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, 2003
Commission File Number: 000-25386
FX ENERGY, INC.
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Nevada 87-0504461
-------------------------------- ---------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206, Salt Lake City, Utah 84106
---------------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: Telephone (801) 486-5555
Telecopy (801) 486-5575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, Par Value $0.001
Preferred Stock Purchase Rights
----------------------------------
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers in response
to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes [ ] No [X]
State the aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price at which the
common equity was last sold, or the average bid and asked price of such common
equity, as of the last business day of the registrant's most recently completed
second fiscal quarter. As of June 30, 2003, the aggregate market value of the
voting and nonvoting common equity held by nonaffiliates of the registrant was
$52,835,000.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. As of February 27,
2004, FX Energy had outstanding 27,510,930 shares of its common stock, par value
$0.001.
DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy
Statement in connection with the 2004 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, 2003
- --------------------------------------------------------------------------------
Table of Contents
Item Page
- ------------ ------
Part I
-- Special Note on Forward-Looking Statements.................. 3
1 and 2 Business and Properties..................................... 4
3 Legal Proceedings........................................... 19
4 Submission of Matters to a Vote of Security Holders......... 19
Part II
5 Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 20
6 Selected Financial Data..................................... 22
7 Management's Discussion and Analysis of Financial
Condition and Results of Operation.......................... 23
7A Quantitative and Qualitative Disclosures about Market Risk.. 33
8 Financial Statements and Supplementary Data................. 33
9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure......................... 34
9A Controls and Procedures..................................... 34
Part III
10 Directors and Executive Officers of the Registrant.......... 35
11 Executive Compensation...................................... 35
12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.................. 35
13 Certain Relationships and Related Transactions.............. 35
14 Principal Accountant Fees and Services...................... 35
Part IV
15 Exhibits, Financial Statement Schedules and Reports
on Form 8-K................................................. 36
-- Signatures.................................................. 40
-- Report of Independent Auditors.............................. F-1
2
SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS
- --------------------------------------------------------------------------------
This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "could," "should,"
"expect," "anticipate," "estimate," "project," "propose," "plan," "intend" and
similar words and expressions. We intend that the forward-looking statements
will be covered by the safe harbor provisions for forward-looking statements
contained in Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Statements that describe our future strategic
plans, goals or objectives are also forward-looking statements.
Readers of this report are cautioned that any forward-looking
statements, including those regarding us or our management's current beliefs,
expectations, anticipations, estimations, projections, proposals, plans or
intentions, are not guarantees of future performance or results of events and
involve risks and uncertainties, such as:
o future drilling and other exploration schedules and sequences
for various wells and other activities;
o the future results of drilling individual wells and other
exploration and development activities;
o future variations in well performance as compared to initial
test data;
o the ability to economically develop and market discovered
reserves;
o the prices at which we may be able to sell oil or gas;
o fluctuations in prevailing prices for oil and gas;
o future events that may result in the need for additional
capital;
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 industry or financial
participants to share the costs of exploration, exploitation,
development and acquisition activities;
o future plans and the financial and technical resources of
industry or financial participants;
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 foreign currency exchange rate fluctuations;
o uncertainties regarding future political, economic,
regulatory, fiscal, taxation and other policies in Poland,
including events that may occur related to its European Union
accession; and
o other factors that are not listed above.
The forward-looking information is based on present circumstances and
on our predictions respecting events that have not occurred, that may not occur,
or that may occur with different consequences from those now assumed or
anticipated. Actual events or results may differ materially from those discussed
in the forward-looking statements. The forward-looking statements included in
this report are made only as of the date of this report.
3
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 in
association with the Polish Oil and Gas Company, or POGC, and others, as
discussed below. We believe the cooperative working environment with POGC in
Poland allows us to operate effectively with in-country operating and technical
personnel, access geological and geophysical data readily, and interact in
general with governmental and industry contacts in Poland.
We are focused on Poland because we believe it provides attractive oil
and gas exploration and production opportunities. In our view, these
opportunities exist because the country was closed to competition from foreign
oil and gas companies for many decades. As a result, we believe its known
productive areas are underexplored, underdeveloped and underexploited today.
Poland is a net importer of oil and gas, and its fiscal regime is favorable to
foreign investment, which reinforce the attractiveness of Poland.
We believe the gas-bearing Rotliegendes sandstone reservoir rock in
Poland's Permian Basin is a direct analog to the Southern North Sea gas basin
offshore England, and represents a largely untapped source of potentially
significant gas reserves. We believe that we are uniquely positioned, because of
our land position, our relationship with POGC, our significant working
interests, and our current financial condition, to exploit this untapped
potential and create substantial growth in oil and gas reserves and cash flows
for our stockholders.
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.
Strategy
We seek the rewards of high potential exploration while endeavoring to
minimize our exposure to the risks normally associated with exploration.
Historically, we have compensated for our small size and limited capital with
farmout arrangements in which we convey an interest in our exploration projects
in exchange for contribution of the financial and technical resources by larger
industry participants. As a result of raising $25.4 million in net proceeds from
the sale of securities, converting $3.6 million of outstanding debt to
securities, and forming our Technical Advisory Panel discussed below, as
circumstances warrant, we now anticipate that we will rely principally on our
own financial and technical resources in drilling prospects for our own account
or under our sharing arrangements with POGC.
We concentrate on underexplored acreage in productive fairways or
geologic trends where we believe we have the opportunity to find significant gas
reserves with lower risk. Our strategy is to:
o acquire large acreage positions in underexplored areas of
known production fairways, particularly where there has been
little or no exploration for many years;
o carry out the work necessary to advance these properties
toward exploration drilling, including collecting, evaluating
and reprocessing data, identifying prospects that we believe
merit drilling based on available data and preparing a
detailed exploration work program; and
o either drill these prospects for our own account, or where
circumstances warrant, market interests in these properties to
industry participants on terms that will provide the funds
necessary for exploration.
Our primary strategic relationship is with POGC, a fully integrated oil
and gas company owned by the Treasury of the Republic of Poland, which is
4
Poland's principal domestic oil and gas exploration entity. Under our existing
agreements, POGC provides us with access to exploration opportunities, important
previously-collected exploration data, and technical and operational support.
Technical and Advisory Panel
In February 2003, we announced the creation of a Technical and Advisory
Panel, consisting of three individuals with decades of combined experience to
advise and consult with management in connection with the three "Fences" project
areas. Their responsibilities include assisting us in defining and exploiting
the potential of our projects in Poland and in attracting funding and/or
industry participation for that effort as we deem necessary. The Technical and
Advisory Panel consists of the following three individuals:
Richard Hardman, CBE, has built a career in international exploration
over the past 40 years in the upstream oil and gas industry as a geologist in
Libya, Kuwait, Colombia, and Norway. In the United Kingdom, his career
encompasses almost the whole of the exploration history of the North Sea - 1969
to the present. With Amerada Hess from 1983 to 2002, as Exploration Director and
later Vice President Exploration, he was responsible for key Amerada North Sea
and international discoveries, including Valhall, Scott and South Arne fields.
Mr. Hardman was made Commander of the British Empire in the New Year Honours,
1998, and has served as the Chairman of the Petroleum Society of Great Britain,
President of the Geological Society, and President of the European Region of
AAPG Europe. Mr. Hardman was appointed to our board of directors in October
2003, and was designated the Chairman of our Technical and Advisory Panel.
Steven McTiernan has over 30 years of diverse energy industry and
banking experience as a petroleum engineer with Amoco, Mesa, and British
Petroleum, and as a banker with Chase Manhattan, CIBC and NatWest. He was the
Global Head of Oil & Gas for Chase in New York and for NatWest in London. Mr.
McTiernan advised FX Energy in connection with the 2003 farmout of the Fences I
project area to CalEnergy Gas (Holdings) Ltd.
Robert J.J. Hardy, Ph.D., served 11 years with Amerada Hess from 1990
to 2001 where he was in charge of the geophysical operations group in London
with responsibility for Northwest Europe (including the North Sea) and
International. He has considerable experience in all aspects of the design,
acquisition and processing of 2-D, 3-D and 4-D projects and has applied advanced
analytical methodologies on over 500 geophysical projects including projects
dealing with complex salt swells, gas cloud problems and structural imaging. He
identified the need for and established a multidisciplinary team incorporating
specialized seismic attributes for complex structures in the North Sea,
resulting in improved appraisal strategy and successful drilling. In 2003, Dr.
Hardy joined the Geology Department of Trinity College Dublin to establish a
basin analysis group to conduct research programs in multiple suppression, depth
imaging and attribute interpretation. Dr. Hardy holds a Ph.D. in Geophysics from
Cambridge University and a B.Sc. Geology and Geophysics 1st Class from the
University of Durham. Dr. Hardy is guiding the Company's seismic acquisition,
processing and reprocessing projects in the Fences project areas.
Project Area Summary
Our ongoing activities in Poland are conducted in five project areas:
Fences I, II and III, Pomeranian and Wilga. We are currently working almost
exclusively on the three Fences project areas, where we believe the gas-bearing
Rotliegendes sandstone reservoir rock in Poland's Permian Basin is a direct
analog to the Southern North Sea gas basin offshore England. We are focused in
the Fences area because there have been substantial gas reserves developed and
produced by POGC in this Rotliegendes trend, and we have concluded that there
are likely to be substantial additional gas and oil reserves in the same
horizons that can be identified through the application of geophysical
techniques that have not previously been applied in this area in Poland.
Fences
Fences I project area is 265,000 acres (1,074 sq. km.) in western
Poland's Permian Basin. Several gas fields located in the Fences I block are
excluded or "fenced off" from our exploration acreage. These fields, discovered
by POGC between 1974 and 1982, produce from Rotliegendes sandstone reservoirs.
In April 2000, we agreed to spend $16.0 million on exploration costs in the
Fences I project area to earn a 49% interest. As of December 31, 2003, we had
completed $10.7 million of our $16.0 million earn-in requirement. We expect that
the balance of our earning requirement will be met by the approximately $2.5
million in costs paid by CalEnergy Gas associated with the Zaniemysl-3 well, the
5
costs of drilling the initial test well on the Rusocin prospect, and the
acquisition and reprocessing of additional seismic in the Fences I area
scheduled for 2004.
Fences II project area is 670,000 acres (2,715 sq. km.) located north
of and contiguous with the Fences I block. POGC's Radlin field forms part of the
Fences II's southern border. Under a January 2003 agreement, we have the right
to earn a 49% interest from POGC, subject to satisfactory completion of our
obligations in Fences I and our expenditure of $4.0 million in exploration
costs. We expect to satisfy the earning requirements during 2004 by continuing
our ongoing two-dimensional, or 2-D, seismic reprocessing, along with drilling
the initial well at the Sroda prospect.
Fences III project area is 770,000 acres (3,122 sq. km.) located
approximately 25 miles south of Fences I, where we own 100% of the exploration
rights. As with the Fences I block, several gas fields located in the Fences III
block are fenced off from the exploration acreage. These fields, discovered by
POGC between 1967 and 1976, produced from both Rotliegendes sandstone and
Zechstein (Ca1 and Ca2) carbonate reservoirs.
The Fences I, II and III project areas (a total of 1.7 million gross
acres or 6,911 sq. km.) are all within an area of underexplored Rotliegendes
sandstone. To our knowledge, no exploration program focused on Rotliegendes gas
reserves has been undertaken in Poland using the technology available today, and
no sustained exploration effort has been made in the three Fences project areas
for Rotliegendes gas fields in the last 20 years.
Along with our partners, POGC and CalEnergy Gas (Holdings) Ltd., we
recently drilled and will be completing for production, as discussed below, the
Zaniemysl-3 well on the Fences I prospect. During the balance of 2004, our
objectives with respect to the Fences area are threefold:
o develop a complete subsurface seismic picture of the
Rotliegendes and Zechstein (Ca1 and Ca2) horizons across our
entire acreage, building an inventory of high potential,
drillable prospects;
o drill at least four more wells in the Fences I and II areas,
including the initial tests on the Rusocin and Sroda
prospects; and
o endeavor to expand our holdings in and around the Fences area.
More detailed information concerning the Fences area and our
exploration history there can be found under the section Exploration,
Development and Production Activities in Poland below.
Pomeranian
The Pomeranian project area consists of exploration rights covering
approximately 2.2 million gross acres lying along the underexplored northern
edge of the Permian Basin in northwestern Poland. We are the operator and have a
100% interest in the Pomeranian project area, except for Block 108, where we
have an 85% interest and POGC has a 15% interest. The Pomeranian project area is
relatively unexplored and has had little oil and gas production. Although we
believe the Pomeranian project area has very significant potential, we have made
the decision to drop this acreage to focus on the much lower risk Rotliegendes
and Zechstein plays in the Fences area.
Wilga
The Wilga project area in central southeast Poland consists of
exploration rights on approximately 250,000 gross acres held by us, Apache
Corporation and POGC in Block 255, where the Wilga 2 discovery well is located.
We have a 45% working interest in the Wilga project area, which is operated by
Apache Corporation. We and our partners successfully completed an extended flow
test on the Wilga 2, confirming that the well is capable of producing at a
commercial rate, but the well continues to be shut-in. We have no current plans
to place this well into commercial production in light of the required capital
investment in pipeline and facilities. No further exploration is planned for the
block at this time, and we may farm-out or sell our interest.
6
Exploration, Development and Production Activities in Poland
Polish Exploration Rights
As of December 31, 2003, we had the right to earn or had earned oil and
gas exploration rights in Poland in the following gross acreage components:
Operator
----------------------------------------------- Total
FX Energy Apache POGC Acreage
--------------- --------------- --------------- ---------------
Project Area:
Fences I(1)............................... -- -- 265,000 265,000
Fences II(2).............................. -- -- 670,000 670,000
Fences III(3)............................. 770,000 -- -- 770,000
Pomeranian(4)............................. 2,200,000 -- -- 2,200,000
Wilga(5).................................. -- 250,000 -- 250,000
--------------- --------------- --------------- ---------------
Total gross acreage..................... 2,970,000 250,000 935,000 4,155,000
=============== =============== =============== ===============
- -------------------------
(1) In April 2000, we entered into an agreement with POGC to earn 49% of POGC's
100% interest in the Fences I project area by spending $16.0 million of
exploration costs.
(2) In January 2003, we entered into an agreement with POGC to earn 49% of
POGC's 100% interest in the Fences II project area by completing our Fences
I work requirement, and by spending $4.0 million of exploration costs.
(3) In March 2003, we entered into an agreement with the Ministry of the
Environment in Poland to earn a 100% interest in the Fences III project
area by spending approximately $1.5 million of exploration costs.
(4) We own a 100% interest in the Pomeranian project area, except for Block 108
(approximately 250,000 acres), where we own an 85% interest and POGC owns a
15% interest. We have decided to drop all of the Pomeranian acreage.
(5) We own a 45% interest, Apache owns a 45% interest and POGC owns a 10%
interest in the Wilga project area.
As we 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.
Exploratory Activities in Poland
Fences I Project Area
In April 2000, we agreed to spend $16.0 million on exploration costs in
the Fences I project area to earn a 49% interest. POGC is obligated to pay its
51% share of any costs in excess of $16 million. As of December 31, 2003, we
have incurred expenditures of approximately $10.7 million toward the $16.0
million earn-in requirement, leaving a remaining work commitment of $5.3
million. Our remaining commitment will be further reduced by all costs paid for
by CalEnergy Gas (Holdings) Ltd. in connection with the Zaniemysl-3 well,
discussed below, which we expect to be approximately $2.5 million.
The Rotliegendes is the primary target horizon throughout most of the
Fences I project area, at depths from about 2,800 to 3,200 meters, except along
the extreme southwest portion where the target reservoir is carbonates of the
lower Permian. During 2000, we drilled the Kleka 11, our first Rotliegendes
target, which began producing in early 2001. During 2001, we drilled the
Mieszkow 1, an exploratory dry hole. The Mieszkow well demonstrated the need to
apply modern seismic processing and to assure careful handling of velocities in
seismic interpretation. In 2002, we reprocessed approximately 1,200 kilometers
of existing two-dimensional, or 2-D, seismic data that had not previously been
processed with modern geophysical techniques, covering most of the Fences I
area. POGC has since begun reprocessing some of the existing three-dimensional,
or 3-D, data covering the Fences I area.
In late 2002, as part of our discussions with POGC concerning the
CalEnergy Gas (Holdings) Ltd. Farmout Agreement and the opportunity to
participate with pogc in other exploration projects, we reaffirmed our intent to
fulfill the $16.0 million earn-in requirement with pogc and entered into an
agreement to restructure our payments to pogc. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operation:
Introduction--Fences I Settlement Agreement. As part of our future payments
towards a $4.4 million accrued liability at December 31, 2002, we agreed to pay
7
to POGC a certain amount of cash, assign all of our rights to the Kleka 11 well
to POGC, and offset against that liability $0.6 million recorded as accounts
receivable as of December 31, 2002, for Kleka gas sales.
During 2003, we paid a total of $2.9 million in cash and recorded a
$190,000 value added tax liability in partial settlement of the $4.4 million
liability to POGC. When we complete the assignment of the Kleka 11 well, we
believe we will have satisfied this liability in full. As of December 31, 2003,
we had estimated proved developed producing gas reserves, as determined by an
independent engineer, with an estimated net present value, discounted at 10%, of
approximately $1.1 million related to our interest in the Kleka 11 well. We
continue to discuss with POGC the amount we will be credited for assigning to it
the Kleka well. Should POGC not concur with the independent engineer's
assessment of reserves, we may be required to pay additional cash to settle the
remaining $1.1 million liability to POGC.
In January 2003, we entered into a farmout agreement with CalEnergy
Gas, the upstream gas business unit of MidAmerican Energy Holdings Company,
whereby CalEnergy Gas had the right, but not the obligation, to earn a 24.5%
interest in the entire Fences I project area by spending a total of $10.4
million, including the cost to drill two wells and certain cash payments to us.
Following completion of the Zaniemysl-3 well in early 2004, CalEnergy Gas
requested more than a six-month extension in which to undertake an additional
technical evaluation before committing to an additional exploration well. We and
POGC elected instead to proceed without delay to select a specific drillsite in
the Rusocin prospect in Fences I and to proceed with drilling as soon as
possible. Accordingly, CalEnergy Gas no longer has the right to participate in
our right to earn a 49% interest in the Fences I project area, except for the
approximately 2,200 acre Zaniemysl field, in which we and CalEnergy Gas each
hold a 24.5% interest. For details of our agreement with CalEnergy Gas
(Holdings) Ltd., see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation: Introduction--CalEnergy Gas Agreement.
The operating committee approved the Zaniemysl prospect as the first
well to be drilled under this farmout agreement and drilling commenced in
October 2003. In February 2004, we announced that the Zaniemysl-3 exploratory
well in the Fences I project area was commercial and encountered approximately
38 net meters (125 feet) of porous gas bearing Rotliegendes sandstone. During a
drill stem test of the top 18 meters of the structure, the well flowed at a
stabilized rate of approximately 12.5 million cubic feet of gas per day.
Together with our partners, POGC and CalEnergy Gas, we are evaluating how to
best produce and exploit the Zaniemysl structure. Further analysis of the core,
log and pressure data will be required before reserve numbers can be
established. A 10-mile pipeline will be required to tie into the POGC grid near
the Radlin field. We are currently planning to drill two additional exploratory
wells in Fences I in 2004, including the first well in the Rusocin prospect,
which we hope will be the first well in a continuous drilling program in Fences
I, utilizing the same drilling rig. We have no plans to seek a farmout with an
industry participant.
