by reference from the registration statement on
Form SB-2, SEC File No. 33-88354-D.
(2) Incorporated by reference from the report on Form 8-K dated
August 16, 1995.
(3) Incorporated by reference from the report on Form 8-K dated
August 22, 1995.
(4) Incorporated by reference from the quarterly report on Form
10-Q for the quarter ended September 30, 1995.
(5) Incorporated by reference from the annual report on Form 10-K
for the year ended December 31, 1995.
(6) Incorporated by reference from the reports on Form 8-K dated
May 3, 1996.
(7) Incorporated by reference from the report on Form 8-K dated
May 21, 1996.
(8) Incorporated by reference from the registration statement on
Form S-1, SEC File No.333-05583.
(9) Incorporated by reference from the report on Form 8-K dated
October 1, 1996.
(10) Incorporated by reference from the annual report on Form
10-KSB for the year ended December 31, 1996.
(11) Incorporated by reference from the proxy statement respecting
the 1997 annual meeting of shareholders.
(12) Incorporated by reference from the quarterly report on Form
10-QSB for the quarter ended September 30, 1997.
(13) Incorporated by reference from the report on Form 8-K dated
August 6, 1997.
(14) Incorporated by reference from the report on Form 8-K dated
April 4, 1997.
(15) Incorporated by reference from the annual report on Form
10-KSB for the year ended December 31, 1997.
Incorporated by reference notes (continued):
47
(16) Incorporated by reference from the annual report on Form 10-Q
for the quarter ended March 31, 1998, as amended on Form
10-Q/A filed July 15, 1998.
(17) Incorporated by reference from the report on Form 8-K dated
March 23, 1998.
(18) Incorporated by reference from the report on Form 8-K dated
April 20, 1998.
(19) Incorporated by reference from the report on Form 8-K dated
June 2, 1998.
(20) Incorporated by reference from the annual report on Form 10-K
for the year ended December 31, 1999.
(21) Incorporated by reference from the report on Form 8-K dated
April 11, 2000.
(22) Incorporated by reference from the quarterly report on Form
10-Q for the quarter ended March 31, 2000.
(23) Incorporated by reference from the quarterly report on Form
10-Q for the quarter ended September 30, 2000
(b) Reports on Form 8-K.
During the quarter ended December 31, 2000, we filed the following
items on Form 8-K:
Date of Event Reported Item(s) Reported
--------------------------- --------------------------
October 23, 2000 Item 5. Other Events
November 3, 2000 Item 5. Other Events
December 8, 2000 Item 5. Other Events
December 18, 2000 Item 5. Other Events
48
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: March 15, 2001. FX ENERGY, INC.
(Registrant)
/s/ David N. Pierce
-------------------------------
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: March 15, 2001
/s/ David N. Pierce
----------------------------------------------------
David N. Pierce, Director and President
(Principal Executive and Financial Officer)
/s/ Andrew W. Pierce
----------------------------------------------------
Andrew W. Pierce, Director, Vice President
(Principal Operations Officer)
/s/ Jerzy B. Maciolek
----------------------------------------------------
Jerzy B. Maciolek, Vice President International
Exploration
and Director
/s/ Thomas B. Lovejoy
----------------------------------------------------
Thomas B. Lovejoy, Director,
Chief Financial Officer and Vice Chairman
/s/ Scott J. Duncan
----------------------------------------------------
Scott J. Duncan, Director, Vice President
Investor Relations and Secretary
/s/ Dennis L. Tatum
----------------------------------------------------
Dennis L. Tatum, Director, Vice President
and Treasurer (Principal Accounting Officer)
/s/ Peter L. Raven
----------------------------------------------------
Peter L. Raven, Director
/s/ Jay W. Decker
----------------------------------------------------
Jay W. Decker, Director
/s/ Dennis B. Goldstein
----------------------------------------------------
Dennis B. Goldstein, Director
49
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors
of FX Energy, Inc. and Subsidiaries:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, cash flows, and stockholders' equity
present fairly, in all material respects, the consolidated financial position of
FX Energy, Inc., and Subsidiaries (the "Company") as of December 31, 2000 and
1999, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 2000, 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Salt Lake City, Utah
March 12, 2001
F-1
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2000 and 1999
2000 1999
----------------- ----------------
ASSETS
Current assets:
Cash and cash equivalents........................................................... $ 1,079,038 $ 1,619,237
Investment in marketable debt securities............................................ 1,281,993 5,249,003
Receivables:
Accrued oil sales............................................................... 250,954 243,183
Joint interest and other receivables............................................ 143,763 86,723
Interest receivable............................................................. 31,935 171,242
Inventory........................................................................... 87,920 66,361
Other current assets................................................................ 80,313 126,006
----------------- ----------------
Total current assets........................................................ 2,955,916 7,561,755
----------------- ----------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved.......................................................................... 4,318,056 1,687,089
Unproved........................................................................ 3,031,863 1,382,880
Other property and equipment........................................................ 3,333,791 2,652,102
----------------- ----------------
Gross property and equipment.................................................... 10,683,710 5,722,071
Less accumulated depreciation, depletion and amortization........................... (3,428,649) (3,173,493)
----------------- ----------------
Net property and equipment...................................................... 7,255,061 2,548,578
----------------- ----------------
Other assets:
Certificates of deposit............................................................. 356,500 356,500
Deposits............................................................................ 2,789 2,789
----------------- ----------------
Total other assets.............................................................. 359,289 359,289
----------------- ----------------
Total assets............................................................................ $ 10,570,266 $ 10,469,622
================= ================
