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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
Commission File Number: 000-25386
FX ENERGY, INC.
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(Exact name of registrant as specified in its charter)
Nevada 87-0504461
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206, Salt Lake City, Utah 84106
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: Telephone (801) 486-5555
Facsimile (801) 486-5575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, Par Value $0.001
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(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 pursuant 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 [X] No [ ]
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, 2004, the aggregate market value of the
voting and nonvoting common equity held by nonaffiliates of the registrant was
$258,178,000.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. As of March 4, 2005,
FX Energy had outstanding 34,526,843 shares of its common stock, par value
$0.001.
DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy
Statement in connection with the 2005 Annual Meeting of Stockholders is
incorporated by reference in response to Part III of this Annual Report.
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FX ENERGY, INC.
Form 10-K for the fiscal year ended December 31, 2004
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TABLE OF CONTENTS
Item Page
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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, Related Stockholder
Matters and Issuer Purchases of Equity Securities.............19
6 Selected Financial Data.........................................20
7 Management's Discussion and Analysis of Financial Condition
and Results of Operation......................................22
7A Quantitative and Qualitative Disclosures about Market Risk......31
8 Financial Statements and Supplementary Data.....................31
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure......................................31
9A Controls and Procedures.........................................32
9B Other Information...............................................32
Part III
10 Directors and Executive Officers of the Registrant..............33
11 Executive Compensation..........................................33
12 Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters...............................33
13 Certain Relationships and Related Transactions..................33
14 Principal Accountant Fees and Services..........................33
Part IV
15 Exhibits and Financial Statement Schedules......................34
-- Signatures......................................................38
-- Management's Report on Internal Control Over Financial
Reporting....................................................F-1
-- Report of Independent Registered Public Accounting Firm........F-2
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. Statements that describe our future strategic
plans, goals or objectives are also forward-looking statements. 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.
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, strategies, 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 foreign currency exchange rate fluctuations;
o exploration and development priorities and the financial and
technical resources of Polish Oil and Gas Company, our
principal strategic relationship in Poland;
o uncertainties inherent in estimating quantities of proved
reserves and actual production rates and associated costs;
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 uncertainties regarding future political, economic,
regulatory, fiscal, taxation and other policies in Poland and
the European Union; 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
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ITEMS 1 AND 2. BUSINESS AND PROPERTIES
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Introduction
We are an independent oil and gas company focused on exploration,
development and production opportunities in the Republic of Poland in
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 we believe 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.
See "Oil and Gas Terms" at the end of this item for definitions of certain
industry terms.
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 have conveyed interests in our exploration
projects in exchange for contributions of financial and technical resources by
larger industry participants. As a result of significant improvements in our
financial position during the past two years and the formation of our Technical
Advisory Panel discussed below, we now anticipate that we will rely principally
on our own financial and technical resources, including expert consultants, in
identifying and drilling prospects for our own account or under our sharing
arrangements with POGC.
We concentrate on acreage in productive fairways or geologic trends
where we believe we have the opportunity to find significant gas and oil
reserves with lower risk. Our strategy is to:
o acquire large acreage positions in areas of known productive
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, acquiring new data, identifying
prospects that we believe merit drilling, and preparing a
detailed exploration work program; and
o either drill these prospects for our own account, or where
circumstances may warrant in the future, market interests in
these properties to industry participants on terms that will
provide all or a portion of the funds necessary for
exploration.
4
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
Poland's principal domestic oil and gas exploration entity. Under our existing
agreements, POGC provides us with access to exploration opportunities,
previously-collected exploration data, and technical and operational support.
Technical and Advisory Panel
We have created a Technical and Advisory Panel consisting of
individuals with decades of combined experience to advise and consult with
management in connection with the four current principal project areas discussed
below. The panel's 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 includes 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 CIBC and 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. Mr. McTiernan is
currently assisting us in our gas contract negotiations with POGC and our
long-term gas marketing strategic planning.
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 geophysical projects and has
applied advanced analytical methodologies on over 500 geophysical projects. 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 our
seismic data acquisition, processing and reprocessing projects in the Fences and
Wilga project areas.
Project Area Summary
Our ongoing activities in Poland are conducted in four project areas:
Fences I, II and III, 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. Our recent Rusocin well, which
discovered a gas accumulation in a stratigraphic trap, is a model of this
strategy.
5
Fences
The 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.
We entered into an agreement in April 2000 with POGC to explore this area and by
December 31, 2004, had spent $16.0 million on exploration costs in the Fences I
project area to earn a 49% interest.
The Fences II project area is 670,000 acres (2,715 sq. km.) located
north of and contiguous with the Fences I block. POGC's Radlin field forms part
of the Fences II'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 satisfied the earning requirements in early 2005 by continuing our
ongoing two-dimensional, or 2-D, seismic data reprocessing, along with drilling
the initial well at the Sroda prospect.
The 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, produce from both Rotliegendes sandstone and
Zechstein carbonate (Ca1 and Ca2) 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.
During the balance of 2005, our objectives with respect to the Fences
areas are to:
o continue developing a complete subsurface seismic and
geological picture of the Rotliegendes and Zechstein carbonate
(Ca1 and Ca2) horizons across our entire acreage, in the
process building an inventory of drill-ready prospects;
o drill approximately five wells, subject to the exploration
priorities and financial and technical resources of our
partner, POGC, and the ability of our technical group to
acquire and assimilate new technical data;
o build the necessary infrastructure to begin producing our
Zaniemysl discovery and begin planning for production from
other potential discoveries; and
o endeavor to expand our holdings in and around the Fences and
perhaps other areas.
More detailed information concerning the Fences area and our
exploration history there can be found under the section Exploration,
Development and Production Activities below.
Wilga
The Wilga project area in central southeast Poland consists of
exploration rights on approximately 250,000 gross acres held by us and POGC in
Block 255, where the Wilga 2 discovery well is located. We have for some years
held a 45% working interest in the Wilga project area; however, our former
partner, Apache Corporation, recently surrendered its interest so that,
effective January 31, 2005, we have an 82% working interest and are the
operator; POGC holds the remaining 18% working interest. 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. We plan to place this well
into commercial production as soon as we have negotiated an acceptable gas
contract with a suitable buyer, which will enable us to begin construction of
production facilities. We plan to discuss with POGC further exploration for the
block during the next few months.
6
Exploration, Development and Production Activities
Polish Exploration Rights
As of December 31, 2004, we had earned oil and gas exploration rights
in Poland in the following gross acreage components:
Operator
------------------------------- Gross
FX Energy POGC Acreage
--------------- --------------- ---------------
Project Area:
Fences I....................... X 265,000
Fences II...................... X 670,000
Fences III..................... X 770,000
Wilga.......................... X 250,000
---------------
Total gross acreage.......... 1,955,000
===============
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. As of December 31, 2004, we
had completed the $16.0 million earn-in requirement. As a result, POGC is
obligated to pay its 51% share of any further costs. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operation:
Introduction--Fences I Commitment and Settlement for further information on how
the commitment was satisfied.
The Rotliegendes is the primary target horizon throughout most of the
Fences I project area, at depths from approximately 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. In 2003, we agreed to
assign our interest in the Kleka 11 well, including accrued gas sales proceeds
and proceeds from ongoing production during 2003 and 2004 to POGC as a credit
against our earning requirement in Fences I. By December 31, 2004, we had met
our earning requirement without crediting assignment of the Kleka well, so we
have agreed with POGC not to assign our interest in the Kleka 11 well, subject
to the completion of formal documentation.
During 2001, we drilled the Mieszkow 1, an exploratory dry hole. The
Mieszkow well demonstrated the need to apply modern seismic data processing and
to assure careful handling of velocities in seismic data interpretation. In 2002
and 2003, we acquired, processed and interpreted a substantial amount of seismic
data.
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.
The operating committee approved the Zaniemysl prospect as the first
well to be drilled under the CalEnergy Gas 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 (59 feet) of the
structure, the well flowed at a stabilized rate of approximately 12.5 MMcf of
gas per day. Total recoverable reserves for the field are estimated at
approximately 40 Bcf of gas. Together with our partners, POGC and CalEnergy Gas,
we have begun development work to build facilities and connect to the pipeline
7
grid through a pipeline to be built by POGC to produce gas from the Zaniemysl
structure at a permitted rate of 10 MMcf of gas per day. Gas production is
scheduled to commence by the end of 2005.
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
drill site in the Rusocin prospect in Fences I and to proceed with drilling as
soon as possible. Accordingly, CalEnergy Gas did not complete its earning
requirement and no longer has the right to participate in the Fences I project
area, except for the approximately 45,000 acres surrounding the Zaniemysl field
referred to as the Greater Zaniemysl Area, or GZA. The GZA was established to
allow the two companies to put the Zaniemysl discovery into production while
exploring together for other nearby natural gas opportunities that would have
the potential to add economic value to the overall Zaniemysl project.
The GZA quantifies the acreage earned by CalEnergy Gas at 45,220 acres,
covering approximately 17% of Fences I, and will require CalEnergy Gas to pay
$250,000 of our share of geological and geophysical work on the GZA project.
Both companies anticipate additional seismic data acquisition and reprocessing
in the expanded project. We and CalEnergy Gas each hold a 24.5% interest in the
GZA, and POGC holds a 51% interest.
Outside of the CalEnergy Gas GZA, during the second half of 2004, we
drilled with POGC the Rusocin-1 well, the first well intentionally focused on a
stratigraphic trap in the Rotliegendes. In a January 2005 initial drill stem
test, the well flowed gas from an 18 meter (59 feet) section of the Rotliegendes
sandstone target reservoir. The top of the Rotliegendes was encountered at
approximately 2,747 meters. Results of the initial drill stem test indicate that
the reservoir may extend beyond the mapped faults, suggesting a larger reservoir
along the Wolsztyn High. We believe the well may have discovered the lower edge
of a pinch-out at the top of the Rotliegendes sandstone with 20-25% porosity.
We are testing the Rusocin well to determine whether it is commercial.
If warranted, we will propose to POGC, the operator, one or more appraisal wells
on the Rusocin prospect. At the same time, we are completing geological and
geophysical work on the Lugi prospect, another stratigraphic test of the
pinch-out play. During the remainder of 2005, we plan to acquire new 2-D seismic
data on selected structural prospects as well as along the apparent
stratigraphic trap trend; we are also considering acquiring new
three-dimensional, or 3-D seismic data along the stratigraphic trap trend. We
intend to propose additional wells, both exploratory and appraisal, as our
technical staff approves specific projects.
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 we believe 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 that was
completed by POGC and Conoco before Conoco's withdrawal from the project at the
end of 2002 was made available to us by POGC. During 2003 and 2004, we
reprocessed and interpreted approximately 2,600 kilometers of 2-D seismic data
to complement the 1,200 kilometers reprocessed in 2002 in order to develop a
more complete subsurface model of the Rotliegendes and Zechstein horizons. In
the second half of 2004, we received operating committee approval to drill the
Sroda prospect, a structural feature modeled on POGC's Radlin field. Although
slowed by mechanical problems, drilling operations should conclude in
approximately the first quarter of 2005. We have identified several other
prospects near Sroda. We are also working to identify prospects in adjacent
areas on the southeastern end of Fences II and may seek to expand our
exploration rights accordingly.
8
Fences III Project Area
We have assembled the existing seismic data, which includes seismic
data on approximately the northern third of the Fences III project area. We
expect to finish reprocessing and interpreting this data in the first quarter of
2005 and, if results warrant, plan to acquire new 2-D seismic data in the second
and third quarters of 2005 to identify leads and prospects that merit drilling.
We also plan to tender in the second quarter of 2005 for a multi-well drilling
contract that will then make it possible for us to drill without delay if and as
prospects are approved by our technical group.
Wilga Project Area
In January 2005, we announced plans to begin working with POGC to bring
the Wilga well into production. The well is expected to produce at a rate of 5-6
MMcf of gas and 230 Bbls of condensate per day when it begins production. The
Wilga well was drilled in 2000 and as of December 31, 2004, has gross proved
reserves of 6.3 Bcf and 247,000 barrels of condensate. Effective January 31,
2005, we are the operator of the Wilga project area and own an 82% interest.
POGC owns an 18% interest.
Prior to January 2005, Apache Corp. was the operator and a 45% interest
owner in the Wilga area. In connection with its exit from Poland, Apache
relinquished its interest in the Wilga area, which then reverted to us and POGC
ratably by virtue of our existing agreements with POGC and Apache.
Exploratory Activities in the United States
Nevada
During 2004, we drilled the East Inselberg well to a total depth of
1,322 feet in a 680-acre lease block near our existing Trap Spring / Munson
Ranch producing area. The well encountered shows of oil, and we are testing to
determine whether it is commercial. Makoil is the operator and owns a 50%
working interest, and we own the remaining 50%. We plan to drill several
additional exploratory wells this year in Railroad Valley near our existing
producing properties.