Fences II Project Area
In early 2002, Conoco, Inc., Ruhrgas and POGC drilled a dry hole in the
northeast of the Fences II area. The well, although dry, did confirm the
presence of reservoir quality Rotliegendes sandstone at a depth of more than
3,700 meters, which makes virtually the entire block prospective for
Rotliegendes, subject to accurate geophysical resolution of the trapping
features.
A significant amount of geological and geophysical work was completed
by POGC and Conoco before Conoco's withdrawal from the project at the end of
2002 and made available to us by POGC. As a result, we were able to immediately
identify drill-ready prospects in the Fences II project area. We are currently
reprocessing approximately 2,600 kilometers of 2-D seismic data, which will
complement the 1,200 kilometers reprocessed in 2002, to develop a complete
subsurface picture of the Rotliegendes and Zechstein horizons, and are planning
to drill at least two exploratory wells in this area in 2004, including the
initial test of the Sroda prospect. As with the Rusocin prospect, we hope the
Sroda test will be the first well in a continuous drilling program in Fences II.
We have no plans to seek a farmout with an industry participant.
Fences III Project Area
We have assembled the existing seismic data, which includes seismic in
the northern 30% of the Fences III project area. We have evaluated the seismic
data for reprocessing and plan to carry out a geophysical exploration program to
8
identify leads and prospects that merit drilling. At this time, we intend to
carry out this work before deciding whether to drill on our own or seek a
farmout with an industry participant.
The Republic of Poland
The Republic of Poland is located in central Europe, has a population
of approximately 39 million people, and covers an area comparable in size to New
Mexico. During 1989, Poland peacefully asserted its independence and became a
parliamentary democracy. Since 1989, Poland has enacted comprehensive economic
reform programs and stabilization measures that have enabled it to form a
free-market economy and turn its economic ties from the east to the west, with
most of its current international trade with the countries of the European Union
and the United States. The economy has undergone extensive restructuring in the
post-communist era. The Polish government credits foreign investment as a
forceful growth factor in successfully creating a stable free-market economy.
According to the Polish Foreign Investment Agency, cumulative foreign direct
investment flow into Poland is estimated to have aggregated approximately $68
billion from 1989 through mid-2003.
Since its transition to a market economy and a parliamentary democracy,
Poland has experienced significant economic growth and political change. Poland
has developed and is refining legal, tax and regulatory systems characteristic
of parliamentary democracies with interpretation and procedural safeguards. The
Polish government has generally taken steps to harmonize Polish legislation with
that of the European Union in anticipation of Poland's entry into the European
Union in May 2004 and to facilitate interaction with European Union members.
Since 1995, the Polish corporate income tax rate has been gradually reduced and
is at 19% of taxable income as of January 1, 2004.
Poland has created an attractive legal framework and fiscal regime for
oil and gas exploration by actively encouraging investment by foreign companies
to offset its lack of capital to further explore its oil and gas resources. In
July 1995, Poland's Council of Ministers approved a program to restructure and
privatize the Polish petroleum sector. So far under this plan, a refinery
located in Plock has been privatized as a publicly-held company with its stock
trading on the London and Warsaw stock exchanges. We expect that the gas
distribution segments of POGC will be privatized next, followed by the
exploration, production and oilfield services segment. Increased participation
by Western companies using Western capital in the oil and gas sector is
consistent with the approved privatization policy.
Prior to becoming a parliamentary democracy during 1989, the
exploration and development of Poland's oil and gas resources were hindered by a
combination of foreign influence, a centrally-controlled economy, limited
financial resources, and a lack of modern exploration technology. As a result,
Poland is currently a net energy importer. Oil is imported primarily from
countries of the former Soviet Union and the Middle East, and gas is imported
primarily from Russia. In the early 1990s, the World Bank loaned Poland $250
million to fund the purchase of new exploration and drilling equipment for
Poland's oil and gas industry to help shift its domestic sources of energy
consumed from coal to oil and natural gas. Poland has also improved its
technical and data gathering capabilities.
Poland joined NATO in 1998 and will join the European Union in May
2004. In order to achieve member status in the European Union, Poland must raise
its environmental standards. In Poland, coal is the dominant energy source.
Increased consumption of natural gas, as an alternative to coal, is considered
to be a key component in meeting the European Union's strict environmental
guidelines for its members. The demand for gas in Poland is expected by some to
increase in the future, primarily due to increased economic growth coupled with
the conversion to gas from coal as an energy source for power plants. However,
to date, the demand for natural gas has remained flat and is predicted by others
to remain so over the next decade, due in large part to the fact that natural
gas is uneconomical for power generation in Poland compared to coal, which is
widely and cheaply produced.
Poland has crude oil pipelines serving the major refineries and a
network of gas pipelines serving major metropolitan, commercial, industrial and
gas production areas, including significant portions of our acreage. Poland has
a well-developed infrastructure of hard-surfaced roads and railways over which
we believe oil produced could be transported for sale. There are refineries in
Gdansk and Plock in Poland and one in Germany near the western Polish border
that we believe could process any crude oil we may produce in Poland. All
facilities and pipelines currently used to gather and transport oil and gas in
Poland are owned and operated by POGC.
9
Polish Properties
Legal Framework
General Usufruct and Concession Terms
In 1994, Poland adopted the Geological and Mining Law, which specifies
the process for obtaining domestic exploration and exploitation rights. All of
our rights in Poland have been awarded pursuant to this law. Under the
Geological and Mining Law, the concession authority enters into oil, gas and
mining usufruct (lease) agreements that grant the holder the exclusive right to
explore or exploit the designated oil and gas or minerals for a specified period
under prescribed terms and conditions. The holder of the mining usufruct must
also acquire an exploration concession to obtain surface access to the
exploration area by applying to the concession authority and providing the
opportunity for comment by local governmental authorities.
The concession authority has granted us oil and gas exploration rights
on the Fences III, Wilga, and Pomeranian project areas, and has granted POGC oil
and gas exploration rights on the Fences I and II project areas. The agreements
divide these areas into blocks, generally containing approximately 250,000 acres
each. Concession licenses have been acquired for surface access to all areas
that lie within existing usufructs. The exploration period begins after the date
of the last concession signed under each respective usufruct. We believe all
material concession terms have been satisfied to date.
If commercially viable oil or gas is discovered, the concession owner
then applies for an exploitation concession, as provided by the usufructs,
generally with a term of 25 to 30 years or as long as commercial production
continues. Upon the grant of the exploitation concession, the concession owner
may become obligated to pay a fee, to be negotiated, but expected to be less
than 1% of the market value of the estimated recoverable reserves in place. The
concession owner would also be required to pay a royalty on any production, the
amount of which will be set by the Council of Ministers, within a range
established by legislation for the mineral being extracted. The royalty rate for
gas is currently less than $0.03 per Mcf. This rate could be increased or
decreased by the Council of Ministers to a rate between $0.02 and $0.08 per Mcf
(the current statutory minimum and maximum royalty rate). Local governments will
receive 60% of any royalties paid on production. The holder of the exploitation
concession license must also acquire rights to use the land from the surface
owner. The usufruct owner could be subject to significant delays in obtaining
the consents of local authorities or satisfying other governmental requirements
prior to obtaining an exploitation concession.
Fences I Project Area
The Fences I project area consists of a single oil and gas exploration
concession controlled by POGC. Three producing fields (Radlin, Kleka and Kaleje)
lie within the concession boundary, but are excluded from the Fences I
concession. The concession is for a period of six years ending in September 2007
and carries a work requirement during the first three years of one exploratory
well, 70 square kilometers of 3-D seismic data, and reprocessing of 400
kilometers of 2-D seismic data. The drilling and seismic reprocessing
requirements have been completed.
Fences II Project Area
The Fences II project area consists of four oil and gas exploration
concessions controlled by POGC. The concessions have expiration dates ranging
from July 2006 to August 2007, with three-year extension rights. Remaining work
commitments in the aggregate include 70 kilometers of 3-D seismic, 250
kilometers of new 2-D seismic, 100 kilometers of seismic reprocessing and
drilling four wells.
Fences III Project Area
The Fences III project area consists of a single oil and gas
exploration concession held by us. Several producing fields lie within the
concession boundaries, but are excluded from the Fences III project area. The
10
concession is for a period of six years ending in December 2009 and carries a
work requirement during the first two years, which includes the reprocessing of
100 kilometers of existing 2-D seismic, 100 kilometers of new 2-D seismic, and
analysis and interpretation of existing well data. Beginning in the third year,
there is a drilling requirement of one well.
Wilga/Block 255 Project Area
The Wilga project area consists of a single oil and gas exploration
concession controlled by Apache. All work commitments have been completed. No
further exploration is planned for the block at this time, and we may farm-out
or sell our interest.
Pomeranian Project Area
The Pomeranian project area consists of 10 oil and gas concessions
controlled by us. The concessions are for a period of six years ending in
December 2004, when the concession must be relinquished except for lands within
exploitation concessions or for which an application for an exploitation
concession has been filed. We have decided to drop this acreage to focus on the
much lower risk Rotliegendes and Zechstein plays in the Fences area.
As of December 31, 2003, all required usufruct/concession payments had
been made for each of the above project areas.
Production, Transportation and Marketing
Poland has a network of gas pipelines and crude oil pipelines
traversing the country serving major metropolitan, commercial, industrial and
gas production areas, including significant portions of our acreage. Poland has
a well-developed infrastructure of hard-surfaced roads and railways over which
we believe oil produced could be transported for sale. There are refineries in
Gdansk and Plock in Poland and one in Germany near the western Polish border
that we believe could process crude oil produced in Poland. Should we choose to
export any oil or gas we produce, we will be required to obtain prior
governmental approval.
During early 2001, we and POGC constructed a pipeline from the Kleka 11
well approximately four kilometers to POGC's Radlin field gas processing
facility and began selling gas produced to POGC at a price of $2.02 per MMBtu
under a five-year contract that may be terminated by us with a 90-day written
notice. As part of our restructured agreement with POGC, we agreed to assign our
interest in the Kleka 11 well, including amounts representing unpaid gas sales,
to POGC to reduce the outstanding obligation to POGC. Accordingly, we received
no net gas production from the Kleka 11 well in 2003, our only producing well in
Poland. See Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operation.
We did not have any oil or gas production in Poland during 2003. The
following table sets forth our average net daily gas production, average sales
price and average production costs associated with our Polish gas production
during 2002 and 2001:
2003 2002 2001
---- ---- ----
Polish producing property data:
Average daily net gas production (Mcf)(1)... -- 494 800
Average sales price per MMBtu(2)............ -- $ 2.02 $ 2.02
Average production costs per Mcf(3)......... -- $ 0.16 $ 0.16
- --------------------
(1) Consists solely of the Kleka 11 well, which began producing on February 22,
2001, and which we agreed to transfer to POGC effective December 2002.
Production was reduced during 2002 to control the production of water.
(2) Gross sales prices before downward adjustment of $0.44 per Mcf for caloric
content.
(3) Production costs include lifting costs (electricity, fuel, water, disposal,
repairs, maintenance, pumper, transportation and similar items). Production
costs do not include such items as G&A costs, depreciation, depletion or
Polish income taxes.
11
United States Properties
Producing Properties
In the United States, we currently produce oil in Montana and Nevada.
All of our producing properties, except for the Rattlers Butte field (an
exploratory discovery during 1997), were purchased during 1994. A summary of our
average daily production, average working interest and net revenue interest for
our United States producing properties during 2003 follows:
Average Daily Production
(Bbls) Average Average
---------------------------- Working Net Revenue
Gross Net Interest Interest
------------- -------------- -------------- -----------------
United States producing properties:
Montana:
Cut Bank............................ 239 206 99.6% 86.4%
Bears Den........................... 10 8 90.0 81.0
Rattlers Butte...................... 29 2 6.3 5.1
------------- --------------
Total............................. 278 216
------------- --------------
Nevada:
Trap Spring......................... 7 1 21.6 20.0
Munson Ranch........................ 38 13 36.0 34.1
Bacon Flat.......................... 31 4 16.9 12.5
------------- --------------
Total............................. 76 18
------------- --------------
Total United States producing
properties................... 354 234
============= ==============
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 99.6% in 93 producing oil wells, 27 active injection
wells and one active water supply well. The Bears Den field was discovered in
1929 and has been under waterflood since 1990. In the Bears Den field, we own a
90% 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%. 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.
12
Production, Transportation and Marketing
The following table sets forth our average net daily oil production,
average sales price and average production costs associated with our United
States oil production during 2003, 2002 and 2001:
Years Ended December 31,
-------------------------------------
2003 2002 2001
----------- ----------- -----------
United States producing property data:
Average daily net oil production (Bbls).......................... 234 249 256
Average sales price per Bbl...................................... $26.29 $21.19 $19.41
Average production costs per Bbl(1).............................. $17.22 $14.59 $14.50
- ----------------------
(1) Production costs include lifting costs (electricity, fuel, water, disposal,
repairs, maintenance, pumper, transportation and similar items) and
production taxes. Production costs do not include such items as G&A costs,
depreciation, depletion, state income taxes or federal income taxes.
We sell oil at posted field prices to one of several purchasers in each
of our production areas. From June 2002 through July 2003, we sold our Montana
production, which represents over 85% of our total oil sales, to Plains
Marketing Canada L.P. In August 2003, we began selling the majority of our
production to CENEX, a regional refiner and marketer. For the first half of 2002
and for the entire year ended December 31, 2001, the bulk of our total oil sales
were also to CENEX. Posted prices are generally competitive among crude oil
purchasers. Our crude oil sales contracts may be terminated by either party upon
30 days' notice.
Oilfield Services - Drilling Rig and Well-Servicing Equipment
In Montana, we perform, through our drilling subsidiary, FX Drilling
Company, Inc., a variety of third-party contract oilfield services, including
drilling, workovers, location work, cementing and acidizing. We currently have a
drilling rig capable of drilling to a vertical depth of 6,000 feet, a workover
rig, two service rigs, cementing equipment, acidizing equipment and other
associated oilfield servicing equipment. We first started our oilfield servicing
business in 1998 in an effort to increase our United States revenues, which had
been declining due to the depressed oil prices that had occurred throughout that
year.
Proved Reserves
Proved reserves are the estimated quantities of crude oil and natural
gas 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, 2003, of $27.53 per Bbl for oil in
the United States and $2.60 per Mcf of gas in Poland. The determination of oil
and gas reserves is based on estimates and is highly complex and interpretive,
as there are numerous uncertainties inherent in estimating 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 future net cash flows, or PV-10 Value, was determined in
accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities" and SEC
guidelines. Our proved reserve estimates are subject to continuing revisions as
additional information becomes available or assumptions change.
Estimates of our proved United States oil reserves were prepared by
Larry Krause Consulting, an independent engineering firm in Billings, Montana.
Estimates of our proved Polish gas reserves were prepared by Troy-Ikoda Limited,
an independent engineering firm in the United Kingdom. No estimates of our
proved reserves have been filed with or included in any report to any other
federal agency during 2003.
13
The following summary of proved reserve information as of December 31,
2003, represents estimates net to us only and should not be construed as exact:
United States Poland
---------------------------- --------------------------- Total
Oil PV-10 Value Gas PV-10 Value PV-10 Value
------------ --------------- ------------ -------------- ------------------
(MBbls) (In thousands) (MMcf) (In thousands) (In thousands)
Proved reserves:
Developed producing........ 991 $ 4,934 1,116 $ 1,052 $ 5,986
Undeveloped................ -- -- 2,844 3,870 3,870
------------ --------------- ------------ -------------- ------------------
Total.................... 991 $ 4,934 3,960 $ 4,922 $ 9,856
============ =============== ============ ============== ==================
Our proved developed producing gas reserves in Poland relate solely to
the Kleka 11 well in the Fences I project area, which we agreed effective
December 2002 to transfer to POGC for a credit against our obligation to it. We
continue to discuss with POGC the amount we will be credited for assigning to it
the Kleka well. Should POGC not concur with the independent engineer's
assessment of reserves summarized above, we may be required to pay additional
cash to settle our remaining $1.1 million liability to POGC.
Drilling Activities
The following table sets forth the exploratory wells that we drilled
during the years ended December 31, 2003, 2002 and 2001:
Years Ended December 31,
-------------------------------------------------------------------
2003 2002 2001
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- ---------- ---------- ---------- ----------
Discoveries:
United States....................... -- -- -- -- -- --
Poland.............................. -- -- -- -- 1.0 0.5
---------- ---------- ---------- ---------- ---------- ----------
Total............................. -- -- -- -- 1.0 0.5
---------- ---------- ---------- ---------- ---------- ----------
Exploratory dry holes:
United States....................... -- -- -- -- -- --
Poland.............................. -- -- -- -- 2.0 1.0
---------- ---------- ---------- ---------- ---------- ----------
Total............................. -- -- -- -- 2.0 1.0
---------- ---------- ---------- ---------- ---------- ----------
Total wells drilled................... -- -- -- -- 3.0 1.5
========== ========== ========== ========== ========== ==========
We did not complete any exploratory wells in 2003 and 2002, and we did
not drill any development wells during 2003, 2002 or 2001. At December 31, 2003,
we were drilling the Zaniemysl-3 well, which discovered commercial gas in
February 2004.
Wells and Acreage
As of December 31, 2003, our producing gross and net well count
consisted of the following:
Number of Wells
------------------------
Gross Net
----------- -----------
Well count:
United States(1)....................... 119.0 113.7
Poland(2).............................. 1.0 0.5
----------- -----------
Total................................ 120.0 114.2
=========== ===========
- -------------------------------
(1) All of our United States wells are producing oil wells. We have no gas
production in the United States.
(2) Consists of the Kleka 11, a producing gas well which we agreed to transfer
to POGC effective December 2002.
14
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2003:
Developed Undeveloped
---------------------------- ----------------------------
Gross Net Gross Net
---------------------------- ----------------------------
United States:
North Dakota................................. -- -- 7,955 5,351
Montana...................................... 10,732 10,418 1,150 1,057
Nevada....................................... 400 128 37 16
------------- ------------- ------------- --------------
Total..................................... 11,132 10,546 9,142 6,424
------------- ------------- ------------- --------------
Poland: (1)(2)
Fences I project area(3)..................... 225 110 -- --
Wilga project area........................... 543 244 250,000 113,000
Pomeranian project area(4)................... -- -- 2,200,000 2,248,000
------------- ------------- ------------- --------------
Total Polish acreage..................... 768 354 2,450,000 2,361,000
------------- ------------- ------------- --------------
Total Acreage.................................. 11,900 10,900 2,459,142 2,367,424
============= ============= ============= ==============
- --------------------------
(1) All gross undeveloped Polish acreage is rounded to the nearest 50,000 acres
and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.
(2) Developed acreage in the Fences project areas is attributable only to the
Kleka 11 well, which we have now agreed to transfer to POGC. The net
acreage amount assumes we spend $16.0 million of exploration expenditures
to earn a 49% interest.
(3) Excludes acreage in which we may earn an interest under arrangements
reached after December 31, 2003.
(4) We own a 100% interest in the Pomeranian project area, except for Block 108
(approximately 250,000 acres), where we own an 85% interest. We have made
the decision to drop all of the Pomeranian acreage.
In addition to the acreage shown in the above table, we have the right,
subject to the satisfactory completion of our earning obligations, to earn
acreage in the Fences I, II, and III project areas as shown in the table found
under Exploration, Development and Production Activities in Poland: Polish
Exploration Rights.
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. The
European Union Treaty of Accession will require divestment by the Polish
government of certain portions of the oil and gas business. Changes in the
industry ownership may affect the business climate where we operate.