-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, 2000 and 1999
-Continued-
2000 1999
----------------- ----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.................................................................... $ 598,926 $ 623,911
Accrued liabilities................................................................. 1,740,604 1,478,862
Total current liabilities................................................... 2,339,530 2,102,773
----------------- ----------------
Commitments (Note 5)
Stockholders' equity:
Preferred stock, $.001 par value, 5,000,000 shares authorized as of December
31, 2000 and 1999; no shares outstanding........................................ -- --
Common stock, $.001 par value, 100,000,000 and 30,000,000 shares authorized
as of December 31, 2000 and 1999, respectively; 17,913,575 and
14,849,003 shares issued as of December 31, 2000 and 1999, respectively......... 17,914 14,849
Treasury stock, at cost, 233,340 shares as of December 31, 2000;
no shares as of December 31, 1999............................................... (773,055) --
Notes and interest receivable from officers......................................... -- (1,370,873)
Note receivable from stock option exercise.......................................... (156,000) --
Deferred compensation from stock option modifications............................... (913,485) --
Additional paid in capital.......................................................... 49,655,675 38,480,556
Accumulated deficit................................................................. (39,600,313) (28,757,683)
----------------- ----------------
Total stockholders' equity...................................................... 8,230,736 8,366,849
----------------- ----------------
Total liabilities and stockholders' equity.............................................. $ 10,570,266 $ 10,469,622
================= ================
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, 2000, 1999 and 1998
2000 1999 1998
---------------- ----------------- ----------------
Revenues:
Oil sales......................................................... $ 2,520,779 $ 1,554,474 $ 1,123,511
Oilfield services................................................. 1,290,055 864,689 322,769
Gain on sale of property interests................................ -- -- 466,891
---------------- ----------------- ----------------
Total revenues................................................ 3,810,834 2,419,163 1,913,171
---------------- ----------------- ----------------
Operating costs and expenses:
Lease operating expenses.......................................... 1,169,478 899,258 966,732
Production taxes.................................................. 178,921 63,141 79,602
Geological and geophysical costs.................................. 4,679,391 1,959,422 2,109,375
Exploratory dry hole costs........................................ 2,034,206 1,001,433 17,422
Impairment of oil and gas properties.............................. 674,158 92,605 5,885,042
Oilfield services................................................. 1,084,129 641,871 240,061
Depreciation, depletion and amortization.......................... 385,807 494,052 671,277
General and administrative ("G&A") costs.......................... 2,654,430 2,961,878 2,572,212
Apache Poland G&A costs........................................... 956,936 -- --
Amortization of deferred compensation (G&A)....................... 652,489 -- --
---------------- ----------------- ----------------
Total operating costs and expenses............................ 14,469,945 8,113,660 12,541,723
---------------- ----------------- ----------------
Operating loss........................................................ (10,659,111) (5,694,497) (10,628,552)
---------------- ----------------- ----------------
Other income (expense):
Interest and other income......................................... 557,080 511,636 506,209
Interest expense.................................................. (2,422) (7,997) --
Impairment of notes receivable from officers...................... (738,177) (665,512) --
---------------- ----------------- ----------------
Total other income (expense).................................. (183,519) (161,873) 506,209
---------------- ----------------- ----------------
Net loss.............................................................. $ (10,842,630) $ (5,856,370) $ (10,122,343)
================ ================= ================
Basic and diluted net loss per share.................................. $ (.66) $ (.41) $ (.78)
================ ================= ================
Basic and diluted weighted average number of shares
outstanding....................................................... 16,435,436 14,198,724 12,978,900
================ ================= ================
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, 2000, 1999 and 1998
2000 1999 1998
---------------- ----------------- ----------------
Cash flows from operating activities:
Net loss......................................................... $ (10,842,630) $ (5,856,370) $ (10,122,343)
Adjustments to reconcile net loss to net cash used
in operating activities:
Depreciation, depletion and amortization................. 385,807 494,052 671,277
Impairment of oil and gas properties..................... 674,158 92,605 5,885,042
Impairment of notes receivable from officers............. 738,177 665,512 --
Accrued interest income from officer loans............... (140,359) (134,295) (64,170)
Gain on sale of property interests....................... -- -- (466,891)
Exploratory dry hole costs............................... 2,034,206 1,001,433 17,422
Common stock and stock options issued for services....... 80,813 302,687 119,375
Amortization of deferred compensation (G&A).............. 652,489 -- --
Increase (decrease) from changes in working capital items:
Receivables.............................................. 74,496 (100,044) 260,024
Inventory................................................ (21,559) 1,966 (945)
Other current assets..................................... 45,693 (59,953) 20,960
Accounts payable and accrued liabilities................. 236,757 608,285 588,908
---------------- ----------------- ----------------
Net cash used in operating activities................ (6,081,952) (2,984,122) (3,091,341)
---------------- ----------------- ----------------
Cash flows from investing activities:
Additions to oil and gas properties.............................. (6,988,314) (1,224,688) (197,187)
Additions to other property and equipment........................ (812,340) (137,094) (260,877)
Net change in other assets....................................... -- (2,789) --
Proceeds from sale of property interests......................... -- 6,000 506,000
