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, 2005
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 if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or 15(d) of the Act. Yes [ ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act 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 a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes [ ] No [X]
State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity, as of
the last business day of the registrant's most recently completed second fiscal
quarter. As of June 30, 2005, the aggregate market value of the voting and
nonvoting common equity held by nonaffiliates of the registrant was
$373,225,000.
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 3, 2006, FX Energy
had outstanding 35,097,279 shares of its common stock, par value $0.001.
DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy Statement in
connection with the 2006 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, 2005
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TABLE OF CONTENTS
Item Page
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Part I
-- Special Note on Forward-Looking Statements........................ 3
1 Business.......................................................... 4
1A Risk Factors...................................................... 8
1B Unresolved Staff Comments......................................... 14
2 Properties........................................................ 15
3 Legal Proceedings................................................. 24
4 Submission of Matters to a Vote of Security Holders............... 24
Part II
5 Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities....................... 25
6 Selected Financial Data........................................... 26
7 Management's Discussion and Analysis of Financial Condition and
Results of Operation............................................ 28
7A Quantitative and Qualitative Disclosures about Market Risk........ 35
8 Financial Statements and Supplementary Data....................... 36
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................ 36
9A Controls and Procedures........................................... 36
9A Other Events...................................................... 36
Part III
10 Directors and Executive Officers of the Registrant................ 37
11 Executive Compensation............................................ 37
12 Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters................................. 37
13 Certain Relationships and Related Transactions.................... 37
14 Principal Accountant Fees and Services............................ 37
Part IV
15 Exhibits and Financial Statement Schedules........................ 38
-- Signatures........................................................ 42
-- 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 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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ITEM 1. BUSINESS
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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. 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.
We hold approximately 1.7 million gross acres in western Poland's
Permian Basin where the gas-bearing Rotliegend sandstone reservoir rock is, in
our opinion, 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 the Polish Oil and Gas Company ("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 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 through the application of new exploration technology.
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 bring to bear exploration technology that has not previously
been applied to the area and carry out the work necessary to
advance these properties toward exploration drilling,
including collecting, evaluating and reprocessing seismic
data, acquiring new seismic 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 market
interests in these properties to industry participants on
terms that will provide all or a portion of the funds
necessary for exploration.
Our primary strategic relationship is with POGC, a fully integrated oil
and gas company primarily owned by the Treasury of the Republic of Poland, which
is Poland's principal domestic oil and gas exploration and production entity.
Under our existing agreements, POGC has provided us with access to exploration
opportunities, previously-collected exploration data, and technical and
operational support.
Our chief technical advisor is Richard Hardman, CBE, who 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 of Exploration, he was
responsible for key Amerada North Sea and international discoveries, including
the 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
4
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 is Chairman of our Technical and
Advisory Panel.
Our Country Manager in Poland is Zbigniew Tatys, the former General
Director of POGC's Upstream Exploration and Production Division. During his
20-year career with POGC, he rose through the ranks as a production engineer and
was serving as Vice Chairman of POGC at the time of his retirement. Mr. Tatys
has unique qualifications to lead us through our transition from a pure
exploration company to a natural gas producer in Poland.
Project Area Summary
Our ongoing activities in Poland are conducted in four project areas:
Fences I, II and III, and Wilga. Our exploration activities are currently
focused primarily on the three Fences project areas, where we believe the
gas-bearing Rotliegend sandstone reservoir rock in Poland's Permian Basin is a
direct analog to the Southern North Sea gas basin offshore England. We are
focused on the Fences area because there have been substantial gas reserves
developed and produced by POGC in this Rotliegend trend, and we have concluded
that there are likely to be substantial additional gas reserves in the same
horizons that can be identified through the application of geophysical
techniques that have not previously been applied in this area in Poland.
Fences
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 Rotliegend sandstone reservoirs. We
entered into an agreement in 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. We entered into an agreement in 2003 with
POGC to explore this area and by December 31, 2004, had spent $4.0 million on
exploration costs in the Fences II project area to earn a 49% interest.
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 Rotliegend 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 Rotliegend
sandstone. To our knowledge, no exploration program focused on Rotliegend 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 Rotliegend gas fields in the last 20 years.
During the balance of 2006, our objectives with respect to the Fences
areas are to:
o continue the work of developing a complete subsurface seismic
and geological picture of the productive horizons across our
entire acreage, in the process building an inventory of
drill-ready prospects;
o drill up to seven wells in 2006, including the Drozdowice-1
well, subject to the results of drilling and seismic
interpretation and to the exploration priorities of our
partner, POGC;
o build the necessary infrastructure to begin producing our
Zaniemysl discovery and begin planning for production from the
Sroda-4 well and other 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.
5
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 an 82% working
interest and are the operator; POGC holds the remaining 18% working interest. We
successfully completed an extended flow test on the Wilga 2, confirming that the
well is capable of producing at a commercial rate. We are building production
facilities and a pipeline to place this well into commercial production in the
second half of 2006. Seismic interpretation is underway to determine if further
drilling is warranted either in the Wilga field or elsewhere in Block 255.
Exploration, Development and Production Activities
Polish Exploration Rights
As of December 31, 2005, 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. We have completed the $16.0
million earn-in requirement. As a result, POGC paid its 51% share of costs
during 2005. 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 Rotliegend 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
Rotliegend 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 each year since, we have acquired, processed and interpreted a substantial
amount of seismic data, with particular emphasis on utilizing acquisition,
processing and interpretation techniques that have been used successfully in the
Rotliegend gas fields of the southern United Kingdom Gas Basin.
6
In January 2003, we entered into a farmout agreement with CalEnergy Gas
(Holdings) Ltd., 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 all or a portion of the Fences I project area.
In February 2004, we completed the Zaniemysl-3 exploratory well in the
Fences I project area as a commercial well with proved reserves for the well
estimated at approximately 24 Bcf of gas. See Item 2. Properties: Proved
Reserves. Together with our partners, POGC and CalEnergy Gas, we are building
facilities and will connect to the pipeline grid through a pipeline being 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 in the second half
of 2006.
As a result of paying for the Zaniemysl-3 well, CalEnergy Gas earned a
24.5% interest in the approximately 45,000 acres surrounding the Zaniemysl field
referred to as the Greater Zaniemysl Area, or GZA.
Outside of the CalEnergy Gas GZA, during the second half of 2004, we
and POGC drilled the Rusocin-1 well, the first well intentionally focused on a
stratigraphic trap in the Rotliegend. In a January 2005 initial drill stem test,
the well flowed gas from an 8 meter (26 feet) section of the Rotliegend
sandstone target reservoir. The top of the Rotliegend 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 Rotliegend sandstone with 20-25% porosity.
During 2005, we drilled the Lugi-1 well southeast of the Rusocin-1
well. The Lugi-1 was another stratigraphic test of the pinch-out play, and was
determined to be noncommercial in December 2005. We are currently completing a
two-dimensional, or 2-D, seismic acquisition program over the prospective
pinch-out area of Fences I and anticipate completing our reinterpretation in the
second half of 2006, at which time we will decide when to drill another test of
the pinch-out play.
During the remainder of 2006, as we have done each year since 2002, 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 January 2003, we agreed to spend $4.0 million on exploration costs
in the Fences II project area to earn a 49% interest. We have completed the $4.0
million earn-in requirement. As a result, POGC paid its 51% share of costs
during 2005. See Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation: Introduction--Fences II Commitment, for
further information on how the commitment was satisfied.
The Rotliegend is the primary target horizon throughout most of the
Fences II project area, at depths from approximately 3,200 to 3,800 meters. 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 Rotliegend sandstone at a depth of more than 3,700 meters,
which we believe makes virtually the entire block prospective for Rotliegend,
subject to accurate geophysical resolution of the trapping features.
During 2003 and 2004, we reprocessed and interpreted several thousand
kilometers of 2-D seismic data to develop a more complete subsurface model of
the Rotliegend and Zechstein horizons. In the second half of 2004, we received
operating committee approval to drill the Sroda-4 prospect, a structural feature
modeled on POGC's Radlin field. Drilling operations resulted in a commercial
well in April 2005, with proved reserves of approximately 16 Bcf of gas. We plan
to begin sizing production facilities once we have a second successful well in
the Sroda area.
In September 2005, we began drilling another well, Sroda-5, into
another structure located about 4km east southeast of the Sroda-4 structure.
This well was determined to be noncommercial, largely due to cementation in the
top 15 meters of the otherwise porous Rotliegend sandstone. This kind of
cementation can be the result of faulting and our technical group is reviewing
new seismic data to determine whether to recommend drilling a near offset to
Sroda-5.
7
We have continued to acquire new seismic each year since 2003, with
particular attention to acquisition, processing and interpretation, endeavoring
to capitalize on advances developed in the Rotliegend gas fields of the southern
United Kingdom Gas Basin. We have identified several additional prospects in the
Sroda region, including Sroda City, Sroda Northwest and Winna Gora, and
anticipate drilling at least three wells in this area during 2006.
We have also identified other structural features outside this area and
we are continuing to work on interpretation and mapping throughout the Fences II
area. We believe the Fences II area, in general, and the Sroda area, in
particular, have potential for discoveries of large gas accumulations.
Fences III Project Area
Also in 2003 we acquired the Fences III project area with a 100%
interest. During the next two years, we reprocessed and interpreted several
thousand kilometers of existing seismic data covering approximately the northern
third of the Fences III project area, and in January 2006 began drilling our
first well, the Drozdowice-1. This well targeted a potential combination
reservoir of Zechstein limestone and Rotliegend sandstone at a total depth of
approximately 1400 meters. Upon reaching total depth, a drill stem test of the
target reservoir yielded no observable hydrocarbons. We plan to evaluate the
drilling data in conjunction with existing seismic data before pursuing
additional drilling in Fences III.