15
United States
State and Local Regulation of Drilling and Production
Our exploration and production operations are subject to various types
of regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells and regulating the location of wells, the method
of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, and the plugging and abandoning of wells. Our
operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration
units and the density of wells that may be drilled and the unitization or
pooling of oil and gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state conservation
laws establish maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of gas, and impose certain requirements
regarding the ratability of production.
Our oil production is affected to some degree by state regulations.
States in which we operate have statutory provisions regulating the production
and sale of oil and gas, including provisions regarding deliverability. Such
statutes and related regulations are generally intended to prevent waste of oil
and gas and to protect correlative rights to produce oil and gas between owners
of a common reservoir. Certain state regulatory authorities also regulate the
amount of oil and gas produced by assigning allowable rates of production to
each well or proration unit.
Environmental Regulations
The federal government and various state and local governments have
adopted laws and regulations regarding the control of contamination of the
environment. These laws and regulations may require the acquisition of a permit
by operators before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution resulting from
our operations. These laws and regulations may also increase the costs of
drilling and operation of wells. We may also be held liable for the costs of
removal and damages arising out of a pollution incident to the extent set forth
in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act
of 1990, or OPA `90. In addition, we may be subject to other civil claims
arising out of any such incident. As with any owner of property, we are also
subject to clean-up costs and liability for hazardous materials, asbestos or any
other toxic or hazardous substance that may exist on or under any of our
properties. We believe that we are in compliance in all material respects with
such laws, rules and regulations and that continued compliance will not have a
material adverse effect on our operations or financial condition. Furthermore,
we do not believe that we are affected in a significantly different manner by
these laws and regulations than our competitors in the oil and gas industry.
The Comprehensive Environmental Response, Compensation and Liability
Act, or CERCLA, also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources, and for the costs of certain
health studies. Furthermore, it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.
The Resource Conservation and Recovery Act, or RCRA, and regulations
promulgated thereunder govern the generation, storage, transfer and disposal of
hazardous wastes. RCRA, however, excludes from the definition of hazardous
wastes "drilling fluids, produced waters and other wastes associated with the
exploration, development, or production of crude oil, gas or geothermal energy."
Because of this exclusion, many of our operations are exempt from RCRA
regulation. Nevertheless, we must comply with RCRA regulations for any of our
operations that do not fall within the RCRA exclusion.
16
The OPA `90 and related regulations impose a variety of regulations on
responsible parties related to the prevention of oil spills and liability for
damages resulting from such spills. OPA `90 establishes strict liability for
owners of facilities that are the site of a release of oil into "waters of the
United States." While OPA `90 liability more typically applies to facilities
near substantial bodies of water, at least one district court has held that OPA
`90 liability can attach if the contamination could enter waters that may flow
into navigable waters.
Stricter standards in environmental legislation may be imposed on the
oil and gas industry in the future, such as proposals made in Congress and at
the state level from time to time, that would reclassify certain oil and gas
exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent and costly handling, disposal and
clean-up requirements. The impact of any such changes, however, would not likely
be any more burdensome to us than to any other similarly situated company
involved in oil and gas exploration and production.
Federal and Indian Leases
A substantial part of our producing properties in Montana consist of
oil and gas leases issued by the Bureau of Land Management or by the Blackfeet
Tribe under the supervision of the Bureau of Indian Affairs. These activities
must comply with rules and orders that regulate aspects of the oil and gas
industry, including drilling and operating on leased land and the calculation
and payment of royalties to the federal government or the governing Indian
nation. Operations on Indian lands must also comply with applicable requirements
of the governing body of the tribe involved including, in some instances, the
employment of tribal members. We believe we are currently in full compliance
with all material provisions of such regulations.
Safety and Health Regulations
We must also conduct our operations in accordance with various laws and
regulations concerning occupational safety and health. Currently, we do not
foresee expending material amounts to comply with these occupational safety and
health laws and regulations. However, since such laws and regulations are
frequently changed, we are unable to predict the future effect of these laws and
regulations.
Title to Properties
We rely on sovereign ownership of exploration rights and mineral
interests by the Polish government in connection with our activities in Poland
and have not conducted and do not plan to conduct any independent title
examination. We regularly consult with our Polish legal counsel when doing
business in Poland.
Nearly all of our United States working interests are held under leases
from third parties. We typically obtain a title opinion concerning such
properties prior to the commencement of drilling operations. We have obtained
such title opinions or other third-party review on nearly all of our producing
properties, and we believe that we have satisfactory title to all such
properties sufficient to meet standards generally accepted in the oil and gas
industry. Our United States properties are subject to typical burdens, including
customary royalty interests and liens for current taxes, but we have concluded
that such burdens do not materially interfere with the use of such properties.
Further, we believe the economic effects of such burdens have been appropriately
reflected in our acquisition cost of such properties and reserve estimates.
Title investigation before the acquisition of undeveloped properties is less
thorough than that conducted prior to drilling, as is standard practice in the
industry.
Employees and Consultants
As of December 31, 2003, we had 28 employees, consisting of eight in
Salt Lake City, Utah; seventeen 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.
17
We have no employees residing in Poland but rely on others to conduct
field operations or provide services under consulting or other contracts. Our
executive officers and other management employees regularly travel to Poland to
supervise activities conducted by others under contract on our behalf.
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. Jerozolimskie 65/79, as an office of record
in Poland.
Oil and Gas Terms
The following terms have the indicated meaning when used in this
report:
"Bbl" means barrel of oil.
"Btu" means British thermal units.
"Development well" means a well drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon known to
be productive.
"Exploratory well" means a well drilled to find and produce oil or gas
in an unproved area, to find a new reservoir in a field previously
found to be productive of oil or gas in another reservoir or to extend
a known reservoir.
"Field" means an area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic conditions.
"Gross" acres and "gross" wells means the total number of acres or
wells, as the case may be, in which an interest is owned, either
directly or though a subsidiary or other Polish enterprise in which we
have an interest.
"Horizon" means an underground geological formation that is the portion
of the larger formation that has sufficient porosity and permeability
to constitute a reservoir.
"MBbls" means thousand barrels of oil.
"Mcf" means thousand cubic feet of natural gas.
"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 that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. "Proved reserves"
may be developed or undeveloped.
18
"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.
"Usufruct" means the Polish equivalent of a U.S. oil and gas lease.
- --------------------------------------------------------------------------------
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, 2003.
19
PART II
- --------------------------------------------------------------------------------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
Price Range of Common Stock and Dividend Policy
The following table sets forth for the periods indicated the high and
low closing prices for our common stock as quoted under the symbol "FXEN" on the
Nasdaq SmallCap Market since April 2002 and on the Nasdaq National Market
previously:
Low High
2004:
First Quarter (through March 9, 2004).......... $4.55 $12.45
2003:
Fourth Quarter................................. 3.20 5.52
Third Quarter.................................. 2.84 3.30
Second Quarter................................. 2.81 3.36
First Quarter.................................. 2.60 3.54
2002:
Fourth Quarter................................. 2.24 3.04
Third Quarter.................................. 1.83 2.99
Second Quarter................................. 1.99 2.98
First Quarter.................................. 1.97 3.01
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 February 27, 2004, we had approximately 4,200 stockholders.
Our common stock is currently traded on the Nasdaq SmallCap Market
under the symbol FXEN.
Recent Sales of Unregistered Securities
In November 2003, we received net proceeds of approximately $1.9
million from the sale of 726,173 Units, each Unit consisting of one share of
common stock and a five-year warrant to purchase one share of common stock at
$3.75 per share, an aggregate of 1,452,346 additional shares. These Units were
sold in a private placement of securities to five unaffiliated purchasers
pursuant to antidilution provisions of our March 2003 private placement of 2003
Series Convertible Preferred Stock and to one officer.
In December 2003, we sold 2,362,051 shares of common stock in a private
placement of securities to 17 unaffiliated purchasers, raising a total of $9.1
million (net of offering costs of $600,000). The offering was placed privately,
primarily through CDC Securities, Inc., and included unaffiliated purchasers
pursuant to antidilutive provisions of our March 2003 private placement of 2003
Series Convertible Preferred Stock.
Net proceeds from these placements will be used to pay geological and
geophysical costs, general and administrative and project marketing costs, and
our share of further exploration and possible production facilities.
20
Each of the purchasers in each transaction was an accredited investor
who was provided with a private placement memorandum detailing our business and
financial information, including copies of our periodic reports as filed with
the Securities and Exchange Commission, and who was provided with the
opportunity to ask questions directly of our executive officers.
In each of the above transactions, the securities purchased were
restricted securities taken for investment. Certificates for all shares issued
in the such transactions bore a restrictive legend conspicuously on their face
and stop-transfer instructions were noted respecting such certificates on our
stock transfer records. Each of the foregoing transactions was effected in
reliance on the exemption from registration provided in Section 4(2) of the
Securities Act of 1933 as transactions not involving any public offering.
21
- --------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
The following selected financial data for the five years ended December
31, 2003, are derived from our audited financial statements and notes thereto,
certain of which are included in this report. The selected financial data should
be read in conjunction with Management's Discussion and Analysis of Financial
Condition and Results of Operations, and our Consolidated Financial Statements
and the Notes thereto included elsewhere in this report:
Years Ended December 31,
---------------------------------------------------------------
2003 2002 2001 2000 1999
----------- ------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales....................... $ 2,230 $ 2,209 $ 2,229 $ 2,521 $ 1,554
Oilfield services....................... 98 533 1,584 1,290 865
----------- ----------- ----------- ----------- -----------
Total revenues........................ 2,328 2,742 3,813 3,811 2,419
----------- ----------- ----------- ----------- -----------
Operating costs and expenses:
Lease operating costs (1)............... 1,546 1,365 1,358 1,349 962
Exploration costs (2)................... 523 1,541 6,544 7,389 3,053
Proved property impairment (3).......... 161 1,038 -- -- --
Oilfield services costs................. 190 540 1,301 1,084 642
Depreciation, depletion and
amortization.......................... 599 618 662 386 494
Amortization of deferred
compensation (G&A).................... -- 55 1,078 652 --
Variable stock option
compensation (G&A).................... -- -- -- -- (645)
Apache Poland general and
administrative costs.................. -- -- 575 957 --
Accretion expense....................... 37 -- -- -- --
----------- ----------- ----------- ----------- -----------
General and administrative.............. 3,253 2,440 883 2,654 2,962
----------- ----------- ----------- ----------- -----------
Total operating costs and expenses.. 6,309 7,597 12,401 14,471 7,468
----------- ----------- ----------- ----------- -----------
Operating loss............................ (3,981) (4,855) (8,588) (10,660) (5,049)
----------- ----------- ----------- ----------- -----------
Other income (expense):
Interest and other income............... 37 119 543 417 377
Interest expense........................ (788) (1,189) (331) (2) (7)
Impairment of notes receivable.......... -- -- (34) -- --
----------- ----------- ----------- ----------- -----------
Total other income (expense)........ (751) (1,070) 178 415 370
Net loss before cumulative effect of
change in accounting principle.............. (4,732) (5,925) (8,410) (10,245) (4,679)
Cumulative effect of change in
accounting principle.................... 1,799 -- -- -- --
Net loss.................................. $ (2,933) $ (5,925) $ (8,410) $ (10,245) $ (4,679)
=========== =========== =========== =========== ===========
- Continued -
22
Years Ended December 31,
--------------------------------------------------------------
2003 2002 2001 2000 1999
----------- ----------- ----------- ----------- -----------
(In thousands)
Basic and diluted net loss per share:
Net loss before cumulative effect of change in
accounting principle.............................. $ (0.24) $ (0.34) $ (0.48) $ (0.62) $ (0.33)
Cumulative effect of change in
accounting principle.............................. 0.09 -- -- -- --
----------- ----------- ----------- ----------- -----------
Net loss........................................ $ (0.15) $ (0.34) $ (0.48) $ (0.62) $ (0.33)
=========== =========== =========== =========== ===========
Basic and diluted weighted average
shares outstanding................................ 19,885 17,641 17,673 16,435 14,199
Cash Flow Statement Data:
Net cash used in operating activities............... $ (5,561) $ (2,162) $ (3,248) $ (6,082) $ (2,984)
Net cash provided by (used in) investing activities. (1,446) (295) 326 (3,834) (3,678)
Net cash provided by (used in) financing activities. 23,673 5 5,000 9,375 6,469
Balance Sheet Data:
Working capital..................................... $ 16,032 $ (9,150) $ 558 $ 616 $ 5,459
Total assets........................................ 23,769 5,441 9,168 10,570 10,470
Long-term debt...................................... -- -- 4,907 -- --
Stockholders' equity................................ 21,459 (4,869) 953 8,231 8,367
- ----------------------
(1) Includes lease operating expenses and production taxes.
(2) Includes geophysical and geological costs, exploratory dry hole costs and
nonproducing leasehold impairments.
(3) Includes proved property write downs relating to our properties in the
United States and Poland.
- --------------------------------------------------------------------------------
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION
- --------------------------------------------------------------------------------
The following discussion of our historical financial condition and
results of operations should be read in conjunction with Item 6. "Selected
Consolidated Financial Data," our Consolidated Financial Statements and related
Notes contained in this report.
Introduction
2003 was an important year for FX Energy. At the beginning of the year,
we were in a tenuous financial situation, with negative working capital of $9.2
million and $700,000 in cash. There was doubt about our ability to continue as a
going concern. During the year, we made considerable progress in improving our
financial condition. Through private placements of common and preferred stock,
we raised $25.4 million (net of offering costs). In addition, we converted $3.6
million of outstanding debt and accrued interest payable into common stock. We
also used proceeds from our equity offerings to make payments on our outstanding
obligations to POGC. At the end of the year, we had cash of approximately $17.0
million, with working capital of $16.0 million.
We were also successful in 2003 in launching our exploration program in
the Fences I and II prospect areas. We entered into a farmout agreement with
CalEnergy Gas, and in October 2003 with POGC and CalEnergy Gas began drilling
23
the Zaniemysl-3 well in the Fences I area. We announced early in 2004 that the
well encountered approximately 38 net meters (125 feet) of porous gas-bearing
Rotliegendes sandstone. During a drill stem test of the top 18 meters of the
structure, the well flowed at a controlled rate of approximately 12.5 million
cubic feet of gas per day. Together with our partners, POGC and CalEnergy Gas,
we are evaluating how to best produce and exploit the Zaniemysl field. For
further discussion concerning the Zaniemysl-3 well and the Fences I and II
areas, see Exploration, Development and Production Activities in Poland.
In early 2003, we also announced the creation of our Technical and
Advisory Panel, consisting of three individuals with extensive experience in
international oil and gas exploration and investment banking, including
extensive experience and success in the Southern North Sea. We believe that the
addition of these individuals to our technical team greatly enhanced our
exploration expertise and our ability to attract capital.
We believe that we are now well positioned to carry out our exploration
plans in Poland. We believe that we have enough capital to drill at least four
additional wells in the Fences I and II areas during 2004, without selling or
farming out any of our working interests, in addition to funding increased
levels of geological and geophysical costs and ongoing administrative expenses.
Following is a brief discussion concerning some the significant events
that occurred during 2003:
Private Placements of Common and Convertible Preferred Stock
In March 2003, we sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of
$5,593,871 after offering costs of $31,129. Each share of preferred stock
immediately converted into one share of common stock and one warrant to purchase
one share of common stock at $3.60 per share upon registration of the common
shares. The warrants to purchase common stock are exercisable anytime between
March 1, 2004, and March 1, 2008, and entitle the holders, for a period of 10
days following any new issuances of equity securities or securities convertible
or exercisable into equity securities in other than a public offering, to
preserve their approximate 16.3% ownership subsequent to this offering by
purchasing such new securities issued on the same terms as issued to others. The
preferred stock had a liquidation preference equal to the sales price for the
shares, which was $2.50 per share. The 2,250,000 shares of 2003 Series
Convertible Preferred Stock were converted to our common stock on a one-for-one
basis on October 27, 2003, pursuant to a registration statement that became
effective on that date.
Between the months of July and November, 2003, we sold 3,991,310 Units,
consisting of one share of common stock and one warrant to purchase one share of
common stock at $3.75 per share, raising a total of $10,734,672 after offering
costs of $41,685. The warrants to purchase common stock are exercisable one year
after closing and expire between July 22, 2008, and November 4, 2008.
In December 2003, we placed privately 2,362,051 shares of common stock,
raising a total of $9,137,021 after offering costs of $571,009. Approximately
$6.5 million of the net proceeds came from several European investors including
banks, mutual funds, life insurance companies and pension funds located in
Germany, Austria, Belgium and Spain. This is the first significant investment in
the Company by investors in the European financial community, and we are hopeful
that this placement will create additional interest from other European
investors.
The net proceeds from the 2003 offerings were used to reduce the note
payable to Rolls-Royce Power Ventures Limited, or RRPV, to reduce the accrued
liability to the Polish Oil and Gas Company, and will be used to fund ongoing
geological, geophysical and drilling costs in Poland, and support ongoing
prospect marketing and general and administrative costs.
Rolls-Royce Power Ventures
In March 2003, following the private placement of convertible preferred
stock, we paid $2.3 million to RRPV, which included $1.7 million in principal,
$500,000 in accrued interest, and a $100,000 loan extension fee. In return, RRPV
amended the loan agreement to extend the maturity date of the note to December
31, 2003. We agreed to pay 40% of the gross proceeds of any subsequent equity or
debt offering concluded prior to the amended maturity date, up to the amount
still owing under the loan agreement to RRPV, and also agreed to assign our
24
rights to payments under the CalEnergy Gas agreement to RRPV, except for those
amounts relating to two wells required to be drilled under the agreement. All
such payments would be used to offset the remaining principal and interest.
The loan amendment contained other terms and conditions, including an
increase in the interest rate on the note from 9.5% to 12% per annum effective
March 9, 2003, an extension of the conversion period until December 31, 2003,
with the conversion price being changed from $5.00 per share to $3.42 per share,
the market price of our stock when RRPV agreed to extend the payment date, and
an extension fee payment of $100,000.
In September 2003, we placed the then outstanding $3.3 million
principal balance of the note into an escrow account in favor of RRPV. In turn,
the interest rate on the loan was reduced to 9% per annum. In December 2003,
RRPV exercised its right to convert the outstanding principal balance and
accrued interest into 972,222 shares of common stock. RRPV released to us the
escrowed funds and subsequently released all outstanding liens and other
collateral secured by the note to us. Consequently, we have fully satisfied and
discharged all of our obligations to RRPV.
CalEnergy Gas Agreement
In January 2003, we signed a farmout agreement with CalEnergy Gas
(Holdings) Ltd., an affiliate of MidAmerican Energy Holdings Company, for the
joint exploration of our Fences I project in Poland. Under the terms of the
agreement, CalEnergy Gas had the right, but not the obligation, to pay 100% of
the costs to drill an initial well, and by so doing, earn a 24.5% interest (50%
of our 49% interest) in that drilling prospect. Following the completion of the
initial well, CalEnergy Gas could elect to terminate the agreement or to drill a
second well. If CalEnergy Gas elected to drill a second well, it would be
obligated to pay us $1 million prior to drilling. CalEnergy Gas would also have
been obligated to pay 100% of the costs of drilling a second well to earn 24.5%
interest in that prospect. Following the second well, CalEnergy Gas had the
option to acquire 24.5% (50% of our 49% interest) of the entire Fences project
area by paying to us the sum of $10.4 million, less the costs of drilling the
first two wells and less the cost of any additional geological and geophysical
costs it incurred on the Fences area.
Following completion of the Zaniemysl-3 well in early 2004, CalEnergy
Gas requested more than a six-month extension in which to undertake an
additional technical evaluation before committing to an additional exploration
well. We and POGC elected instead to proceed without delay to select a specific
drillsite in the Rusocin prospect in Fences I and to proceed with drilling as
soon as possible.