Proceeds from sale of equipment.................................. -- -- 6,928
Purchase of marketable debt securities........................... (6,314,990) (6,617,089) (6,578,332)
Proceeds from marketable debt securities......................... 10,282,000 4,298,000 7,589,000
---------------- ----------------- ----------------
Net cash provided by (used in) investing activities.......... (3,833,644) (3,677,660) 1,065,532
---------------- ----------------- ----------------
Cash flows from financing activities:
Notes receivable from officers................................... -- (597,563) (840,357)
Proceeds from issuance of common stock, net of offering costs.... 9,272,453 7,053,552 --
Proceeds from the exercise of options and warrants............... 102,944 13,250 166,027
---------------- ----------------- ----------------
Net cash provided by (used in) financing activities...... 9,375,397 6,469,239 (674,330)
---------------- ----------------- ----------------
Decrease in cash..................................................... (540,199) (192,543) (2,700,139)
Cash and cash equivalents at beginning of year....................... 1,619,237 1,811,780 4,511,919
---------------- ----------------- ----------------
Cash and cash equivalents at end of year............................. $ 1,079,038 $ 1,619,237 $ 1,811,780
================ ================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
For the years ended December 31, 2000, 1999 and 1998
2000 1999 1998
---------------- ----------------- ----------------
Common shares issued:
Beginning balance................................................. 14,849,003 13,054,503 12,661,881
Sale of common stock.............................................. 2,969,000 1,792,500 --
Exercise of options and warrants.................................. 95,572 2,000 382,622
Common stock issued for services.................................. -- -- 10,000
---------------- ----------------- ----------------
Total common shares outstanding............................... 17,913,575 14,849,003 13,054,503
================ ================= ================
Stockholders' equity:
Common stock, $.001 par value:
Beginning balance............................................. $ 14,849 $ 13,055 $ 12,662
Sale of common stock.......................................... 2,969 1,792 --
Exercise of options and warrants.............................. 96 2 383
Common stock issued for services.............................. -- -- 10
---------------- ----------------- ----------------
Total common stock........................................ 17,914 14,849 13,055
---------------- ----------------- ----------------
Treasury stock:
Acquisition of treasury stock (233,340 shares at cost)........ (773,055) -- --
---------------- ----------------- ----------------
Total treasury stock...................................... (773,055) -- --
---------------- ----------------- ----------------
Notes receivable from officers:
Beginning balance............................................. (1,370,873) (1,304,527) --
Advances to officers.......................................... -- (597,563) (1,240,357)
Interest...................................................... (140,359) (134,295) (64,170)
Impairment.................................................... 738,177 665,512 --
Shares tendered for payment of notes receivable from officers. 773,055 -- --
---------------- ----------------- ----------------
Total notes receivable from officers...................... -- (1,370,873) (1,304,527)
Notes receivable from stock option exercise:
Recourse note receivable from stock option exercise........... (156,000) -- --
---------------- ----------------- ----------------
Total note receivable from stock option exercise.......... (156,000) -- --
---------------- ----------------- ----------------
Deferred compensation from stock option modifications:
Deferred compensation from stock option modifications......... (1,565,974) -- --
Amortization of deferred compensation (G&A)................... 652,489 -- --
---------------- ----------------- ----------------
Total deferred compensation from stock option modifications (913,485) -- --
---------------- ----------------- ----------------
Additional paid in capital:
Beginning balance............................................. 38,480,556 31,112,861 30,377,852
Sale of common stock, net of offering costs................... 9,269,484 7,051,760 --
Exercise of options and warrants.............................. 258,848 13,248 615,644
Common stock and stock options issued for services............ 80,813 302,687 119,365
Deferred compensation from stock option modifications......... 1,565,974 -- --
---------------- ----------------- ----------------
Total additional paid in capital.......................... 49,655,675 38,480,556 31,112,861
---------------- ----------------- ----------------
Accumulated deficit:
Beginning balance............................................. (28,757,683) (22,901,313) (12,778,970)
Net loss for year............................................. (10,842,630) (5,856,370) (10,122,343)
---------------- ----------------- ----------------
Total accumulated deficit................................. (39,600,313) (28,757,683) (22,901,313)
Total stockholders' equity............................................ $ 8,230,736 $ 8,366,849 $ 6,920,076
================ ================= ================
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") operate in the oil and gas industry in
Poland and the United States. In Poland, the Company is engaged in oil and gas
exploration, appraisal, development and property acquisition activities. In the
United States, the Company is engaged in exploring, developing and producing oil
and gas properties and operates an oilfield services company.
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, 2000, 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 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 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 not considered to be
realizable. Depletion, depreciation and amortization ("DD&A") of capitalized
costs of proved oil and gas properties is provided on a property-by-property
basis using the unit-of-production method. The computation of DD&A takes into
consideration dismantlement, restoration and abandonment costs and the
anticipated proceeds from equipment salvage. The estimated dismantlement,
restoration and abandonment costs are expected to be substantially offset by the
estimated residual value of lease and well equipment.
F-7
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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. (Note 12)
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.
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.