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, which
we anticipate will be in the second half of 2006. The Wilga well was drilled in
2000 and as of December 31, 2004, had gross proved reserves of 6.3 Bcf and
254,000 barrels of condensate. We are the operator of the Wilga project area and
own an 82% interest. POGC owns an 18% interest. During 2005 we began allocating
technical resources to the Wilga area in an effort to understand the two
noncommercial wells that were drilled following the commercially successful
Wilga-2 and to identify other potential targets in the Block. We anticipate
carrying out additional technical work during 2006.
Exploratory Activities in the United States
Nevada
During 2005, we drilled and abandoned three wildcat oil wells in
Railroad Valley, Nevada. In addition, we also plugged and abandoned another well
that had been drilled during late 2004. We plan to drill a small number of
exploratory wells again in 2006 on land that is near our existing producing
properties in Nevada. Our actual cash costs to drill each well is approximately
$100,000. We are able to achieve such low drilling costs due to an agreement
with our partner whereby it contributes drilling equipment and we contribute all
drilling labor, made up of our existing employees in Montana.
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ITEM 1A. RISK FACTORS
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Risk Factors
Our business is subject to a number of material risks, including, but
not limited to, the following factors related directly and indirectly to our
business activities in the United States and Poland.
8
Risks Relating to our Business
Our success depends largely on our discovery of economic quantities of
oil or gas in Poland.
We currently have a limited amount of production in the United States
and Poland. We do not currently generate sufficient revenues to cover our costs
of operation, including our exploration and general and administrative costs,
and will continue to rely on funds from external sources until we generate
sufficient revenue to cover these costs. Our exploration programs in Poland are
based on interpretations of geological and geophysical data. The factors listed
below, most of which are outside our control, may prevent us from establishing
additional commercial production or substantial reserves as a result of our
exploration, appraisal and development activities in Poland:
o we cannot assure that any future well will encounter
commercial quantities of oil or gas;
o there is no method to predict in advance of drilling and
testing whether any prospect encountering oil or gas will
yield oil or gas in sufficient quantities to cover drilling or
completion costs or to be economically viable;
o one or more appraisal wells may be required to confirm the
commercial potential of an oil or gas discovery;
o we may continue to incur exploration costs in specific areas
even if initial appraisal wells are plugged and abandoned or,
if completed for production, do not result in production of
commercial quantities of oil or gas; and
o drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, including operating problems
encountered during drilling, weather conditions, compliance
with governmental requirements, shortages or delays in the
delivery of equipment or availability of services, and other
factors.
We have limited control over our exploration and development activities
in Poland.
Our partner, POGC, holds the majority interest and is operator of our
two most important project areas and has a minority interest in a third project
area. As a paying partner, we rely to a significant extent on the financial
capabilities of POGC. If POGC were to fail to perform its obligations under
contracts with us, it would most likely have a material adverse effect on us. In
particular, we have prepared our exploration budget through 2006 based on the
participation of and funding to be provided by POGC. Although we have rights to
participate in exploration and development activities on some POGC-controlled
acreage, we have limited rights to initiate such activities. Further, we have no
direct interest in some of the underlying agreements, licenses and grants from
the Polish agencies governing the exploration, exploitation, development or
production of acreage controlled by POGC. Thus, our program in Poland involving
POGC-controlled acreage would be adversely affected if POGC should elect not to
pursue activities on such acreage, if the relationship between us and POGC
should deteriorate or terminate or if POGC or the governmental agencies should
fail to fulfill the requirements of or elect to terminate such agreements,
licenses or grants.
We cannot assure the exploration models we are using in Poland will
lead to finding oil or gas in Poland.
We cannot assure the exploration models we and POGC have developed will
provide a useful or effective guide for selecting exploration prospects and
drilling targets. We will have to revise or replace these exploration models as
a guide to further exploration if ongoing drilling results do not confirm their
validity. These exploration models may be based on incomplete or unconfirmed
data and theories that have not been fully tested. The seismic data, other
technologies, and the study of producing fields in the area do not enable us to
know conclusively prior to drilling that oil or gas will be present in
commercial quantities. We cannot assure that the analogies that we draw from
available data from other wells, more fully explored prospects, or producing
fields will be applicable to our drilling prospects.
9
We cannot accurately predict the size of exploration targets or foresee
all related risks.
Notwithstanding the accumulation and study of 2-D and 3-D seismic data,
drilling logs, production information from established fields, and other data,
we cannot predict accurately the oil or gas potential of individual prospects
and drilling targets or the related risks. Our predictions are only rough,
preliminary geological estimates of the forecasted volume and characteristics of
possible reservoirs and are not an estimate of reserves. In some cases, our
estimates may be based on a review of data from other exploration or producing
fields in the area that ultimately may be found not to be similar to our
exploration prospects. We may require several test wells and long-term analysis
of test data and history of production to determine the oil or gas potential of
individual prospects.
We have had limited exploratory success in Poland.
We have participated in drilling 21 exploratory wells in Poland,
including five exploratory successes (the Wilga 2, Kleka 11, Zaniemysl-3,
Sroda-4 and Rusocin-1), and sixteen exploratory dry holes. Of our five
exploratory successes in Poland, only the Kleka 11 well is currently producing.
Gas production is scheduled to commence in the second half of 2006 at Wilga 2
and Zaniemysl-3.
We may not achieve the results anticipated in placing our current or
future discoveries into production.
We may encounter delays in commencing the production and the sale of
gas in Poland, including our recent gas discoveries and other possible future
discoveries. The possible delays may include obtaining rights-of-way to connect
to the POGC pipeline system, obtaining construction permits, availability of
materials and contractors, the signing of an oil or gas purchase contract, and
other factors. Such delays would correspondingly delay the commencement of cash
flow and may require us to obtain additional short-term financing pending
commencement of production. Further, we may design proposed surface and pipeline
facilities based on possible estimated results of additional drilling. We cannot
assure that additional drilling will establish additional reserves or production
that will provide an economic return for planned expenditures for facilities. We
may have to change our anticipated expenditures if costs of placing a particular
discovery into production are higher, if the project is smaller, or if the
commencement of production takes longer than expected.
Privatization of POGC could affect our relationship and future
opportunities in Poland.
Our activities in Poland have benefited from our relationship with
POGC, which has provided us with exploration acreage, seismic data and
production data under our agreements. The Polish government commenced the
privatization of POGC by selling POGC"s refining assets. In late 2005, POGC
successfully completed an initial public offering on the Warsaw stock exchange,
and approximately 35% of POGC is now owned by the public and current and former
employees. Privatization may result in new policies, strategies or ownership
that could adversely affect our existing relationship and agreements, as well as
the availability of opportunities with POGC in the future.
We have a history of operating losses and may require additional
capital in the future to fund our operations.
From our inception in January 1989 through December 31, 2005, we have
incurred cumulative net losses of $68.5 million. We expect that our exploration
and production activities may continue to result in net losses and that our
accumulated deficit may increase. We anticipate that we will incur losses
through 2006 and possibly beyond, depending on whether our activities in Poland
and the United States result in sufficient revenues to cover related operating
expenses.
Until sufficient cash flow from operations can be obtained, we expect
we will need additional capital to fully fund our ongoing planned exploration,
appraisal, development and property acquisition programs in Poland. We have no
current arrangement for any such additional financing, but may seek required
funds from the issuance of additional debt or equity securities, project
financing, strategic alliances or other arrangements. Although we are currently
negotiating with commercial lenders to establish a credit facility, we can offer
no assurances that we will be able to obtain financing on acceptable or
favorable terms. Obtaining additional financing may dilute the interest of our
10
existing stockholders or our interest in the specific project being financed. We
cannot assure that additional funds could be obtained or, if obtained, would be
on terms favorable to us. In addition to planned activities in Poland, we may
require additional funds for general corporate purposes.
The loss of key personnel could have an adverse impact on our
operations.
We rely on our officers and key employees and consultants and their
expertise, particularly David N. Pierce, President and Chief Executive Officer;
Thomas B. Lovejoy, Chairman and Chief Financial Officer; Andrew W. Pierce,
Vice-President and Chief Operating Officer, Jerzy B. Maciolek, Vice-President of
Exploration, Zbigniew Tatys, Poland Country Manager, and Richard Hardman,
Director and Chairman of our technical committee. The loss of the services of
any of these individuals may materially and adversely affect us. We have entered
into employment agreements with our key executives. We do not maintain key-man
insurance on any of our employees.
The price we receive for gas we sell will likely be lower than free
market gas prices in western Europe.
Our limited number of wells and reserves means we cannot assure
uninterruptible supply in sufficient quantities to meet the anticipated
requirements of industrial users, so we currently are dependent on selling gas
to POGC at prices generally lower than prevailing in western Europe. The market
for the sale of gas in Poland is open to competition, but there are not yet many
participants. Accordingly, we expect that the prices we receive for the gas we
produce will be lower than would be the case in a fully competitive setting and
may be lower than prevailing western European prices, at least until a fully
competitive market develops in Poland or until we are able to assure potential
purchasers other than POGC that we have sufficient wells and reserves to assure
an uninterruptible supply in sufficient quantities. Further, there is no
established market relationship between gas prices in short-term and long-term
sales agreements. Notwithstanding the strong demand for gas in Poland, the
availability of abundant quantities of gas from former members of the Soviet
Union and the low cost of electricity from coal-fired generating facilities may
also tend to depress gas prices in Poland.
Oil and gas price decreases and volatility could adversely affect our
operations and our ability to obtain financing.
Oil and gas prices have been and are likely to continue to be volatile
and subject to wide fluctuations in response to the following factors:
o the market and price structure in local markets;
o changes in the supply of and demand for oil and gas;
o market uncertainty;
o political conditions in international oil and gas producing
regions;
o the extent of production and importation of oil and gas into
existing or potential markets;
o the level of consumer demand;
o weather conditions affecting production, transportation and
consumption;
o the competitive position of oil or gas as a source of energy,
as compared with coal, nuclear energy, hydroelectric power and
other energy sources;
o the availability, proximity and capacity of gathering systems,
pipelines and processing facilities;
o the refining and processing capacity of prospective oil or gas
purchasers;
o the effect of governmental regulation on the production,
transportation and sale of oil and gas; and
o other factors beyond our control.