By virtue of the Zaniemysl-3 well, CalEnergy Gas retains a 24.5%
working interest in the approximately 2,200 gross acre Zaniemysl field, but
CalEnergy Gas will have no right to participate in other prospects in the Fences
I area. We will continue to work with CalEnergy Gas and POGC on development of
the Zaniemysl-3 discovery and surrounding opportunities that can be developed as
part of a single economic unit.
All of the qualifying costs related to our 49% interest in the Fences I
project area that are paid for by CalEnergy Gas will be credited against the
remaining obligation under our $16.0 million earn-in agreement with POGC (see
below). We believe that our outstanding obligation will be reduced by
approximately $2.5 million related to the costs of the Zanymiesl-3 well.
CalEnergy Gas has received consent from POGC to the transfer of one-half of our
working interest according to the agreement terms.
Fences I Settlement Agreement
On April 11, 2000, we agreed to spend $16.0 million of exploration
costs on the Fences I project area to earn a 49% interest. When expenditures
exceed $16.0 million, POGC will be obligated to pay its 51% share of further
costs. Through the end of 2001, we had paid $6.7 million towards the $16.0
million and had accrued approximately $2.7 million of additional costs
pertaining to the Fences I project area.
In late 2002, as part of our discussions with POGC concerning the
CalEnergy Gas agreement and the opportunity to participate with POGC in other
exploration projects, we reaffirmed our intent to fulfill the $16.0 million
commitment with POGC and entered into an agreement to restructure our payments
to them. In connection with this agreement, and in order to clarify
25
uncertainties about the nature and timing of our obligation regarding the
balance of our $16.0 million commitment, we agreed to recognize in 2002, and pay
to POGC at a future date, an additional $2.3 million of costs related to prior
exploration activities in the Fences project areas, $1.6 million of which will
be credited towards the $16.0 million commitment. The 2002 amount includes
$704,000 in interest costs related to our prior liabilities to POGC, $433,000 in
drilling costs, $418,000 in pipeline costs, $502,000 in seismic costs, and
$250,000 related to foreign exchange adjustments.
As part of our agreement, we agreed that the remaining balance under
our $16.0 million commitment was $5.4 million as of January 2003. Since that
time, we have incurred additional qualifying costs of approximately $100,000,
reducing our outstanding commitment to approximately $5.3 million as of December
31, 2003. We expect that our outstanding commitment will be further reduced by
approximately $2.5 million in costs paid by CalEnergy Gas associated with the
Zaniemysl-3 well. Following the drilling of the initial test well on the Rusocin
prospect, and the acquisition and reprocessing of additional seismic in the
Fences I area scheduled for this year, we believe that we will have satisfied
the entire $16.0 million commitment by the end of 2004.
As part of our future payments towards the $16.0 million commitment, we
agreed to assign to POGC all of our rights to the Kleka 11 well, including the
amounts recorded as accounts receivable for Kleka gas sales. Accordingly, at
December 31, 2002, our receivable from POGC in the amount of $607,000 was offset
against the POGC liability. The liability is to be further offset by the value
of the remaining gas reserves associated with the Kleka well, as determined by
an independent engineer. We also agreed to begin accruing interest on the past
due amount to POGC. The interest rate in effect at December 31, 2002, was 12.8%
per annum; the interest rate was reduced in March 2003 to 10.4%, and again to
9.8% in September 2003.
During 2003, we paid a total of $2.9 million in cash to POGC and
recorded a $190,000 value added tax liability related to the Kleka gas sales in
partial settlement of the outstanding liability. When we complete the assignment
of the Kleka 11 well, we believe we will have satisfied this obligation in full.
As of December 31, 2003, our share of the Kleka 11 well had estimated proved
developed producing gas reserves with an estimated net present value, discounted
at 10%, of approximately $1.1 million, as determined by an independent engineer,
an amount equal to our outstanding liability to POGC. Should POGC not concur
with the independent engineer's assessment of reserves, we may be required to
pay additional cash to settle our remaining $1.1 million liability to POGC.
Critical Accounting Policies
Oil and Gas Activities
We follow the successful efforts method of accounting for our oil and
gas properties. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves. If an
exploratory well has not found proved reserves, these costs plus the costs of
drilling the well are expensed. The costs of development wells are capitalized,
whether productive or nonproductive. Geological and geophysical costs on
exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are considered not to be realizable. An impairment loss is recorded if
the net capitalized costs of proved oil and gas properties exceed the aggregate
undiscounted future net cash flows determined on a property-by-property basis.
The impairment loss recognized equals the excess of net capitalized costs over
the related fair value, determined on a property-by-property basis. As a result
of the foregoing, our results of operations for any particular period may not be
indicative of the results that could be expected over longer periods.
Intangible Leasehold Costs
Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS 141") and Statement of Financial Accounting Standards No.
142, "Goodwill and Intangible Assets" ("SFAS 142") were issued by the FASB in
June 2001 and became effective for us on July 1, 2001, and January 1, 2002,
respectively. SFAS 141 requires all business combinations initiated after June
30, 2001, to be accounted for using the purchase method. Additionally, SFAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. SFAS 142 establishes new guidelines for accounting for
26
goodwill and other intangible assets. Under SFAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. One interpretation being considered relative to these standards is
that oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds should be classified separately from oil
and gas properties, as intangible assets on our balance sheets. In addition, the
disclosures required by SFAS 141 and 142 relative to intangibles would be
included in the notes to financial statements. Historically, we have included
these oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves as part of the oil
and gas properties, even after SFAS 141 and 142 became effective.
This interpretation of SFAS 141 and 142 described above would only
affect our balance sheet classification of oil and gas leaseholds. Our results
of operations and cash flows would not be affected, since these oil and gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves would continue to be amortized in accordance
with accounting rules for oil and gas companies provided in Statement of
Financial Accounting Standards No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies."
At both December 31, 2003 and 2002, we had undeveloped leaseholds of
approximately $166,000 and $147,000, respectively, that would be classified
under that interpretation on our consolidated balance sheets as "intangible
undeveloped leaseholds" and developed leaseholds of approximately $7,000 in both
years that would be classified under that interpretation as "intangible
developed leaseholds" if we applied the interpretation currently being
considered.
We will continue to classify our oil and gas mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further interpretative
guidance is provided.
Oil and Gas Reserves
Engineering estimates of our oil and gas reserves are inherently
imprecise and represent only approximate amounts because of the subjective
judgments involved in developing such information. There are authoritative
guidelines regarding the engineering criteria that have to be met before
estimated oil and gas reserves can be designated as "proved." Proved reserve
estimates are updated at least annually and take into account recent production
and technical information about each field. In addition, as prices and cost
levels change from year to year, the estimate of proved reserves also changes.
This change is considered a change in estimate for accounting purposes and is
reflected on a prospective basis in related depreciation rates.
Despite the inherent imprecision in these engineering estimates, these
estimates are used in determining depreciation expense and impairment expense
and in disclosing the supplemental standardized measure of discounted future net
cash flows relating to proved oil and gas properties. Depreciation rates are
determined based on estimated proved reserve quantities (the denominator) and
capitalized costs of producing properties (the numerator). Producing properties'
capitalized costs are amortized based on the units of oil or gas produced.
Therefore, assuming all other variables are held constant, an increase in
estimated proved reserves decreases our depreciation, depletion and amortization
expense. Also, estimated reserves are often used to calculate future cash flows
from our oil and gas operations, which serve as an indicator of fair value in
determining whether a property is impaired or not. The larger the estimated
reserves, the less likely the property is impaired.
Stock Based Compensation
We have chosen to account for stock options granted to employees and
directors under the recognition and measurement principles of APB Opinion No. 25
instead of the fair value recognition provisions of SFAS No. 123, "Accounting
for Stock-based Compensation," as amended by SFAS No. 148, "Accounting for
Stock-based Compensation Transition and Disclosure."
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, general and administrative costs, or G&A, and other income
27
directly associated with their respective segments are detailed within the
following discussion. DD&A, G&A, amortization of deferred compensation (G&A),
interest income, other income, interest expense, impairment of notes receivable
from officers and other costs, which are not allocated to individual operating
segments for management or segment reporting purposes, are discussed in their
entirety following the segment discussion. A comparison of the results of
operations by business segment and the information regarding nonsegmented items
for the years ended December 31, 2003, 2002 and 2001, respectively, follows.
Further information concerning our business segments can be found in Note 13,
Business Segments, in the financial statements.
Exploration and Production Segment
A summary of the amount and percentage change, as compared to their
respective prior year period, for oil and gas revenues, average oil and gas
prices, oil and gas production volumes, and lifting costs per barrel and Mcf for
the years ended December 31, 2003, 2002 and 2001, is set forth in the following
table:
For the year ended December 31,
----------------------------------------------------------------------------
2003 2002 2001
-------------------------------------------------- -------------------------
Oil Gas Oil Gas Oil Gas
------------ ----------- ------------ ----------- ------------ ------------
Revenues.............................. $2,230,000 $ -- $1,924,000 $ 285,000 $ 1,835,000 $ 394,000
Percent change versus prior year.... +15.9% -100.0% +4.9% -27.7% -28.0% +100%
Average price (Bbls or Mcf)(1)........ $ 26.29 $ -- $ 21.19 $ 1.58 $ 19.41 $ 1.58
Percent change versus prior year.... 24.1% -- +9.2% -- -25.8% +100%
Production volumes (Bbls or Mcf)...... 84,811 -- 90,817 180,407 94,522 249,661
Percent change versus prior year.... -6.6% -100.0% -3.9% -27.7% -1.9% +100%
Lifting costs per Bbls or Mcf(2)...... $ 17.22 $ -- $ 14.28 $ 0.16 $ 13.62 $ 0.16
Percent change versus prior year.... +20.6% -- +4.8% -- +12.3% --
- -----------------------
(1) The contract price for gas during 2002 and 2001 was $2.02 per MMBtu; the
produced gas averaged 0.8 MMBtu per Mcf.
(2) Lifting costs per barrel are computed by dividing the related lease
operating expenses by the total barrels of oil produced. Lifting costs per
Mcf of gas are computed by dividing the related lease operating expenses by
the total Mcf of gas produced before royalties. Lifting costs do not include
production taxes.
Oil Revenues. Oil revenues were $2.2 million, $1.9 million and $1.8
million for the years ended December 31, 2003, 2002 and 2001, respectively. All
oil revenues during the three years were derived from our producing properties
in the United States. During these three years, oil revenues fluctuated
primarily due to volatile oil prices and the declining production rates
attributable to the natural production declines of our producing properties. Oil
revenues in 2003 increased from 2002 levels by approximately $433,000 due to
higher oil prices, offset by approximately $127,000 related to production
declines. Oil revenues in 2002 increased from 2001 levels by approximately
$161,000 due to higher oil prices, offset by approximately $72,000 related to
production declines.
Gas Revenues. Our gas revenues are derived solely from our Polish
producing operations. Gas revenues were $285,000 and $394,000 for the years
ended December 31, 2002 and 2001, respectively. There were no gas revenues
during 2003. As part of our Fences I settlement with POGC in early 2003, we
agreed to assign our interest in the Kleka 11 well effective December 2002,
along with the related accounts receivable, to POGC as soon as possible in order
to conserve cash while reducing the balance of our liability due to POGC.
Accordingly, we recorded no gas sales in 2003. Gas volumes in 2002 reflected a
full year of production from the Kleka 11, our first producing well in Poland,
which began producing in late February 2001. During 2002 and 2001, gas produced
by the Kleka 11 was sold to POGC based on U.S. dollar pricing at a fixed price
under a five-year contract, which may be terminated by giving POGC a 90-day
written notice. The decline in gas production from 2001 to 2002 is the result of
the operator choking back the well to avoid any increase in water production.
Lease Operating Costs. Lease operating costs were $1.5 million in 2003
and $1.4 million for each of 2002 and 2001. Operating costs rose slightly from
2002 to 2003, and from 2001 to 2002, as higher oil lifting costs offset lower
oil and gas production. Operating costs in 2003 increased approximately $250,000
due to higher lifting costs, offset by approximately $86,000 related to lower
oil and gas production. Operating costs in 2002 increased approximately $68,000
due to higher lifting costs, offset by approximately $61,000 related to lower
oil and gas production.
28
Exploration Costs. Our exploration efforts are focused in Poland, and
the expenses consist of geological and geophysical costs, or G&G costs,
exploratory dry holes and oil and gas leasehold impairments. Exploration costs
were $684,000, $2.6 million and $6.5 million for the years ended December 31,
2003, 2002 and 2001, respectively. Limited available capital caused us to
sharply curtail our exploration activities in Poland in 2003 and 2002. We expect
to increase our level of exploration costs in 2004 as we increase our pace of
prospect development, selection, and drilling.
G&G costs were $523,000, $1.0 million and $2.9 million for the years
ended December 31, 2003, 2002 and 2001, respectively. During 2003 and 2002, most
of our G&G costs were spent on reprocessing and further analyzing the seismic
data on the Fences I area. During 2001, we spent approximately $1.8 million on
acquiring 3-D seismic data in the Fences project areas, and the remainder
acquiring and analyzing 2-D seismic data on the Pomeranian project area.
Exploratory dry-hole costs were $0, $0 and $3.1 million for the years
ended December 31, 2003, 2002 and 2001, respectively. Due to our capital
limitations, we did not participate in any exploratory drilling in 2003 and
2002. During 2001, we incurred dry hole costs of $3.1 million pertaining to the
Mieszkow 1 well on the Fences I project area.
Impairments of oil and gas properties were $161,000, $1.5 million and
$584,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
During 2003, the entire impairment related to the Kleka 11 well, which was
written down to the value established by an independent reservoir engineer, and
included both capital costs and related pipeline costs. We have agreed to
transfer the Kleka 11 well to POGC to satisfy outstanding obligations. During
2002, we incurred an impairment of $509,000 in costs associated with the Tuchola
108-2 well. The well was completed in 2001, but has since been shut-in pending a
pipeline connection. Constrained capital has prevented us from drilling the
additional appraisal and development wells and building the necessary
infrastructure. We also recognized an impairment of $1.0 million associated with
the Kleka 11 well, where lower production profiles caused a downward revision in
recoverable future reserves. During 2001, we incurred impairments of $525,000
for the Baltic project area and $59,000 for the Warsaw West project area, both
of which are located in Poland in areas where we no longer have exploration
plans.
Apache Poland G&A Costs. Apache Poland G&A costs consist of our share
of direct overhead costs incurred by Apache in Poland in accordance with the
terms of the Apache Exploration Program. Apache Poland G&A costs were $0, $0 and
$575,000 for the years ended December 31, 2003, 2002 and 2001. During mid-2001,
we began to narrow the focus of our ongoing exploratory efforts with Apache by
continuing to work only on the Pomeranian and Wilga project areas and
discontinued our exploratory activities on the Lublin Basin, Warsaw West and
Carpathian project areas. There were no jointly conducted activities in the
Wilga project area in 2003 and 2002.
DD&A Expense - Producing Operations. DD&A expense for producing
properties was $347,000, $281,000 and $322,000 for the years ended December 31,
2003, 2002 and 2001, respectively. DD&A expense during 2003, 2002 and 2001
includes approximately $0, $205,000 and $258,000, respectively, or $1.03 per Mcf
of gas produced, associated solely with the Kleka 11 well that began producing
in Poland during February 2001. DD&A expense declined from 2001 to 2002 due to
reduced production from the well. There was no DD&A expense associated with
Poland during 2003, as we agreed to transfer our interest in the Kleka 11 well
to POGC. The increase from 2002 to 2003 is due primarily to the net book value
of domestic assets being increased as a result of the adoption of SFAS 143
effective January 1, 2003.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $98,000,
$523,000 and $1.6 million for the years ended December 31, 2003, 2002 and 2001,
respectively. During 2003, the contract drilling industry was at a virtual
standstill in the area where we operate, and the outlook for 2004 remains
unfavorable. The industry was also significantly curtailed in the area where we
operate in 2002, and our revenues declined sharply from 2001 as a result.
Oilfield services revenues will continue to fluctuate from period to period
based on market demand, weather, the number of wells drilled, downtime for
equipment repairs, the degree of emphasis on using our oilfield services
equipment on our company-owned properties, and other factors.
29
Oilfield Services Costs. Oilfield services costs were $190,000,
$540,000 and $1.3 million for the years ended December 31, 2003, 2002 and 2001,
respectively, or 194%, 101% and 82% of oilfield servicing revenues,
respectively. During 2003 and 2002, oilfield servicing costs were a higher
percentage of oilfield services revenues, as compared to 2001, due to increased
downtime, maintenance and repair costs associated with our oilfield servicing
equipment. In general, oilfield servicing costs are directly associated with
oilfield services revenues. As such, oilfield services costs will continue to
fluctuate period to period based on the number of wells drilled, revenues
generated, weather, downtime for equipment repairs, the degree of emphasis on
using our oilfield services equipment on our company-owned properties, and other
factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $304,000, $310,000 and $308,000 for the years ended December 31, 2003, 2002
and 2001, respectively. We spent $116,000, $248,000 and $779,000 on upgrading
our oilfield servicing equipment during 2002, 2001 and 2000, respectively.
Nonsegmented Items
G&A Costs - Corporate. G&A costs were $3.2 million, $2.4 million and
$883,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
During 2002, in recognition of our limited resources, we aggressively pursued
certain cost reduction measures to help conserve capital. As part of those
reductions, most of our employees and directors and some of our consultants
reduced their salaries and fees by 50%. During 2003, after we successfully
raised more than $25 million through the sale of equity, we reinstated those
salaries and fees. In addition, we incurred higher accounting and legal fees as
a result of an SEC review of our 2002 and 2003 filings and the submission of
several SEC registration statements resulting from our stock sales. Accordingly,
our 2003 G&A costs were significantly higher than those incurred during 2002. In
addition, we were able to resume many of our activities in Poland, which
resulted in higher travel costs for the year. During 2001, G&A costs were
unusually low, primarily due to the Company writing off $1.7 million of
compensation that was accrued as of December 31, 2000. None of this waived
compensation has or will be paid.
Interest and Other Income - Corporate. Interest and other income was
$36,000, $119,000 and $514,000 for the years ended December 31, 2003, 2002 and
2001, respectively. Lower cash balances and interest rates in 2003 and 2002
reduced our interest income in both years. During the years ended December 31,
2002 and 2001, we recorded other income of $93,000 and $341,000, respectively,
pertaining to the amortization of an option premium resulting from granting RRPV
an option to purchase gas from our properties in Poland.
Interest Expense. Interest expense was $788,000, $1.2 million and
$331,000 for the years ended December 31, 2003, 2002 and 2001, respectively. In
March 2002, we began to accrue interest on the $5.0 million RRPV obligation at
an annual rate of 9.5%. From May to September, 2003, the RRPV interest rate
increased to 12%. It was reduced to 9.5% from October to November, 2003, at
which time RRPV converted its note payable and accrued interest into common
stock. We began accruing interest our on obligation to POGC during 2002, which
accounted for interest expense of $371,000 and $614,000 in 2003 and 2002,
respectively. As part of our further restructured agreement with POGC, we
stopped accruing interest on the obligation at December 31, 2003. During 2002
and 2001, we recorded $93,000 and $341,000, respectively, of imputed interest
expense relating to our financing arrangement with RRPV.