Other property and equipment historical cost, presented on a gross basis before
accumulated depreciation, is summarized as follows:
December 31, Estimated
---------------------------- Useful Life
2000 1999 (in years)
------------- ------------- -------------
(In thousands)
Other property and equipment:
Oilfield servicing equipment.................................. $ 2,509 $ 1,906 6
Trucks........................................................ 236 190 5
Building...................................................... 95 80 40
Office equipment and furniture................................ 494 476 3 to 6
------------- -------------
Total..................................................... $ 3,334 $ 2,652
============= =============
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,
-----------------------------------
2000 1999 1998
---------- ----------- -----------
(In thousands)
Non cash investing and financing transactions:
Shares tendered for payment of notes receivable from officers......... $ 773 $ -- $ --
Bonus applied to stock option exercise by officers.................... -- -- 200
Recourse notes receivable from officers due to stock option exercise.. -- -- 250
Reclassification of notes receivable from officers.................... -- -- 150
Recourse note receivable from stock option exercise................... 156 -- --
Non-cash consideration received from the sale of equipment............ 23 -- --
Additions to oil and gas properties financed with accrued liabilities. -- 63 --
Supplemental disclosure of cash paid for interest and income taxes include the
following:
Year Ended December 31,
-----------------------------------
2000 1999 1998
---------- ----------- -----------
(In thousands)
Supplemental disclosure:
Cash paid during the year for interest................................ $ 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 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 1999 and 1998 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 discounted future net cash flows. (Note 13)
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, 2000, 1999 and 1998 were as follows:
Options and
Warrants Price Range
------------------ ------------------
December 31, 2000....................................................... 4,572,917 $1.50 - $10.25
December 31, 1999....................................................... 4,167,073 $1.50 - $10.25
December 31, 1998....................................................... 3,684,239 $1.50 - $10.25
The Company had a net loss in 2000, 1999 and 1998. The above options or warrants
were not included in the computation of diluted earnings per share for the years
ended December 31, 2000, 1999 or 1998 because the effect would have been
antidilutive. On March 9, 2001, the Company entered into a financing agreement
whereby an additional 1.0 million common shares may be issued under certain
circumstances. (Note 14)
F-9
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 2: 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 and 1999, the
Company's marketable debt securities consisted of corporate bonds with remaining
contractual maturities of less than twelve months and a carrying amount which
approximated market value. The Company has classified all of its marketable debt
securities as available for sale as of December 31, 2000 and held to maturity as
of December 31, 1999.
Note 3: Performance Bond Deposits
As of December 31, 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 4: Accrued Liabilities
The Company's accrued liabilities as of December 31, 2000 and 1999 are composed
of the following:
December 31,
----------------------------
2000 1999
------------- -------------
(In thousands)
Accrued liabilities:
Compensation costs........................................................... $ 1,388 $ 985
Contractual bonus............................................................ 300 200
Unproved property additions.................................................. -- 63
Exploratory dry hole costs................................................... -- 99
Seismic costs................................................................ -- 28
Other costs.................................................................. 53 104
------------- -------------
Total.................................................................... $ 1,741 $ 1,479
============= =============
The accrued compensation costs as of December 31, 2000 include $560,000 relating
to the 2000 bonuses and $828,000 pertaining to unpaid 1999 bonuses and accrued
raises. The accrued compensation costs as of December 31, 1999 include unpaid
1999 bonuses only.
Note 5: Commitments
Fences Project Area
On April 11, 2000, the Company signed an agreement with the Polish Oil and Gas
Company, or 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.
During 2000, the Company paid $6,689,000 to POGC under the agreement, including
approximately $4,586,000 for drilling activities and $2,103,000 for 3-D seismic
activities, leaving a remaining commitment of $9,311,000.
Apache Exploration Program
The Apache Exploration Program December 31, consists of various agreements
signed between the Company and Apache Corporation, or Apache, during 1997
through January 1, 2001 (Note 14).
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 and to acquire 2,000 kilometers of 2-D seismic to earn a
fifty-percent interest in the Company's Lublin Basin and Carpathian
F-10
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
project areas. The initial terms were later modified to allow the ten
exploratory wells to be drilled anywhere in Poland. As of December 31, 2000,
Apache has, in effect, paid the Company's share of costs to drill an equivalent
of nine exploratory wells (including two that were being drilled as of December
31, 2000) and to acquire 1,661 kilometers of 2-D seismic.
Capital Requirements
As of December 31, 2000, the Company had approximately $2.4 million of cash,
cash equivalents and marketable debt securities with no long-term debt. The
Company believes this amount, along with the proceeds of a $5.0 million loan
agreement it signed during March 2001 (Note 14), the remaining Apache carried
costs and positive cash flow generated from its E&P and oilfield services
segments, will be sufficient to cover the Company's minimum exploration and
operating commitments during 2001. The Company has initiated discussions with
commercial lenders and other gas purchasers for possible project funding related
to its recent discoveries in Poland as well as possible other future
discoveries. In order to fully fund or accelerate the Company's current planned
exploration and development activities, it will need additional capital. The
timing, pace, scope and amount of the Company's capital expenditures are largely
dependent on the availability of capital.
Employment and Consulting 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. The terms of such employment agreements are automatically extended
for an additional year on the anniversary date of each such agreement. 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.
On July 1, 1996, the Company entered into a three-year employment agreement with
Jerzy B. Maciolek, an officer of the Company. The employment agreement provided
for a contractual bonus of $100,000 to be issued annually on May 12, 1998, 1999
and 2000 to be applied against future stock option exercises. In the event such
bonuses are not used by Mr. Maciolek and his employment with the Company is
terminated, the Company must pay the contractual bonuses to Mr. Maciolek in
cash. As of December 31, 2000, the Company had accrued $300,000 relating to the
contractual bonuses. 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 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.
Effective August 3, 1995, the Company entered into a consulting agreement with
Lovejoy and Associates, a consulting company owned by Tom Lovejoy, a director of
the Company, under which Lovejoy and Associates would advise the Company
respecting future financing alternatives, possible sources of debt and equity
financing, with particular emphasis on funding for the Company's Polish
activities and the Company's relationship with the investment community at a fee
of $10,000 per month commencing October 15, 1995 and continuing through December
31, 1997. The agreement was extended through December 31, 1999 at a rate of
$15,000 per month for January and February 1998 and a subsequent rate of $17,000
per month thereafter. The consulting agreement was terminated effective May 1,
1999 when Mr. Lovejoy became the Company's Chief Financial Officer.