11
We have not entered into any agreements to protect us from price fluctuations
and may or may not do so in the future.
Our industry is subject to numerous operating risks. Insurance may not
be adequate to protect us against all these risks.
Our oil and gas drilling and production operations are subject to
hazards incidental to the industry. These hazards include blowouts, cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution,
releases of toxic gas and other environmental hazards and risks. These hazards
can cause personal injury and loss of life, severe damage to and destruction of
property and equipment, pollution or environmental damage, and suspension of
operations. To lessen the effects of these hazards, we maintain insurance of
various types to cover our domestic operations. We cannot assure that the
general liability insurance of $10.0 million carried by us can continue to be
obtained on reasonable terms. POGC, as operator of the Fences project area, is
self-insured. We do not plan to purchase well control insurance on wells we
drill in the Fences project area and may elect not to purchase such insurance on
wells drilled in other areas in Poland as well. The current level of insurance
does not cover all of the risks involved in oil and gas exploration, drilling
and production. Where additional insurance coverage does exist, the amount of
coverage may not be sufficient to pay the full amount of such liabilities. We
may not be insured against all losses or liabilities that may arise from all
hazards because such insurance is unavailable at economic rates, because of
limitations on existing insurance coverage, or other factors. For example, we do
not maintain insurance against risks related to violations of environmental
laws. We would be adversely affected by a significant adverse event that is not
fully covered by insurance. Further, we cannot assure that we will be able to
maintain adequate insurance in the future at rates we consider reasonable.
Risks Relating to Conducting Business in Poland
Polish laws, regulations and policies may be changed in ways that could
adversely impact our business.
Our oil and gas exploration, development and production activities in
Poland are and will continue to be subject to ongoing uncertainties and risks,
including:
o possible changes in government personnel, the development of
new administrative policies, and practices and political
conditions in Poland that may affect the administration of
agreements with governmental agencies or enterprises;
o possible changes to the laws, regulations and policies
applicable to us and our partners or the oil and gas industry
in Poland in general;
o uncertainties as to whether the laws and regulations will be
applicable in any particular circumstance;
o uncertainties as to whether we will be able to enforce our
rights in Poland;
o uncertainty as to whether we will be able to demonstrate, to
the satisfaction of the Polish authorities, our and POGC's
compliance with governmental requirements respecting
exploration expenditures, results of exploration,
environmental protection matters, and other factors;
o the inability to recover previous payments to the Polish
government made under the exploration rights or any other
costs incurred respecting those rights if we were to lose or
cancel our exploration and exploitation rights at any time;
o political instability and possible changes in government;
o export and transportation tariffs;
o local and national tax requirements;
12
o expropriation or nationalization of private enterprises and
other risks arising out of foreign government sovereignty over
our acreage in Poland; and
o possible significant delays in obtaining opinions of local
authorities or satisfying other governmental requirements in
connection with a grant of permits to conduct exploration and
production activities.
Poland has a developing regulatory regime, regulatory policies and
interpretations.
Poland has a developing regulatory regime governing exploration and
development, production, marketing, transportation and storage of oil and gas.
These provisions were recently promulgated and are relatively untested.
Therefore, there is little or no administrative or enforcement history or
established practice that can aid us in evaluating how the regulatory regime
will affect our operations. It is possible that such governmental policies will
change or that new laws and regulations, administrative practices or policies or
interpretations of existing laws and regulations will materially and adversely
affect our activities in Poland. For example, Poland's laws, policies and
procedures were changed to conform to the requirements that had to be met before
Poland was admitted as a full member of the European Union.
Our oil and gas operations are subject to rapidly changing
environmental laws and regulations that could have a negative impact on
our operations.
Operations on our project areas are subject to environmental laws and
regulations in Poland that provide for restrictions and prohibitions on spills,
releases or emissions of various substances produced in association with oil and
gas exploration and development. Additionally, if significant quantities of gas
are produced with oil, regulations prohibiting the flaring of gas may inhibit
oil production. In such circumstances, the absence of a gas gathering and
delivering system may restrict production or may require significant
expenditures to develop such a system prior to producing oil and gas. We may be
required to prepare and obtain approval of environmental impact assessments by
governmental authorities in Poland prior to commencing oil or gas production,
transportation and processing functions.
We and our partners cannot assure that we have complied with all
applicable laws and regulations in drilling wells, acquiring seismic data or
completing other activities in Poland to date. The Polish government may adopt
more restrictive regulations or administrative policies or practices. The cost
of compliance with current regulations or any changes in environmental
regulations could require significant expenditures. Further, breaches of such
regulations may result in the imposition of fines and penalties, any of which
may be material. These environmental costs could have a material adverse effect
on our financial condition, results of operations, or cash flows in the future.
Certain risks of loss arise from our need to conduct transactions in
foreign currency.
The amounts in our agreements relating to our activities in Poland are
sometimes expressed and payable in United States dollars and sometimes in Polish
zlotys. Conversions between United States dollars and Polish zlotys are made on
the date amounts are paid or received. In the future, our financial results and
cash flows in Poland may be affected by fluctuations in exchange rates between
the Polish zloty and the United States dollar. We have not hedged our foreign
currency activities in the past and do not plan to do so. Currencies used by us
may not be convertible at satisfactory rates. In addition, the official
conversion rates between United States and Polish currencies may not accurately
reflect the relative value of goods and services available or required in
Poland. Further, inflation may lead to the devaluation of the Polish zloty.
Risks Related to an Investment in our Common Stock
Our stockholder rights plan and bylaws discourage unsolicited takeover
proposals and could prevent our stockholders from realizing a premium
on our common stock.
We have a stockholder rights plan that may have the effect of
discouraging unsolicited takeover proposals. The rights issued under the
stockholder rights plan would cause substantial dilution to a person or group
13
that attempts to acquire us on terms not approved in advance by our board of
directors. In addition, our articles of incorporation and bylaws contain
provisions that may discourage unsolicited takeover proposals that our
stockholders may consider to be in their best interests that include:
o provisions that members of the board of directors are elected
and retire in rotation; and
o the ability of the board of directors to designate the terms
of, and to issue new series of, preferred shares.
Together, these provisions and our stockholder rights plan may discourage
transactions that otherwise could involve payment to our stockholders of a
premium over prevailing market prices for our common shares.
Our common stock price has been and may continue to be extremely
volatile.
Our common stock has traded as low as $4.50 and as high as $16.71
during intra-day trading between January 1, 2005, and the date of this report.
Some of the factors leading to this volatility include:
o the outcome of individual wells or the timing of exploration
efforts in Poland;
o the potential sale by us of newly issued common stock to raise
capital or by existing stockholders of restricted securities;
o price and volume fluctuations in the general securities
markets that are unrelated to our results of operations;
o the investment community's view of companies with assets and
operations outside the United States in general and in Poland
in particular;
o actions or announcements by POGC that may affect us;
o prevailing world prices for oil and gas;
o the potential of our current and planned activities in Poland;
and
o changes in stock market analysts' recommendations regarding
us, other oil and gas companies or the oil and gas industry in
general.
We may encounter additional exploration failures in Poland that will adversely
affect the trading prices for our common stock.
- --------------------------------------------------------------------------------
ITEM 1B. UNRESOLVED STAFF COMMENTS
- --------------------------------------------------------------------------------
None.
14
- --------------------------------------------------------------------------------
ITEM 2. 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. In September of 2005, POGC
sold 15% of its stock in an initial public offering on the Warsaw Stock
Exchange, raising a total of 2.7 billion Polish zlotys (approximately US $900
million). POGC also issued 20% of its stock to current and former employees. We
expect the additional funding will allow POGC to become more aggressive with the
exploration spending as it pursues its stated goal of increasing gas production
in-country by 60% in the next three years.
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 to us or to POGC 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.
15
If commercially viable oil or gas is discovered, the concession owner,
during the first two years of production, 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, all of which have been completed except
for the acquisition of 70 kilometers of 3-D seismic data.
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 July 2008. Remaining work commitments in the aggregate include
acquiring 30 kilometers of new 2-D seismic data and drilling one well. POGC is
currently working on an extension for the concessions that expire in 2006.
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. Remaining work
commitments include acquiring 100 kilometers of new 2-D seismic data or drilling
one well, which has been satisfied by the drilling of the Drozdowice-1 well, and
analysis and interpretation of existing well data. Beginning in the fourth year,
there is a drilling requirement of a second well.
Wilga/Block 255 Project Area
The Wilga project area consists of a single oil and gas exploration
concession that expires in July 2006. We are in the process of submitting a
routine extension application. All work commitments have been completed.
As of December 31, 2005, 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.
16
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; 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.
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 2005 follows:
Average Daily Production
(Bbls) Average Average
---------------------------- Working Net Revenue
Gross Net Interest Interest
------------- -------------- -------------- ---------------
United States producing properties:
Montana:
Cut Bank............................ 227 195 99.6% 86.4%
Bears Den........................... 7 5 98.0 81.0
Rattlers Butte...................... 15 1 6.3 5.1
------------- --------------
Total............................. 249 201
------------- --------------
Nevada:
Trap Springs........................ 7 1 21.6 18.9
Munson Ranch........................ 33 11 36.0 34.1
Bacon Flat.......................... 23 4 16.9 12.5
------------- --------------
Total............................. 63 16
------------- --------------
Total United States producing
properties.................... 312 217
============= ==============
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 Springs and Munson Ranch fields and have
an interest in the Bacon Flat field, which is operated by an industry partner.
The Trap Springs field was discovered in 1976. In the Trap Springs 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.
17
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 2005, 2004 and 2003:
Years Ended December 31,
-------------------------------------
2005 2004 2003
----------- ----------- -----------
United States producing property data:
Average daily net oil production (Bbls).......................... 217 234 234
Average sales price per Bbl...................................... $48.09 $36.34 $26.29
Average production costs per Bbl(1).............................. $26.79 $18.85 $17.22
- ------------------
(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 general and
administrative costs; depreciation, depletion and amortization; 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 84% of our total oil sales, to CENEX,
a regional refiner and marketer. Posted prices are generally competitive among
crude oil purchasers. Our crude oil sales contracts may be terminated by either
party upon 30 days' notice.