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $0, $55,000, and $1.1 million during the years ended December
31, 2003, 2002 and 2001, respectively. On April 5, 2001, we extended the term of
options to purchase 125,000 shares of our common stock that were to expire
during 2001 for a period of two years, with a one-year vesting period. On August
4, 2000, we extended the term of options and warrants to purchase 678,000 shares
of our common stock that were to expire during 2000 for a period of two years,
with a one-year vesting period. In accordance with FIN 44 "Accounting for
Certain Transactions involving Stock Compensation," we incurred noncash deferred
compensation costs of $1.8 million, including $219,000 for the April 5, 2001,
option extension and $1.6 million for the August 4, 2000, option extension, to
be amortized over their respective one-year vesting periods from the date of
extension. The deferred costs were all amortized as of December 31, 2002.
30
Income Taxes. We incurred net losses of $2.9 million, $5.9 million and
$8.4 million for the years ended December 31, 2003, 2002 and 2001, respectively.
SFAS No. 109 "Accounting for Income Taxes" requires that a valuation allowance
be provided if it is more likely than not that some portion or all of a deferred
tax asset will not be realized. Our ability to realize the benefit of our
deferred tax asset will depend on the generation of future taxable income
through profitable operations and the expansion of our exploration and
development activities. The market and capital risks associated with achieving
the above requirement are considerable, resulting in our conclusion that a full
valuation allowance be provided. Accordingly, we did not recognize any income
tax benefit in our consolidated statement of operations for these years.
Liquidity and Capital Resources
We have made significant progress in improving our liquidity and
capital resources during the past year. At the beginning of the year, we were in
a tenuous financial situation, with negative working capital of $9.2 million and
$700,000 in cash. Through private placements of common and preferred stock, we
raised $25.4 million (net of offering costs) during 2003. In addition, $3.6
million of outstanding debt and accrued interest were converted into common
stock. We used proceeds from our equity sales to reduce our outstanding
obligations to POGC. At the end of the year, we had cash of approximately $17
million, with working capital of $15.8 million. We believe we are now well
positioned to carry out our exploration activities in Poland.
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities, and agreements with industry
participants that funded our share of costs in certain exploratory activities in
return for an interest in our properties. The continuation of our exploratory
efforts in Poland may be dependent on our ability to raise additional capital or
to farm out our properties. The availability of such capital or farmouts may
affect the timing, pace, scope and amount of our future capital expenditures. We
cannot assure that we will be able to secure additional participants or obtain
additional equity or debt financing or complete farmout or other industry cost-
and risk-sharing arrangements, particularly, if we fail to make additional
discoveries. Such events would materially and adversely affect our financial
position and results of operations.
We may seek to obtain additional funds for future capital investments
from strategic alliances with other energy or financial participants, the sale
of additional securities, project financing, sale of partial property interests,
or other arrangements, all of which may dilute the interest of our existing
stockholders or our interest in the specific project financed. We may change the
allocation of capital among the categories of anticipated expenditures depending
upon future events. For example, we may change the allocation of our
expenditures based on the actual results and costs of future exploration,
appraisal, development, production, property acquisition and other activities.
In addition, we may have to change our anticipated expenditures if costs of
placing any particular discovery into production are higher, if the field is
smaller, or if the commencement of production takes longer than expected.
Working Capital (current assets less current liabilities). Our working
capital was $16.0 million as of December 31, 2003, an increase of $25.0 million
from December 31, 2002. The improvement is due primarily to the sale of equity
securities discussed earlier. In addition, $3.6 million of outstanding debt and
accrued interest were converted into common stock, which paid in full our note
payable to RRPV.
Our current liabilities include $1.1 million of costs related to our
Fences I project in Poland. This amount is equal to the value of the remaining
gas reserves at the Kleka 11, which we have agreed to assign to POGC effective
December 2002. We may be required to pay additional cash to settle this
liability.
Operating Activities. We used net cash of $5.6 million, $2.1 million
and $3.1 million in our operating activities during 2003, 2002 and 2001,
respectively, primarily as a result of the net losses incurred in those years.
We made significant progress in reducing our outstanding liabilities during
2003.
Investing Activities. We used net cash of $1.4 million in investing
activities in 2003, used $295,000 in investing activities during 2002, and
received net cash of $326,000 from our investing activities during 2001. During
2003, we used $700,000 to pay liabilities associated with oil and gas property
additions from prior years. Also included in this amount is a deposit with
CalEnergy Gas in the amount of $366,000 to cover drilling expenses for the
Zaniemysl-3 well, in the event costs exceed an agreed upon target amount. We
spent $194,000 in 2003 related to our proved properties and oilfield equipment
31
in the United States. During 2002, the bulk of cash used was for upgrading our
producing oil and gas properties and our well-servicing equipment. During 2001,
our capital expenditures for producing properties and well-servicing equipment
were offset by $1.3 million in maturing marketable debt securities.
Financing Activities. We received net cash of $23.7 million, $4,500 and
$5.0 million from our financing activities during 2003, 2002 and 2001,
respectively. During 2003, we received a total of $25.4 million in net proceeds
from the sale of securities. These proceeds were offset by $1.8 million paid to
RRPV, $1.7 million of which was a principal payment on its note payable, and
$100,000 of which was a loan extension fee paid in March 2003. During 2001, we
received $5.0 million pertaining to our RRPV loan and gas purchase option
agreement.
We believe that our capital resources from existing cash balances are
adequate to meet the requirements of our business through 2004, and that we have
adequate liquidity to maintain our operations as they currently exist.
Contractual Obligations and Contingent Liabilities and Commitments
The following is a summary of our significant contractual obligations
and commitments as of December 31, 2003:
Contractual Obligations and Commitments Due by December 31, 2004
--------------------------------------- ------------------------
(In thousands)
Fences I work commitment(1)................... $5,265
------
Total................................... $5,265
======
- --------------------------
(1) The Fences I work commitment is required in order for us to earn a 49%
interest in the Fences I project area. We expect that the balance of our
earning requirement will be met by the approximately $2.5 million in costs
paid by CalEnergy Gas associated with the Zaniemysl-3 well, the costs of
drilling the initial test well on the Rusocin prospect, and the acquisition
and reprocessing of additional seismic in the Fences I area scheduled for
2004.
Our oil and gas drilling and production operations are subject to
hazards incidental to the industry that can cause severe damage to and
destruction of property and equipment, pollution or environmental damage and
suspension of operations, personal injury, and loss of life. To lessen the
effects of these hazards, we maintain insurance of various types to cover our
United States operations and rely on the insurance or financial capabilities of
our exploration participants in Poland. These measures do not cover risks
related to violations of environmental laws or all other risks involved in oil
and gas exploration, drilling and production. We would be adversely affected by
a significant adverse event that is not fully covered by insurance or by our
inability to maintain adequate insurance in the future at rates we consider
reasonable.
New Accounting Pronouncements
We have reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on our results
of operations or financial position. Based on that review, we believe that none
of these pronouncements will have a significant effect on current or future
earnings or operations.
32
- --------------------------------------------------------------------------------
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISKS
- --------------------------------------------------------------------------------
Price Risk
Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.
We currently have no gas production in Poland. Previously, our gas in
Poland was sold to POGC based on U.S. dollar pricing under a five-year contract.
The limited volume and sources of our gas production means we cannot assure
uninterruptible production or production in amounts that would be meaningful to
industrial users, which may depress the price we may be able to obtain. There is
currently no competitive market for the sale of gas in Poland. Accordingly, we
expect that the prices we receive for the gas we produce will be lower than
would be the case in a competitive setting and may be lower than prevailing
western European prices, at least until a fully competitive market develops in
Poland.
We currently do not engage in any hedging activities or have any
derivative financial instruments to protect ourselves against market risks
associated with oil and gas price fluctuations, although we may elect to do so
if we achieve a significant amount of production in Poland.
Foreign Currency Risk
We have entered into various agreements in Poland, primarily in U.S.
dollars or the U.S. dollar equivalent of the Polish zloty. We conduct our
day-to-day business on this basis as well. The Polish zloty is subject to
exchange rate fluctuations that are beyond our control. We do not currently
engage in hedging transactions to protect ourselves against foreign currency
risks, nor do we intend to do so in the foreseeable future.
- --------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
Our financial statements, including the auditor's report, are included
beginning at page F-1 immediately following the signature page of this report.
33
- --------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------
We have not disagreed with our auditors on any items of accounting
treatment or financial disclosure.
- --------------------------------------------------------------------------------
ITEM 9A. CONTROLS AND PROCEDURES
- --------------------------------------------------------------------------------
We maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed by us in the reports that we
file or submit to the Securities and Exchange Commission under the Securities
Exchange Act of 1934, as amended, is recorded, processed, summarized and
reported within the time periods specified by the Securities and Exchange
Commission's rules and forms, and that information is accumulated and
communicated to our management, including our principal executive and principal
financial officers (whom we refer to in this periodic report as our Certifying
Officers), as appropriate to allow timely decisions regarding required
disclosure. Our management evaluated, with the participation of our Certifying
Officers, the effectiveness of our disclosure controls and procedures as of
December 31, 2003, pursuant to Rule 13a-15(b) under the Securities Exchange Act.
Based upon that evaluation, our Certifying Officers concluded that, as of
December 31, 2003, our disclosure controls and procedures were effective.
There were no changes in our internal control over financial reporting
that occurred during our most recently completed fiscal quarter that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
34
PART III
- --------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual
meeting of stockholders under the captions "Corporate Governance," "Proposal 1.
Election of Directors," and "Section 16(a) Beneficial Ownership Reporting
Compliance" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual
meeting of stockholders under the caption "Executive Compensation" is
incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual
meeting of stockholders under the caption "Principal Stockholders" is
incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual
meeting of stockholders under the caption "Certain Relationships and Related
Transactions" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual
meeting of stockholders under the caption "Relationship with Independent
Auditors" is incorporated herein by reference.
35
PART IV
- --------------------------------------------------------------------------------
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
(a) The following documents are filed as part of this report or incorporated
herein by reference.
1. Financial Statements. See the following beginning at page F-1:
Page
-------
Report of Independent Auditors............................... F-1
Consolidated Balance Sheets as of December 31, 2003
and 2002................................................... F-2
Consolidated Statements of Operations for each of the
Three Years Ended December 31, 2003, 2002 and 2001........ F-3
Consolidated Statements of Cash Flows for each of the
Three Years Ended December 31, 2003, 2002 and 2001........ F-5
Consolidated Statements of Stockholders' Equity (Deficit)
for each of the Three Years Ended December 31, 2003,
2002 and 2001............................................. 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:
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
Item 3 Articles of Incorporation and Bylaws
- ------------ -----------------------------------------------------
3.01 Restated and Amended Articles of Incorporation Incorporated by reference from the quarterly
report on Form 10-Q for the quarter ended
September 30, 2000, filed November 7, 2000.
3.02 Bylaws
Incorporated by reference from the registration
statement on Form SB-2, SEC File No. 33-88354-D.
Instruments Defining the
Item 4 Rights of Security Holders
- ------------ -----------------------------------------------------
4.01 Specimen Stock Certificate Incorporated by reference from the registration
statement on Form SB-2, SEC File No. 33-88354-D.
4.02 Form of Designation of Rights, Privileges, and Attached.
Preferences of Series A Preferred Stock
4.03 Form of Rights Agreement dated as of April 4, 1997, Attached.
between FX Energy, Inc. and Fidelity Transfer Corp.
Item 10 Material Contracts
- ------------ -----------------------------------------------------
10.26 Frontier Oil Exploration Company 1995 Stock Option Attached.
and Award Plan**
36
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
10.27 FX Energy, Inc. 1996 Stock Option and Award Plan** Attached.
10.28 FX Energy, Inc. 1997 Stock Option and Award Plan** Attached.
10.29 FX Energy, Inc. 1998 Stock Option and Award Plan** Attached.
10.30 Employment Agreements between FX Energy, Inc. and Incorporated by reference from the registration
each of David Pierce and Andrew Pierce, effective statement on Form SB-2, SEC File No. 33-88354-D.
January 1, 1995**
10.32 Form of Stock Option with related schedule Incorporated by reference from the registration
(D. Pierce and A. Pierce)** statement on Form SB-2, SEC File No. 33-88354-D.
10.39 Employment Agreement between FX Energy, Inc. and Incorporated by reference from the registration
Jerzy B. Maciolek** statement on Form S-1, SEC File No. 333-05583,
filed June 10, 1996.
10.42 Employment Agreement between FX Energy, Inc. and Attached.
Scott J. Duncan**
10.52 Form of Indemnification Agreement between FX Energy, Attached.
Inc. and certain directors, with related schedule**
10.53 Agreement on Cooperation in Exploration of Incorporated by reference from the quarterly
Hydrocarbons on Foresudetic Monocline dated April report on Form 10-Q for the quarter ended
11, 2000, between Polskie Gornictwo Naftowe I March 31, 2000, filed May 15, 2000.
Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z
o.o. relating to Fences I project area
10.57 US$5,000,000 9.5% Convertible Secured Note dated as Incorporated by reference from the annual report
of March 9, 2001 on Form 10-K for the year ended December 31,
2000, filed March 20, 2001.
10.58 Form of Pledge Agreement FX Energy Poland Sp. z o.o. Incorporated by reference from the annual report
and Rolls Royce Power Ventures Limited dated March on Form 10-K for the year ended December 31,
9, 2001, and related schedules 2000, filed March 20, 2001.
10.59 Sales / Purchase Agreement Special Provisions Incorporated by reference from the annual report
between Plains Marketing Canada, L.P. and FX on Form 10-K for the period ended December 31,
Drilling Company Inc. agreed April 29, 2002 2002, filed March 27, 2003.
10.60 Form of Non-Qualified Stock Option awarded August Incorporated by reference from the annual report
14, 2002, with related schedule** on Form 10-K for the period ended December 31,
2002, filed March 27, 2003.
10.61 Description of compensation arrangement with Thomas Incorporated by reference from the annual report
B. Lovejoy and outside directors** on Form 10-K for the period ended December 31,
2002, filed March 27, 2003.
10.62 Agreement Regarding Cooperation within the Poznan Incorporated by reference from the annual report
Area (Fences II) entered into January 8, 2003, by on Form 10-K for the period ended December 31,
and between Polskie Gornictwo Naftowe i Gazownictwo 2002, filed March 27, 2003.
S.A. and FX Energy Poland Sp. z o.o.
37
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
10.63 Settlement Agreement Regarding the Fences I Area Incorporated by reference from the annual report
entered into January 8, 2003, by and between Polskie on Form 10-K for the period ended December 31,
Gornictwo Naftowe i Gazownictwo S.A. and FX Energy 2002, filed March 27, 2003.
Poland Sp. z o.o.
10.64 Farmout Agreement Entered into by and between FX Incorporated by reference from the annual report
Energy Poland Sp. z o.o. and CalEnergy Power on Form 10-K for the period ended December 31,
(Polska) Sp. z o.o. Covering the "Fences Area" in 2002, filed March 27, 2003.
the Foresudetic Monocline made as of January 9, 2003
10.65 Letter Agreement between Rolls-Royce Power Ventures Incorporated by reference from the annual report
Limited and FX Energy, Inc. dated February 6, 2003 on Form 10-K for the period ended December 31,
2002, filed March 27, 2003.
10.66 Amendment Agreement No. 1 to 9.5% Convertible Incorporated by reference from the annual report
Secured Note between FX Energy, Inc. and Rolls-Royce on Form 10-K for the period ended December 31,
Power Ventures Limited dated March 10, 2003 2002, filed March 27, 2003.
10.67 FX Energy, Inc. 1999 Stock Option and Award Plan** Attached.
10.68 FX Energy, Inc. 2000 Stock Option and Award Plan** Attached.
10.69 FX Energy, Inc. 2001 Stock Option and Award Plan** Attached.
10.70 FX Energy, Inc. 2003 Long-Term Incentive Plan Attached.
10.71 Form of Indemnification Agreement between FX Energy, Attached.
Inc. and directors with related schedule
Item 21 Subsidiaries of the Registrant
- ------------ -----------------------------------------------------
21.01 Schedule of Subsidiaries Attached.
Item 23 Consents of Experts and Counsel
- ------------ -----------------------------------------------------
23.01 Consent of PricewaterhouseCoopers LLP, independent Attached.
accountants
23.02 Consent of Larry D. Krause, Petroleum Engineer Attached.
23.03 Consent of Troy-Ikoda Limited, Petroleum Engineers Attached.
Item 31 Rule 13a-14(a)/15d-14(a) Certifications
- ------------ -----------------------------------------------------
31.01 Certification of Chief Executive Officer Pursuant to Attached.
Rule 13a-14
31.02 Certification of Chief Financial Officer Pursuant to Attached.
Rule 13a-14
Item 32 Section 1350 Certifications
- ------------ -----------------------------------------------------
32.01 Certification of Chief Executive Officer Pursuant to Attached.
18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
38
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
32.02 Certification of Chief Financial Officer Pursuant to Attached.
18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
- ----------------------------
* All exhibits are numbered with the number preceding the decimal indicating
the applicable SEC reference number in Item 601 and the number following
the decimal indicating the sequence of the particular document. Omitted
numbers in the sequence refer to documents previously filed as an exhibit,
but no longer required.
** Identifies each management contract or compensatory plan or arrangement
required to be filed as an exhibit, as required by Item 15(a)(3) of Form
10-K.
(b) Reports on Form 8-K.
During the quarter ended December 31, 2003, we filed or furnished the
following items on Form 8-K:
Date of Event Reported Item(s) Reported
-------------------------- -------------------------------------------
December 4, 2003 Items 7 and 9
November 19, 2003 Items 7 and 9
November 17, 2003 Items 7 and 9
November 5, 2003 Items 7 and 9
October 29, 2003 Item 5
October 28, 2003 Item 5
October 16, 2003 Items 7 and 9
During the quarter ended December 31, 2003, we filed the following item on Form
8-K/A:
Date of Event Reported Item(s) Reported
------------------------- ----------------------------------------
December 4, 2003 Items 5 and 7
39
- --------------------------------------------------------------------------------
SIGNATURES
- --------------------------------------------------------------------------------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
FX ENERGY, INC. (Registrant)
Dated: March 10, 2004 By: /s/ David N. Pierce
--------------------------------------
David N. Pierce
President and Chief Executive Officer
Dated: March 10, 2004 By: /s/ Thomas B. Lovejoy
--------------------------------------
Thomas B. Lovejoy
Chief Financial Officer
Dated: March 10, 2004 By: /s/ Clay Newton
--------------------------------------
Clay Newton
Chief Accounting Officer
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
/s/ Thomas B. Lovejoy
-------------------------------------
Dated: March 10, 2004 Thomas B. Lovejoy, Director
/s/ David N. Pierce
-------------------------------------
Dated: March 10, 2004 David N. Pierce, Director
/s/ Scott J. Duncan
-------------------------------------
Dated: March 10, 2004 Scott J. Duncan, Director
/s/ Dennis B. Goldstein
-------------------------------------
Dated: March 10, 2004 Dennis B. Goldstein, Director
/s/ David L. Worrell
-------------------------------------
Dated: March 10, 2004 David L. Worrell, Director
/s/ Arnold S. Grundvig, Jr.
-------------------------------------
Dated: March 10, 2004 Arnold S. Grundvig, Jr., Director
/s/ Jerzy B. Maciolek
-------------------------------------
Dated: March 10, 2004 Jerzy B. Maciolek, Director
/s/ Richard Hardman
-------------------------------------
Dated: March 10, 2004 Richard Hardman, Director
40
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors
of FX Energy, Inc. and its subsidiaries:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of cash flows and of stockholders' equity
present fairly, in all material respects, the financial position of FX Energy,
Inc., and its subsidiaries (the "Company") at December 31, 2003 and 2002, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2003 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.