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.
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 taken steps to harmonize Polish legislation with that of
the European Union, which it joined in May of 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.
9
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.
Polish Properties
Legal Framework
General Usufruct and Concession Terms
All of our rights in Poland have been awarded pursuant to the
Geological and Mining Law, which specifies the process for obtaining domestic
exploration and exploitation rights. Under the Geological and Mining Law, the
concession authority enters into mining usufruct (lease) agreements that grant
the holder the exclusive right to explore for oil and gas in a designated area
or to exploit the designated oil and/or gas field for a specified period under
prescribed terms and conditions. The holder of the mining usufruct covering
exploration must also acquire an exploration concession 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 and Wilga 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.
Concessions have been acquired for exploration in 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
high-methane gas is currently less than $0.05 per Mcf. This rate could be
increased or decreased by the Council of Ministers to a rate between $0.02 and
$0.10 per Mcf (the current statutory minimum and maximum royalty rates). Local
governments will receive 60% of any royalties paid on production. The holder of
the exploitation concession must also acquire rights to use the land from the
surface owner and 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 carried certain work requirements during the first three years, all of which
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 acquiring 70 kilometers of 3-D seismic
data, 250 kilometers of new 2-D seismic data, reprocessing 100 kilometers of
seismic data and drilling four wells.
10
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
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 data, acquiring 100 kilometers of new 2-D
seismic data, 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 us. All work commitments have been completed.
As of December 31, 2004, 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 in 2003 to
assign our interest in the Kleka 11 well, including amounts representing unpaid
gas sales, to POGC to reduce our outstanding obligation to POGC. Accordingly, we
received no net gas production from the Kleka 11 well in 2004 and 2003. See Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operation: Introduction--Fences I Commitment and Settlement for further
information concerning the Kleka 11 well.
We did not record any oil or gas production in Poland during 2004 and
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 the past three years:
2004 2003 2002
---- ---- ----
Polish producing property data:
Average daily net gas production (Mcf)........... -- -- 494
Average sales price per MMBTU(1)................. -- -- $ 2.02
Average production costs per Mcf(2).............. -- -- $ 0.16
- ---------------------
(1) Gross sales prices before downward adjustment of $0.44 per Mcf for caloric
content.
(2) Production costs include lifting costs (electricity, fuel, water, disposal,
repairs, maintenance, pumper, transportation and similar items). Production
costs do not include such items as G&A costs, depreciation, depletion or
Polish income taxes.
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 2004 follows:
Average Daily Production
(Bbls) Average Average
---------------------------- Working Net Revenue
Gross Net Interest Interest
------------- -------------- -------------- --------------------
United States producing properties:
Montana:
Cut Bank............................ 243 210 99.6% 86.4%
Bears Den........................... 9 7 98.0 81.0
Rattlers Butte...................... 19 1 6.3 5.1
------------- --------------
Total............................. 271 218
------------- --------------
Nevada:
Trap Spring......................... 8 1 21.6 18.9
Munson Ranch........................ 35 12 36.0 34.1
Bacon Flat.......................... 27 3 16.9 12.5
------------- --------------
Total............................. 70 16
------------- --------------
Total United States producing
properties................... 341 234
============= ==============
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 99 producing oil wells, 25 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
98% 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 2004, 2003 and 2002:
Years Ended December 31,
------------------------------
2004 2003 2002
-------- --------- ---------
United States producing property data:
Average daily net oil production (Bbls)........ 234 234 249
Average sales price per Bbl.................... $36.34 $26.29 $21.19
Average production costs per Bbl(1)............ $18.85 $17.22 $14.59
- ------------------
(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. In July 2003, we began selling the majority of our
Montana production, which represents over 85% of our total oil sales, to CENEX,
a regional refiner and marketer. From June 2002 through June 2003, we sold our
Montana production to Plains Marketing Canada L.P. For the first half of 2002
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.
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, 2004, of $36.69 per Bbl for oil in
the United States and $35.39 per Bbl of oil and $1.91 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 and amount 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 Statement of Financial Accounting
Standards ("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 2004.
13
The following summary of proved reserve information as of December 31,
2004, represents estimates net to us only and should not be construed as exact:
United States Poland
--------------------------- ---------------------------------------- Total
Oil PV-10 Value Oil Gas PV-10 Value PV-10 Value
----------- -------------- ------------ ------------ -------------- -----------------
(MBbls) (In thousands) (MBbls) (MMcf) (In thousands) (In thousands)
Proved reserves:
Developed producing....... 809 $ 5,134 -- 1,011 $ 814 $ 5,948
Undeveloped............... -- -- 111 9,187 12,277 12,277
----------- -------------- ------------ ------------ -------------- -----------------
Total................... 809 $ 5,134 111 10,198 $ 13,091 $ 18,225
=========== ============== ============ ============ ============== =================
Gas reserves in Poland include 1.0 Bcf of gas attributable to the Kleka
11 well, which we agreed in 2003 to convey to POGC; in early 2004, we and POGC
agreed that we would not convey the Kleka 11 well, subject to completing final
documentation. See Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation: Introduction--Fences I Commitment and
Settlement, for further information concerning the Kleka 11 well.
Drilling Activities
The following table sets forth the exploratory wells that we drilled
during the years ended December 31, 2004, 2003 and 2002:
Years Ended December 31,
-------------------------------------------------------------------
2004 2003 2002
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- --------- ---------- --------- ----------
Discoveries:
United States....................... -- -- -- -- -- --
Poland.............................. 2.0 0.7 -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total............................. 2.0 0.7 -- -- -- --
--------------------- --------- ---------- --------- ----------
Exploratory dry holes:
United States....................... -- -- -- -- -- --
Poland.............................. -- -- -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total............................. -- -- -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total wells drilled................... 2.0 0.7 -- -- -- --
========== ========== ========= ========== ========= ==========
We did not complete any exploratory wells in 2003 and 2002, and we did
not drill any development wells during 2003 and 2002. At December 31, 2004,
drilling operations were in progress at the Sroda-4 well in Poland and the East
Inselberg well in Nevada.
Wells and Acreage
As of December 31, 2004, our producing gross and net well count
consisted of the following:
Number of Wells
------------------------
Gross Net
----------- -----------
Well count:
United States(1)........................... 118.0 112.0
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 Kleka 11 well, which we agreed in 2003 to convey to POGC; in
early 2004, we and POGC agreed that we would not convey the Kleka 11 well,
subject to completing final documentation. See Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operation: Introduction--
Fences I Commitment and Settlement, for further information concerning the Kleka
11 well.
14
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2004:
Developed Undeveloped
---------------------------- ----------------------------
Gross Net Gross Net
------------- ------------- ------------- --------------
United States:
Montana...................................... 10,732 10,418 1,150 1,057
Nevada....................................... 400 128 7,132 4,151
------------- ------------- ------------- --------------
Total..................................... 11,132 10,546 8,282 5,208
------------- ------------- ------------- --------------
Poland: (1)
Fences I project area........................ 225 110 265,000 119,000
Fences II project area....................... -- -- 670,000 328,000
Fences III project area...................... -- -- 770,000 770,000
Wilga project area(2)........................ 543 244 250,000 113,000
------------- ------------- ------------- --------------
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) Effective January 31, 2005, our interest changed to 82%, increasing our net
acreage to 205,000 acres.
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.
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
15
of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, and the plugging and abandoning of wells. Our
operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration
units and the density of wells that may be drilled and the unitization or
pooling of oil and gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state conservation
laws establish maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of gas, and impose certain requirements
regarding the ratability of production.
Our oil production is affected to some degree by state regulations.
States in which we operate have statutory provisions regulating the production
and sale of oil and gas, including provisions regarding deliverability. Such
statutes and related regulations are generally intended to prevent waste of oil
and gas and to protect correlative rights to produce oil and gas between owners
of a common reservoir. Certain state regulatory authorities also regulate the
amount of oil and gas produced by assigning allowable rates of production to
each well or proration unit.
Environmental Regulations
The federal government and various state and local governments have
adopted laws and regulations regarding the control of contamination of the
environment. These laws and regulations may require the acquisition of a permit
by operators before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution resulting from
our operations. These laws and regulations may also increase the costs of
drilling and operation of wells. We may also be held liable for the costs of
removal and damages arising out of a pollution incident to the extent set forth
in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act
of 1990, or OPA `90. In addition, we may be subject to other civil claims
arising out of any such incident. As with any owner of property, we are also
subject to clean-up costs and liability for hazardous materials, asbestos or any
other toxic or hazardous substance that may exist on or under any of our
properties. We believe that we are in compliance in all material respects with
such laws, rules and regulations and that continued compliance will not have a
material adverse effect on our operations or financial condition. Furthermore,
we do not believe that we are affected in a significantly different manner by
these laws and regulations than our competitors in the oil and gas industry.
The Comprehensive Environmental Response, Compensation and Liability
Act, or CERCLA, also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources, and for the costs of certain
health studies. Furthermore, it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.
The Resource Conservation and Recovery Act, or RCRA, and regulations
promulgated thereunder govern the generation, storage, transfer and disposal of
hazardous wastes. RCRA, however, excludes from the definition of hazardous
wastes "drilling fluids, produced waters and other wastes associated with the
exploration, development, or production of crude oil, gas or geothermal energy."
Because of this exclusion, many of our operations are exempt from RCRA
regulation. Nevertheless, we must comply with RCRA regulations for any of our
operations that do not fall within the RCRA exclusion.
The OPA `90 and related regulations impose a variety of regulations on
responsible parties related to the prevention of oil spills and liability for
damages resulting from such spills. OPA `90 establishes strict liability for
owners of facilities that are the site of a release of oil into "waters of the
United States." While OPA `90 liability more typically applies to facilities
near substantial bodies of water, at least one district court has held that OPA
`90 liability can attach if the contamination could enter waters that may flow
into navigable waters.
16
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. Our activities on
these properties 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. Our 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, 2004, we had 33 employees, consisting of seven in
Salt Lake City, Utah; 20 in Oilmont, Montana; one in Greenwich, Connecticut;
three in Houston, Texas, one in the United Kingdom, and one in Poland. 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. 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. 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.
17
Oil and Gas Terms
The following terms have the indicated meaning when used in this
report:
"Bbl" means oilfield barrel.
"Bcf" means billion cubic feet of natural gas.
"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 oilfield barrels.
"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.
"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 general
and administrative 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.
18
- --------------------------------------------------------------------------------
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, 2004.
PART II
- --------------------------------------------------------------------------------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
- --------------------------------------------------------------------------------
Price Range of Common Stock and Dividend Policy
The following table sets forth for the periods indicated the high and
low closing prices for our common stock as quoted under the symbol "FXEN" on the
Nasdaq National Market since August 2004 and on the Nasdaq SmallCap Market
previously:
Low High
--- ----
2005:
First Quarter (through March 4, 2005)............ $12.63 $15.98
2004:
Fourth Quarter................................... 4.85 11.91
Third Quarter.................................... 6.81 9.18
Second Quarter................................... 7.71 9.71
First Quarter.................................... 8.10 11.68
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
We have never paid cash dividends on our common stock and do not
anticipate that we will pay dividends in the foreseeable future. We intend to
reinvest any future earnings to further expand our business. We estimate that,
as of March 4, 2005, we had approximately 4,200 stockholders.
Our common stock is currently traded on the Nasdaq National Market
under the symbol FXEN.