F-11
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 6: Income Taxes
The Company recognized no income tax benefit from the losses generated during
2000, 1999 and 1998. The components of the net deferred tax asset as of December
31, 2000 and 1999 are as follows:
2000 1999
------------- -------------
(In thousands)
Deferred tax liability:
Property and equipment basis differences..................................... $ (213) $ (104)
Deferred tax asset:
Net operating loss carryforwards: 11,340 10,203
United States............................................................ 2,771 977
Poland...................................................................
Oil and gas properties....................................................... 1,218 1,218
Impairment of notes receivable from officers................................. 523 248
Options issued for services.................................................. 143 113
Other........................................................................ 331 193
Valuation allowance.......................................................... (16,113) (12,848)
------------- -------------
Total.................................................................... $ -- $ --
============= =============
The change in the valuation allowance during 2000, 1999 and 1998 is as follows:
Year Ended December 31,
-------------------------------------------
2000 1999 1998
------------- ------------- -------------
(In thousands)
Valuation allowance:
Balance, beginning of year.................................. $ (12,848) $ (10,685) $ (6,131)
Decrease due to property and equipment basis differences.... 109 4 22
Increase due to impairment of oil and gas properties....... -- -- (2,196)
Increase due to net operating loss.......................... (2,931) (1,989) (2,444)
Other....................................................... (443) (178) 64
------------ ------------ ------------
Total................................................... $ (16,113) $ (12,848) $ (10,685)
============ ============ ============
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, 2000 and 1999.
United States NOL
At December 31, 2000, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $30,402,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and $11,653,000 expires subsequent to 2017. The utilization of the NOL
carryforwards in the United States 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 in the United States will be credited to additional paid-in
capital.
F-12
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Polish NOL
As of December 31, 2000, the Company had NOL carryforwards in Poland totaling
approximately $7,428,000, including $4,809,000 and $2,619,000 generated in 2000
and 1999, respectively. The NOL carryforwards in Poland may be carried forward
five years in Poland. However, no more than fifty-percent of the NOL
carryforwards in Poland for any given year may be applied against Polish income
in succeeding years.
Note 7: Private Placement of Common Stock
During June 2000, the Company completed a private placement of 2,969,000 shares
of common stock that resulted in net proceeds of approximately $9,272,000
($10,392,000 gross). The proceeds from this placement were used to partially
fund ongoing exploration and development activities in Poland and for other
general corporate purposes.
On April 8, 1999, the Company initiated a private placement that resulted in the
sale of 1,792,500 shares of common stock for net proceeds of approximately
$7,054,000 ($7,170,000 gross). The proceeds from this placement were used to
partially fund ongoing exploration and development activities in Poland and for
other general corporate purposes.
Note 8: Stock Options and Warrants
Stock Options
As of December 31, 2000, the Company's 1999 Stock Option Plan had issued
options to purchase 474,917 shares out of a maximum total of 500,000 authorized
shares allowed within the 1999 Stock Option Plan. As of December 31, 2000, all
other prior year stock option plans had issued the maximum allowed options under
each respective stock option plan. The Company has submitted the 2000 Stock
Option Plan, which includes a maximum of 600,000 options, for shareholder
approval at the 2001 annual shareholders' meeting. As of the date of this
report, no options had been issued under the 2000 Stock Option Plan.
All stock option plans are each administered by a committee (the "Committee")
consisting of the board of directors or a committee thereof. At its discretion,
the Committee may grant stock options to any employee, including officers, in
the form of incentive stock options ("ISOs"), as defined in the Internal Revenue
Code, or options which do not qualify as ISOs or stock awards. In addition to
the options granted under the stock option plans, the Company also issues
non-qualified options outside the stock option plans. Options granted under
these stock option plans have terms ranging from five to seven years and vest
over periods ranging from the date of grant to three years.
As of December 31, 2000, the Company had options outstanding under the stock
option 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 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:
Year Ended December 31,
-------------------------------------------
2000 1999 1998
------------- ------------- -------------
(In thousands, except per share amounts)
Net loss:
As reported.................................................. $ (10,843) $ (5,856) $ (10,122)
Pro forma.................................................... (12,733) (7,930) (11,680)
Basic and diluted net loss per share:
As reported.................................................. $ (0.66) $ (0.41) $ (0.78)
Pro forma.................................................... (0.77) (0.56) (0.90)
F-13
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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 2000,
1999 and 1998 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 79.8% to 86.6% for 2000,
80.5% for 1999 and 76.2% for 1998; (2) expected lives ranging from four to seven
years; (3) risk-free interest rates at the date of grant ranging from 4.44% to
6.43%; and, (4) dividend yield of zero for each year.
The following table summarizes fixed option activity for the years ended
December 31, 2000, 1999 and 1998:
December 31,
--------------------------------------------------------------------------------
2000 1999 1998
--------------------------------------------------------------------------------
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......... 3,896,501 $ 5.248 3,413,667 $ 5.183 3,357,500 $ 4.473
Granted................... 501,750 $ 4.063 521,000 5.866 480,000 8.875
Exercised................. (75,000) $ 3.000 (2,000) 6.625 (303,000) 1.500
Canceled.................. (334) $ 8.625 (36,166) 7.920 (120,833) 8.400
-------------- -------------- -------------
End of year........... 4,322,917 $ 5.149 3,896,501 $ 5.248 3,413,667 $ 5.183
============== ============== =============
Exercisable at year-end....... 2,744,183 $ 5.613 2,872,681 $ 4.656 2,329,012 $ 4.350
============== ============== =============
The weighted average fair value per share of options granted during 2000, 1999
and 1998 was $2.56, $3.61 and $3.93, respectively.