As discussed in Note 2 to the Financial Statements, the Company changed its
method of accounting for asset retirement costs, effective January 1, 2003.
/s/ PricewaterhouseCoopers LLP
Salt Lake City, Utah
February 20, 2004
F-1
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2003 and 2002
2003 2002
--------------- --------------
ASSETS
Current assets:
Cash and cash equivalents............................................................ $ 17,370,531 $ 705,012
Receivables:
Accrued oil sales................................................................ 245,511 238,236
Joint interest and other receivables............................................. 137,479 36,893
Inventory............................................................................ 79,318 84,262
Other current assets................................................................. 126,007 95,726
--------------- --------------
Total current assets......................................................... 17,958,846 1,160,129
--------------- --------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved........................................................................... 5,752,518 4,754,377
Unproved......................................................................... 173,969 154,261
Other property and equipment......................................................... 3,598,137 3,683,226
--------------- --------------
Gross property and equipment..................................................... 9,524,624 8,591,864
Less accumulated depreciation, depletion and amortization............................ (4,451,168) (4,685,487)
--------------- --------------
Net property and equipment................................................... 5,073,456 3,906,377
--------------- --------------
Other assets:
Certificates of deposit.............................................................. 356,500 356,500
Deposits............................................................................. 379,743 18,072
--------------- --------------
Total other assets........................................................... 736,243 374,572
--------------- --------------
Total assets............................................................................. $ 23,768,545 $ 5,441,078
=============== ==============
-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, 2003 and 2002
-Continued-
2003 2002
--------------- --------------
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable..................................................................... $ 621,414 $ 376,264
Accrued liabilities.................................................................. 1,305,735 4,933,393
Note payable......................................................................... -- 5,000,000
--------------- --------------
Total current liabilities.................................................... 1,927,149 10,309,657
Asset retirement obligation.............................................................. 382,696 --
--------------- --------------
Total liabilities............................................................ 2,309,845 10,309,657
--------------- --------------
Commitments (Note 6)
Stockholders' equity (deficit):
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
December 31, 2003 and 2002; no shares outstanding................................ -- --
Common stock, $0.001 par value, 100,000,000 shares authorized as of December 31,
2003 and 2002; 27,300,063and 17,651,917 shares issued as of
December 31, 2003 and 2002, respectively......................................... 27,300 17,652
Additional paid in capital........................................................... 77,326,046 48,075,035
Accumulated deficit.................................................................. (55,894,646) (52,961,266)
--------------- --------------
Total stockholders' equity (deficit)......................................... 21,458,700 (4,868,579)
--------------- --------------
Total liabilities and stockholders' equity (deficit)..................................... $ 23,768,545 $ 5,441,078
=============== ==============
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, 2003, 2002 and 2001
2003 2002 2001
--------------- --------------- ---------------
Revenues:
Oil and gas sales.................................................. $ 2,229,993 $ 2,208,916 $ 2,229,064
Oilfield services.................................................. 97,694 533,438 1,583,811
--------------- --------------- ---------------
Total revenues................................................. 2,327,687 2,742,354 3,812,875
--------------- --------------- ---------------
Operating costs and expenses:
Lease operating expenses........................................... 1,545,912 1,365,454 1,358,304
Geological and geophysical costs................................... 523,401 1,030,660 2,909,270
Exploratory dry hole costs......................................... -- -- 3,051,334
Impairment of oil and gas properties............................... 160,886 1,547,860 583,855
Oilfield services costs............................................ 189,920 539,783 1,300,713
Depreciation, depletion and amortization........................... 598,548 617,937 661,644
Amortization of deferred compensation (G&A)........................ -- 54,688 1,077,547
Apache Poland general and administrative costs..................... -- -- 575,303
Accretion expense.................................................. 37,145 -- --
Other general and administrative costs (G&A)....................... 3,253,129 2,440,528 882,985
--------------- --------------- ---------------
Total operating costs and expenses............................. 6,308,941 7,596,910 12,400,955
--------------- --------------- ---------------
Operating loss......................................................... (3,981,254) (4,854,556) (8,588,080)
--------------- --------------- ---------------
Other income (expense):
Interest and other income.......................................... 36,397 118,961 542,824
Interest expense................................................... (788,017) (1,189,216) (330,816)
Impairment of notes receivable..................................... -- -- (34,060)
--------------- --------------- ---------------
Total other income (expense)................................... (751,620) (1,070,255) 177,948
--------------- --------------- ---------------
Loss before cumulative effect of accounting change..................... (4,732,874) (5,924,811) (8,410,132)
Cumulative effect of change in accounting principle................ 1,799,494 -- --
--------------- --------------- ---------------
Net loss............................................................... (2,933,380) (5,924,811) (8,410,132)
Less preferred stock deemed dividend related to beneficial
conversion feature............................................... (3,342,111) -- --
--------------- --------------- ---------------
Net loss applicable to common shares................................... $ (6,275,491) $ (5,924,811) $ (8,410,132)
=============== =============== ===============
Pro forma net loss reflecting adoption of SFAS 143..................... $ (5,958,274) $ (8,440,286)
=============== ===============
Basic and diluted loss per common share before cumulative effect of
change in accounting principle....................................... $ (0.41) $ (0.34) $ (0.48)
Cumulative effect of change in accounting principle................ 0.09) -- --
--------------- --------------- ---------------
Basic and diluted net loss per common share............................ $ (0.32) $ (0.34) $ (0.48)
=============== =============== ===============
Pro forma net loss per share reflecting adoption of SFAS 143........... $ (0.34) $ (0.48)
=============== ===============
Basic and diluted weighted average number of shares
Outstanding........................................................ 19,884,772 17,641,335 17,672,684
=============== =============== ===============
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, 2003, 2002 and 2001
2003 2002 2001
--------------- --------------- ---------------
Cash flows from operating activities:
Net loss........................................................... $ (2,933,380) $ (5,924,811) $ (8,410,132)
Adjustments to reconcile net loss to net cash used in
operating activities:
Cumulative effect of change in accounting principle........ (1,799,494) -- --
Depreciation, depletion and amortization................... 598,548 617,937 661,644
Impairment of oil and gas properties....................... 160,886 1,547,860 583,855
Accretion expense.......................................... 37,145 -- --
Amortization of loan fees.................................. 100,000 -- --
Impairment of notes receivable............................. -- -- 34,060
Accrued interest income from notes receivable.............. -- -- (14,820)
Gain (loss) on property dispositions....................... -- -- (28,864)
Exploratory dry hole costs................................. -- -- 3,051,334
Common stock and stock options issued for services......... 101,186 44,000 35,653
Amortization of deferred compensation (G&A)................ -- 54,688 1,077,547
Increase (decrease) from changes in working capital items:
Receivables.................................................... (107,861) 252,803 (101,280)
Inventory...................................................... 4,944 2,998 660
Other current assets........................................... (30,281) (722) (14,691)
Accounts payable and accrued liabilities....................... (1,692,776) 1,243,345 (122,696)
--------------- --------------- ---------------
Net cash used in operating activities...................... (5,561,083) (2,161,902) (3,247,730)
--------------- --------------- ---------------
Cash flows from investing activities:
Additions to oil and gas properties................................ (945,882) (161,195) (754,500)
Additions to other property and equipment.......................... (138,400) (118,535) (245,414)
Net change in other assets......................................... 15,283 (15,283) --
Proceeds from sale of property interests........................... -- -- 44,040
Partner advances................................................... (376,954) -- --
Proceeds from marketable debt securities........................... -- -- 1,281,993
--------------- --------------- ---------------
Net cash provided by (used) in investing activities............ (1,445,953) (295,013) 326,119
--------------- --------------- ---------------
Cash flows from financing activities:
Proceeds from loan and gas purchase option agreement............... -- -- 5,000,000
Payment of loan fees............................................... (100,000) -- --
Payments on notes payable.......................................... (1,675,000) -- --
Proceeds from issuance of stock, net of offering costs............. 25,447,555 -- --
Proceeds from exercise of stock options and warrants............... -- 4,500 --
--------------- --------------- ---------------
Net cash provided by financing activities...................... 23,672,555 4,500 5,000,000
--------------- --------------- ---------------
Net increase or (decrease) in cash..................................... 16,665,519 (2,452,415) 2,078,389
Cash and cash equivalents at beginning of year......................... 705,012 3,157,427 1,079,038
--------------- --------------- ---------------
Cash and cash equivalents at end of year............................... $ 17,370,531 $ 705,012 $ 3,157,427
=============== =============== ===============
The accompanying notes are an integral part of these consolidated financial statements
F-5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity (Deficit)
For the years ended December 31, 2003, 2002 and 2001
Deferred
Common Stock Preferred Compen-
------------------ Stock sation
Par Par Notes from
Value Value Receivable Stock Total
$0.001 $0.001 From Stock Option Additional Stockholders'
Shares Per Per Treasury Option Modifi- Paid in Accumulated Equity
Issued Share Share Stock Exercise cations Capital Deficit (Deficit)
---------- ------- ------- ----------- --------- ---------- ----------- ------------ -----------
Balance as of
December 31, 2000....... 17,913,575 $17,914 $ -- $(1,747,045) $(156,000) $ (913,485) $49,655,675 $(38,626,323) $ 8,230,736
Interest on notes
receivable............ -- -- -- -- (14,820) -- -- -- (14,820)
Impairment of
notes receivable...... -- -- -- -- 34,060 -- -- -- 34,060
52,000 shares
tendered for
payment of notes
receivable and
accrued interest...... -- -- -- (136,760) 136,760 -- -- -- --
Deferred compensation
from stock option
modifications......... -- -- -- -- -- (218,750) 218,750 -- --
Amortization of
deferred compensation. -- -- -- -- -- 1,077,547 -- -- 1,077,547
Options issued for
services.............. -- -- -- -- -- -- 35,653 -- 35,653
Net loss for year...... -- -- -- -- -- -- -- (8,410,132) (8,410,132)
---------- ------- ------- ----------- --------- ---------- ----------- ------------ -----------
Balance as of
December 31, 2001....... 17,913,575 17,914 -- (1,883,805) -- (54,688) 49,910,078 (47,036,455) 953,044
Retirement of
treasury stock........ (285,340) (285) -- 1,883,805 -- -- (1,883,520) -- --
Amortization of
deferred compensation. -- -- -- -- -- 54,688 -- -- 54,688
Common stock
issued for services... 20,682 20 -- -- -- -- 43,980 -- 44,000
Exercise of stock
options............... 3,000 3 -- -- -- -- 4,497 -- 4,500
Net loss for year...... -- -- -- -- -- -- -- (5,924,811) (5,924,811)
---------- ------- ------- ----------- --------- ---------- ----------- ------------ -----------
Balance as of
December 31, 2002....... 17,651,917 17,652 -- -- -- -- 48,075,035 (52,961,266) (4,868,579)
Preferred stock
offering, net......... -- -- 2,250 -- -- -- 5,589,372 -- 5,591,622
Conversion of
preferred stock
to common stock....... 2,250,000 2,250 (2,250) -- -- -- -- -- --
Common stock
offerings, net........ 6,353,361 6,353 -- -- -- -- 19,849,578 -- 19,855,931
Conversion of note
payable and accrued
interest into
common stock.......... 972,222 972 -- -- -- -- 3,592,548 -- 3,593,520
Common stock issued
for services.......... 72,563 73 -- -- -- -- 219,513 -- 219,586
Net loss for year...... -- -- -- -- -- -- -- (2,933,380) (2,933,380)
---------- ------- ------- ----------- --------- ---------- ----------- ------------ -----------
Balance as of
December 31, 2003....... 27,300,063 $27,300 $ -- $ -- $ -- $ -- $77,326,046 $(55,894,646) $21,458,700
========== ======= ======= =========== ========= ========== =========== ============ ===========
The accompanying notes are an integral part of these consolidated financial statements.
F-6
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
Organization
FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively
referred to hereinafter as the "Company") is an independent energy company with
activities concentrated within the upstream oil and gas industry. In Poland, the
Company has projects involving the exploration and exploitation of oil and gas
prospects with the Polish Oil and Gas Company ("POGC") and other industry
partners. In the United States, the Company produces oil from fields in Montana
and Nevada and has an oilfield services company in northern Montana that
performs contract drilling and well servicing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries and the Company's undivided interests in Poland.
All significant inter-company accounts and transactions have been eliminated in
consolidation. At December 31, 2003, the Company owned 100% of the voting common
stock or other equity securities of its subsidiaries.
Cash Equivalents
The Company considers all highly-liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents.
Concentration of Credit Risk
The majority of the Company's receivables are within the oil and gas industry,
primarily from the purchasers of its oil and gas, fees generated from oilfield
services and its industry partners. The receivables are not collateralized. To
date, the Company has experienced minimal bad debts, and has no allowance for
doubtful accounts at December 31, 2003 and 2002. The majority of the Company's
cash and cash equivalents is held by three financial institutions in Utah,
Montana and New York.
Inventory
Inventory consists primarily of tubular goods and production related equipment
and is valued at the lower of average cost or market.
F-7
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and
gas operations. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether an individual well has found proved reserves.
If it is determined that an exploratory well has not found proved reserves, or
if the determination that proved reserves have been found cannot be made within
one year, the costs of the well are expensed. The costs of development wells are
capitalized whether productive or nonproductive. Geological and geophysical
costs on exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are not considered to be realizable. Depletion, depreciation and
amortization ("DD&A") of capitalized costs of proved oil and gas properties is
provided on a property-by-property basis using the unit-of-production method.
The computation of DD&A takes into consideration the anticipated proceeds from
equipment salvage. An impairment loss is recorded if the net capitalized costs
of proved oil and gas properties exceed the aggregate undiscounted future net
revenues determined on a property-by-property basis. The impairment loss
recognized equals the excess of net capitalized costs over the related fair
value determined on a property-by-property basis. Gains and losses are
recognized on sales of entire interests in proved and unproved properties. Sales
of partial interests are generally treated as a recovery of costs and any
resulting gain or loss is recorded as other income.
Other Property and Equipment
Other property and equipment, including oilfield servicing equipment, is stated
at cost. Depreciation of other property and equipment is calculated using the
straight-line method over the estimated useful lives (ranging from 3 to 40
years) of the respective assets. The costs of normal maintenance and repairs are
charged to expense as incurred. Material expenditures that increase the life of
an asset are capitalized and depreciated over the estimated remaining useful
life of the asset. The cost of other property and equipment sold, or otherwise
disposed of, and the related accumulated depreciation are removed from the
accounts and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis
with accumulated depreciation, is summarized as follows:
December 31, Estimated
---------------------------- Useful Life
2003 2002 (in years)
------------- ------------- -------------
(In thousands)
Other property and equipment:
Drilling rigs.................................................. $ 2,216 $ 2,205 6
Other vehicles................................................. 887 878 5
Building....................................................... 96 96 40
Office equipment and furniture................................. 399 504 3 to 6
----------- -----------
Total cost..................................................... 3,598 3,683
Accumulated depreciation (2,908) (2,819)
----------- -----------
Net property and equipment................................. $ 690 $ 864
=========== ===========
F-8
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Supplemental Disclosure of Cash Flow Information
Non-cash investing and financing transactions not reflected in the consolidated
statements of cash flows include the following:
Year Ended December 31,
-----------------------------------
2003 2002 2001
----------- ----------- -----------
(In thousands)
Non-cash investing transactions:
Additions to properties included in current liabilities................ $ 2,145 $ 851 $ 999
----------- ----------- ----------
Total.............................................................. $ 2,145 $ 851 $ 999
=========== =========== ==========
Non-cash financing transactions:
Shares tendered for payment of notes receivable and accrued interest... $ -- $ -- $ 137
Conversion of note payable and accrued interest into common stock...... 3,594 -- --
----------- ----------- ----------
Total.............................................................. $ 3,594 $ -- $ 137
=========== =========== ==========
Supplemental disclosure of cash paid for interest and income taxes:
Year Ended December 31,
-----------------------------------
2003 2002 2001
----------- ----------- -----------
(In thousands)
Supplemental disclosure:
Cash paid during the year for interest................................ $ 475 $ 1 $ 2
Cash paid during the year for income taxes............................ -- -- --
Revenue Recognition
Revenues associated with oil and gas sales are recorded when the title passes
and are net of royalties. Oilfield service revenues are recognized when the
related service is performed.
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board ("APB") Opinion No. 25
and related interpretations. Nonemployee stock-based compensation is accounted
for using the fair value method in accordance with SFAS No. 123 "Accounting for
Stock-based Compensation."
F-9
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
As of December 31, 2003, the Company had 4,784,517 options outstanding under
stock option and award plans as well as from other individual grants. The
Company applies APB Opinion No. 25 and related interpretations in accounting for
options granted under the stock option and award plans and for other option
agreements. Had compensation cost for the Company's options been determined
based on the fair value at the grant dates consistent with SFAS No. 123, the
Company's net loss and loss per share would have been increased to the pro forma
amounts indicated in the following table:
2003 2002 2001
----------- ----------- ------------
(In thousands, except per share amounts)
Net loss:
Net loss, as reported.............................................. $ (2,933) $ (5,925) $ (8,410)
Add: stock-based employee compensation expense included in
reported net loss, net of any related tax effects................ -- 55 1,078
Less: Total stock-based employee compensation expense
determined under the fair value based method for all awards,
net of any related tax effects (907) (1,125) (1,515)
----------- ----------- ------------
Pro forma net loss............................................ $ (3,840) $ (6,995) $ (8,847)
=========== =========== ============
Basic and diluted net loss per share:
As reported................................................... $ (0.41) $ (0.34) $ (0.48)
Pro forma..................................................... (0.46) (0.40) (0.50)
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 2003,
2002 and 2001 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 70% for 2003, 90% for 2002
and 78% to 83% for 2001; (2) expected lives ranging from three to seven years;
(3) risk-free interest rates at the date of grant ranging from 3.00% to 4.24%;
and, (4) dividend yield of zero for each year.
Income Taxes
Deferred income taxes are provided for the differences between the tax bases of
assets or liabilities and their reported amounts in the financial statements.
Such differences may result in taxable or deductible amounts in future years
when the asset or liability is recovered or settled, respectively.
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 estimates of proved oil and gas reserve quantities and the related
future net cash flows.
Net Loss Per Share
Basic earnings per share is computed by dividing the net loss by the weighted
average number of common shares outstanding. Diluted earnings per share is
F-10
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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 or debt.
Outstanding options and warrants as of December 31, 2003, 2002 and 2001 were as
follows:
Options and
Warrants Price Range
------------- ----------------
Balance sheet date:
December 31, 2003............. 11,025,827 $2.40 - $10.25
December 31, 2002............. 5,544,017 $1.50 - $10.25
December 31, 2001............. 5,785,585 $1.50 - $10.25
The Company had a net loss in 2003, 2002 and 2001. The above options and
warrants, as well as 1,000,000 shares of common stock that could have been
issued under the RRPV note, were not included in the computation of diluted
earnings per share for 2003, 2002 or 2001 because the effect would have been
antidilutive.
Note 2: Asset Retirement Obligation
In August 2001, the Financial Accounting Standards Board, or FASB, issued
Statement No. 143 (SFAS 143), "Accounting for Asset Retirement Obligations." The
Company adopted SFAS 143 beginning January 1, 2003. The most significant impact
of this standard on the Company was a change in the method of accruing for site
restoration costs. Under SFAS 143, the fair value of asset retirement
obligations is recorded as a liability when incurred, which is typically at the
time the assets are placed in service. Amounts recorded for the related assets
are increased by the amount of these obligations. Over time, the liabilities are
accreted for the change in their present value and the initial capitalized costs
are depreciated over the useful lives of the related assets.