19
- --------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
The following selected financial data for the five years ended December
31, 2004, 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,
---------------------------------------------------------------
2004 2003 2002 2001 2000
----------- ------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales....................... $ 3,096 $ 2,230 $ 2,209 $ 2,229 $ 2,521
Oilfield services....................... 710 98 533 1,584 1,290
----------- ------------ ------------ ------------ ------------
Total revenues........................ 3,806 2,328 2,742 3,813 3,811
----------- ------------ ------------ ------------ ------------
Operating costs and expenses:
Lease operating expenses (1)............ 1,946 1,546 1,365 1,358 1,349
Exploration costs (2)................... 3,013 523 1,031 6,544 7,389
Impairments of oil and gas
properties (3)........................ -- 161 1,548 -- --
Oilfield services costs................. 551 190 540 1,301 1,084
Depreciation, depletion and
amortization.......................... 636 599 618 662 386
Accretion expense....................... 41 37 -- -- --
Amortization of deferred
compensation (G&A).................... -- -- 55 1,078 652
Stock compensation (G&A) (4)............ 5,859 -- -- -- --
Apache Poland general and
administrative costs (G&A)............ -- -- -- 575 957
General and administrative (G&A)........ 4,909 3,253 2,440 883 2,654
----------- ------------ ------------ ------------ ------------
Total operating costs and expenses.. 16,955 6,309 7,597 12,401 14,471
----------- ------------ ------------ ------------ ------------
Operating loss............................ (13,149) (3,981) (4,855) (8,588) (10,660)
----------- ------------ ------------ ------------ ------------
Other income (expense):
Interest and other income............... 529 37 119 543 417
Interest expense........................ -- (788) (1,189) (331) (2)
Impairment of notes receivable.......... -- -- -- (34) --
----------- ------------ ------------ ------------ ------------
Total other income (expense)........ 529 (751) (1,070) 178 415
Net loss before cumulative effect of
change in accounting principle.......... (12,620) (4,732) (5,925) (8,410) (10,245)
Cumulative effect of change in
accounting principle.................... -- 1,799 -- -- --
----------- ------------ ------------ ------------ ------------
Net loss.................................. $ (12,620) $ (2,933) $ (5,925) $ (8,410) $ (10,245)
=========== ============ ============ ============ ============
- Continued -
20
Years Ended December 31,
-----------------------------------------------------------
2004 2003 2002 2001 2000
------------ ---------- ----------- ---------- -----------
(In thousands)
Basic and diluted net loss per share:
Net loss attributable to common shares before
cumulative effect of change in accounting
principle......................................... $ (0.41) $ (0.41) $ (0.34) $ (0.48) $ (0.62)
Cumulative effect of change in
accounting principle.............................. -- 0.09 -- -- --
------------ ---------- ----------- ---------- -----------
Net loss........................................ $ (0.41) $ (0.32) $ (0.34) $ (0.48) $ (0.62)
============ ========== =========== ========== ===========
Basic and diluted weighted average
shares outstanding................................ 30,691 19,885 17,641 17,673 16,435
Cash Flow Statement Data:
Net cash used in operating activities............... $ (4,809) $ (5,561) $ (2,162) $ (3,248) $ (6,082)
Net cash (used in) provided by investing activities. (42,568) (1,446) (295) 326 (3,834)
Net cash provided by financing activities........... 37,791 23,673 5 5,000 9,375
Balance Sheet Data:
Working capital (deficit)........................... $ 33,777 $ 16,032 $ (9,150) $ 558 $ 616
Total assets........................................ 52,962 23,769 5,441 9,168 10,570
Long-term debt...................................... -- -- -- 4,907 --
Stockholders' equity (deficit)...................... 48,556 21,459 (4,869) 953 8,231
- -----------------------
(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.
(4) Includes noncash compensation charge of $5.8 million associated with the
cashless exercise of certain employee stock options.
21
- --------------------------------------------------------------------------------
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
We made important progress on several different fronts in 2004:
o Our drilling program in Poland is off to a successful start. We
announced early in 2004 that the Zaniemysl-3 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 MMcf of gas per day. Together with our partners, POGC and
CalEnergy Gas, we have begun development work to build facilities and
connect to the pipeline grid through a pipeline to be built by POGC to
produce gas from the Zaniemysl structure at a permitted rate of 10 MMcf
of gas per day. Gas production is scheduled to commence by the end of
2005.
During the second half of 2004 we received operating committee approval
to drill the first well focused on a stratigraphic trap in the
Rotliegendes, the Rusocin-1 well. In January 2005 we announced that the
well flowed gas in an initial test of an 18 meter section of the
Rotliegendes sandstone target reservoir. The top of the Rotliegendes
was encountered at approximately 2,747 meters. Results of the initial
drill stem test indicate that the reservoir may extend beyond the
mapped faults, suggesting a larger reservoir along the Wolsztyn High.
The well found what is believed to be the lower edge of a pinch-out at
the top of the Rotliegendes sandstone with 20-25% porosity.
We are testing the Rusocin well to determine whether it is commercial.
If warranted, we will propose one or more appraisal wells on the
Rusocin prospect. At the same time, we are completing geological and
geophysical work on the Lugi prospect, another stratigraphic test, and
expect this well to be the next test of the pinch-out play. During the
remainder of 2005, we plan to acquire new 2-D seismic data on selected
structural prospects as well as along the stratigraphic trap trend; we
are also considering acquiring new 3-D seismic data along the
stratigraphic trap trend. We intend to propose additional wells, both
exploratory and appraisal, as our technical staff approves specific
prospects.
In the second half of 2004, we also received operating committee
approval to drill the Sroda prospect, a structural feature modeled on
POGC's Radlin field. Although slowed by mechanical problems, drilling
operations should conclude in the first quarter of 2005. We have
identified several other prospects near Sroda and we are also working
to identify prospects on Block 248 on the eastern end of Fences II. For
further discussion concerning the Zaniemysl-3 well and the Fences I and
II areas, see Exploration, Development and Production Activities.
o We continued to strengthen our balance sheet, raising a total of $33.8
million from the sale of common stock through a registered offering and
a subsequent private placement and from the exercise of certain
warrants and options.
o We satisfied our earning commitments with POGC on both our Fences I and
Fences II prospect areas. This means that POGC is now obligated to pay
its 51% share of all drilling, seismic, and other qualifying costs as
we move forward with our exploration program.
We are committed to pursuing an active exploration program in Poland.
At the same time, we recognize that good science takes time, and that our
specific goals do not necessarily coincide with those of our partners.
22
Following is a brief discussion concerning some of the significant
financial events that have occurred during the past two years.
Sales of Common and Convertible Preferred Stock
2004
We completed a registered offering during April of 2004 of 2,152,778
shares of common stock, resulting in net proceeds of $14,348,298 after offering
costs of $1,151,704. In August of 2004, we placed privately an additional
950,000 shares, resulting in net proceeds of $6,375,286 after offering costs of
$464,717. In addition, warrant and option holders purchased a total of 3,241,638
shares of common stock during the year, providing an additional $13,067,148 in
proceeds.
2003
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 was
immediately convertible 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 stock. 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 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.
Fences I Commitment and Settlement
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
exceeded $16.0 million, POGC would be obligated to pay its 51% share of further
costs. Through the end of 2003, we had incurred qualifying costs of $10.7
million. Total qualifying costs incurred during 2004 exceeded the remaining $5.3
million commitment. These costs included $3.1 million paid by us through the end
of the year towards the Rusocin-1 well, $3.2 million paid by CalEnergy Gas
towards the Zaniemysl-3 well, and other geological and geophysical costs
incurred on the Fences I project area. We have now earned our 49% interest, and
POGC is obligated to pay its 51% share of all qualifying project costs. At
December 31, 2004 we had recorded a receivable from POGC related to costs we
spent in excess of our commitment requirement in the amount of $770,000.
In early 2003, we entered into a settlement agreement with POGC to
address the methods by which we would satisfy our then existing unpaid liability
incurred in connection with meeting our $16.0 million commitment. Our total
unpaid liability, including interest accrued through the end of 2003, was
approximately $5.0 million as of December 31, 2003. As a partial settlement
towards our liabilities, POGC agreed to offset approximately $800,000 owed to us
for prior gas sales from the Kleka 11 well. Included in that amount was $190,000
of value added tax that will be paid by us to the Polish tax authorities, and
for which we established a separate liability. In addition, we paid POGC a total
23
of $2.9 million in cash. Lastly, we agreed to assign to POGC all of our rights
to the Kleka 11 well, and the liability was to be further offset by the value of
the remaining gas reserves associated with the well. 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 $1.3 million, as determined by an independent engineer. Upon
completion of the assignment of the Kleka 11 well, our previously unpaid
liability was to have been settled in full.
Due to the fact that we have now exceeded our $16.0 million commitment,
we have agreed with POGC not to assign our interest in the Kleka 11 well to it.
This agreement will be in formal documentation that we expect to conclude in the
first half of 2005, at which time we will be required to pay approximately $1.3
million in cash to POGC to settle our remaining unpaid liabilities, offset by
approximately $250,000 in gas production revenue from 2003 and 2004, and any
overpayment relating to the $16 million earn in. We would also then begin
accruing our share of gas sales from the Kleka 11 well. We will recognize a gain
or loss on the settlement equal to the difference between the recorded liability
and the actual cash payment.
Fences II Commitment
Under a January 2003 agreement, we had 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 satisfied the
expenditure requirements in early 2005 by continuing our ongoing 2-D seismic
data reprocessing, along with drilling the initial well at the Sroda prospect.
We have now earned our 49% interest, and POGC has begun paying its 51% share of
all qualifying project costs.
CalEnergy Gas Agreement
In January 2003, we signed a farmout agreement with CalEnergy Gas
Holdings Ltd., an affiliate of MidAmerican Energy Holdings Company, for the
joint exploration of our Fences I project in Poland. Under the terms of the
agreement, CalEnergy Gas 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
drill site in the Rusocin prospect in Fences I and to proceed with drilling as
soon as possible. As a result of its failure to drill a second well, CalEnergy
Gas forfeited the right to participate in other prospects in the Fences I area.
In March 2004, we signed a new agreement with CalEnergy Gas expanding
the area of the FX/CalEnergy Gas joint operations in Poland. CalEnergy Gas had
previously earned the acreage covering the Zaniemysl gas field by paying the
cost to drill the Zaniemysl-3 well. The new agreement covers additional acreage
surrounding the Zaniemysl field referred to as the Greater Zaniemysl Area, or
GZA. The GZA was established to allow the two companies to put the Zaniemysl
discovery into production while exploring together for other nearby natural gas
opportunities that would have the potential to add economic value to the overall
Zaniemysl project.
The GZA quantifies the acreage earned by CalEnergy Gas at 45,220 acres,
covering approximately 17% of Fences I, and will require CalEnergy Gas to pay
$250,000 of our share of geological and geophysical work on the GZA project.
Both companies anticipate additional seismic data acquisition and reprocessing
in the expanded project. FX Energy and CalEnergy Gas each hold a 24.5% interest
in the GZA and POGC holds 51%.
All of the qualifying costs related to our 49% interest in the Fences I
project area that are paid for by CalEnergy Gas were credited against our $16.0
million earn-in agreement with POGC.
24
Gain Contingency
Throughout our operating history in Poland, we have been unable to
obtain a refund of most of the value added taxes paid in connection with goods
and services purchased (Input VAT). Polish tax laws have restricted the refund
of Input VAT for exploration activities to concession holders. In our case, POGC
has traditionally been the concession holder, while we are a working interest
owner by virtue of our agreements with POGC.
During 2004, Poland joined the European Union. In connection with this
activity, certain tax laws have changed, and we believe we may now be entitled
to reclaim some or all of the Input VAT paid since 1998, which totals
approximately $3.2 million at year-end exchange rates.
We are preparing the necessary forms to file with appropriate Polish
tax authorities to obtain a refund of the Input VAT in question. Should we be
successful in reclaiming our historical Input VAT, we would reduce capital costs
for the related Input VAT, and record a gain for the Input VAT related to past
geological, geophysical, and other costs.
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.
As of December 31, 2004, we had capitalized exploratory well costs,
pending the determination of proved reserves, of approximately $3.1 million
associated with the Rusocin well and $5.6 million associated with the Sroda-4
well in Poland, and approximately $0.1 million associated with the East
Inselberg well in Nevada.
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
25
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 Accounting
Principles Board 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."
During the second quarter of 2004, two of our officers exercised
options to acquire a total of approximately 650,000 shares of our common stock
at an exercise price of $3.00 per share, by canceling options to purchase
approximately 350,000 shares and applying the option equity to pay the exercise
price on the options exercised. The ten-year options were due to expire during
the second quarter. In connection with this cashless exercise, we recorded a
stock compensation charge of approximately $5.8 million, which is equal to the
difference between the exercise price and fair value of the options on the date
of exercise, and a corresponding increase in additional paid-in capital. This
noncash transaction had no impact on our working capital, cash flows or
stockholders' equity.
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, general and administrative costs, or G&A, and other income
directly associated with their respective segments are detailed within the
following discussion. DD&A, G&A, amortization of deferred compensation ,
interest income, other income, interest expense, 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, 2004, 2003 and
2002, respectively, follows. Further information concerning our business
segments can be found in Note 11, 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, 2004, 2003 and 2002, is set forth in the following
table:
For the year ended December 31,
----------------------------------------------------------------------------
2004 2003 2002
------------------------- ------------------------ -------------------------
Oil Gas Oil Gas Oil Gas
------------ ------------ ------------ ----------- ------------ ------------
Revenues.............................. $3,096,000 $ -- $2,230,000 $ -- $1,924,000 $ 285,000
Percent change versus prior year.... +38.8% -- +15.9% -100.0% +4.9% -27.7%
Average price (per Bbl )(1)........... $ 36.44 $ -- $ 26.29 $ -- $ 21.19 $ 1.58
Percent change versus prior year.... +38.6% -- 24.1% -- +9.2% --
Production volumes (per Bbl).......... 84,970 -- 84,811 -- 90,817 180,407
Percent change versus prior year.... +.01% -- -6.6% -100.0% -3.9% -27.7%
Lifting costs per Bbl (2)............. $ 18.85 $ -- $ 17.79 $ -- $ 14.28 $ 0.16
Percent change versus prior year.... +5.9% -- +20.6% -- +4.8% --
- ------------------------
(1) The contract price for gas during 2002 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. Lifting costs do not include production taxes.