Oilfield Services - Drilling Rig and Well-Servicing Equipment
In Montana, we perform, 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, 2005, of $51.11 per Bbl for oil in
the United States and $50.00 per Bbl of oil and $2.97 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 the 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 RPS Energy, 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 2005.
18
The following summary of proved reserve information as of December 31,
2005, represents discounted, after tax 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 (MBbls) (MMcf) (In (In
thousands) thousands) thousands)
Proved reserves:
Developed producing........ 408 $5,836 -- 974 $ 830 $ 6,666
Undeveloped................ -- -- 209 18,814 35,249 35,249
----------- -------------- ------------ ------------ -------------- -----------------
Total.................... 408 $5,836 209 19,788 $36,079 $41,915
=========== ============== ============ ============ ============== =================
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, 2005, 2004 and 2003:
Years Ended December 31,
-------------------------------------------------------------------
2005 2004 2003
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- --------- ---------- --------- ----------
Discoveries:
United States....................... -- -- -- -- -- --
Poland.............................. -- -- 2.0 0.7 -- --
---------- ---------- --------- ---------- --------- ----------
Total............................. -- -- 2.0 0.7 -- --
---------- ---------- --------- ---------- --------- ----------
Exploratory dry holes:
United States....................... 4.00 2.0 -- -- -- --
Poland.............................. 2.00 1.0 -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total............................. -- -- -- -- -- --
---------- ---------- --------- ---------- --------- ----------
Total wells drilled................... 6.0 3.0 2.0 0.7 -- --
========== ========== ========= ========== ========= ==========
Wells and Acreage
As of December 31, 2005, 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..................................... 119.0 112.5
=========== ===========
- ------------------
(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.
19
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2005:
Developed Undeveloped
---------------------------- ----------------------------
Gross Net Gross Net
---------------------------- ----------------------------
United States:
Montana...................................... 10,732 10,418 1,150 1,057
Nevada....................................... 400 128 9,332 6,351
------------- ------------- ------------- --------------
Total..................................... 11,132 10,546 10,482 7,408
------------- ------------- ------------- --------------
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........................... 543 441 225,000 183,000
------------- ------------- ------------- --------------
Total Polish acreage..................... 768 551 1,930,000 1,400,000
------------- ------------- ------------- --------------
Total Acreage.................................. 11,900 11,097 1,940,482 1,407,408
============= ============= ============= ==============
- -------------------
(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.
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.
We expect Poland will continue 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 its 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
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
20
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 that 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.
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
21
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, 2005, we had 39 employees, consisting of nine in
Salt Lake City, Utah; 21 in Oilmont, Montana; one in Greenwich, Connecticut;
three in Houston, Texas; and five 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 our staff and 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. During 2005, we
opened a new production office in Warsaw, located at Ul. Chalubinskiego 8, where
we rent a small office suite for approximately $3,200 per month.
22
Oil and Gas Terms
The following terms have the indicated meaning when used in this
report:
"Appraisal well" means a well drilled following a successful
exploratory well used to determine the physical extent, reserves and
likely production rate of a field.
"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, future development costs and future
income taxes, 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, and
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.
23
"Usufruct" means the Polish equivalent of a U.S. oil and gas lease.
- --------------------------------------------------------------------------------
ITEM 3. LEGAL PROCEEDINGS
- --------------------------------------------------------------------------------
We are not a party to any material legal proceedings, and no material
legal proceedings have been threatened by us or, to the best of our knowledge,
against us.
- --------------------------------------------------------------------------------
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------
No matter was submitted to a vote of our security holders during the
fourth quarter of the fiscal year ended December 31, 2005.
24
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
2006:
First Quarter (through March 4, 2006)......... $ 4.50 $ 8.37
2005:
Fourth Quarter................................ 7.98 12.35
Third Quarter................................. 9.58 12.08
Second Quarter................................ 9.31 12.23
First Quarter................................. 10.65 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
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 3, 2006, we had approximately 10,000 stockholders.
Our common stock is currently traded on the Nasdaq National Market
under the symbol FXEN.
25
- --------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
The following selected financial data for the five years ended December
31, 2005, 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,
-------------------------------------------------------------
2005 2004 2003 2002 2001
---------- ---------- --------- --------- ----------
(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales....................... $ 3,805 $ 3,096 $ 2,230 $ 2,209 $ 2,229
Oilfield services....................... 2,132 710 98 533 1,584
---------- ---------- --------- --------- ----------
Total revenues........................ 5,937 3,806 2,328 2,742 3,813
---------- ---------- --------- --------- ----------
Operating costs and expenses:
Lease operating expenses (1)............ 2,462 1,946 1,546 1,365 1,358
Exploration costs (2)................... 8,369 3,013 523 1,031 6,544
Recovery of previously expensed
Input VAT............................... (2,121) -- -- -- --
Impairments of oil and gas properties (3) -- -- 161 1,548 --
Oilfield services costs................. 1,689 551 190 540 1,301
Depreciation, depletion and
amortization.......................... 903 636 599 618 662
Accretion expense....................... 45 41 37 -- --
Amortization of deferred
compensation (G&A).................... 125 -- -- 55 1,078
Stock compensation (G&A) (4)............ 76 5,859 -- -- --
Apache Poland G&A (G&A)................. -- -- -- -- 575
General and administrative (G&A)........ 6,592 4,909 3,253 2,440 883
---------- ---------- --------- --------- ----------
Total operating costs and expenses.. 18,140 16,955 6,309 7,597 12,401
---------- ---------- --------- --------- ----------
Operating loss............................ (12,203) (13,149) (3,981) (4,855) (8,588)
---------- ---------- --------- --------- ----------
Other income (expense):
Interest and other income............... 780 529 36 119 543
Interest expense........................ -- -- (788) (1,189) (331)
Impairment of notes receivable.......... -- -- -- -- (34)
---------- ---------- --------- --------- ----------
Total other income (expense)........ 780 529 (752) (1,070) 178
Loss before cumulative effect of
change in accounting principle.......... (11,423) (12,620) (4,733) (5,925) (8,410)
Cumulative effect of change in
accounting principle.................... -- -- 1,800 -- --
---------- ---------- --------- --------- ----------
Net loss.................................. $ (11,423) $ (12,620) $ (2,933) $ (5,925) $ (8,410)
========== ========== ========= ========= ==========
- Continued -
26
Years Ended December 31,
-------------------------------------------------------------
2005 2004 2003 2002 2001
---------- ---------- --------- --------- ----------
(In thousands)
Basic and diluted net loss per share:
Basic and diluted loss per common share
before cumulative effect of change in
accounting principle.................... $ (0.33) $ (0.41) $ (0.41) $ (0.34) $ (0.48)
Cumulative effect of change in
accounting principle.................... -- -- 0.09 -- --
---------- ---------- --------- --------- ----------
Basic and diluted net loss per common
share.................................... $ (0.33) $ (0.41) $ (0.32) $ (0.34) $ (0.48)
========== ========== ========= ========= ==========
Basic and diluted weighted average
shares outstanding...................... 34,733 30,691 19,885 17,641 17,673
Cash Flow Statement Data:
Net cash used in operating activities..... $ (10,105) $ (5,886) $ (5,561) $ (2,162) $ (3,248)
Net cash (used in) provided by investing
activities.............................. 4,656 (41,492) (1,446) (295) 326
Net cash provided by financing activities. 4,055 33,791 23,673 5 5,000
Balance Sheet Data:
Working capital (deficit)................. $ 27,715 $ 33,777 $ 16,032 $ (9,150) $ 558
Total assets.............................. 48,271 52,962 23,769 5,441 9,168
Long-term debt............................ -- -- -- -- 4,907
Stockholders' equity (deficit)............ 42,280 48,556 21,459 (4,869) 953
- ------------------
(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.
27
- --------------------------------------------------------------------------------
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
The following discussion of our historical financial condition and
results of operations should be read in conjunction with Item 6. "Selected
Consolidated Financial Data," our Consolidated Financial Statements and related
Notes contained in this report.
Introduction
Following is a brief discussion concerning some of the significant
financial events that have occurred during the past two years.
Value-Added Tax Refund
Throughout our operating history in Poland, until October 2005, we had
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, the Polish Oil and Gas Company, or 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. This event caused
changes to several tax laws, including the law that precluded us from obtaining
refunds of Input VAT. In April 2005, we filed a refund application for
approximately 13.7 million Polish zlotys, representing all Input VAT paid since
our inception in Poland through March of 2005. The Polish taxing authorities
began their review of our refund application in October 2005.
As part of the normal course of the review, and in order to prevent
interest accruing on the refund amount, the taxing authorities deposited all
13.7 million zlotys in our bank account in Poland in October 2005, equal to
approximately $4.2 million at then-current exchange rates. We have since
received requested refunds for the months of April through June of 2005.
A portion of the past Input VAT is related to capital costs, with the
remainder attributed to current and prior years' geological and geophysical
costs, along with overhead and other expenses. Accordingly, we have reduced our
capital costs by approximately $1.9 million, current year's expenses by $0.1
million, with the remaining $2.2 million related to prior years' expenses shown
as a Recovery of Previously Expensed Input VAT in the Consolidated Statements of
Operations. In addition, we recorded an Input VAT receivable at December 31,
2005, of $2.0 million, representing Input VAT paid since April 2005, and we
expect to be Input VAT neutral from this point forward.
This means that all of our costs in Poland going forward have
effectively been reduced by 22%.
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.