The Company used an expected cash flow approach to estimate its asset retirement
obligations under SFAS 143. Upon adoption, the Company recorded a retirement
obligation of $345,000, an increase in property and equipment cost of
$1,535,000, a decrease in accumulated depreciation, depletion and amortization
of $609,000, and a cumulative effect of change in accounting principle, net of
$0 tax, of $1,799,000. As a result of the adoption of SFAS 143, the Company
recorded accretion expense of $37,000 in 2003.
At January 1 and December 31, 2003, there are no assets legally restricted for
purposes of settling asset retirement obligations. There was no impact on the
Company's cash flows as a result of adopting SFAS 143 because the cumulative
effect of change in accounting principle is a noncash transaction.
The Company's estimated asset retirement obligation liability at January 1, 2002
and 2001 was approximately $322,000 and $285,000, respectively.
Following is a reconciliation of the changes in the asset retirement obligation
from December 31, 2002, to December 31, 2003:
Asset retirement obligation as of December 31, 2002....... $ --
Obligation arising from adoption of SFAS 143.............. 345,551
Liabilities settled....................................... --
Accretion expense......................................... 37,145
----------
Asset retirement obligation as of December 31, 2003....... $ 382,696
==========
F-11
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 3: Other Assets
As of December 31, 2003 and 2002, the Company had a replacement bond with 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. As of
December 31, 2003, the Company had advanced $377,000 to one of its partners to
cover drilling expenses for an exploratory well in Poland in the event costs
exceed an agreed upon target amount.
Note 4: Accrued Liabilities
The Company's accrued liabilities as of December 31, 2003 and 2002 were
comprised of the following:
December 31,
----------------------------
2003 2002
------------- -------------
(In thousands)
Accrued liabilities:
Exploratory dry hole costs.......... $ 880 $ 880
Drilling costs...................... 172 433
Seismic costs....................... -- 1,859
Pipeline costs...................... -- 502
Interest payable, POGC.............. -- 704
Interest payable, RRPV.............. -- 392
Other costs......................... 254 163
------------ ------------
Total........................... $ 1,306 $ 4,933
============ ============
Note 5: Notes Payable
On March 9, 2001, the Company signed a $5.0 million, 9.5% loan agreement and gas
purchase option agreement with Rolls Royce Power Ventures ("RRPV"). The proceeds
from the loan were used for exploration and development of additional gas
reserves in Poland. The loan was interest free for the first year. In
consideration for the loan and not charging interest for the first year, the
Company granted RRPV an option to purchase up to 17 Mmcf of gas per day from the
Company's properties in Poland, subject to availability, exercisable on or
before March 9, 2002. The option to purchase gas from the Company's Polish
properties was not exercised by RRPV. In accordance with the loan agreement, the
entire principal amount plus accrued interest was due on or before March 9,
2003, unless RRPV elected to convert the loan to restricted common stock at
$5.00 per share, the market value of the Company's common stock at the time the
terms with RRPV were finalized, on or before March 9, 2003. As collateral for
the loan, the Company granted RRPV a lien on most of the Company's Polish
property interests.
For financial reporting purposes, the Company imputed interest expense for the
first year at 9.5%, or $433,790, which was amortized ratably over the one-year
interest free period beginning March 9, 2001 and recorded an option premium of
$433,790 pertaining to granting RRPV an option to purchase gas from the
Company's properties in Poland, to be amortized ratably to other income over the
one-year option period.
In March, 2003, following a private placement of convertible preferred stock,
the Company paid $2.3 million to RRPV, which included $1.7 million in principal,
$0.5 million in accrued interest, and a $100,000 loan extension fee. In return,
RRPV extended the maturity date of the note to December 31, 2003. The Company
agreed to pay 40% of the gross proceeds of any subsequent equity or debt
offering concluded prior to the amended maturity date to RRPV, and also agreed
to assign its rights to payments under the CalEnergy Gas agreement to RRPV,
except for those amounts relating to two wells required to be drilled under the
agreement. All such payments would be used to offset the remaining principal and
interest. In exchange for these payments, RRPV agreed to release its lien on
interests earned by CalEnergy Gas under its agreement with the Company.
F-12
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The loan amendment contained other terms and conditions, including an increase
in the interest rate on the note from 9.5% to 12% per annum effective March 9,
2003, and an extension of the conversion period until December 31, 2003, with
the conversion price being changed from $5.00 per share to $3.42 per share, the
market price of the Company's stock when RRPV agreed to extend the payment date.
In accordance with EITF 98-5, "Accounting for Convertible Securities with
Beneficial Conversion Features or Contingently Adjustable Conversion Ratios," no
charge to income was recorded as a result of the reduction in conversion price
as the new conversion price did not result in any intrinsic value.
In September, 2003, the Company placed the then outstanding principal balance of
the note, $3.3 million, into an escrow account in favor of RRPV. In turn, the
interest rate on the loan was reduced to 9% per annum. In December, 2003, RRPV
exercised its right to convert the outstanding principal balance and accrued
interest into 972,222 shares of common stock. Accordingly, RRPV released the
escrowed funds to the Company, and subsequently released all outstanding liens
and other collateral secured by the note to the Company.
Note 6: Commitments
Fences I Project Area
On April 11, 2000, the Company signed an agreement with POGC under which the
Company will earn a 49.0% working interest in approximately 265,000 gross acres
in west central Poland (the "Fences I" project area) by spending $16.0 million
for agreed drilling, seismic acquisition and other related activities.
During 2000, the Company paid $6,689,432 to POGC under the agreement leaving a
remaining commitment of $9,310,568. During 2002 and 2001, the Company did not
make any additional cash payments to POGC relating to this agreement. As of
December 31, 2001, the Company had accrued $2,678,477 of additional costs
pertaining to the Fences project area $16.0 million commitment, including
$880,121 for drilling activities and $1,798,356 for 3-D seismic activities.
During 2002, the Company reaffirmed its intent to fulfill its $16 million
commitment with POGC. In connection with this agreement, the Company agreed to
recognize and pay at a future date an additional $2,306,627 of costs related to
prior exploration activities in the Fences I area to POGC, $1,602,902 of which
will be credited towards the $16 million commitment. The $2,306,627 was recorded
as an accrued liability, net of accounts receivable from POGC, at December 31,
2002. The 2002 amount includes $703,725 in interest costs related to the
Company's prior liabilities to POGC, $432,875 in drilling costs, $417,653 in
seismic costs, $502,244 in pipeline costs, and $250,130 related to foreign
exchange adjustments. As part of its future payment, the Company agreed to
assign in 2003 all of its right to the Kleka well, including the amounts
recorded as accounts receivable for Kleka gas sales. Accordingly, at December
31, 2002, the Company's account receivable from POGC in the amount of $606,986
was offset against the POGC liability. The liability is to be offset by the
value of the remaining gas reserves associated with the Kleka well, as
determined by an independent engineer jointly appointed by the Company and POGC.
The Company further agreed to begin accruing interest on the past due amount to
POGC. The interest rate in effect at December 31, 2002 was 12.8%. The interest
rate changed on January 1, 2003, to 10.4%.
During 2003, the Company paid a total of $2,916,003 in cash to POGC and recorded
a $190,000 VAT liability related to the Kleka gas sales in full settlement of
the outstanding liability, with the exception of the Kleka 11 assignment. As of
December 31, 2003, the Kleka 11 well had estimated proved, developed, producing
gas reserves with an estimated net present value, discounted at 10%, of
approximately $1.1 million, as determined by an independent engineer. The
parties continue to discuss the assignment of the Kleka well to POGC. Should the
parties not be able to reach a consensus concerning the independent engineer's
assessment of reserves, the Company may be required to pay additional cash to
settle the remaining liability to POGC.
F-13
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Apache Exploration Program
The Apache Exploration Program ("AEP") consists of various agreements signed
between the Company and Apache Corporation ("Apache") from 1997 through 2001.
Apache Poland general and administrative ("G&A") costs consist of the Company's
share of direct overhead costs incurred by Apache in Poland in accordance with
the terms of the AEP. Apache Poland G&A costs were $0, $0, and $575,000 during
2003, 2002 and 2001, respectively. The initial primary terms of the Apache
Exploration Program included a commitment by Apache to cover the Company's share
of costs to drill ten exploratory wells, to acquire 2,000 kilometers of 2-D
seismic and cover the Company's share of other specified costs to earn a
fifty-percent interest in the Company's Lublin Basin and Carpathian project
areas. There are no ongoing obligations under the AEP as of December 31, 2001.
Note 7: Income Taxes
The Company recognized no income tax benefit from the losses generated during
2003, 2002 and 2001. The components of the net deferred tax asset as of December
31, 2003 and 2002 are as follows:
December 31,
----------------------------
2003 2002
-------------- -------------
(In thousands)
Deferred tax liability:
Property and equipment basis differences...................................... $ (338) $ (370)
Deferred tax asset:
Net operating loss carryforwards:
United States............................................................. 13,175 12,475
Poland.................................................................... 4,353 4,224
Oil and gas properties........................................................ 1,855 1,795
Options issued for services................................................... 578 610
Asset retirement obligation................................................... 143 --
Other......................................................................... -- 10
Valuation allowance........................................................... (19,766) (18,744)
------------ ------------
Total..................................................................... $ -- $ --
============ ============
The change in the valuation allowance during 2003, 2002 and 2001 is as follows:
Year Ended December 31,
---------------------------------------------
2003 2002 2001
------------- ------------- ---------------
(In thousands)
Valuation allowance:
Balance, beginning of year..................................... $ (18,744) $ (17,089) $ (15,590)
Decrease due to property and equipment basis differences....... -- (577) 136
Increase due to net operating loss............................. (828) (632) (1,956)
Other.......................................................... (194) (446) 321
----------- ----------- -----------
Total...................................................... $ (19,766) $ (18,744) $ (17,089)
=========== =========== ===========
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, 2003 and 2002.
F-14
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
United States NOL
At December 31, 2003, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $35,321,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and 16,572,000 expires subsequent to 2018. The utilization of the NOL
carryforwards against future taxable income in the United States may become
subject to an annual limitation if there is a change in ownership. The NOL
carryforwards in the United States include $6,326,000 relating to tax deductions
resulting from the exercise of stock options. The tax benefit from adjusting the
valuation allowance related to this portion of the NOL carryforward will be
credited to additional paid-in capital.
Polish NOL
As of December 31, 2003, the Company had NOL carryforwards in Poland totaling
approximately $11,670,000, including $345,516, $882,262 and $1,925,220 generated
in 2003, 2002 and 2001, respectively. The NOL carryforwards may be carried
forward five years in Poland. However, no more than fifty-percent of the NOL
carryforwards for any given year may be applied against Polish income in
succeeding years.
The domestic and foreign components of the Company's net loss are as follows:
Year Ended December 31,
------------------------------------------
2003 2002 2001
------------ ------------ -----------
(In thousands)
Domestic.................. $ (1,820) $ (3,570) $ (1,585)
Foreign................... (1,113) (2,355) (6,825)
------------ ------------ -----------
Total................. $ (2,933) $ (5,925) $ (8,410)
============ ============ ============
Note 8: Private Placements of Common and Convertible Preferred Stock
In March 2003, the Company sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of
$5,593,871 after offering costs of $31,129. Each share of preferred stock
immediately converts into one share of common stock and one warrant to purchase
one share of common stock at $3.60 per share upon registration of the common
shares. The warrants to purchase common stock are exercisable anytime between
March 1, 2004, and March 1, 2008, and entitle the holders, for a period of 10
days following any new issuances of equity securities or securities convertible
or exercisable into equity securities in other than a public offering, to
preserve their approximate 16.3% ownership subsequent to this offering by
purchasing such new securities issued on the same terms as issued to others. The
preferred stock had a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.
In connection with the issuance of the 2003 Series Convertible Preferred Stock,
the Company allocated approximately $2.3 million of the proceeds to the
warrants, and the remaining amount of the proceeds to a beneficial conversion
feature. As the conversion of the preferred shares and the issuance of the
warrants were contingent upon the registration of the underlying shares, these
shares became included in the calculation of earnings per share upon the
conversion of the preferred stock to common stock.
The Company's 2,250,000 shares of 2003 Series Convertible Preferred Stock were
converted to common stock on a one-for-one basis on October 27, 2003, pursuant
to a registration statement that became effective on that date.
Between the months of July and November, 2003, the Company sold 3,991,310 Units,
consisting of one share of common stock and one warrant to purchase one share of
common stock at $3.75 per share, raising a total of $10,734,672 after offering
costs of $41,865. The warrants to purchase common stock are exercisable one year
after closing, and expire between July 22, 2008 and November 4, 2008.
F-15
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
In December, 2003, the Company sold 2,362,051 shares of common stock, raising a
total of $9,137,021 after offering costs of $571,009.
The net proceeds from the 2003 offerings were used to reduce the note payable to
Rolls-Royce Power Ventures Limited, to reduce the obligation to the Polish Oil
and Gas Company, and will be used to fund ongoing geological and geophysical
costs in Poland and support ongoing prospect marketing and general and
administrative costs.
Note 9: Stock Options and Warrants
Equity Compensation Plans
The Company's equity compensation consists of annual stock option and award
plans that are each subject to approval by the Board of Directors and are
subsequently presented for approval by the stockholders at the Company's annual
meetings.
The following table summarizes information regarding the Company's stock option
and award plans as of December 31, 2003:
Weighted
Average Number of
Number of Exercise Shares
Shares Price of Available
Authorized Outstanding for Future
Under Plan Shares Issuance
------------- --------------- -------------
Equity compensation plans approved by stockholders:
1995 Stock Option and Award Plan................................ 500,000 $ 7.09 337,500
1996 Stock Option and Award Plan................................ 500,000 5.81 500
1997 Stock Option and Award Plan................................ 500,000 7.78 30,400
1998 Stock Option and Award Plan................................ 500,000 6.35 4,000
1999 Stock Option and Award Plan................................ 500,000 4.32 9,333
2000 Stock Option and Award Plan................................ 600,000 2.50 7,750
2001 Stock Option and Award Plan................................ 600,000 3.00 6,000
2003 Long Term Incentive Plan................................... 800,000 3.00 390,000
--------- -------------- ----------
Total......................................................... 4,500,000 $ 4.77 785,483
========= ============== ==========
The above table excludes 1,120,000 options that have been granted outside of
shareholder approved option plans.
All stock option and award plans are administered by a committee (the
"Committee") consisting of members of the board of directors or a committee
thereof. At its discretion, the Committee may grant stock, incentive stock
options ("ISOs") or non-qualified options to any employee, including officers.
In addition to the options granted under the stock option plans, the Company
also issues non-qualified options outside the stock option plans. The granted
options have terms ranging from five to seven years and vest over periods
ranging from the date of grant to three years. Under terms of the stock option
award plans, the Company may also issue restricted stock.
F-16
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The following table summarizes fixed option activity for 2003, 2002 and 2001:
2003 2002 2001
-------------------------- ------------------------ -------------------------
Weighted Weighted Weighted
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Shares Price Shares Price Shares Price
------------- ----------- ----------- ----------- ------------ -----------
Fixed Options Outstanding:
Beginning of year......... 4,544,017 $ 4.68 4,785,585 $ 4.87 4,322,917 $ 5.15
Granted................... 785,000 3.97 551,000 2.40 501,750 2.44
Exercised................. -- -- (3,000) 1.50 -- --
Canceled.................. (10,000) 4.66 (114,568) 6.00 (33,082) 5.00
Expired................... (534,500) 7.50 (675,000) 2.61 (6,000) 5.75
------------ ----------- ----------
End of year........... 4,784,517 $ 4.42 4,544,017 $ 4.68 4,785,585 $ 4.87
============ =========== ==========
Exercisable at year-end....... 3,474,270 $ 4.84 3,515,867 $ 5.41 3,669,356 $ 5.28
============ =========== ==========
The weighted average fair value per share of options granted during 2003, 2002
and 2001 was $1.90, $1.80 and $1.16, respectively.
The following table summarizes information about fixed stock options outstanding
as of December 31, 2003:
Outstanding Exercisable
------------------------------------------------------ -------------------------------
Weighted Average
Number of Remaining Weighted Number of Weighted
Exercise Options Contractual Life Average Options Average
Price Range Outstanding (in years) Exercise Price Exercisable Exercise Price
-------------------------------------- -------------------- --------------- -------------- ---------------
$2.40 - $2.40......... 549,000 5.62 $ 2.40 182,997 $ 2.40
$2.44 - $2.44......... 477,750 4.93 2.44 318,506 2.44
$3.00 - $3.00......... 1,000,000 0.44 3.00 1,000,000 0.44
$3.14 - $3.98......... 785,000 6.82 3.92 -- --
$4.06 - $4.06......... 470,000 3.80 4.06 470,000 --
$5.75 - $6.63......... 808,100 2.02 6.12 808,100 6.12
$6.75 - $10.25........ 694,667 1.49 8.28 694,667 8.28
--------------- -------------------- --------------- -------------- ---------------
Total.......... 4,784,517 3.28 $ 4.42 3,474,270 $ 4.84
=============== ==================== =============== ============== ===============
Warrants
The following table summarizes changes in outstanding and exercisable warrants
during 2003, 2002 and 2001:
2003 2002 2001
---------------------------- --------------------------- -----------------------------
Number of Price Number of Price Number of Price
Shares Range Shares Range Shares Range
----------- ---------------- ------------- ------------- -------------- --------------
Warrants outstanding:
Beginning of year. -- $ -- 100,000 $ 3.00 250,000 $3.00 - $6.90
Issued............ 6,241,310 $3.60 - $3.75
Exercised......... -- -- -- -- -- --
Expired........... -- -- (100,000) $ 3.00 (150,000) $ 6.90
---------- ----------- -----------
End of year... 6,241,310 $3.60 - $3.75 -- $ -- 100,000 $ 3.00
========== =========== ===========
F-17
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Option and Warrant Extensions
On August 5, 2001, the Company extended the term of options and warrants to
purchase 125,000 shares of the Company's common stock that were to expire during
2001 for a period of two years, with a one-year vesting period. In accordance
with FIN 44 "Accounting for Certain Transactions Involving Stock Compensation,"
the Company incurred deferred compensation costs of $218,750 applicable to an
officer and a non-officer, to be amortized to expense over the one-year vesting
period.
Note Receivable from Stock Option Exercises
On November 8, 2000, a former employee exercised an option to purchase 52,000
shares of the Company's common stock at a price of $3.00 per share. The former
employee elected to pay for the cost of the exercise by signing a full recourse
promissory note with the Company for $156,000. Terms of the note receivable
included a three-year term with annual principal payments of $52,000 plus
interest accrued at 9.5%. On November 8, 2001, the former employee surrendered
52,000 shares of the Company's common stock in return for cancellation of the
note receivable. The Company recorded a loss of $34,060 on the transaction and
the acquisition of 52,000 shares of common stock as treasury stock at a price of
$2.63 per share, the closing price of the Company's stock on November 8, 2001.
Note 10: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2003 and 2002 is as follows:
Quarter Ended
---------------------------------------------------------------------------
December 31 September 30 June 30 March 31
----------------- ----------------- ------------------ ------------------
(In thousands, except per share amounts)
2003:
Revenues....................... $ 575 $ 602 $ 530 $ 621
Net operating loss............. (1,973) (654) (866) (488)
Net income (loss).............. (2,053) (866) (1,106) 1,092
Basic and diluted net loss per
common share................. $ (0.28) $ (0.04) $ (0.05) $ (0.04)
2002:
Revenues....................... $ 708 $ 977 $ 607 $ 450
Net operating loss............. (2,833) (271) (751) (1,000)
Net loss....................... (3,664) (373) (870) (1,018)
Basic and diluted net loss per
common share................. $ (0.21) $ (0.02) $ (0.05) $ (0.06)
The net operating loss for the fourth quarter of 2003 includes $160,886 in
property impairment costs. The net operating loss for the fourth quarter of 2002
includes $1,547,860 in property impairment costs, and $703,725 and $502,244 in
interest and seismic costs, respectively, incurred in connection with a revision
of the Company's agreement with POGC relative to the Fences I project area.