The following table summarizes information about fixed stock options outstanding
at December 31, 2000:
December 31, 2000
---------------------------------------------------------------------------------------
Outstanding Exercisable
------------------------------------------------------ -------------------------------
Weighted Average
Number of Remaining Weighted Number of Weighted
Exercise Options Contractual Life Average Options Average
Prices Outstanding (in years) Exercise Price Exercisable Exercise Price
-------------------------------------- -------------------- --------------- -------------- ---------------
$ 1.500 178,000 1.59 $ 1.500 -- $ --
3.000 1,625,000 1.73 3.000 1,225,000 3.000
4.063 - 5.750 988,750 6.33 4.894 166,341 5.750
6.625 - 7.375 554,500 5.64 6.802 530,500 6.781
8.250 - 8.875 970,667 3.53 8.700 816,342 8.714
10.250 6,000 4.13 10.250 6,000 10.250
--------------- -------------------- --------------- -------------- ---------------
Total......... 4,322,917 4.72 $ 5.149 2,744,183 $ 5.613
=============== ==================== =============== ============== ===============
F-14
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Warrants
The following table summarizes changes in outstanding and exercisable warrants
during the years ended December 31, 2000, 1999 and 1998:
Year Ended December 31,
-----------------------------------------------------------------------------------
2000 1999 1998
--------------------------- --------------------------- ---------------------------
Number of Price Range Number of Price Range Number of Price Range
Shares Shares Shares
------------ -------------- ------------ -------------- ------------ -------------
Warrants outstanding:
Beginning of year..... 270,572 $1.65 - 6.90 270,572 $1.65 - 6.90 350,194 $1.10 - 6.90
Exercised............. 20,572 $1.65 -- -- 79,622 1.10 - 2.60
------------ ------------ ------------
End of year....... 250,000 $3.00 - 6.90 270,572 $1.65 - 6.90 270,572 $1.10 - 6.90
============ ============ =============
The 250,000 warrants outstanding as of December 31, 2000 are comprised of
150,000 warrants with an exercise price of $6.90 per share and an expiration
date of August 7, 2001 and 100,000 warrants with an exercise price of $3.00 per
share and an expiration date of August 3, 2002.
Option and Warrant Extensions
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. In accordance
with FIN 44 "Accounting for Certain Transactions Involving Stock Compensation,"
the Company incurred deferred compensation costs of $1.6 million, including $1.2
million covering the intrinsic value applicable to officers and employees and
$378,000 covering the fair market value calculated using the Black-Scholes model
for a consultant, to be 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
include a three-year term with annual principal payments of $52,000 plus
interest accrued at 9.5%.
Note 9: 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 $1,838,000. The carrying value of the notes receivable from officers
was $773,000 as of December 28, 2000, including principal of $1,838,000 and
accrued interest of $339,000, which was reduced by an impairment allowance of
$1,404,000 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 $773,000.
F-15
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 10: Quarterly Financial Data (Unaudited)
Summary quarterly information for the years ended December 31, 2000 and 1999 is
as follows:
Quarter Ended
---------------------------------------------------------------------------
December 31 September 30 June 30 March 31
----------------- ----------------- ------------------ ------------------
(In thousands, except per share amounts)
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)
1999:
Revenues...................... $ 785 $ 862 $ 451 $ 321
Operating loss................ (2,746) (1,228) (895) (825)
Net loss...................... (3,272) (1,072) (789) (723)
Basic and diluted net loss per
common share.............. $ (.21) $ (.08) $ (.06) $ (.06)
Note 11: Business Segments
The Company operates within two business segments of the oil and gas industry:
exploration and production ("E&P") and oilfield services. Mining, which is
comprised solely of gold exploration on the Company's Sudety project area in
Poland, has been discontinued and is excluded from the discussion herein.
The Company's revenues associated with its E&P activities are comprised of oil
sales from its producing properties in Montana and Nevada and gains on the sale
of partial property interests of the Company's exploratory properties in Poland.
During 2000, 1999 and 1998, over 85.0% of the Company's total oil sales were to
one purchaser located in Montana. The Company believes this purchaser 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 and 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 the years ended
December 31, 2000, 1999 and 1998 is summarized as follows:
F-16
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Year Ended December 31, 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................... (7,172) 206 (6,966)
DD&A expense................................................. 73 247 320
------------- ------------- -------------
Operating loss........................................... $ (7,245) $ (41) $ (7,286)
============= ============= =============
Identifiable net property and equipment:
Unproved property - Poland (2).............................. $ 3,014 $ -- $ 3,014
Unproved property - Domestic................................. 18 -- 18
Proved properties - Domestic................................. 623 -- 623
Proved properties - Poland................................... 2,429 -- 2,429
Equipment and other.......................................... -- 1,045 1,045
------------- ------------- -------------
Total.................................................... $ 6,084 $ 1,045 $ 7,129
============= ============= =============
Property and equipment capital expenditures (3).................. $ 6,988 $ 780 $ 7,768
============= ============= =============
- ---------------------
(1) 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) Includes $2,157,000 relating to the Mieszkow 1, which was in the
process of being drilled as of December 31, 2000.
(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.