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 spending commitment. Among other things,
we agreed to assign to POGC all of our rights to prior production from the Kleka
11 well, and the liability was to be further offset by the value of the
remaining gas reserves associated with the well. Accordingly, we ceased
recording gas sales from the Kleka 11 well as of December 31, 2002. As of
December 31, 2004, our share of the Kleka 11 well had estimated reserves of
28
approximately $1.3 million, equal to the accrued liability recorded in favor of
POGC. Upon completion of the assignment of the Kleka 11 well, our previously
unpaid liability was to have been settled in full.
Through the end of 2004, exclusive of the Kleka 11 well assignment, we
incurred qualifying costs in excess of the commitment amount, which means that
we had earned our 49% interest, and POGC became 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.
Due to the fact that we exceeded our $16.0 million commitment through
actual cash expenditures in 2004, we and POGC subsequently agreed that the Kleka
11 well would not be assigned to POGC, nor would POGC take credit for prior
years' gas sales. In addition, during the first half of 2005, POGC applied
approximately $1.3 million in unused cash-call proceeds against our outstanding
accrued liability. Accordingly, as of December 31, 2005, by virtue of the
various transactions related to our Fences I exploration commitment, POGC now
owes us an amount equal to our prior overpayment and our share of gas sales from
the Kleka 11 well from inception through the end of 2005 ($1.4 million) and we
owe POGC an amount attributable to prior costs and interest that were to have
been settled against prior year gas sales from the Kleka 11 well ($0.4 million).
In connection with settling our accounts, we recorded a net charge of
approximately $55,000, which is included in Interest and Other Income in the
Consolidated Statements of Operations. We expect to begin recording gas sales
from the Kleka 11 well during 2006.
Final documentation of our Fences I account is pending instructions
from local tax authorities with respect to proper reporting for Value-Added Tax
purposes and should be concluded in early 2006.
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 in the Fences II project
area. We satisfied the expenditure requirements in late 2004 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.
Sales of Common Stock
We received proceeds from the exercise of stock options and warrants of
$4,054,646 during 2005. 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 2004, providing an additional
$13,067,148 in proceeds.
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 net capitalized costs of unproved properties, on a
property-by-property basis, are not considered 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. 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
29
recorded as other income. 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, 2005, we had $3.4 million in capitalized exploratory
well costs associated with our Rusocin well pending the determination of proved
reserves.
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, depletion and
amortization ("DD&A") rates.
Despite the inherent imprecision in these engineering estimates, these
estimates are used in determining DD&A expense and impairment expense and in
disclosing the supplemental standardized measure of discounted future net cash
flows relating to proved oil and gas properties. DD&A 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 DD&A expense. Also, estimated reserves are used to calculate
future cash flows from our oil and gas operations, which serve as an indicator
of fair value in determining whether a property is impaired or not. The larger
the estimated reserves, the less likely the property is impaired.
Stock-based Compensation
We have chosen to account for stock-based compensation using the
intrinsic value method prescribed by 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."
See Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations: New Accounting Pronouncements, for information on the
adoption of SFAS 123(R), "Share Based Payments."
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, 2005, 2004 and
2003, respectively, follows. Further information concerning our business
segments can be found in Note 11, Business Segments, in the financial
statements.
30
Exploration and Production Segment
A summary of the amount and percentage change, as compared to their
respective prior year period, for oil revenues, average oil prices, oil
production volumes, and lifting costs per barrel for the years ended December
31, 2005, 2004 and 2003, is set forth in the following table:
For the year ended December 31,
----------------------------------------------------------------------------
2005 2004 2003
----------------------- -------------------------- -------------------------
Oil Oil Oil
----------------------- -------------------------- -------------------------
Revenues.............................. $3,805,000 $3,096,000 $2,230,000
Percent change versus prior year.... +22.9% +38.8% +15.9%
Average price (per Bbl ).............. $48.45 $36.44 $26.29
Percent change versus prior year.... +32.9% +38.6% +24.1%
Production volumes (per Bbl).......... 78,534 84,970 84,811
Percent change versus prior year.... -7.5% +.10% -6.6%
Lifting costs per Bbl (1)............. $26.79 $18.85 $17.79
Percent change versus prior year.... +42.1% +5.9% +20.6%
- ----------------
(1) Lifting costs per barrel are computed by dividing the related lease
operating expenses by the total barrels of oil produced. Lifting costs do
not include production taxes.
Oil Revenues. Oil revenues were $3.8 million, $3.1 million and $2.2
million for the years ended December 31, 2005, 2004 and 2003, respectively. All
oil revenues during the three years were derived from our producing properties
in the United States. During these three years, oil revenues fluctuated
primarily due to volatile oil prices and changing production rates that are a
function of normal property declines. Oil revenues in 2005 increased from 2004
levels by approximately $922,000 due to higher oil prices, offset by
approximately $213,000 related to production declines. 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.
Gas Revenues. We did not record any gas revenues during 2005, 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 reduce the balance of our
liability due to POGC. See Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation: Introduction--Fences I Commitment
and Settlement, related to settling our Fences I obligation with POGC. We now
expect to begin recording gas sales from the Kleka 11 well in 2006.
Lease Operating Costs. Lease operating costs were $2.5 million in 2005,
$1.9 million in 2004 and $1.5 million in 2003. Operating costs rose from 2004 to
2005 as we took advantage of higher oil prices and revenues to work over and
recomplete several wells in Montana, which increased our operating costs by
approximately $440,000. In addition, the higher oil revenues in 2005 resulted in
higher value-based production taxes of approximately $34,000. Operating costs
rose in 2004 from 2003 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.
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 $8.4 million, $3.0 million and $684,000 for the years ended December 31,
2005, 2004 and 2003, respectively.
G&G costs were $3.3 million, $2.5 million and $523,000 for the years
ended December 31, 2005, 2004 and 2003, respectively. During all three years,
most of our G&G costs were spent on acquiring, processing and interpreting new
seismic data on the Fences I and II areas, including 800 km of new 2-D seismic
shot in 2005.
31
Exploratory dry-hole costs were $5.1 million, $472,000 and $0 for the
years ended December 31, 2005, 2004 and 2003, respectively. During 2005, we
plugged and abandoned two wells in Poland, the Sroda-5 and Lugi 1 wells, for a
total cost of approximately $4.6 million. In addition, we plugged and abandoned
four exploratory wells in Nevada for a total cost of approximately $713,000. 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, $0 and $161,000 for the
years ended December 31, 2005, 2004 and 2003, 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.
DD&A Expense - Producing Operations. DD&A expense for producing
properties was $511,000, $259,000 and $347,000 for the years ended December 31,
2005, 2004 and 2003, respectively. The increase from 2004 to 2005 is due
primarily to a reduction in oil reserves associated with higher operating costs,
offset by lower production volumes. 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 $2.1
million, $710,000 and $98,000 for the years ended December 31, 2005, 2004 and
2003, respectively. Activity in the contract drilling industry picked up
significantly during 2004 and continued in 2005, resulting in increases of 625%
and 200% respectively, in oilfield services revenues. During 2003, the industry
was at a virtual standstill in the area where we operate. Oilfield services
revenues will continue to fluctuate from period to period based on market
demand, weather, the number of wells drilled, downtime for equipment repairs,
the degree of emphasis on using our oilfield services equipment on our
Company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $1.7 million,
$551,000 and $190,000 for the years ended December 31, 2005, 2004 and 2003,
respectively, or 79%, 78% and 194% of oilfield servicing revenues, respectively.
During 2003, oilfield servicing costs were a higher percentage of oilfield
services revenues, as compared to 2004 and 2005, 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 $243,000, $290,000 and $304,000 for the years ended December 31, 2005, 2004
and 2003, respectively. We spent $264,000, $99,000 and $75,000 on upgrading our
oilfield servicing equipment during 2005, 2004 and 2003, respectively.
Nonsegmented Items
G&A Costs - Corporate. G&A costs were $6.6 million, $4.9 million and
$3.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.
During 2005, we opened a new office in Warsaw, Poland, hiring five experienced
individuals to assist in our exploration and production efforts. A portion of
the G&A increase in 2005 is attributable to these new office costs, including
salaries, taxes and benefits. In addition, we added administrative staff in the
United States, where we also experienced higher compensation related costs. We
continue to see higher legal and accounting fees associated with Sarbanes-Oxley
compliance and have expanded our use of consultants in our Polish operations. 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). Stock compensation of $76,000 in 2005
represents the value of stock and options granted to non-employees. In 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 10-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 2005 or 2003.
32
Amortization of Deferred Compensation. (G&A). During November 2005, we
issued 298,050 restricted stock purchase rights to employees, resulting in
deferred compensation of approximately $3.1 million, which will be amortized
ratably over the three-year vesting period. Expense recognized during 2005
totaled approximately $125,000.
Interest and Other Income - Corporate. Interest and other income was
$725,000, $529,000 and $36,000 for the years ended December 31, 2005, 2004 and
2003, respectively. Increases in both yearly periods are due to higher cash
balances generally available for investment, coupled with rising interest rates
over the two-year period.
Interest Expense. Interest expense was $0, $0 and $788,000 for the
years ended December 31, 2005, 2004 and 2003, 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 in 2003. As part of our further restructured
agreement with POGC, we stopped accruing interest on the obligation at December
31, 2003.
Income Taxes. We incurred net losses of $11.3 million, $12.6 million
and $2.9 million for the years ended December 31, 2005, 2004 and 2003,
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 and marketable
securities at December 31, 2005, together with revenues that we expect to begin
generating with gas sales in 2006, should allow us to carry out our planned
exploration program for at least the balance of 2006 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 proved or unproved property interests, or other arrangements, some 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 $27.7 million as of December 31, 2005, a decrease of $6.1 million
from December 31, 2004. The decrease is due primarily to costs associated with
our drilling and seismic activities during 2005, offset to a degree by our Input
VAT refund discussed earlier.
Operating Activities. We used net cash of $10.1 million, $5.9 million
and $5.6 million in our operating activities during 2005, 2004 and 2003,
respectively, primarily as a result of the net losses, excluding noncash
charges, incurred in those years. Our current assets at year-end included
approximately $2.0 million in refundable Input VAT that we expect to receive
during the first six months of 2006. Our current liabilities at year-end
included approximately $0.6 million in costs related to our drilling and seismic
activities in Poland that were paid in early 2006.