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. The Company's revenues
associated with its E&P activities are comprised of oil sales from its producing
properties in the United States and oil and gas sales from its producing
properties in Poland. Over 85% of the Company's oil sales in the United States
were to Cenex during 2001 and the first half of 2002. From July 2002 to June
2003, over 85% of the Company's oil sales were to Plains Marketing Canada, LP.
Commencing in July 2003, over 85% of the Company's oil sales were to Cenex.
During 2002 and 2001, all of the Company's oil and gas sales in Poland were to
POGC. There were no oil and gas sales in Poland during 2003. The Company
F-18
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
believes the purchasers of its oil and gas production could be replaced, if
necessary, without a loss in revenue. E&P operating costs are comprised of: (1)
exploration costs (geological and geophysical costs, exploratory dry holes, and
non-producing leasehold impairments) and, (2) lease operating costs (lease
operating expenses and production taxes). Substantially all exploration costs
are related to the Company's operations in Poland. Substantially all lease
operating costs are related to the Company's domestic production.
The Company's revenues associated with its oilfield services segment are
comprised of contract drilling and well servicing fees generated by the
Company's oilfield servicing equipment in Montana. Oilfield servicing costs are
comprised of direct costs associated with its oilfield services.
DD&A directly associated with a respective business segment is disclosed within
that business segment. The Company does not allocate current assets, corporate
DD&A, general and administrative costs, amortization of deferred compensation,
interest income, interest expense, other income or other expense to its
operating business segments for management and business segment reporting
purposes. All material inter-company transactions between the Company's business
segments are eliminated for management and business segment reporting purposes.
F-19
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Information on the Company's operations by business segment for 2003, 2002 and
2001 is summarized as follows:
2003
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues(1).................................................... $ 2,230 $ 98 $ 2,328
Operating costs(2)............................................. (2,267) (190) (2,457)
DD&A expense................................................... (287) (299) (586)
------------ ----------- ------------
Operating loss................................................ $ (324) $ (391) $ (715)
============ =========== ============
Identifiable net property and equipment:
Unproved properties - Poland.................................. $ 166 $ -- $ 166
Unproved properties - Domestic................................. 8 -- 8
Proved properties - Poland..................................... 1,202 -- 1,202
Proved properties - Domestic................................... 3,007 -- 3,007
Equipment and other............................................ -- 565 565
------------ ----------- ------------
Total...................................................... $ 4,383 $ 565 $ 4,948
============ =========== ============
Net Capital Expenditures:
Property and equipment $ 191 $ 11 $ 202
------------- ------------- -------------
Total...................................................... $ 191 $ 11 $ 202
============= ============= =============
--------------------
(1) All E&P revenues were generated in the United States.
(2) E&P operating costs include $161,000 in property impairments,
$319,000 in geological and geophysical costs, $8,000 in lease
operating costs, and $265,000 in general and administrative costs
incurred in Poland.
2002
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues(3).................................................... $ 2,209 $ 533 $ 2,742
Operating costs(4)............................................. (3,941) (540) (4,481)
DD&A expense................................................... (281) (310) (591)
------------ ------------ ------------
Operating loss................................................ $ (2,013) $ (317) $ (2,330)
============ ============ ============
Identifiable net property and equipment:
Unproved properties - Poland.................................. $ 146 $ -- $ 146
Unproved properties - Domestic................................. 8 -- 8
Proved properties - Poland..................................... 1,931 -- 1,931
Proved properties - Domestic................................... 957 -- 957
Equipment and other............................................ -- 791 791
------------ ------------ ------------
Total...................................................... $ 3,042 $ 791 $ 3,833
============ ============ ============
Net Capital Expenditures:
Property and equipment(5) $ 1,012 $ 116 $ 1,128
------------ ------------ ------------
Total...................................................... $ 1,012 $ 116 $ 1,128
============ ============ ============
---------------------
(3) E&P revenues include $1,924,000 generated in the United States and
$285,000 generated in Poland.
(4) E&P operating costs include $129,000 in geological and geophysical
costs, $41,000 in lease operating costs, and $171,000 in general
and administrative costs incurred in Poland.
(5) E&P includes $418,000 of pipeline costs and $586,000 of proved
property additions incurred in Poland and $8,000 of unproved
property additions in the United States.
F-20
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
2001
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues(1).................................................... $ 2,229 $ 1,584 $ 3,813
Operating costs(2)............................................. (8,478) (1,300) (9,778)
DD&A expense(3)................................................ (322) (308) (630)
----------- ----------- ------------
Operating loss................................................ $ (6,571) $ (24) $ (6,595)
=========== =========== ============
Identifiable net property and equipment:
Unproved properties - Poland.................................. $ 648 $ -- $ 648
Unproved properties - Domestic................................. 8 -- 8
Proved properties - Poland..................................... 2,324 -- 2,324
Proved properties - Domestic................................... 877 -- 877
Equipment and other............................................ -- 985 985
----------- ----------- ------------
Total...................................................... $ 3,857 $ 985 $ 4,842
============ =========== ============
Net Capital Expenditures:
Property and equipment(4)...................................... $ 1,745 $ 248 $ 1,993
----------- ----------- ------------
Total...................................................... $ 1,745 $ 248 $ 1,993
============ =========== ============
---------------------
(1) E&P revenues include $1,815,000 generated in the United States and
$414,000 generated in Poland.
(2) E&P operating costs include $2,541,000 in geological and
geophysical costs, $3,051,000 in exploratory dry hole costs,
$59,000 in property impairments, $42,000 in lease operating costs,
and $733,000 in general and administrative costs incurred in
Poland.
(3) E&P DD&A includes $258,000 in DD&A costs incurred in Poland.
(4) E&P includes a $894,000 of exploratory dry hole costs, $320,000 of
proved property additions and $531,000 of unproved property
additions.
F-21
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
A reconciliation of the segment information to the consolidated totals for 2003,
2002 and 2001 follows:
2003 2002 2001
------------- ------------- -------------
(In thousands)
Revenues:
Reportable segments.............................................. $ 2,328 $ 2,742 $ 3,813
Non-reportable segments.......................................... -- -- --
------------ ------------ ------------
Total revenues.................................................. $ 2,328 $ 2,742 $ 3,813
============ ============ ============
Operating loss:
Reportable segments.............................................. $ (715) $ (2,330) $ (6,595)
Expense or (revenue) adjustments:
Corporate DD&A expense......................................... (13) (27) (32)
Amortization of deferred compensation (G&A).................... -- (55) (1,078)
General and administrative expenses............................ (3,253) (2,443) (883)
Other.......................................................... -- -- --
------------ ------------ ------------
Total net operating loss..................................... $ (3,981) $ (4,855) $ (8,588)
============ ============ ============
Net property and equipment:
Reportable segments.............................................. $ 4,948 $ 3,833 $ 4,842
Corporate assets................................................. 125 73 100
------------ ------------ ------------
Net property and equipment...................................... $ 5,073 $ 3,906 $ 4,942
============ ============ ============
Property and equipment capital expenditures:
Reportable segments.............................................. $ 202 $ 1,128 $ 1,993
Corporate assets................................................. 63 2 6
------------ ------------ ------------
Net property and equipment capital expenditures................. $ 265 $ 1,130 $ 1,999
============ ============ ============
Note 12: Disclosure about Oil and Gas Properties and Producing Activities (unaudited)
Capitalized Oil and Gas Property Costs
Capitalized costs relating to oil and gas exploration and production activities
as of December 31, 2003 and 2002 are summarized as follows:
United States Poland Total
------------- ------------- -------------
(In thousands)
December 31, 2003:
Proved properties......................................... $ 4,088 $ 1,665 $ 5,753
Unproved properties....................................... 8 166 174
------------- ------------- -------------
Total gross properties.................................. 4,096 1,831 5,927
Less accumulated depreciation, depletion and amortization. (1,082) (462) (1,544)
------------- ------------- -------------
Total.............................................. $ 3,014 $ 1,369 $ 4,383
============= ============= =============
December 31, 2002:
Proved properties......................................... 2,360 $ 2,394 $ 4,754
Unproved properties....................................... 8 146 154
------------- ------------- -------------
Total gross properties.................................. 2,368 2,540 4,908
Less accumulated depreciation, depletion and amortization. (1,404) (462) (1,866)
------------- ------------- -------------
Total.............................................. $ 964 $ 2,078 $ 3,042
============= ============= =============
F-22
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Results of Operations
Results of operations are reflected in Note 13, Business Segments. There is no
tax provision as the Company is not likely to pay any federal or local income
taxes due to its operating losses. Total production costs for 2003, 2002 and
2001 were $1,545,913, $1,365,454 and $1,358,304, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities
during 2003, 2002 and 2001, whether capitalized or expensed, are summarized as
follows:
United States Poland Total
------------- ------------ -------------
(In thousands)
Year ended December 31, 2003:
Acquisition of properties:
Proved................................................ $ -- $ -- $ --
Unproved.............................................. -- 20 20
Exploration costs......................................... -- 523 523
Development costs......................................... 191 -- 191
------------- ------------ -------------
Total................................................. $ 191 $ 543 $ 734
============= ============ =============
Year ended December 31, 2002:
Acquisition of properties:
Proved................................................ $ -- -- --
Unproved.............................................. -- 8 8
Exploration costs......................................... -- 1,031 1,031
Development costs......................................... 153 851 1,004
------------- ------------ -------------
Total................................................. $ 153 $ 1,890 $ 2,043
============= ============ =============
Year ended December 31, 2001:
Acquisition of properties:
Proved................................................ $ -- $ -- $ --
Unproved.............................................. -- 525 525
Exploration costs......................................... -- 6,542 6,542
Development costs......................................... 319 2 321
------------- ------------ -------------
Total................................................. $ 319 $ 7,069 $ 7,388
============= ============ =============
Impairment of Oil and Gas Properties
The Company has recorded impairment charges in its E&P segment related to oil
and gas properties as follows:
2003 2002 2001
------------ ------------ ------------
Proved........................... $ 160,886 $ 1,038,362 $ --
Unproved......................... -- 509,498 583,855
------------ ------------ ------------
Total.......................... $ 160,886 $ 1,547,860 $ 583,855
============ ============ ============
Exploratory dry hole costs
During 2001, for financial reporting purposes, the Company classified the
Mieszkow 1 as an exploratory dry hole, and recorded exploratory dry hole costs
of $3,051,334, including cash expenditures of $2,171,750 and accrued costs of
$879,584. There were no dry hole costs in 2003 and 2002.
F-23
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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, 2003 of $27.53 per bbl for oil in the
United States and $2.60 per MCF of gas in Poland. The determination of oil and
gas reserves is based on estimates and is highly complex and interpretive, as
there are numerous uncertainties inherent in estimated quantities and values of
proved reserves, projecting future rates of production and timing of development
expenditures. The estimates are subject to continuing revisions as additional
information becomes available or assumptions change.
Estimates of the Company's proved domestic reserves were prepared by Larry
Krause Consulting, an independent engineering firm in Billings, Montana.
Estimates of the Company's proved Polish reserves were prepared by Troy-Ikoda
Limited, an independent engineering firm in the United Kingdom. The following
unaudited summary of proved developed reserve quantity information represents
estimates only and should not be construed as exact:
Crude Oil Natural Gas
-------------------------------- --------------------------------
United States Poland United States Poland
--------------- --------------- --------------- ---------------
(In thousand barrels of oil) (In millions of cubic feet)
Proved Developed Reserves:
December 31, 2003.......................... 991 -- -- 1,116
December 31, 2002.......................... 1,015 -- -- 1,374
December 31, 2001.......................... 1,075 -- -- 2,167
The following unaudited summary of proved developed and undeveloped reserve
quantity information represents estimates only and should not be construed as
exact:
Crude Oil Natural Gas
-------------------------------- --------------------------------
United States Poland United States Poland
--------------- --------------- --------------- ---------------
(In thousand barrels of oil) (In millions of cubic feet)
December 31, 2003:
Beginning of year....................... 1,042 114 -- 4,210
Extensions or discoveries............... -- -- -- --
Revisions of previous estimates......... 34 -- -- (250)
Production.............................. (85) -- -- --
--------------- --------------- --------------- ---------------
End of year......................... 991 114 -- 3,960
=============== =============== =============== ===============
December 31, 2002:
Beginning of year....................... 1,100 114 -- 5,010
Extensions or discoveries............... -- -- -- --
Revisions of previous estimates......... 33 -- -- (620)
Production.............................. (91) -- -- (180)
--------------- --------------- --------------- ---------------
End of year......................... 1,042 114 -- 4,210
=============== =============== =============== ===============
December 31, 2001:
Beginning of year....................... 1,220 -- -- 2,381
Extensions or discoveries............... -- 114 -- 2,844
Revisions of previous estimates......... (26) -- -- 35
Production.............................. (94) -- -- (250)
--------------- --------------- --------------- ---------------
End of year......................... 1,100 114 -- 5,010
=============== =============== =============== ===============
F-24
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Standardized Measure of Discounted Future Net Cash Flows ("SMOG") and
Changes Therein Relating to Proved Oil Reserves
Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities."
Certain information concerning the assumptions used in computing the valuation
of proved reserves and their inherent limitations are discussed below. The
Company believes such information is essential for a proper understanding and
assessment of the data presented. The assumptions used to compute the proved
reserve valuation do not necessarily reflect the Company's expectations of
actual revenues to be derived from those reserves nor their present worth.
Assigning monetary values to the reserve quantity estimation process does not
reduce the subjective and ever-changing nature of such reserve estimates.
Additional subjectivity occurs when determining present values because the rate
of producing the reserves must be estimated. In addition to errors inherent in
predicting the future, variations from the expected production rates also could
result directly or indirectly from factors outside the Company's control, such
as unintentional delays in development, environmental concerns and changes in
prices or regulatory controls. The reserve valuation assumes that all reserves
will be disposed of by production. However, if reserves are sold in place,
additional economic considerations also could affect the amount of cash
eventually realized. Future development and production costs are computed by
estimating expenditures to be incurred in developing and producing the proved
oil reserves at the end of the period, based on period-end costs and assuming
continuation of existing economic conditions. A discount rate of 10.0% per year
was used to reflect the timing of the future net cash flows. The discounted
future net cash flows for the Company's Polish reserves are based on a gas and
condensate sales contracts the Company has with POGC.
The components of SMOG are detailed below:
United States Poland(1) Total
--------------- --------------- ---------------
(In thousands)
December 31, 2003:
Future cash flows....................................... $ 27,290 $ 10,323 $ 37,613
Future production costs................................. (17,527) (425) (17,952)
Future development costs................................ (3) (1,800) (1,803)
Future income tax expense............................... -- -- --
------------- ------------- -------------
Future net cash flows................................... 9,760 8,098 17,858
10% annual discount for estimated timing of cash flows.. (4,826) (3,176) (8,002)
------------- ------------- -------------
Discounted net future cash flows........................ $ 4,934 $ 4,922 $ 9,856
============= ============= =============
December 31, 2002:
Future cash flows....................................... $ 26,049 $ 10,964 $ 37,013
Future production costs................................. (16,254) (455) (16,709)
Future development costs................................ (115) (1,800) (1,915)
Future income tax expense............................... -- -- --
------------- ------------- -------------
Future net cash flows................................... 9,680 8,709 18,389
10% annual discount for estimated timing of cash flows.. (4,783) (3,386) (8,169)
------------- ------------- -------------
Discounted net future cash flows........................ $ 4,897 $ 5,323 $ 10,220
============= ============= =============
December 31, 2001:
Future cash flows....................................... $ 13,922 $ 7,749 $ 21,671
Future production costs................................. (9,464) (425) (9,889)
Future development costs................................ (73) (1,390) (1,463)
Future income tax expense............................... -- -- --
------------- ------------- -------------
Future net cash flows................................... 4,385 5,934 10,319
10% annual discount for estimated timing of cash flows.. (2,213) (2,520) (4,733)
------------- ------------- -------------
Discounted net future cash flows........................ $ 2,172 $ 3,414 $ 5,586
============= ============= =============
-------------------------
(1) Includes $1,052 related to the Kleka 11 well, which the Company has
agreed to transfer to POGC.
F-25
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The principal sources of changes in SMOG are detailed below:
Year Ended December 31,
-------------------------------------------
2003 2002 2001
------------- ------------- -------------
(In thousands)
SMOG sources:
Balance, beginning of year...................................... $ 10,220 $ 5,586 $ 7,420
Sale of oil and gas produced, net of production costs........... (732) (843) (871)
Net changes in prices and production costs...................... 607 4,890 (2,241)
Extensions and discoveries, net of future costs................. -- -- 1,330
Changes in estimated future development costs................... (321) (251) (686)
Previously estimated development costs incurred during
the year.................................................... 191 586 321
Revisions in previous quantity estimates........................ 26 270 59
Accretion of discount........................................... 1,022 559 742
Net change in income taxes...................................... -- -- --
Changes in rates of production and other........................ (1,157) (577) (488)
---------- ---------- -----------
Balance, end of year........................................ $ 9,856 $ 10,220 $ 5,586
========== ========== ===========
Note 14: New Accounting Pronouncements
The Company has reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on its results
of operations or financial position. Based on that review, the Company believes
that none of these pronouncements will have a significant effect on current or
future earnings or operations.
Note 15: Interests Held Under Oil and Gas Leases
Statement of Financial Accounting Standards No. 141, "Business Combinations"
(SFAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill
and Intangible Assets" (SFAS 142) were issued by the Financial Accounting
Standards Board (FASB) in June 2001 and became effective for the Company on July
1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business
combinations initiated after June 30, 2001, to be accounted for using the
purchase method. Additionally, SFAS 141 requires companies to disaggregate and
report separately from goodwill certain intangible assets. SFAS 142 establishes
new guidelines for accounting for goodwill and other intangible assets. Under
SFAS 142, goodwill and certain other intangible assets are not amortized, but
rather are reviewed annually for impairment. One interpretation being considered
relative to these standards is that oil and gas mineral rights held under lease
and other contractual arrangements representing the right to extract such
reserves for both undeveloped and developed leaseholds should be classified
separately from oil and gas properties, as intangible assets on the Company's
balance sheets. In addition, the disclosures required by SFAS 141 and 142
relative to intangibles would be included in the notes to financial statements.
Historically, the Company has included these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves as part of the oil and gas properties, even after SFAS 141 and 142
became effective.
This interpretation of SFAS 141 and 142 described above would only affect our
balance sheet classification of oil and gas leaseholds. The Company's results of
operations and cash flows would not be affected, since these oil and gas mineral
rights held under lease and other contractual arrangements representing the
right to extract such reserves would continue to be amortized in accordance with
accounting rules for oil and gas companies provided in Statement of Financial
Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies.".
F-26
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
At December 31, 2003 and 2002, the Company had undeveloped leaseholds of
approximately $166,000 and $147,000, respectively, that would be classified
under that interpretation on the balance sheet as "intangible undeveloped
leasehold" and developed leaseholds of an estimated $7,000 in both years that
would be classified under that interpretation as "intangible developed
leaseholds" if the Company applied the interpretation currently being
considered.
The Company will continue to classify its oil and gas mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further interpretive guidance
is provided.
F-27