Oil Revenues. Oil revenues were $3.1 million, $2.2 million and $1.9
million for the years ended December 31, 2004, 2003 and 2002, respectively. All
26
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 in 2003
attributable to the natural production declines of our producing properties. Oil
revenues in 2004 increased from 2003 levels by approximately $862,000 due to
higher oil prices and by approximately $4,000 related to higher oil production.
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.
Gas Revenues. Our gas revenues are derived solely from our Polish
producing operations. Gas revenues were $285,000 for the year ended December 31,
2002. There were no gas revenues during 2004 and 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 in order to conserve cash while reducing the balance of our
liability due to POGC. Accordingly, we recorded no gas sales in 2003 or 2004.
Gas volumes in 2002 reflected a full year of production from the Kleka 11, which
began producing in late February 2001.
Lease Operating Costs. Lease operating costs were $1.9 million in 2004,
$1.5 million in 2003 and $1.4 million in 2002. Operating costs in 2004 increased
by approximately $279,000 due to higher value-based production taxes, and
$121,000 due to higher lifting costs as the Company incurred costs for new
environmental compliance procedures. Operating costs rose from 2002 to 2003 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.
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 $3.0 million, $684,000 and $2.6 million for the years ended December 31,
2004, 2003 and 2002, respectively. Limited available capital caused us to
curtail our exploration activities in Poland in 2003.
G&G costs were $2.5 million, $523,000, and $1.0 million for the years
ended December 31, 2004, 2003 and 2002, respectively. During all three years,
most of our G&G costs were spent on reprocessing and further analyzing seismic
data on the Fences I and II areas.
Exploratory dry-hole costs were $472,000, $0, and $0 for the years
ended December 31, 2004, 2003 and 2002, respectively. As part of the abandonment
of our Pomeranian project area, we were required to plug and abandon the Tuchola
108-2 well in 2004.
Impairments of oil and gas properties were $0, $161,000, and $1.5
million for the years ended December 31, 2004, 2003 and 2002, respectively.
During 2003, the entire impairment related to the Kleka 11 well, which was
written down to its reserve value, and included both capital costs and related
pipeline costs. During 2002, we incurred an impairment of $509,000 in costs
associated with the Tuchola 108-2 well. We also recognized an impairment of $1.0
million associated with the Kleka 11 well, where lower production profiles
caused a downward revision in estimates of recoverable future reserves.
DD&A Expense - Producing Operations. DD&A expense for producing
properties was $259,000, $347,000, and $281,000 for the years ended December 31,
2004, 2003 and 2002, respectively. 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 No. 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003. The decrease from 2003 to 2004 is due primarily to
certain wells being fully depreciated in 2003.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $710,000,
$98,000, and $523,000 for the years ended December 31, 2004, 2003 and 2002,
respectively. Activity in the contract drilling industry picked up significantly
during 2004, resulting in a 625% increase in oilfield services revenues. During
2003, the industry was at a virtual standstill in the area where we operate,
continuing the slowdown that began in late 2002. 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.
27
Oilfield Services Costs. Oilfield services costs were $551,000,
$190,000, and $540,000 for the years ended December 31, 2004, 2003 and 2002,
respectively, or 78%, 194%, and 101% of oilfield servicing revenues,
respectively. During 2003 and 2002, oilfield servicing costs were a higher
percentage of oilfield services revenues, as compared to 2004, due to increased
downtime and 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 $290,000, $304,000, and $310,000 for the years ended December 31, 2004, 2003
and 2002, respectively. We spent $99,000, $75,000 and $116,000 on upgrading our
oilfield servicing equipment during 2004, 2003 and 2002, respectively.
Nonsegmented Items
G&A Costs - Corporate. G&A costs were $4.9 million, $3.2 million, and
$2.4 million for the years ended December 31, 2004, 2003 and 2002, 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, we reinstated those
salaries and fees. In addition, in 2003 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. In 2003, we were also able to resume many of our activities in Poland,
which resulted in higher travel costs for the year. In 2004, G&A costs increased
as we incurred higher accounting and legal fees for Sarbanes-Oxley Section 404
compliance, higher investor relations fees as we moved from the NASDAQ SmallCap
Market to the National Market, higher salaries and related payroll taxes and
benefits as we enlarged our technical staff, and higher consulting fees as we
increased our investor relations activities.
Stock Compensation (G&A). During the second quarter of 2004, two of our
officers exercised options to acquire a total of approximately 650,000 shares of
our common stock at an exercise price of $3.00 per share, by canceling options
to purchase approximately 350,000 shares and applying the option equity to pay
the exercise price on the options exercised. The ten-year options were due to
expire during the second quarter. In connection with this cashless exercise, we
recorded a stock compensation charge of approximately $5.8 million in the second
quarter, which is equal to the difference between the exercise price and fair
value of the options on the date of exercise, and a corresponding increase in
additional paid-in capital. This noncash transaction had no impact on our
working capital, cash flows or stockholders' equity. There we no similar
transactions in 2003 or 2002.
Interest and Other Income - Corporate. Interest and other income was
$529,000, $36,000, and $119,000 for the years ended December 31, 2004, 2003 and
2002, respectively. The increase from 2003 to 2004 is a direct reflection of
significantly higher cash balances available for investment in 2004. Lower cash
balances and interest rates in 2003 and 2002 reduced our interest income in both
years. During the year ended December 31, 2002, we recorded other income of
$93,000 pertaining to the amortization of an option premium resulting from
granting a third party an option to purchase gas from our properties in Poland.
Interest Expense. Interest expense was $0, $788,000, and $1.2 million
for the years ended December 31, 2004, 2003 and 2002, respectively. In March
2002, we began to accrue interest on a $5.0 million third-party obligation at an
annual rate of 9.5%. From May to September 2003, the loan interest rate
increased to 12%. It was reduced to 9.5% from October to November 2003, at which
time the lender converted its note payable and accrued interest into common
stock. We began accruing interest on our 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,
we recorded $93,000 of imputed interest expense relating to our financing
arrangement with the third-party lender.
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $0, $0, and $55,000 during the years ended December 31, 2004,
2003 and 2002, 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 In accordance with FIN
44 "Accounting for Certain Transactions involving Stock Compensation," we
28
incurred noncash deferred compensation costs of $219,000 for the April 5, 2001
option extension which was amortized over the one-year vesting period from the
date of extension. The deferred costs were all amortized as of December 31,
2002.
Income Taxes. We incurred net losses of $12.6 million, $2.9 million,
and $5.9 million for the years ended December 31, 2004, 2003 and 2002,
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
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. Our cash resources at December 31,
2004, should allow us for the balance of 2005 and 2006 to carry out our planned
exploration program without selling additional equity or farming out our
properties.
We may seek to obtain additional funds for future development-related
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 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 $33.8 million as of December 31, 2004, an increase of $20.8 million
from December 31, 2003. The improvement is due primarily to the sale of equity
securities, including the exercise of warrants and options discussed earlier.
Our current liabilities include $1.1 million of costs related to our
Fences I project in Poland. This amount is equal to the estimated value of the
remaining gas reserves at the Kleka 11 at December 31, 2003, which we agreed to
assign to POGC effective December 2002. As we have now exceeded our $16 million
commitment, we have agreed not to complete that assignment and will instead pay
cash to POGC to satisfy the liability. See "Fences I Commitment and Settlement".
Operating Activities. We used net cash of $5.9 million, $5.6 million,
and $2.1 million in our operating activities during 2004, 2003 and 2002,
respectively, primarily as a result of the net losses, excluding noncash
charges, incurred in those years. Our current liabilities at year-end included
approximately $1.1 million in costs related to our drilling activities in Poland
that were paid in early 2005. We made significant progress in reducing our
outstanding liabilities during 2003.
Investing Activities. We used net cash of $41.5 million, $1.4 million
and $295,000 in investing activities in 2004, 2003 and 2002, respectively. In
2004 we transferred $32.7 million to our investment portfolio of marketable
securities. We also spent $8.4 million for oil and gas property additions, $9.2
million of which was related to our Polish drilling activities, with the
remainder being spent on our domestic properties. We also spent $395,000
upgrading our office equipment and purchasing new oilfield technical software.
During 2003, we used $700,000 to pay liabilities associated with oil and gas
property additions from prior years. In 2003, we deposited $376,000 with
CalEnergy Gas to cover drilling expenses for the Zaniemysl-3 well, in the event
costs exceeded an agreed upon target amount. During the second quarter of 2004,
we agreed to final drilling costs for the well in an amount that enabled
CalEnergy Gas to keep the entire deposit. Accordingly, the total deposit amount
29
was reclassified from other assets to proved property costs. We also spent
$194,000 in 2003 related to our proved properties and oilfield equipment in the
United States. During 2002, the majority of cash used was for improving our
producing oil and gas properties and our well-servicing equipment.
Financing Activities. We received net cash of $33.8 million $23.7
million, and $4,500 from our financing activities during 2004, 2003 and 2002,
respectively. In 2004 we received a total of $20.7 million in net proceeds from
the sale of securities. In addition, the exercise of warrants and options
provided additional proceeds of $13.1 million. 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 a third-party lender, $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.
We believe our current cash resources, coupled with anticipated future
revenues, are sufficient to fund our exploration program through the end of
2006.
Contractual Obligations and Contingent Liabilities and Commitments
We had no significant contractual obligations or commitments as of
December 31, 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
In January 2003, the Financial Accounting Standard Board ("FASB")
issued Interpretation No. 46 ("FIN No. 46"), "Consolidation of Variable Interest
Entities." FIN No. 46 clarifies the application of Accounting Research Bulletin
No. 51 ("ARB No. 51"), "Consolidated Financial Statements," and addresses
consolidation by business enterprises of variable interest entities (more
commonly known as Special Purpose Entities). In December 2003, FASB issued FIN
No. 46R, which replaced FIN No. 46 and clarified ARB No. 51. This interpretation
provides guidance on how to identify a variable interest entity and determine
when the assets, liabilities, noncontrolling interests and results of operations
of a variable interest entity should be consolidated by the primary beneficiary.
FIN No. 46R requires the consolidation of variable interest entities in which we
are the primary beneficiary. As of January 1, 2004, we did not own an interest
in any variable interest entities that met the consolidation requirements of FIN
No. 46R and as such the adoption of FIN No. 46R did not have any effect on our
financial position or results of operations. New interests in entities acquired
or created will be evaluated based on FIN No. 46R criteria and consolidated, if
required.
In December 2004, the FASB issued a revision to SFAS No. 123,
"Accounting for Stock-Based Compensation," SFAS No. 123-R, "Share-Based
Payment." SFAS No. 123-R focuses primarily on transactions in which an entity
exchanges its equity instruments for employee services and generally establishes
standards for the accounting for transactions in which an entity obtains goods
or services in share-based payment transactions. We expect to adopt SFAS No.
123-R effective July 1, 2005, using the modified prospective application with no
restatement of prior interim periods. During the second half of 2005, we expect
to record compensation expense of approximately $1,000,000 in connection with
the adoption of SFAS No. 123-R based on existing unvested options as of December
31, 2004.
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.
30
- --------------------------------------------------------------------------------
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 immediate future.
- --------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
Our financial statements, including the independent registered public
accounting firm's report on our consolidated financial statements, are included
beginning at page F-2 immediately following the signature page of this report.
- --------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------
We have not disagreed with our independent registered public accounting
firm on any items of accounting treatment or financial disclosure.
31
- --------------------------------------------------------------------------------
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, 2004, pursuant to Rule 13a-15(b) under the Securities Exchange Act.
Based upon that evaluation, our Certifying Officers concluded that, as of
December 31, 2004, our disclosure controls and procedures were effective.
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management's
report on internal control over financial reporting and the report of
PricewaterhouseCoopers LLP, our independent registered public accounting firm,
on management's assessment of internal control over financial reporting is
included on pages F-1 and F-2 of this report and are incorporated in this Item
9A by reference.
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.
- --------------------------------------------------------------------------------
ITEM 9B. OTHER INFORMATION
- --------------------------------------------------------------------------------
On November 16, 2004, we entered into an Employment Agreement with Clay
Newton, our Principal Accounting Officer, that provides for continued service in
his current capacity for a period of 18 months, concluding on May 15, 2006. The
agreement provides for a base salary and participation in an incentive and bonus
plan at the discretion of our board of directors, as well as participation in
our stock option and other employee benefit plans that are consistent with and
similar to such plans provided to our employees generally. Mr. Newton has also
agreed to certain confidentiality and noncompetition provisions. In the event
his employment is terminated by us "without cause," or by him "for cause," he is
entitled to receive an amount equal to two times the greater of (a) his then
current annual salary, or (b) his salary plus bonus compensation for the year
most recently ended. The agreement also provides payment provisions in the event
of his death or disability.