33
Investing Activities. We received net cash from investing activities of
$4.7 million in 2005, and used net cash of $41.5 million and $1.4 million in
investing activities in 2004 and 2003, respectively. In 2005 we received $6.8
million from the sale of marketable securities and $1.9 million from the
recovery of previously capitalized Input VAT. We invested $627,000 in marketable
securities. We spent $3.8 million for oil and gas property additions, $3.3
million of which was related to our Polish drilling activities, with the
remainder being spent on our domestic properties. We also spent $158,000
upgrading our office equipment and $264,000 upgrading our oilfield services
equipment. 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, $7.7 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
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.
Financing Activities. We received net cash of $4.1 million, $33.8
million and $23.7 million from our financing activities during 2005, 2004 and
2003, respectively. All of the proceeds in 2005 were from the exercise of stock
options and warrants. 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, 2005, except for the drilling contract for the Drozdowice-1 well,
which began drilling in January 2006, and was plugged and abandoned in March
2006. The contract amount was $0.8 million.
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 December 2004, the Financial Accounting Standards Board (the "FASB")
issued SFAS No. 123R, "Share-Based Payments" ("SFAS No. 123R"), a revision of
SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"), which
requires companies to measure all employee stock-based compensation awards using
a fair value method and record such expense in their consolidated financial
statements. We have adopted this standard effective January 1, 2006, and elected
the modified-prospective transition method. Under the modified-prospective
transition method, awards that are granted, modified, repurchased or cancelled
after the date of adoption should be measured and accounted for in accordance
with SFAS No. 123R. Stock-based awards that are granted prior to the effective
date should continue to be accounted for in accordance with SFAS No. 123, except
that stock option expense for unvested options must be recognized in the
Consolidated Statement of Operations. The impact of adopting SFAS No. 123R is
expected to increase our salaries and benefits expense by approximately $2.7
million for 2006, based on options and other awards outstanding as of December
31, 2005.
34
In April 2005, the FASB issued FSP FAS 19-1, "Accounting for Suspended
Well Costs," which we adopted effective January 1, 2005. This FSP amends SFAS
No. 19 to allow continued capitalization when (a) the well has found a
sufficient quantity of reserves to justify proceeding with the project plan, and
(b) the enterprise is making sufficient progress assessing the reserves and the
economic and operating viability of the project, which may include more than one
exploratory well if the reserves are intended to be extracted in a single
integrated operation. The FSP also requires increased disclosures, which are
included in the accompanying consolidated financial statements. Adoption of this
rule did not impact our consolidated net loss for 2005. If this FSP had been
applied to 2004, it would not have impacted our net loss for that year.
We have reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on our
consolidated results of operations, financial position or cash flows. Based on
that review, we believe that none of these pronouncements will have a
significant effect on our current or future earnings or operations.
- --------------------------------------------------------------------------------
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------
Price Risk
Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.
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. POGC is
the primary purchaser of domestic gas in Poland. We expect that the prices we
receive for the gas we produce will be lower than would be the case in a more
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 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; however, we have
adopted a policy to reduce currency risk by transferring dollars to zlotys on or
about the occasion of making any significant commitment payable in Polish
currency.
35
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
During the year ended December 31, 2005, we have not disagreed with our
independent registered public accounting firm on any items of accounting
treatment or financial disclosure.
- --------------------------------------------------------------------------------
ITEM 9A. CONTROLS AND PROCEDURES
- --------------------------------------------------------------------------------
Evaluation of Disclosure 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, 2005, pursuant to Rule 13a-15(b) under the Securities Exchange Act.
Based upon that evaluation, our Certifying Officers concluded that, as of
December 31, 2005, our disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
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 and the effectiveness 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.
Changes in Internal Control Over Financial Reporting
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 9A. OTHER EVENTS
- --------------------------------------------------------------------------------
None.
36
PART III
- --------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2006 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 2006 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 2006 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 2006 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 2006 annual
meeting of stockholders under the caption "Relationship with Independent
Auditors" is incorporated herein by reference.
37
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, 2005 and 2004.. F-4
Consolidated Statements of Operations for the Years Ended
December 31, 2005, 2004 and 2003............................ F-6
Consolidated Statements of Comprehensive Loss for the Years
Ended December 31, 2005, 2004 and 2003...................... F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2005, 2004 and 2003.......................... F-8
Consolidated Statement of Stockholders' Equity (Deficit) for
the Years Ended December 31, 2005, 2004 and 2003............ F-9
Notes to the Consolidated Financial Statements................ F-10
2. Supplemental Schedules. The supplemental 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.
3.03 Articles of Amendment to the Restated Articles of This filing.
Incorporation of FX Energy, Inc.
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.
4.03 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.
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.
38
Item 10 Material Contracts (continued)
- ------------ -----------------------------------------------------
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.
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.
39
Item 10 Material Contracts (continued)
- ------------ -----------------------------------------------------
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
10.67 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, Incorporated by reference from the annual report
Inc. and directors and officers with related on Form 10-K for the period ended December 31,
schedule** 2003, filed March 15, 2004.
10.76 Supplemental Indemnification Agreement between FX Incorporated by reference from the annual report
Energy, Inc. and Dennis B. Goldstein** on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.77 Description of compensation arrangement with Incorporated by reference from the annual report
executive officers and directors** on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.78 Form of Employment Agreement with related schedule** Incorporated by reference from the annual
report on Form 10-K for the period ended
December 31, 2003, filed March 15, 2004.
10.79 Change in Control Compensation Agreement with Incorporated by reference from the annual report
related schedule** on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
10.80 FX Energy, Inc. 401(k) Stock Bonus Plan** Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
40
Item 10 Material Contracts (continued)
- ------------ -----------------------------------------------------
10.81 FX Energy, Inc. 2004 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.
Item 21 Subsidiaries of the Registrant
- ------------ -----------------------------------------------------
21.01 Schedule of Subsidiaries Incorporated by reference from the annual report
on Form 10-K for the period ended December 31,
2003, filed March 15, 2004.
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 RPS Energy, 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.
41
- --------------------------------------------------------------------------------
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, 2006 By:/s/ Thomas B. Lovejoy
-------------------------------------
Thomas B. Lovejoy
Chief Financial Officer
Dated: March 10, 2006 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, 2006 /s/ Thomas B. Lovejoy
-------------------------------------
Thomas B. Lovejoy, Director
Dated: March 10, 2006 /s/ David N. Pierce
-------------------------------------
David N. Pierce, Director
Dated: March 10, 2006 /s/ Dennis B. Goldstein
-------------------------------------
Dennis B. Goldstein, Director
Dated: March 10, 2006 /s/ David L. Worrell
-------------------------------------
David L. Worrell, Director
Dated: March 10, 2006 /s/ Arnold S. Grundvig, Jr.
-------------------------------------
Arnold S. Grundvig, Jr., Director
Dated: March 10, 2006 /s/ Jerzy B. Maciolek
-------------------------------------
Jerzy B. Maciolek, Director
Dated: March 10, 2006 /s/ Richard Hardman
-------------------------------------
Richard Hardman, Director
42
[FX ENERGY 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 2005 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,
2005, 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 assurance 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 the Company's
consolidated financial statements.
Management's assessment of the effectiveness of the Company's internal
control over financial reporting as of December 31, 2005, 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, 2005.
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 integrated audits of FX Energy, Inc.'s 2005 and 2004
consolidated financial statements and of its internal control over financial
reporting as of December 31, 2005 and an audit of its 2003 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 (deficit) present fairly, in all material respects, the
financial position of FX Energy, Inc. and its subsidiaries (the Company) at
December 31, 2005 and 2004, and the results of their operations and their cash
flows for each of the three fiscal years in the period ended December 31, 2005
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.
As discussed in Note 2 to the Financial Statements, the Company changed its
method of accounting for asset retirement costs, effective January 1, 2003.
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, 2005 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,
2005, 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
F-2
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.
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 and procedures may deteriorate.