Year Ended December 31, 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................... (2,430) 223 (2,207)
DD&A expense................................................. 51 334 385
------------- ------------- -------------
Operating loss........................................... $ (2,481) $ (111) $ (2,592)
============= ============= =============
Identifiable net property and equipment:
Unproved property - Poland.................................. $ 691 $ -- $ 691
Unproved property - Domestic................................. 692 -- 692
Proved properties - Domestic................................. 494 -- 494
Equipment and other.......................................... -- 581 581
------------- ------------- -------------
Total.................................................... $ 1,877 $ 581 $ 2,458
============= ============= =============
Property and equipment capital expenditures (3).................. $ 1,386 $ 138 $ 1,524
============= ============= =============
- ------------------------
(1) Excludes $31,000 of exploratory costs relating to the Company's gold
concessions.
(2) 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-17
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Year Ended December 31, 1998
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues (1)................................................. $ 1,590 $ 323 $ 1,913
Cash operating costs (2)..................................... 3,025 240 3,265
Non-cash operating costs (3)................................ 119 -- 119
------------- ------------- -------------
Operating income or (loss) before DD&A................... (1,554) 83 (1,471)
DD&A expense................................................. 231 322 553
------------- ------------- -------------
Operating loss............................................ $ (1,785) $ (239) $ (2,024)
============= ============= =============
Identifiable net property and equipment:
Unproved property - Poland.................................. $ 461 $ -- $ 461
Unproved property - Domestic................................. 717 -- 717
Proved properties - Domestic................................. 463 -- 463
Equipment and other.......................................... -- 780 780
------------- ------------- -------------
Total.................................................... $ 1,641 $ 780 $ 2,421
============= ============= =============
Property and equipment capital expenditures (4).................. $ 197 $ 156 $ 353
============= ============= =============
- ---------------------
(1) E&P revenues include $1,123,000 generated domestically and $467,000
generated in Poland.
(2) Excludes $29,000 of exploratory costs relating to the Company's gold
concessions.
(3) Includes Company common stock issued for services of $119,000 and
excludes non-cash impairment charge of $5,885,000 for domestic proved
properties.
(4) E&P property includes $17,000 of costs that were reclassed to
exploratory dry hole costs, $132,000 of proved property additions and
$48,000 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 2000,
1999 and 1998 follows:
Years Ended December 31,
-------------------------------------------
2000 1999 1998
------------- ------------- -------------
(In thousands)
Revenues:
Reportable segments............................................. $ 3,811 $ 2,419 $ 1,913
Non-reportable segments......................................... -- -- --
------------- ------------- -------------
Total revenues................................................. $ 3,811 $ 2,419 $ 1,913
============= ============= =============
Operating loss:
Reportable segments............................................. $ (7,286) $ (2,592) $ (2,024)
Expense or (revenue) adjustments:
Non-reportable segments....................................... -- 31 29
Impairment of domestic proved property........................ -- -- 5,885
Corporate DD&A expense........................................ 66 109 118
General and administrative expenses........................... 2,654 2,962 2,572
Amortization of deferred compensation (G&A)................... 652 -- --
1 --
Other......................................................... 1 -- 1
------------- ------------- -------------
Total net operating loss.................................... $ (10,659) $ (5,694) $ (10,629)
============= ============= =============
Net property and equipment:
Reportable segments............................................. $ 7,129 $ 2,458 $ 2,421
Corporate assets................................................ 126 91 178
------------- ------------- -------------
Net property and equipment.................................... $ 7,255 $ 2,549 $ 2,599
============= ============= =============
Property and equipment capital expenditures:
Reportable segments............................................. $ 7,768 $ 1,524 $ 197
Corporate assets................................................ 33 19 105
------------- ------------- -------------
Net property and equipment capital expenditures............... $ 7,01 $ 1,543 $ 302
============= ============= =============
Note 12: Disclosure about Oil and Gas Properties and Producing Activities
Impairment of Unproved Oil and Gas Properties
During 2000, the Company recorded an impairment expense of $674,000 relating to
the Williston Basin in North Dakota where it no longer has further exploration
plans. During 1999, the Company recorded an impairment expense of $21,000
relating to a prospect located in Nevada where it no longer has exploration
plans and $72,000 relating to the Lachowice Farm-in in Poland after the
recompletion of one shut-in well and the testing of another shut-in well yielded
non-commercial results.
Impairment of Domestic Proved Oil and Gas Properties
In accordance with SFAS No. 121 "Accounting for the Impairment of Long-Lived
Assets and for the Long-Lived Assets to be disposed of," the Company must record
an impairment expense if the Company determines the net book value of its proved
oil and gas properties, on a property-by-property basis, exceeds the aggregate
future net revenues from such properties. As of December 31, 1998, the Company's
future undiscounted net revenues from its domestic proved developed properties
was $1,015,000 and its discounted future net revenues (PV-10 Value) of it
domestic proved developed properties was $472,000. The future net revenues at
December 31, 1998 were computed using a price of $8.11 per barrel, the average
price at December 31, 1998. Accordingly, the Company recorded an impairment
expense of $5,885,000 in 1998, which reduced the carrying value of its domestic
proved properties to $463,000, an amount which approximated the fair value of
its domestic proved developed reserves determined on a property-by-property
basis.
F-19
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Capitalized Oil and Gas Property Costs
Capitalized costs relating to oil and gas exploration and production activities
as of December 31, 2000 and 1999 are summarized as follows:
Domestic Poland Total
------------- ------------- -------------
(In thousands)
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
============= ============= =============
December 31, 1999:
Proved properties............................................. $ 1,687 $ -- $ 1,687
Unproved properties........................................... 692 691 1,383
------------- ------------- -------------
Total gross properties...................................... 2,379 691 3,070
Less accumulated depreciation, depletion and amortization..... (1,193) -- (1,193)
------------- ------------- -------------
Total.................................................. $ 1,186 $ 691 $ 1,877
============= ============= =============
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities
during 2000, 1999 and 1998, whether capitalized or expensed, are summarized as
follows:
Domestic Poland Total
------------- ------------- -------------
(In thousands)
Year ended December 31, 2000:
Acquisition of properties:
Proved.................................................... $ -- $ -- $ --
Unproved.................................................. -- 21 21
Exploration costs (1)......................................... 692 11,200 11,892
Development costs............................................. 202 -- 202
------------- ------------- -------------
Total..................................................... $ 894 $ 11,221 $ 12,115
============= ============= =============
----------------------------
(1) Includes $2,429,000 relating to the Kleka 11, which was
categorized as proved property as of December 31, 2000.