On November 16, 2004, we also entered into a separate Change in Control
Compensation Agreement with Mr. Newton. The agreement provides for certain
severance and separation benefits in the event that we are involved in a change
in control of a nature that would be required to be reported in response to Item
6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange
Act of 1934, which generally applies if (i) any person other than our company or
a current director or officer of our company is or becomes the beneficial owner,
directly or indirectly, of our securities representing 20% of the combined
voting power of our then outstanding securities; or (ii) there is a merger or
consolidation of our company in which we do not survive as an independent public
company; or (iii) our business or businesses for which the executive's services
are principally performed are disposed of by us pursuant to our partial or
complete liquidation, a sale of our assets, or otherwise. Following such change
in control, in the event his employment is terminated by us "without cause," or
by him "for cause," he is entitled to receive an amount equal to two times the
greater of (a) his then current annual salary, or (b) his salary plus bonus
compensation for the year most recently ended. In addition, he shall fully vest
in and have the right to exercise all outstanding options, stock purchase
awards, and other outstanding awards, including shares as to which he would not
otherwise be vested or exercisable.
32
PART III
- --------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2005 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 2005 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 2005 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 2005 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 2005 annual
meeting of stockholders under the caption "Relationship with Independent
Auditors" is incorporated herein by reference.
33
PART IV
- --------------------------------------------------------------------------------
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
- --------------------------------------------------------------------------------
(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
-------
Management's Report on Internal Control Over Financial
Reporting................................................. F-1
Report of Independent Registered Public Accounting Firm..... F-2
Consolidated Balance Sheets as of December 31, 2004
and 2003.................................................. F-4
Consolidated Statements of Operations for the Years
Ended December 31, 2004, 2003 and 2002.................... F-6
Consolidated Statements of Comprehensive Loss for the
Years Ended December 31, 2004, 2003 and 2002.............. F-7
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2004, 2003 and 2002.................... F-8
Consolidated Statement of Stockholders' Equity (Deficit)
for the Years Ended December 31, 2004, 2003 and 2002...... F-9
Notes to the Consolidated Financial Statements...............F-10
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 consolidated
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 This filing.
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 Incorporated by reference from the annual report
Preferences of Series A Preferred Stock on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
4.03 Form of Rights Agreement dated as of April 4, 1997, Incorporated by reference from the annual report
between FX Energy, Inc. and Fidelity Transfer Corp. on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
34
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
Item 10 Material Contracts
- ------------ -----------------------------------------------------
10.26 Frontier Oil Exploration Company 1995 Stock Option Incorporated by reference from the annual report
and Award Plan** on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.27 FX Energy, Inc. 1996 Stock Option and Award Plan** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.28 FX Energy, Inc. 1997 Stock Option and Award Plan** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.29 FX Energy, Inc. 1998 Stock Option and Award Plan** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
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 (D. Incorporated by reference from the registration
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 Incorporated by reference from the annual report
Scott J. Duncan** on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.52 Form of Indemnification Agreement between FX Energy, Incorporated by reference from the annual report
Inc. and certain directors, with related schedule** on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.53 Agreement on Cooperation in Exploration of Incorporated by reference from the quarterly
Hydrocarbons on Foresudetic Monocline dated report on Form 10-Q for the quarter ended
April 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
10.59 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.
10.62 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.
35
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
Item 10 Material Contracts
- ------------ -----------------------------------------------------
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 Incorporated by reference from the annual report
FX 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** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.68 FX Energy, Inc. 2000 Stock Option and Award Plan** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.69 FX Energy, Inc. 2001 Stock Option and Award Plan** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.70 FX Energy, Inc. 2003 Long-Term Incentive Plan Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.72 FX Energy, Inc. Placement Agency Agreement with CDC Incorporated by reference from the current
Securities dated April 13, 2004 report on Form 8-K dated April 13, 2004, filed
April 16, 2004.
10.73 FX Energy, Inc. Underwriting Agreement with Incorporated by reference from the current
I-Bankers Securities Incorporated dated April 13, report on Form 8-K dated April 13, 2004, filed
2004 April 16, 2004.
10.74 Greater Zaniemysl Area Agreement made as of March Incorporated by reference from the quarterly
12, 2004, among FX Energy Poland Sp. z o.o. and report on Form 10-Q for the period ended
CalEnergy Resources Poland Sp. z o.o. March 31, 2004, filed May 11, 2004.
10.75 Form of Indemnification Agreement between FX Energy, This filing.
Inc. and directors and officers with related
schedule**
10.76 Supplemental Indemnification Agreement between FX This filing.
Energy, Inc. and Dennis B. Goldstein**
10.77 Description of compensation arrangement with This filing.
executive officers and directors**
36
Exhibit
Number* Title of Document Location
- ------------ ----------------------------------------------------- -------------------------------------------------
Item 10 Material Contracts
- ------------ -----------------------------------------------------
10.78 Form of Employment Agreement with related schedule** This filing.
10.79 Change in Control Compensation Agreement with This filing.
related schedule**
10.80 FX Energy, Inc. 401(k) Stock Bonus Plan** This filing.
10.81 FX Energy, Inc. 2004 Long-Term Incentive Plan** This filing.
Item 21 Subsidiaries of the Registrant
- ------------ -----------------------------------------------------
21.01 Schedule of Subsidiaries This filing.
Item 23 Consents of Experts and Counsel
- ------------ -----------------------------------------------------
23.01 Consent of PricewaterhouseCoopers LLP, independent This filing.
registered public accounting firm
23.02 Consent of Larry D. Krause, Petroleum Engineer This filing.
23.03 Consent of Troy-Ikoda Limited, Petroleum Engineers This filing.
Item 31 Rule 13a-14(a)/15d-14(a) Certifications
- ------------ -----------------------------------------------------
31.01 Certification of Chief Executive Officer Pursuant to This filing.
Rule 13a-14
31.02 Certification of Chief Financial Officer Pursuant to This filing.
Rule 13a-14
Item 32 Section 1350 Certifications
- ------------ -----------------------------------------------------
32.01 Certification of Chief Executive Officer Pursuant to This filing.
18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
32.02 Certification of Chief Financial Officer Pursuant to This filing.
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.
37
- --------------------------------------------------------------------------------
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, 2005 By:/s/ David N. Pierce
-------------------------------------
David N. Pierce
President and Chief Executive Officer
Dated: March 10, 2005 By:/s/ Thomas B. Lovejoy
-------------------------------------
Thomas B. Lovejoy
Chief Financial Officer
Dated: March 10, 2005 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.
Dated: March 10, 2005 /s/ Thomas B. Lovejoy
----------------------------------------
Thomas B. Lovejoy, Director
Dated: March 10, 2005 /s/ David N. Pierce
----------------------------------------
David N. Pierce, Director
Dated: March 10, 2005 /s/ Dennis B. Goldstein
----------------------------------------
Dennis B. Goldstein, Director
Dated: March 10, 2005 /s/ David L. Worrell
----------------------------------------
David L. Worrell, Director
/s/ Arnold S. Grundvig, Jr.
Dated: March 10, 2005 ----------------------------------------
Arnold S. Grundvig, Jr., Director
/s/ Jerzy B. Maciolek
Dated: March 10, 2005 ----------------------------------------
Jerzy B. Maciolek, Director
/s/ Richard Hardman
Dated: March 10, 2005 ----------------------------------------
Richard Hardman, Director
38
[FX Energy's logo]
Management's Report on Internal Control over Financial Reporting
Management of FX Energy, Inc., together with its consolidated
subsidiaries (the Company), is responsible for establishing and maintaining
adequate internal control over financial reporting. The Company's internal
control over financial reporting is a process designed under the supervision of
the Company's principal executive and principal financial officers to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of the Company's financial statements for external reporting
purposes in accordance with U.S. generally accepted accounting principles.
As of the end of the Company's 2004 fiscal year, management conducted
an assessment of the effectiveness of the Company's internal control over
financial reporting based on the framework established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Based on this assessment, management has determined
that the Company's internal control over financial reporting as of December 31,
2004, was effective.
The Company's internal control over financial reporting includes
policies and procedures that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect transactions and dispositions
of assets; (2) provide reasonable assurances that transactions are recorded as
necessary to permit preparation of financial statements in accordance with U.S.
generally accepted accounting principles, and that receipts and expenditures are
being made only in accordance with authorizations of management and the
directors of the Company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use or disposition
of the Company's assets that could have a material effect on our financial
statements.
Management's assessment of the effectiveness of the Company's internal
control over financial reporting as of December 31, 2004, has been audited by
PricewaterhouseCoopers LLP, independent registered public accounting firm, as
stated in its report appearing on pages F-2 and F-3, which expresses unqualified
opinions on management's assessment and on the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004.
F-1
[PriceWaterhouseCoopers logo]
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
of FX Energy, Inc. and its subsidiaries
We have completed an integrated audit of FX Energy, Inc.'s 2004 consolidated
financial statements and of its internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002 consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Consolidated financial statements
- ---------------------------------
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of comprehensive loss, 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,
2004 and 2003, and the results of their operations and their cash flows for each
of the three fiscal years in the period ended December 31, 2004 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
the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit of financial statements 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.
Internal control over financial reporting
- -----------------------------------------
Also, in our opinion, management's assessment, included in Management's Report
on Internal Control over Financial Reporting appearing on page F-1, that the
Company maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), is fairly stated, in all material respects, based on
those criteria. Furthermore, in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control --
Integrated Framework issued by the COSO. The Company's management is responsible
for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit. We conducted our audit of internal control over financial
reporting in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
F-2
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Salt Lake City, Utah
March 15, 2005
F-3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2004 and 2003
(in thousands)
2004 2003
---------------- -----------------
ASSETS
Current assets:
Cash and cash equivalents.................................................... $ 3,784 $ 17,371
Marketable securities........................................................ 32,321 --
Receivables:
Accrued oil sales........................................................ 335 246
Joint interest and other receivables..................................... 1,013 137
Inventory.................................................................... 92 79
Other current assets......................................................... 224 126
---------------- -----------------
Total current assets................................................. 37,769 17,959
---------------- -----------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved................................................................... 15,574 5,753
Unproved................................................................. 355 174
Other property and equipment................................................. 3,992 3,598
---------------- -----------------
Gross property and equipment............................................. 19,921 9,525
Less accumulated depreciation, depletion and amortization.................... (5,087) (4,451)
---------------- -----------------
Net property and equipment........................................... 14,834 5,074
---------------- -----------------
Other assets:
Certificates of deposit...................................................... 356 356
Deposits..................................................................... 3 380
---------------- -----------------
Total other assets................................................... 359 736
---------------- -----------------
Total assets..................................................................... $ 52,962 $ 23,769
================ =================
-Continued-
The accompanying notes are an integral part of these consolidated financial statements.
F-4
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2004 and 2003
(in thousands, except share data)
-Continued-
2004 2003
--------------- ----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................................. $ 2,436 $ 621
Accrued liabilities.......................................................... 1,556 1,306
--------------- ----------------
Total current liabilities............................................ 3,992 1,927
Asset retirement obligation...................................................... 414 383
--------------- ----------------
Total liabilities.................................................... 4,406 2,310
--------------- ----------------
Commitments and Contingencies (Note 6)
Stockholders' equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
December 31, 2004 and 2003; no shares outstanding.......................... -- --
Common stock, $0.001 par value, 100,000,000 shares authorized as of
December 31, 2004 and 2003; 34,398,109 and 27,300,063 shares issued and
outstanding as of December 31, 2004 and 2003, respectively................. 34 27
Additional paid in capital................................................... 117,376 77,327
Accumulated other comprehensive loss......................................... (339) --
Accumulated deficit.......................................................... (68,515) (55,895)
--------------- ----------------
Total stockholders' equity .......................................... 48,556 21,459
--------------- ----------------
Total liabilities and stockholders' equity ...................................... $ 52,962 $ 23,769
=============== ================
The accompanying notes are an integral part of these consolidated financial statements.