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 10, 2006
F-3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2005 and 2004
(in thousands)
2005 2004
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents................................................... $ 2,390 $ 3,784
Marketable securities....................................................... 26,479 32,321
Receivables:
Accrued oil sales....................................................... 416 335
Joint interest and other receivables.................................... 1,592 1,013
Input VAT receivable.................................................... 2,032 --
Inventory................................................................... 96 92
Other current assets........................................................ 270 224
------------- -------------
Total current assets................................................ 33,275 37,769
------------- -------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved.................................................................. 15,918 15,574
Unproved................................................................ 304 355
Other property and equipment................................................ 4,262 3,992
------------- -------------
Gross property and equipment............................................ 20,484 19,921
Less accumulated depreciation, depletion and amortization................... (5,844) (5,087)
------------- -------------
Net property and equipment.......................................... 14,640 14,834
------------- -------------
Other assets:
Certificates of deposit..................................................... 356 356
Deposits.................................................................... - 3
------------- -------------
Total other assets.................................................. 356 359
------------- -------------
Total assets.................................................................... $ 48,271 $ 52,962
============= =============
-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, 2005 and 2004
(in thousands, except share data)
-Continued-
2005 2004
------------- -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................................ $ 4,110 $ 2,436
Accrued liabilities......................................................... 1,450 1,556
------------- -------------
Total current liabilities........................................... 5,560 3,992
Asset retirement obligation..................................................... 431 414
------------- -------------
Total liabilities................................................... 5,991 4,406
------------- -------------
Commitments and contingencies (Note 6)
Stockholders' equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
December 31, 2005 and 2004; no shares outstanding......................... -- --
Common stock, $0.001 par value, 100,000,000 shares authorized as of
December 31, 2005 and 2004; 35,097,279 and 34,398,109 shares issued and
outstanding as of December 31, 2005 and 2004, respectively................ 35 34
Additional paid in capital.................................................. 125,216 117,376
Deferred compensation....................................................... (2,975) --
Accumulated other comprehensive loss........................................ (58) (339)
Accumulated deficit......................................................... (79,938) (68,515)
------------- -------------
Total stockholders' equity ......................................... 42,280 48,556
------------- -------------
Total liabilities and stockholders' equity ..................................... $ 48,271 $ 52,962
============= =============
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, 2005, 2004 and 2003
(in thousands, except per share amounts)
2005 2004 2003
----------------- ---------------- ---------------
Revenues:
Oil and gas sales........................................... $ 3,805 $ 3,096 $ 2,230
Oilfield services........................................... 2,132 710 98
------------- ------------- -------------
Total revenues.......................................... 5,937 3,806 2,328
------------- ------------- -------------
Operating costs and expenses:
Lease operating expenses.................................... 2,462 1,946 1,546
Exploration costs........................................... 8,369 3,013 523
Recovery of previously expensed Input VAT................... (2,121) -- --
Impairment of oil and gas properties........................ -- -- 161
Oilfield services costs..................................... 1,689 551 190
Depreciation, depletion and amortization.................... 903 636 599
Accretion expense........................................... 45 41 37
Stock compensation (G&A).................................... 76 5,859 --
Amortization of deferred compensation (G&A)................. 125 -- --
General and administrative costs (G&A)...................... 6,592 4,909 3,253
------------- ------------- -------------
Total operating costs and expenses...................... 18,140 16,955 6,309
------------- ------------- -------------
Operating loss.................................................. (12,203) (13,149) (3,981)
------------- ------------- -------------
Other income (expense):
Interest and other income................................... 780 529 36
Interest expense............................................ -- -- (788)
------------- ------------- -------------
Total other income (expense)............................ 780 529 (752)
------------- ------------- -------------
Loss before cumulative effect of accounting change.............. (11,423) (12,620) (4,733)
Cumulative effect of change in accounting principle......... -- -- 1,800
------------- ------------- -------------
Net loss........................................................ (11,423) (12,620) (2,933)
Less preferred stock deemed dividend related to beneficial
conversion feature........................................ -- -- (3,342)
------------- ------------- -------------
Net loss attributable to common shares.......................... $ (11,423) $ (12,620) $ (6,275)
============= ============= =============
Basic and diluted loss per common share before cumulative effect
of change in accounting principle............................. $ (0.33) $ (0.41) $ (0.41)
Cumulative effect of change in accounting principle......... -- -- 0.09
------------- ------------- -------------
Basic and diluted net loss per common share..................... $ (0.33) $ (0.41) $ (0.32)
============= ============= =============
Basic and diluted weighted average number of shares
Outstanding................................................. 34,733 30,691 19,885
============= ============= =============
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, 2005, 2004 and 2003
(in thousands)
2005 2004 2003
------------- ------------- -------------
Net loss...................................................... $ (11,423) $ (12,620) $ (2,933)
Other comprehensive income (loss)
Increase (decrease) in market value of available for sale
marketable securities...................................... 281 (339) --
------------- ------------- -------------
Comprehensive loss $ (11,142) $ (12,959) $ (2,933)
============= ============= =============
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, 2005, 2004 and 2003
(in thousands)
2005 2004 2003
-------------- -------------- -------------
Cash flows from operating activities:
Net loss........................................................... $ (11,423) $ (12,620) $ (2,933)
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................... 903 636 599
Impairment of oil and gas properties....................... -- -- 161
Property abandonments...................................... 242 -- --
Accretion expense.......................................... 45 41 37
Adjustment to asset retirement obligation.................. (28) -- --
Amortization of loan fees.................................. -- -- 100
(Gain) loss on property dispositions....................... (18) 1 --
Stock compensation (G&A)................................... 76 5,859 --
Amortization of deferred compensation (G&A)................ 125 -- --
Common stock and stock options issued for services (G&A)... 610 406 101
Increase (decrease) from changes in working capital items:
Receivables.................................................... (2,438) (1,077) (108)
Inventory...................................................... (4) (13) 5
Other current assets........................................... (46) (98) (30)
Other assets .................................................. 3 (10) --
Accounts payable and accrued liabilities....................... 1,848 989 (1,693)
-------------- -------------- -------------
Net cash used in operating activities...................... (10,105) (5,886) (5,561)
-------------- -------------- -------------
Cash flows from investing activities:
Additions to oil and gas properties................................ (2,989) (8,437) (946)
Additions to other property and equipment.......................... (422) (395) (138)
Recovery of previously capitalized VAT............................. 1,921 -- --
Net change in other assets......................................... -- -- 15
Additions to marketable securities................................. (627) (32,660) --
Proceeds from sale of investments.................................. 6,750 -- --
Proceeds from sale of assets....................................... 23 -- --
Deposits........................................................... -- -- (377)
-------------- -------------- -------------
Net cash provided by (used in) investing activities............ 4,656 (41,492) (1,446)
-------------- -------------- -------------
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............... 4,055 13,067 --
-------------- -------------- -------------
Net cash provided by financing activities...................... 4,055 33,791 23,673
-------------- -------------- -------------
Net increase (decrease) in cash........................................ (1,394) (13,587) 16,666
Cash and cash equivalents at beginning of year......................... 3,784 17,371 705
-------------- -------------- -------------
Cash and cash equivalents at end of year............................... $ 2,390 $ 3,784 $ 17,371
============== ============== =============
The accompanying notes are an integral part of these consolidated financial statements.
F-8
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity (Deficit)
For the years ended December 31, 2005, 2004 and 2003
(in thousands)
Common Stock
------------------------- Accumulated Total
Par Value Additional Other Stockholders'
Preferred Shares $0.001 Per Deferred Paid in Comprehensive Accumulated Equity
Stock Issued Share Compensation Capital Loss Deficit (Deficit)
--------- ------ ---------- ------------ ---------- ------------- ----------- ------------
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
common stock....................... (2) 2,250 2 -- -- -- -- --
Common stock offerings, net......... -- 6,353 6 -- 19,850 -- -- 19,856
Conversion of note payable and
accrued interest into common stock -- 972 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 -- (55,895) 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
Common stock issued for services... -- 58 -- -- 610 -- -- 610
Exercise of stock options........... -- 593 1 -- 3,874 -- -- 3,875
Stock compensation.................. -- -- -- -- 76 -- -- 76
Deferred compensation............... -- -- -- (3,100) 3,100 -- -- --
Amortization of deferred
compensation...................... -- -- -- 125 -- -- -- 125
Exercise of warrants................ -- 48 -- -- 180 -- -- 180
Other comprehensive loss............ -- -- -- -- -- 281 -- 281
Net loss for year................... -- -- -- -- -- -- (11,423) (11,423)
----- ------ ----- ------- -------- ------ -------- --------
Balance as of December 31, 2005....... $ -- 35,097 $ 35 $(2,975) $125,216 $ (58) $(79,938) $ 42,280
===== ====== ===== ======= ======== ====== ======== ========
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 explores for and 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, 2005, 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
Excluding the receivable for Input VAT, which is due from the State Treasury
Office of Poland, 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, 2005 and 2004. The
majority of the Company's cash and cash equivalents are 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 units-of-production method.
F-10
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The computation of DD&A takes into consideration the anticipated proceeds from
equipment salvage. An impairment loss is recorded if the net capitalized costs
of proved oil and gas properties exceed the aggregate undiscounted future net
revenues determined on a property-by-property basis. The impairment loss
recognized equals the excess of net capitalized costs over the related fair
value determined on a property-by-property basis. Gains and losses are
recognized on sales of entire interests in proved and unproved properties. Sales
of partial interests are generally treated as a recovery of costs and any
resulting gain or loss is recorded as other income.
The following table reflects the net changes in capitalized exploratory well
costs, which are capitalized pending the determination of proved reserves,
during 2005, 2004 and 2003.
December 31,
-------------------------------------------
2005 2004 2003
------------- ------------- -------------
(In thousands)
Beginning balance at January 1................................. $ 8,779 $ -- $ --
Additions to capitalized exploratory well costs pending the
determination of proved reserves.............................. 313 8,779 --
Reclassifications to wells, facilities and equipment based on
the determination of proved reserves.......................... (5,559) -- --
Capitalized exploratory well costs charged to expense.......... (98) -- --
------------- ------------- -------------
Ending balance at December 31.................................. $ 3,435 $ 8,779 $ --
============= ============= =============
The 2005 balance includes costs associated with the Rusocin well in Poland. The
2004 balance included 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
2005 2004 (in years)
------------- ------------- -------------
(In thousands)
Other property and equipment:
Drilling rigs.................................................. $ 3,022 $ 2,899 6
Other vehicles................................................. 290 302 5
Building....................................................... 106 96 40
Office equipment and furniture................................. 844 695 3 to 6
------------- -------------
Total cost.................................................. 4,262 3,992
Accumulated depreciation (3,530) (3,286)
------------- -------------
Net property and equipment................................. $ 732 $ 706
============ =============
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,
-----------------------------------
2005 2004 2003
----------- ----------- ----------
(In thousands)
Noncash investing transactions:
Additions to properties included in current liabilities................ $ 798 $ 1,076 $ 2,145
Recovery of previously capitalized VAT included in Input VAT
receivable............................................................ 254 -- --
Additions to properties previously included in other and current assets -- 490 --
----------- ----------- ----------
Total.............................................................. $ 1,052 $ 1,566 $ 2,145
=========== =========== ==========
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,
-----------------------------------
2005 2004 2003
----------- ----------- ----------
(In thousands)
Supplemental disclosure:
Cash paid during the year for interest................................ $ -- $ -- $ 475
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,
2005, are as follows (in thousands):
Gross Estimated
Unrealized Market
Cost Losses Value
----------------- ----------------- ----------------
Marketable securities.............................. $ 26,537 $ (58) $ 26,479
================= ================= ================
The investments consist primarily of U.S. government agency bonds and notes,
whose value fluctuates with changes in interest rates. The investments increased
in value during the year ended December 31, 2005. 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" ("SFAS No. 123").