Domestic Poland Total
------------- ------------- -------------
(In thousands)
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
============= ============= =============
F-20
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Domestic Poland Total
------------- ------------- -------------
(In thousands)
Year ended December 31, 1998:
Acquisition of properties:
Proved.................................................... $ -- $ -- $ --
Unproved.................................................. 15 33 48
Exploration costs............................................. 34 2,092 2,126
Development costs............................................. 132 -- 132
------------- ------------- -------------
Total..................................................... $ 181 $ 2,125 $ 2,306
============= ============= =============
Note 13: 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, 2000 of $21.33 per bbl for oil
domestically and $2.09 per MMbtu for 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
---------------------------- ----------------------------
Domestic Poland Domestic Poland
------------- ------------- ------------- -------------
(In thousand barrels of oil) (In millions of cubic feet)
Proved Developed Reserves:
December 31, 2000................................ 1,161 -- -- --
December 31, 1999................................ 1,080 -- -- --
December 31, 1998................................ 1,535 -- -- --
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
---------------------------- ----------------------------
Domestic Poland Domestic Poland
------------- ------------- ------------- -------------
(In thousands of barrels) (In millions of cubic feet)
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 -- -- --
------------- ------------- ------------- -------------
December 31, 1998:
Beginning of year............................. 4,760 -- -- --
Revisions of previous estimates............... (3,110) -- -- --
Production.................................... (115) -- -- --
------------- ------------- ------------- -------------
End of year............................... 1,535 -- -- --
------------- ------------- ------------- -------------
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 sales
contract with a term of five years that the Company signed with POGC during
December 2000.
F-22
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The components of SMOG are detailed below:
Domestic Poland Total
------------- ------------- -------------
(In thousands)
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
============= ============= =============
December 31, 1998:
Future cash flows............................................. $ 12,518 $ -- $ 12,518
Future production costs....................................... (11,408) -- (11,408)
Future development costs...................................... (95) -- (95)
Future income tax expense..................................... -- -- --
------------- ------------- -------------
Future net cash flows ........................................ 1,015 -- 1,015
10% annual discount for estimated timing of cash flows........ (543) -- (543)
------------- ------------- -------------
Discounted net future cash flows.............................. $ 472 $ -- $ 472
============= ============= =============
The principal sources of changes in SMOG are detailed below:
Year Ended December 31,
-------------------------------------------
2000 1999 1998
------------- ------------- -------------
(In thousands)
SMOG sources:
Balance, beginning of year.................................... $ 5,460 $ 472 $ 13,575
Sales of oil produced, net of production costs................ (1,172) (592) (77)
Net changes in prices and production costs.................... (159) 5,032 (4,482)
Extensions and discoveries, net of future costs............... 2,511 -- --
Changes in estimated future development costs................. (53) (6) 2,875
Previously estimated development costs incurred during
the year.................................................. 202 82 132
Revisions in previous quantity estimates...................... (31) (1,650) (9,076)
Accretion of discount......................................... 546 47 1,357
Net change in income taxes.................................... -- -- (952)
Changes in rates of production and other...................... 116 2,075 (2,880)
------------- ------------- -------------
Balance, end of year...................................... $ 7,420 $ 5,460 $ 472
============= ============= =============
F-23
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 14: Subsequent Events
Poland 2001 Agreement
Effective January 1, 2001, the Company signed an agreement with Apache, whereby
both parties agreed to terminate their AMI in Poland, effective December 31,
2000. The Company also agreed to release Apache's remaining commitment to pay
for the Company's fifty-percent share of costs to shoot 339 kilometers of 2-D
seismic on the Carpathian project area. In return, Apache agreed to issue the
Company a credit of $932,000 against any then current outstanding unpaid and
future invoices billed to the Company by Apache pertaining to the Company's
joint operations in Poland with Apache. As of December 31, 2000, there was
$114,000 of outstanding Apache invoices which had not been paid by the Company,
leaving a net credit of $818,000 as of January 1, 2001. If the Company's share
of actual costs to shoot the 339 kilometers of 2-D seismic on the Carpathian
project area exceeds $932,000, the excess will be covered by Apache.
Financing with Rolls Royce Power Ventures
On March 9, 2001, the Company signed a $5.0 million 9.5% convertible note 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.
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 Polish properties in Poland,
subject to availability. The Company's gas production will be delivered at a
POGC pipeline connection and RRPV will be responsible for transportation costs.
RRPV will be required to take at least 80% of the gas it agrees to purchase. The
Company may sell to others gas it produces in excess of the reserves required to
supply the RRPV agreement.
If RRPV elects to purchase gas from the Company, the loan will be repayable over
eight years. If RRPV elects not to buy the Company's gas, the loan will be
repayable in February 2003 unless converted to restricted common stock at $5.00
per share, subject to adjustment under certain circumstances. As security for
the loan, the Company will grant RRPV a lien on a portion of the Company's gas
reserves in Poland.
F-24