F-5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2004, 2003 and 2002
(in thousands, except for per share amounts)
2004 2003 2002
--------------- --------------- ----------------
Revenues:
Oil and gas sales........................................... $ 3,096 $ 2,230 $ 2,209
Oilfield services.......................................... 710 98 533
--------------- --------------- ----------------
Total revenues.......................................... 3,806 2,328 2,742
--------------- --------------- ----------------
Operating costs and expenses:
Lease operating expenses.................................... 1,946 1,546 1,365
Exploration costs........................................... 3,013 523 1,031
Impairment of oil and gas properties........................ -- 161 1,548
Oilfield services costs..................................... 551 190 540
Depreciation, depletion and amortization.................... 636 599 618
Accretion expense........................................... 41 37 --
Amortization of deferred compensation (G&A)................. -- -- 55
Stock compensation (G&A).................................... 5,859 -- --
General and administrative costs (G&A)...................... 4,909 3,253 2,440
--------------- --------------- ----------------
Total operating costs and expenses...................... 16,955 6,309 7,597
--------------- --------------- ----------------
Operating loss.................................................. (13,149) (3,981) (4,855)
--------------- --------------- ----------------
Other income (expense):
Interest and other income................................... 529 36 119
Interest expense............................................ -- (788) (1,189)
--------------- --------------- ----------------
Total other income (expense)............................ 529 (752) (1,070)
--------------- --------------- ----------------
Loss before cumulative effect of accounting change.............. (12,620) (4,733) (5,925)
Cumulative effect of change in accounting principle......... -- 1,800 --
--------------- --------------- ----------------
Net loss........................................................ (12,620) (2,933) (5,925)
Less preferred stock deemed dividend related to beneficial
conversion feature........................................ -- (3,342) --
--------------- --------------- ----------------
Net loss applicable to common shares............................ $ (12,620) $ (6,275) $ (5,925)
=============== =============== ================
Pro forma net loss reflecting adoption of SFAS 143.............. $ (5,958)
================
Basic and diluted loss per common share before
cumulative effect of change in accounting principle......... $ (0.41) $ (0.41) $ (0.34)
Cumulative effect of change in accounting principle......... -- 0.09 --
--------------- --------------- ----------------
Basic and diluted net loss per common share..................... $ (0.41) $ (0.32) $ (0.34)
=============== =============== ================
Pro forma net loss per share reflecting adoption of SFAS 143.... $ (0.34)
================
Basic and diluted weighted average number of shares
outstanding.................................................... 30,691 19,885 17,641
=============== =============== ================
The accompanying notes are an integral part of these consolidated financial statements.
F-6
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Comprehensive Loss
For the years ended December 31, 2004, 2003 and 2002
(in thousands)
2004 2003 2002
--------------- --------------- ----------------
Net loss......................................................... $ (12,620) $ (2,933) $ (5,925)
--------------- --------------- ----------------
Other comprehensive loss
Decrease in market value of available for sale
marketable securities........................................ (339) -- --
--------------- --------------- ----------------
Comprehensive loss $ (12,959) $ (2,933) $ (5,925)
=============== =============== ================
The accompanying notes are an integral part of these consolidated financial statements.
F-7
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2004, 2003 and 2002
(in thousands)
2004 2003 2002
----------------- ---------------- ----------------
Cash flows from operating activities:
Net loss........................................................... $ (12,620) $ (2,933) $ (5,925)
Adjustments to reconcile net loss to net cash used in
operating activities:
Cumulative effect of change in accounting principle........ -- (1,800) --
Depreciation, depletion and amortization................... 636 599 618
Impairment of oil and gas properties....................... -- 161 1,548
Accretion expense.......................................... 41 37 --
Amortization of loan fees.................................. -- 100 --
Gain (loss) on property dispositions....................... 1 -- --
Stock compensation (G&A)................................... 5,859 -- --
Common stock and stock options issued for services (G&A)... 406 101 44
Amortization of deferred compensation (G&A)................ -- -- 55
Increase (decrease) from changes in working capital items:
Receivables.................................................... (1,077) (108) 253
Inventory...................................................... (13) 5 3
Other current assets........................................... (98) (30) (1)
Asset retirement obligation.................................... (10) -- --
Accounts payable and accrued liabilities....................... 989 (1,693) 1,243
----------------- ---------------- ----------------
Net cash used in operating activities...................... (5,886) (5,561) (2,162)
----------------- ---------------- ----------------
Cash flows from investing activities:
Additions to oil and gas properties................................ (8,437) (946) (161)
Additions to other property and equipment.......................... (395) (138) (118)
Net change in other assets......................................... -- 15 (15)
Additions to marketable securities................................. (32,660) -- --
Deposits........................................................... -- (377) --
----------------- ---------------- ----------------
Net cash used in investing activities.......................... (41,492) (1,446) (294)
----------------- ---------------- ----------------
Cash flows from financing activities:
Payment of loan fees............................................... -- (100) --
Payments on notes payable.......................................... -- (1,675) --
Proceeds from issuance of stock and warrants, net of offering
costs............................................................ 20,724 25,448 --
Proceeds from exercise of stock options and warrants............... 13,067 -- 4
----------------- ---------------- ----------------
Net cash provided by financing activities...................... 33,791 23,673 4
----------------- ---------------- ----------------
Net increase (decrease) in cash........................................ (13,587) 16,666 (2,452)
Cash and cash equivalents at beginning of year......................... 17,371 705 3,157
----------------- ---------------- ----------------
Cash and cash equivalents at end of year...............................$ 3,784 $ 17,371 $ 705
================= ================ ================
The accompanying notes are an integral part of these consolidated financial statements.
F-8
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
For the years ended December 31, 2004, 2003 and 2002
Common Stock
-----------------
Par Additional Total
Value Other Stock-
$0.01 Deferred Additional Compre- Accumu- holders'
Preferred Shares Per Treasury Compen- Paid in hensive lated Equity
Stock Issued Share Stock sation Capital Loss Deficit (Deficit)
------- --------- ------- --------- -------- ----------- --------- ----------- ----------
Balance as of December 31, 2001....... -- 17,913 $ 18 $ (1,884) $ (55) $ 49,911 -- $ (47,037) $ 953
Retirement of treasury stock........ -- (285) -- 1,884 -- (1,884) -- -- --
Amortization of deferred -- -- -- -- 55 -- -- -- 55
compensation..........................
Common stock issued for services... -- 21 -- -- -- 44 -- -- 44
Exercise of stock options........... -- 3 -- -- -- 4 -- -- 4
Net loss for year................... -- -- -- -- -- -- -- (5,925) (5,925)
------- --------- ------- --------- ------- ----------- --------- ----------- ----------
Balance as of December 31, 2002....... -- 17,652 18 -- -- 48,075 -- (52,962) (4,869)
Preferred stock offering, net....... $ 2 -- -- -- -- 5,590 -- -- 5,592
Conversion of preferred stock to (2) 2,250
common stock....................... 2 -- -- -- -- -- --
Common stock offerings, net......... -- 6,353 6 -- -- 19,850 -- -- 19,856
Conversion of note payable and -- 972
accrued interest into common stock 1 -- -- 3,592 -- -- 3,593
Common stock issued for services... -- 73 -- -- -- 220 -- -- 220
Net loss for year................... -- -- -- -- -- -- -- (2,933) (2,933)
------- --------- ------- --------- ------- ----------- --------- ----------- ----------
Balance as of December 31, 2003....... -- 27,300 27 -- -- 77,327 -- (55,894) 21,459
Common stock offering, net.......... -- 3,103 3 -- -- 20,721 -- -- 20,724
Common stock issued for services... -- 43 -- -- -- 406 -- -- 406
Exercise of stock options........... -- 554 -- -- -- 2,987 -- -- 2,987
Stock compensation.................. -- 710 1 -- -- 5,858 -- -- 5,859
Exercise of warrants................ -- 2,688 3 -- -- 10,077 -- -- 10,080
Other comprehensive loss............ -- -- -- -- -- -- $ (339) -- (339)
Net loss for year................... -- -- -- -- -- -- -- (12,620) (12,620)
------- --------- ------- --------- ------- ----------- --------- ----------- ----------
Balance as of December 31, 2004....... $ -- 34,398 $ 34 $ -- $ -- $ 117,376 $ (339) $ (68,515) $ 48,556
======= ========= ======= ========= ======= =========== ========= =========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
F-9
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, 2004, 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, 2004 and 2003. The majority of the Company's
cash and cash equivalents is held by three financial institutions in Utah,
Montana and New York. The Company's marketable securities are held by two
financial institutions in Utah and New York.
Inventory
Inventory consists primarily of tubular goods and production related equipment
and is valued at the lower of average cost or market.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and
gas operations. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether an individual well has found proved reserves.
If it is determined that an exploratory well has not found proved reserves, 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
F-10
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
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.
The following table reflects the net changes in capitalized exploratory well
costs, which are capitalized pending the determination of proved reserves,
during 2004, 2003 and 2002.
December 31,
-------------------------------------------
2004 2003 2002
------------- ------------- -------------
(In thousands)
Beginning balance at January 1................................. $ -- $ -- $ --
Additions to capitalized exploratory well costs pending the
determination of proved reserves.............................. 8,779 -- --
Reclassifications to wells, facilities, and equipment based on
the determination of proved reserves.......................... -- -- --
Capitalized exploratory well costs charged to expense.......... -- -- --
------------- ------------- -------------
Ending balance at December 31.................................. $ 8,779 $ -- $ --
============= ============= =============
The 2004 balance includes costs associated with the Rusocin and Sroda wells in
Poland and the East Inselberg well in Nevada.
Other Property and Equipment
Other property and equipment, including oilfield servicing equipment, are stated
at cost. Depreciation of other property and equipment is calculated using the
straight-line method over the estimated useful lives (ranging from 3 to 40
years) of the respective assets. The costs of normal maintenance and repairs are
charged to expense as incurred. Material expenditures that increase the life of
an asset are capitalized and depreciated over the estimated remaining useful
life of the asset. The cost of other property and equipment sold, or otherwise
disposed of, and the related accumulated depreciation are removed from the
accounts and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis
with accumulated depreciation, is summarized as follows:
December 31, Estimated
---------------------------- Useful Life
2004 2003 (in years)
------------- ------------- -------------
(In thousands)
Other property and equipment:
Drilling rigs.................................................. $ 2,279 $ 2,216 6
Other vehicles................................................. 922 887 5
Building....................................................... 96 96 40
Office equipment and furniture................................. 695 399 3 to 6
------------- -------------
Total cost..................................................... 3,992 3,598
Accumulated depreciation (3,286) (2,908)
------------- -------------
Net property and equipment................................. $ 706 $ 690
============= =============
F-11
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Supplemental Disclosure of Cash Flow Information
Noncash investing and financing transactions not reflected in the consolidated
statements of cash flows include the following:
Year Ended December 31,
-----------------------------------
2004 2003 2002
----------- ----------- ----------
(In thousands)
Noncash investing transactions:
Additions to properties included in current liabilities................ $ 1,076 $ 2,145 $ 851
Additions to properties previously included in other and current assets 490 -- --
----------- ----------- -----------
Total.............................................................. $ 1,566 $ 2,145 $ 851
=========== =========== ===========
Noncash financing transactions:
Conversion of note payable and accrued interest into common stock...... $ -- $ 3,594 $ --
----------- ----------- -----------
Total.............................................................. $ -- $ 3,594 $ --
=========== =========== ===========
Supplemental disclosure of cash paid for interest and income taxes:
Year Ended December 31,
-----------------------------------
2004 2003 2002
----------- ----------- ----------
(In thousands)
Supplemental disclosure:
Cash paid during the year for interest................................ $ -- $ 475 $ 1
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.
Investments
The cost and estimated market value of marketable securities at December 31,
2004, are as follows:
Gross Estimated
Unrealized Market
Cost Losses Value
----------------- ----------------- ----------------
Marketable securities.............................. $ 32,660,495 $ (339,296) $ 32,321,199
================= ================= ================
The investments consist primarily of U.S. government agency bonds and notes,
whose value fluctuates with changes in interest rates. The investments decreased
in value during the year ended December 31, 2004. The Company believes the gross
unrealized losses are temporary. The investments have been classified as
available-for-sale, and are reported at fair value with unrealized gains and
losses, if any, recorded as a component of other comprehensive income (loss).
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-12
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
As of December 31, 2004, the Company had 3,851,733 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 employee
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:
2004 2003 2002
------------- ------------- -------------
(In thousands, except per share amounts)
Net loss:
Net loss, as reported.............................................. $ (12,620) $ (2,933) $ (5,925)
Add: stock-based employee compensation expense included in
reported net loss, net of any related tax effects................ 5,820 -- 55
Less: Total stock-based employee compensation expense
determined under the fair value based method for all awards,
net of any related tax effects................................... (1,412) (907) (1,125)
------------- ------------- -------------
Pro forma net loss............................................ $ (8,212) $ (3,840) $ (6,995)
============= ============= =============
Basic and diluted net loss per share:
As reported................................................... $ (0.41) $ (0.41) $ (0.34)
Pro forma..................................................... (0.27) (0.46) (0.40)
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 2004,
2003 and 2002 was 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 2004, 70% for 2003
and 90% for 2002; (2) expected lives ranging from three to seven years; (3)
risk-free interest rates at the date of grant ranging from 2.21% to 4.24%; and,
(4) dividend yield of zero for each year.
During the second quarter of 2004, two of the Company's officers exercised
options to acquire a total of approximately 650,000 shares of FX Energy common
stock at an exercise price of $3.00 per share, by canceling options to purchase
approximately 350,000 shares and applying the option equity to pay the exercise
price on the options exercised. The ten-year options were due to expire during
the second quarter. In connection with this cashless exercise, the Company
recorded a stock compensation charge of approximately $5.8 million, which is
equal to the difference between the exercise price and fair value of the options
on the date of exercise, and a corresponding increase in additional paid-in
capital. This noncash transaction had no impact on the Company's working
capital, cash flows or stockholders' equity.
New Accounting Standards
In January 2003, the Financial Accounting Standard Board ("FASB") issued
Interpretation No. 46 ("FIN No. 46"), "Consolidation of Variable Interest
Entities." FIN No. 46 clarifies the application of Accounting Research Bulletin
No. 51 ("ARB No. 51"), "Consolidated Financial Statements," and addresses
consolidation by business enterprises of variable interest entities (more
commonly known as Special Purpose Entities). In December 2003, FASB issued FIN
No. 46R, which replaced FIN No. 46 and clarified ARB No. 51. This interpretation
provides guidance on how to identify a variable interest entity and determine
when the assets, liabilities, noncontrolling interests and results of operations
of a variable interest entity should be consolidated by the primary beneficiary.
FIN No. 46R requires the consolidation of variable interest entities in which
the Company is the primary beneficiary. As of January 1, 2004, the Company did
not own an interest in any variable interest entities that met the consolidation
requirements of FIN No. 46R and as such the adoption of FIN No. 46R did not have
any effect on the Company's financial position or results of operations. New
interests in entities acquired or created will be evaluated based on FIN No. 46R
criteria and consolidated, if required.
F-13
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
In December 2004, the FASB issued a revision to SFAS No. 123, "Accounting for
Stock-Based Compensation," SFAS No. 123-R, "Share-Based Payment." SFAS No. 123-R
focuses primarily on transactions in which an entity exchanges its equity
instruments for employee services and generally establishes standards for the
accounting for transactions in which an entity obtains goods or services in
share-based payment transactions. The Company expects to adopt SFAS No. 123-R
effective July 1, 2005, using the modified prospective application with no
restatement of prior interim periods. During the second half of 2005, the
Company expects to record compensation expense of approximately $1,000,000 in
connection with the adoption of SFAS No. 123-R, based on existing unvested
options as of December 31, 2004.
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.
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 primarily 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 applicable to
common shares by the weighted average number of common shares outstanding.
Diluted earnings per share is computed by dividing the net loss by the sum of
the weighted average number of common shares and the effect of dilutive
unexercised stock options and warrants and convertible preferred stock or debt.
Outstanding options and warrants as of December 31, 2004, 2003 and 2002, were as
follows:
Options and Warrants Price Range
-------------------------- -------------------
Balance sheet date:
December 31, 2004............ 7,405,106 $2.40 - $ 9.00
December 31, 2003............ 11,025,827 $1.50 - $10.25
December 31, 2002............ 5,544,017 $1.50 - $10.25
The Company had a net loss in 2004, 2003 and 2002. The above options and
warrants, as well 1,000,000 shares of common stock that could have been issued
under a third-party note payable during 2003 and 2002, were not included in the
computation of diluted earnings per share for the years presented because the
effect would have been antidilutive.
F-14
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Note 2: Asset Retirement Obligation
In August 2001, the FASB issued Statement No. 143 (SFAS No. 143), "Accounting
for Asset Retirement Obligations." The Company adopted SFAS No. 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 No.
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 No. 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 No. 143, the Company
recorded accretion expense of $41,000 and $37,000 in 2004 and 2003,
respectively.
At the time of adoption and at December 31, 2004, there were 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 No. 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, was approximately $322,000.
Following is a reconciliation of the yearly changes in the asset retirement
obligation at December 31, 2004 and 2003 (in thousands):
Year ended December 31.................................... 2004 2003
---- ----
Asset retirement obligation at January 1.................. $383 $ --
Obligation arising from adoption of SFAS 143.............. -- 347
Liabilities settled....................................... (10) --
Accretion expense......................................... 41 36
--------- --------
Asset retirement obligation as of December 31............. $414 $383
========= ========
Note 3: Other Assets
As of December 31, 2004 and 2003, 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
exceeded an agreed upon target amount. The total deposit amount was reclassified
from other assets to proved property costs in 2004.
F-15
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Note 4: Accrued Liabilities
The Company's accrued liabilities as of December 31, 2004 and 2003, were
comprised of the following:
December 31,
----------------------------
2004 2003
------------- -------------
(In thousands)
Accrued liabilities:
Exploratory dry hole costs.................... $ 880 $ 880
Drilling costs................................ 172 172
Geological and geophysical costs.............. 269 172
Other costs................................... 235 254
------------- -------------
Total..................................... $ 1,556 $ 1,306
============= =============
The liability for exploratory dry hole costs and drilling costs is payable to
the Polish Oil and Gas Company (POGC), and represents costs incurred in prior
years that were to be settled pursuant to the Company's 2003 settlement
agreement. See Note 6.
Note 5: Notes Payable
On March 9, 2001, the Company signed a $5.0 million, 9.5% convertible secured
note and gas purchase option agreement with Rolls Royce Power Ventures ("RRPV").
The proceeds from the note were used for exploration and development of
additional gas reserves in Poland. The note was interest free for the first
year. In consideration for the note 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
note, the entire principal amount plus accrued interest was due on or before
March 9, 2003, unless RRPV elected to convert the note 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 note, 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, which was 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.
The amendment agreement 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.
F-16
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
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 note 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 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 $16.0 million
commitment with POGC as part of a settlement agreement. In connection with this
agreement, the Company agreed to recognize and pay to POGC at a future date an
additional $2,306,627 of costs related to prior exploration activities in the
Fences I area, $1,602,902 of which will be credited towards the $16.0 million
commitment. The $2,306,627 was recorded as an accrued liability, net of accounts
receivable from POGC, at December 31, 2002. As part of its future payments, the
Company agreed in 2003 to assign to POGC 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 was
to be further offset by the value of the remaining gas reserves associated with
the Kleka well, as determined by an independent engineer. 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%, and POGC stopped accruing interest on December 31,
2003.
During 2003, the Company paid a total of $2,916,003 in cash to POGC and recorded
a $190,000 value-added tax (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.
During 2004, total qualifying costs incurred on the Fences I project area
exceeded the Company's prior remaining commitment. These included costs for the
Rusocin-1 well, the Zaniemysl-3 well, and other geological and geophysical costs
incurred in the project area. The Company has now earned its 49% interest, and
POGC is now obligated to pay its 51% share of all qualifying project costs.
Due to the fact that the Company has exceeded its $16.0 million commitment, it
has elected not to assign the Kleka 11 well to POGC. This election will be the
subject of an amendment to the Company's 2003 settlement agreement, which the
Company expects will be finalized in the first half of 2005. At that time, the
Company expects it will be required to pay approximately $1.3 million in cash to
POGC to settle its remaining unpaid liability, offset by its share of gas
production from the Kleka 11 well that occurred in 2003 and 2004, which is
approximately $250,000, and any overpayment relating to the $16.0 million earn
in. The Company would then begin recognizing its share of 2005 gas sales from
the Kleka 11 well. The Company will recognize a gain or loss on the settlement
equal to the difference between the recorded liability of $1.1 million and the
actual cash payment.
F-17
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Note 7: Income Taxes
The Company recognized no income tax benefit from the losses generated during
2004, 2003 and 2002. The components of the net deferred tax asset as of December
31, 2004 and 2003, are as follows:
December 31,
----------------------------
2004 2003
------------- -------------
(In thousands)
Deferred tax liability:
Property and equipment basis differences...................................... $ (1,219) $ (338)
Deferred tax asset:
Net operating loss carryforwards:
United States............................................................. 18,719 13,175
Poland.................................................................... 6,980 4,353
Oil and gas properties........................................................ 1,855 1,855
Options issued for services................................................... 143 578
Asset retirement obligation................................................... 155 143
Valuation allowance........................................................... (26,633) (19,766)
------------- -------------
Total..................................................................... $ -- $ --
============= =============
The change in the valuation allowance during 2004, 2003 and 2002 is as follows:
Year Ended December 31,
---------------------------------------------
2004 2003 2002
------------- ------------- ---------------
(In thousands)
Valuation allowance:
Balance, beginning of year..................................... $ (19,766) $ (18,744) $ (17,089)
Decrease due to property and equipment basis differences....... 881 -- (577)
Increase due to net operating loss............................. (8,171) (828) (632)
Other.......................................................... 423 (194) (446)
------------- ------------- ---------------
Total...................................................... $ (26,633) $ (19,766) $ (18,744)
============= ============= ===============
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, 2004 and 2003.
United States NOL
At December 31, 2004, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $50,184,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and $31,435,000 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 $14,392,000 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.
F-18
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Polish NOL
As of December 31, 2004, the Company had NOL carryforwards in Poland totaling
approximately $18,172,000, including $7,752,261, $345,516 and $882,262 generated
in 2004, 2003 and 2002, respectively. The NOL carryforwards may be carried
forward five years in Poland. However, no more than 50% 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,
-------------------------------------------
2004 2003 2002
------------- ------------- -------------
(In thousands)
Domestic.................... $ (9,107) $ (1,820) $ (3,570)
Foreign..................... (3,513) (1,113) (2,355)
------------- ------------- -------------
Total................... $ (12,620) $ (2,933) $ (5,925)
============= ============= =============
Note 8: Stockholders' Equity
The Company completed a registered offering during April of 2004 of 2,152,778
shares of common stock, resulting in proceeds of $14,348,298, net of offering
costs of $1,151,704. In August of 2004, the Company placed privately an
additional 950,000 shares of registered stock, resulting in proceeds of
$6,375,286 net of offering costs of $464,714.
During 2004, warrant holders exercised warrants for 2,687,937 shares of common
stock, resulting in proceeds to the Company of $10,079,763. In addition, option
holders paid cash to exercise 553,701 shares of common stock, resulting in
proceeds of $2,987,383.
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 net of 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, net of 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.
In December 2003, the Company sold 2,362,051 shares of common stock, raising a
total of $9,119,012, net of offering costs of $571,009.
F-19
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
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, 2004:
Weighted
Average Number of
Number of Exercise Options
Shares Price of Available
Authorized Outstanding for Future
Under Plan Options Issuance
-------------- --------------- -------------
Equity compensation plans approved by stockholders:
1995 Stock Option and Award Plan................................ 500,000 $ 7.28 11,500
1996 Stock Option and Award Plan................................ 500,000 3.96 53,833
1997 Stock Option and Award Plan................................ 500,000 8.29 8,234
1998 Stock Option and Award Plan................................ 500,000 6.19 --
1999 Stock Option and Award Plan................................ 500,000 4.24 4,000
2000 Stock Option and Award Plan................................ 600,000 2.51 10,667
2001 Stock Option and Award Plan................................ 600,000 3.14 7,332
2003 Long Term Incentive Plan................................... 800,000 6.65 34,000
2004 Long Term Incentive Plan................................... 1,000,000 8.37 825,000
-------------- -------------
Total......................................................... 5,500,000 $ 5.47 954,566
============== =============== =============
The above table excludes 80,000 options that have been granted outside of
stockholder approved option plans.
All stock option and award plans are administered by a committee (the
"Committee") consisting of members of the board of directors. At its discretion,
the Committee may grant stock, incentive stock options ("ISOs") or non-qualified
options to any employee, including officers. In addition to the options granted
under the stock option plans, the Company also issues non-qualified options
outside the stock option plans. The granted options have terms ranging from five
to seven years and vest over periods ranging from the date of grant to three
years. Under terms of the stock option award plans, the Company may also issue
restricted stock.
The following table summarizes fixed option activity for 2004, 2003 and 2002:
2004 2003 2002
-------------------------- ------------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Options Price Options Price Options Price
------------- ----------- ------------ ------------ ------------- ------------
Fixed options outstanding:
Beginning of year......... 4,784,517 $ 4.42 4,544,017 $ 4.68 4,785,585 $ 4.87
Granted................... 1,040,000 8.38 785,000 3.97 551,000 2.40
Exercised................. (1,743,701) 4.16 -- -- (3,000) 1.50
Canceled.................. (53,083) 4.26 (10,000) 4.66 (114,568) 6.00
Expired................... (176,000) 7.75 (534,500) 7.50 (675,000) 2.61
------------- ------------ -------------
End of year........... 3,851,733 $ 5.47 4,784,517 $ 4.42 4,544,017 $ 4.68
============= ============ =============
Exercisable at year-end....... 2,124,731 $ 4.67 3,474,270 $ 4.84 3,515,867 $ 5.41
============= ============ =============
F-20
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
The weighted average fair value per share of options granted during 2004, 2003
and 2002 was $4.00, $1.90 and $1.80, respectively.
The following table summarizes information about fixed stock options outstanding
as of December 31, 2004:
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......... 513,999 4.62 $ 2.40 336,663 $ 2.40
$2.44 - $2.44......... 368,734 3.93 2.44 368,734 2.44
$3.14 - $3.98......... 766,000 5.84 3.92 253,334 3.92
$4.06 - $4.06......... 366,000 2.80 4.06 366,000 4.06
$5.75 - $7.38......... 438,000 1.91 5.88 428,000 5.88
$8.37 - $8.37......... 952,000 6.67 8.37 -- --
$8.63 - $9.00......... 447,000 1.75 8.69 372,000 8.63
--------------- ---------------
Total.......... 3,851,733 4.49 $ 5.47 2,124,731 $ 4.67
=============== ===============
Warrants
The following table summarizes warrant activity for during 2004, 2003 and 2002:
2004 2003 2002
----------------------------- ------------------------------- --------------------------
Number of Price Number of Price Number of Price
Shares Range Shares Range Shares Range
------------ -------------- -------------- ---------------- ------------ -------------
Warrants outstanding and
exercisable:
Beginning of year... 6,241,310 $3.60--$3.75 -- -- 100,000 $ 3.00
Issued.............. -- -- 6,241,310 $3.60--$3.75
Exercised........... (2,687,937) $3.75 -- -- -- --
Expired............. -- -- -- -- (100,000) $ 3.00
------------ -------------- ------------
End of year..... 3,553,373 $3.60--$3.75 6,241,310 $3.60--$3.75 -- --
============ ============== ============
Note 10: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2004 and 2003 is as follows:
Quarter Ended
---------------------------------------------------------------------------
December 31 September 30 June 30 March 31
----------------- ------------------ ------------------ -----------------
(In thousands, except per share amounts)
2004:
Revenues....................... $ 1,199 $ 970 $ 750 $ 887
Net operating loss............. (2,695) (1,571) (7,831) (1,052)
Net loss....................... (2,449) (1,405) (7,736) (1,030)
Basic and diluted net loss per
common share................. $ (0.07) $ (0.05) $ (0.25) $ (0.04)
2003:
Revenues....................... $ 575 $ 602 $ 530 $ 621
Net operating loss............. (1,973) (654) (866) (488)
Net (loss) income.............. (2,053) (866) (1,106) 1,092
Basic and diluted net loss per
common share................. $ (0.28) $ (0.04) $ (0.05) $ 0.05
F-21
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
The net operating loss for the fourth quarter of 2004 includes $471,833 in dry
hole costs associated with the abandonment of the Tuchola 108 well. The net
operating loss for the fourth quarter of 2003 includes $160,886 in oil and gas
property impairment costs.
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 2004 and the second half of 2003. From July 2002 to June
2003, over 85% of the Company's oil sales were to Plains Marketing Canada, LP.
Over 85% of the Company's oil sales were to Cenex during the first half of 2002.
During 2002, all of the Company's oil and gas sales in Poland were to POGC.
There were no oil and gas sales in Poland during 2004 and 2003. The Company
believes the purchasers of its oil and gas production in the United States 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 proved property 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-22
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Information on the Company's operations by business segment for 2004, 2003 and
2002 is summarized as follows:
2004
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues(1).................................................... $ 3,096 $ 710 $ 3,806
Operating costs(2)............................................. (4,999) (551) (5,550)
DD&A expense................................................... (259) (290) (549)
------------- ------------- -------------
Operating loss................................................ $ (2,162) $ (131) $ (2,293)
============= ============= =============
Identifiable net property and equipment:
Unproved properties - Poland................................... $ 308 $ -- $ 308
Unproved properties - Domestic................................. 47 -- 47
Proved properties - Poland..................................... 10,436 -- 10,436
Proved properties - Domestic................................... 3,336 -- 3,336
Equipment and other............................................ -- 379 379
------------- ------------- -------------
Total...................................................... $ 14,127 $ 379 $ 14,506
============= ============= =============
Net Capital Expenditures:
Property and equipment(3) $ 9,513 $ 99 $ 9,612
------------- ------------- -------------
Total...................................................... $ 9,513 $ 99 $ 9,612
============= ============= =============
- --------------------
(1) All E&P revenues were generated in the United States.
(2) E&P operating costs include $2,536,000 in geological and geophysical costs,
$472,000 in dry hole costs, $36,000 in lease operating costs, and $471,000
in general and administrative costs incurred in Poland.
(3) E&P property and equipment expenditures include $8,744,000 in proved
property costs and $141,000 in unproved property costs in Poland.
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(3) $ 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 oil and gas 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.
(3) E&P property and equipment expenditures include $191,000 in unproved
property costs in Poland.
F-23
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
2002
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues(1).................................................... $ 2,209 $ 533 $ 2,742
Operating costs(2)............................................. (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(3) $ 1,012 $ 116 $ 1,128
------------- ------------- -------------
Total...................................................... $ 1,012 $ 116 $ 1,128
============= ============= =============
- --------------------
(1) E&P revenues include $1,924,000 generated in the United States and $285,000
generated in Poland.
(2) E&P 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.
(3) E&P includes $418,000 of pipeline costs and $586,000 of proved property
additions incurred in Poland and $8,000 of unproved property additions in
the United States.
A reconciliation of the segment information to the consolidated totals for 2004,
2003 and 2002 follows:
2004 2003 2002
------------- ------------- -------------
(In thousands)
Revenues:
Reportable segments...............................................$ 3,806 $ 2,328 $ 2,742
Non-reportable segments........................................... -- -- --
------------- ------------- -------------
Total revenues...................................................$ 3,806 $ 2,328 $ 2,742
============= ============= =============
Net loss:
Reportable segments...............................................$ (2,293) $ (715) $ (2,330)
Expense or (revenue) adjustments:
Corporate DD&A expense.......................................... (88) (13) (27)
Amortization of deferred compensation (G&A)..................... -- -- (55)
General and administrative costs (G&A).......................... (4,909) (3,253) (2,443)
Stock compensation (G&A)........................................ (5,859) -- --
------------- ------------- -------------
Total net operating loss...................................... (13,149) (3,981) (4,855)
Non-operating income (loss)..................................... 529 (752) (1,070)
Cumulative effect of change in accounting principle............. -- 1,800 --
------------- ------------- -------------
Net loss.................................................$ (12,620) $ (2,933) $ (5,925)
============= ============= =============
Net property and equipment:
Reportable segments...............................................$ 14,506 $ 4,948 $ 3,833
Corporate assets.................................................. 328 125 73
------------- ------------- -------------
Net property and equipment.......................................$ 14,834 $ 5,073 $ 3,906
============= ============= =============
Property and equipment capital expenditures:
Reportable segments...............................................$ 9,612 $ 202 $ 1,128
Corporate assets.................................................. 296 63 2
------------- ------------- -------------
Total property and equipment capital expenditures................$ 9,908 $ 265 $ 1,130
============= ============= =============
F-24
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
-Continued-
Note 12: Gain Contingency
Throughout the Company's operating history in Poland, it has been unable to
obtain a refund of most of the value added taxes paid in connection with goods
and services purchased (Input VAT). Polish tax laws have restricted the refund
of Input VAT for exploration activities to concession holders. In the Company's
case, POGC has traditionally been the concession holder, while the Company is a
working interest owner by virtue of its agreements with POGC.
During 2004, Poland joined the European Union. In connection with this activity,
certain tax laws have changed, and the Company believes it may now be entitled
to obtain a refund of some or all of the Input VAT paid since 1998, which totals
approximately $3.2 million at year-end exchange rates.
The Company is preparing the necessary forms to file with appropriate Polish tax
authorities to reclaim the Input VAT in question. The review and refund process
may take up to 180 days from the date the refund application is filed. Should
the Company be successful in reclaiming its historical Input VAT, the Company
would reduce capital costs for the related Input VAT, and record a gain for the
Input VAT related to past geological, geophysical, and other costs.
Note 13: Subsequent Event
In connection with its exit from Poland, on January 31, 2005, Apache Corporation
relinquished its 45% working interest in the Wilga area, which then reverted to
the Company and POGC ratably by virtue of the Company's existing agreements with
POGC and Apache. Accordingly, on that date the Company's working interest
increased from 45% to 81.18%, which in turn increased the Company's total proved
gas reserves by approximately 22% and total proved oil reserves by approximately
10%.
F-25
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
Disclosure about Oil and Gas Properties and Producing Activities (unaudited)
Capitalized Oil and Gas Property Costs
Capitalized costs relating to oil and gas exploration and production activities
as of December 31, 2004 and 2003, are summarized as follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
December 31, 2004:
Proved properties..........................................$ 4,676 $ 10,898 $ 15,574
Unproved properties........................................ 47 308 355
--------------- --------------- ---------------
Total gross properties................................... 4,723 11,206 15,959
Less accumulated depreciation, depletion and amortization.. (1,340) (462) (1,802)
--------------- --------------- ---------------
$ 3,383 $ 10,744 $ 14,127
=============== =============== ===============
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)
--------------- --------------- ---------------
$ 3,014 $ 1,369 $ 4,383
=============== =============== ===============
Results of Operations
Results of operations are reflected in Note 11, 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 2004, 2003 and
2002 were $1,945,766, $1,545,913 and $1,365,454, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities
during 2004, 2003 and 2002, whether capitalized or expensed, are summarized as
follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
Year ended December 31, 2004:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
Unproved............................................... 40 141 181
Exploration costs.......................................... 103 11,752 11,855
Development costs.......................................... 490 -- 490
--------------- --------------- ---------------
Total..................................................$ 633 $ 11,893 $ 12,526
=============== =============== ===============
Year ended December 31, 2003:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
Unproved............................................... -- 20 20
Exploration costs.......................................... -- 523 523
Development costs.......................................... 191 -- 191
--------------- --------------- ---------------
Total..................................................$ 191 $ 543 $ 734
=============== =============== ===============
F-26
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
United States Poland Total
--------------- --------------- ---------------
(In thousands)
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
=============== =============== ===============
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:
2004 2003 2002
---- ---- ----
Proved........................... $ -- $ 160,886 $ 1,038,362
Unproved......................... -- -- 509,498
--------------- ---------------- --------------
Total.......................... $ -- $ 160,886 $ 1,547,860
=============== ============ ============
Exploratory dry hole costs
During 2004, the Company plugged and abandoned the Tuchola 108-2 well, incurring
dry hole costs of $471,883. There were no dry hole costs in 2003 and 2002.
Summary Oil and Gas Reserve Data (Unaudited)
Estimated Quantities of Proved Reserves
Proved reserves are the estimated quantities of crude oil that geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reserves under existing economic and operating
conditions. 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, 2004, of $36.69 per bbl for oil in the
United States and $35.39 per bbl of oil and $1.91 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.
F-27
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
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, 2004................................ 809 -- -- 1,011
December 31, 2003................................ 991 -- -- 1,116
December 31, 2002................................ 1,015 -- -- 1,374
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, 2004:
Beginning of year........................ 991 114 -- 3,960
Extensions or discoveries................ -- -- -- 6,342
Revisions of previous estimates.......... (97) (3) -- (104)
Production............................... (85) -- -- --
--------------- --------------- --------------- ---------------
End of year.......................... 809 111 -- 10,198
=============== =============== =============== ===============
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
=============== =============== =============== ===============
F-28
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--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 future net cash
flows for the Company's Polish reserves are based on a gas and condensate sales
contract the Company has with POGC.
The components of SMOG are detailed below:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
December 31, 2004:
Future cash flows..........................................$ 29,670 $ 24,145 $ 53,815
Future production costs.................................... (21,779) (1,304) (23,083)
Future development costs................................... (1) (2,780) (2,781)
Future income tax expense.................................. -- -- --
--------------- --------------- ---------------
Future net cash flows ..................................... 7,890 20,061 27,951
10% annual discount for estimated timing of cash flows..... (2,756) (6,970) (9,726)
--------------- --------------- ---------------
Discounted net future cash flows...........................$ 5,134 $ 13,091 $ 18,225
=============== =============== ===============
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
=============== =============== ===============
F-29
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
The principal sources of changes in SMOG are detailed below:
Year Ended December 31,
--------------------------------------------
2004 2003 2002
------------- ------------- --------------
(In thousands)
SMOG sources:
Balance, beginning of year...................................... $ 9,856 $ 10,220 $ 5,586
Sale of oil and gas produced, net of production costs........... (1,150) (732) (843)
Net changes in prices and production costs...................... 3,816 607 4,890
Extensions and discoveries, net of future costs................. 4,135 -- --
Changes in estimated future development costs................... (638) (321) (251)
Previously estimated development costs incurred during the year. 588 191 586
Revisions in previous quantity estimates........................ (211) 26 270
Accretion of discount........................................... 986 1,022 559
Net change in income taxes...................................... -- -- --
Changes in rates of production and other........................ 843 (1,157) (577)
------------- ------------- --------------
Balance, end of year........................................ $ 18,225 $ 9,856 $ 10,220
============= ============= ==============
F-30