F-12
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
As of December 31, 2005 the Company had 3,492,283 options outstanding under
stock option and award plans as well as from other individual grants. 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:
2005 2004 2003
------------- ------------- -------------
(In thousands, except per share amounts)
Net loss:
Net loss, as reported.............................................. $ (11,423) $ (12,620) $ (2,933)
Add: stock-based employee compensation expense included in
reported net loss, net of any related tax effects................ 201 5,820 --
Less: Total stock-based employee compensation expense
determined under the fair value based method for all awards,
net of any related tax effects................................... (1,959) (1,412) (907)
------------- ------------- -------------
Pro forma net loss............................................ $ (13,181) $ (8,212) $ (3,840)
============= ============= =============
Basic and diluted net loss per share:
As reported................................................... $ (0.33) $ (0.41) $ (0.41)
Pro forma..................................................... (0.38) (0.27) (0.46)
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 2005,
2004 and 2003 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 60% for 2005, 70% for 2004
and 70% for 2003; (2) expected life of three years; (3) risk-free interest rates
at the date of grant ranging from 2.21% to 4.39%; 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 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 December 2004, the Financial Accounting Standards Board (the "FASB") issued
SFAS No. 123R, "Share-Based Payments" ("SFAS No. 123R"), a revision of SFAS No.
123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"), which requires
companies to measure all employee stock-based compensation awards using a fair
value method and record such expense in their consolidated financial statements.
The Company has adopted this standard effective January 1, 2006 and elected the
modified-prospective transition method. Under the modified-prospective
transition method, awards that are granted, modified, repurchased or cancelled
after the date of adoption should be measured and accounted for in accordance
with SFAS No. 123R. Stock-based awards that are granted prior to the effective
date should continue to be accounted for in accordance with SFAS No. 123, except
that stock option expense for unvested options must be recognized in the
consolidated statement of operations. The impact of adopting SFAS No. 123R is
expected to increase salaries and benefits expense by approximately $2.7 million
for 2006, based on options and other awards outstanding as of December 31, 2005.
F-13
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
In April 2005, the FASB issued FSP FAS 19-1, "Accounting for Suspended Well
Costs," which the Company adopted effective January 1, 2005. This FSP amends
SFAS No. 19 to allow continued capitalization when (a) the well has found a
sufficient quantity of reserves to justify proceeding with the project plan, and
(b) the enterprise is making sufficient progress assessing the reserves and the
economic and operating viability of the project, which may include more than one
exploratory well if the reserves are intended to be extracted in a single
integrated operation. The FSP also requires increased disclosures, which are
included in the accompanying consolidated financial statements. Adoption of this
rule did not impact the Company's consolidated net loss for 2005. If this FSP
had been applied to 2004, it would not have impacted the Company's net loss for
that year.
The Company has reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on its
consolidated results of operations, financial position and cash flows. 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 consolidated 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.
Reclassification
Certain amounts in the Consolidated Financial Statements for 2004 and 2003 have
been reclassified to conform to the 2005 presentation. These reclassifications
had no impact on the Company's net loss or 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, 2005, 2004 and 2003, were as
follows:
Options and Warrants Price Range
-------------------------- --------------------
Balance sheet date:
December 31, 2005........................................ 6,997,656 $0.00 - $10.65
December 31, 2004........................................ 7,405,106 $2.40 - $9.00
December 31, 2003........................................ 11,025,827 $1.50 - $10.25
F-14
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The Company had a net loss in 2005, 2004 and 2003. 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, were not included in the
computation of diluted earnings per share for the years presented because the
effect would have been antidilutive.
Note 2: Asset Retirement Obligation
In August 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS No. 143"). 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 $44,565, $41,000 and $37,000 in 2005, 2004 and
2003, respectively.
At the time of adoption and at December 31, 2005, 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.
Following is a reconciliation of the yearly changes in the asset retirement
obligation at December 31, 2005 and 2004 (in thousands):
Year ended December 31................................................ 2005 2004
------ ------
Asset retirement obligation at January 1.............................. $414 $383
Liabilities settled................................................... -- (10)
Adjustment to asset retirement obligation............................. (28) --
Accretion expense..................................................... 45 41
------ ------
Asset retirement obligation as of December 31......................... $431 $414
====== ======
Note 3: Other Assets
As of December 31, 2005 and 2004, 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, 2005 and 2004, were
comprised of the following:
December 31,
----------------------------
2005 2004
------------- -------------
(In thousands)
Accrued liabilities:
Exploratory dry hole costs................................................... $ 196 $ 880
Drilling costs............................................................... 387 172
Geological and geophysical costs............................................. -- 269
Compensation related costs................................................... 867 --
Other costs.................................................................. -- 235
------------- -------------
Total.................................................................... $ 1,450 $ 1,556
============= =============
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 and Contingencies
Fences I Project Area
On April 11, 2000, the Company 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.
In early 2003, the Company entered into a settlement agreement with POGC to
address the methods by which the Company would satisfy its then existing unpaid
liability incurred in connection with meeting its spending commitment. Among
other things, the Company agreed to assign to POGC all of its rights to prior
production from 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, 2004, the Company's share of the Kleka 11 well had estimated reserves of
approximately $1.3 million, equal to the accrued liability recorded in favor of
POGC. Upon completion of the assignment of the Kleka 11 well, the Company's
previously unpaid liability was to have been settled in full.
Through the end of 2004, exclusive of the Kleka 11 well assignment, the Company
incurred qualifying costs in excess of the commitment amount, which means that
the Company had earned its 49% interest, and POGC is obligated to pay its 51%
share of all qualifying project costs. At December 31, 2004, the Company had
recorded a receivable from POGC related to costs the Company spent in excess of
its commitment requirement in the amount of $770,000.
Due to the fact that the Company exceeded its $16.0 million commitment through
actual cash expenditures in 2004, the Company and POGC subsequently agreed that
the Kleka 11 well would not be assigned to POGC, nor would POGC take credit for
prior years' gas sales. In addition, during the first half of 2005, POGC applied
approximately $1.3 million in unused cash-call proceeds against the Company's
outstanding accrued liability. Accordingly, as of December 31, 2005, by virtue
of the various transactions related to the Company's Fences I exploration
commitment, POGC now owes the Company an amount equal to the Company's prior
overpayment and its share of gas sales from the Kleka 11 well from inception
through the end of 2005 ($1.4 million) and the Company owes POGC an amount
attributable to prior costs and interest that were to have been settled against
prior year gas sales from the Kleka 11 well ($0.4 million). At December 31, 2005
and 2004 the receivable from POGC was included in Joint interest and other
receivables in the Consolidated Balance Sheets. In connection with settling its
accounts, the Company recorded a net charge of approximately $55,000 which is
included in Interest and Other Income in the Consolidated Statements of
Operations.
Final documentation of the Company's Fences I account is pending instructions
from local tax authorities with respect to proper reporting for Value Added Tax
purposes, and should be concluded in early 2006.
Note 7: Value Added Tax Refund
Throughout the Company's operating history in Poland, until October 2005, the
Company had 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, the Polish Oil and Gas Company, or POGC, has
traditionally been the concession holder, while the Company is a working
interest owner by virtue of its agreements with POGC.
F-17
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
During 2004, Poland joined the European Union. This event caused changes to
several tax laws, including the law that precluded the Company from obtaining
refunds of Input VAT. In April 2005, the Company filed a refund application for
approximately 13.7 million Polish zlotys, representing all Input VAT paid since
the Company's inception in Poland through March of 2005. The Polish taxing
authorities began their review of the refund application in October, 2005.
As part of the normal course of the review, and in order to prevent interest
accruing on the refund amount, the taxing authorities deposited all 13.7 million
zlotys in the Company's bank account in Poland in October, 2005, equal to
approximately $4.2 million at then-current exchange rates. The Company has since
received requested refunds for the months of April through June of 2005.
A portion of the past Input VAT is related to capital costs, with the remainder
attributed to current and prior years' geological and geophysical costs, along
with overhead and other expenses. Accordingly, for the $4.2 million refund, the
Company has reduced its capital costs by approximately $1.9 million, current
year's expenses by $0.1 million, with the remaining $2.2 million related to
prior years' expenses shown as a Recovery of Previously Expensed Input VAT in
the Consolidated Statements of Operations. In addition, the Company recorded an
Input VAT receivable at December 31, 2005 of $2.0 million, representing Input
VAT paid since April, 2005 and the Company expects to be Input VAT neutral from
this point forward.
Note 8: Income Taxes
The Company recognized no income tax benefit from the losses generated during
2005, 2004 and 2003. The components of the net deferred tax asset as of December
31, 2005 and 2004 are as follows:
December 31,
----------------------------
2005 2004
------------- -------------
(In thousands)
Deferred tax liability:
Property and equipment basis differences...................................... $ (1,126) $ (1,219)
Deferred tax asset:
Net operating loss carryforwards:
United States............................................................. 21,582 18,719
Poland.................................................................... 4,380 6,980
Oil and gas properties........................................................ 1,855 1,855
Options issued for services................................................... 184 143
Asset retirement obligation................................................... 161 155
Valuation allowance........................................................... (27,036) (26,633)
------------- -------------
Total..................................................................... $ -- $ --
============= =============
The change in the valuation allowance during 2005, 2004 and 2003 is as follows:
Year Ended December 31,
-------------------------------------------
2005 2004 2003
------------- ------------- -------------
(In thousands)
Valuation allowance:
Balance, beginning of year..................................... $ (26,633) $ (19,766) $ (18,744)
Change in property and equipment basis differences............ (93) 881 --
Increase due to net operating loss............................. (263) (8,171) (828)
Other.......................................................... (47) 423 (194)
------------- ------------- -------------
Total...................................................... $ (27,036) $ (26,633) $ (19,766)
============= ============= =============
F-18
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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, 2005 and 2004.
United States NOL
At December 31, 2005, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $57,861,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and $39,112,000 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 $17,312,000 relating to tax
deductions resulting from the exercise of stock options. The tax benefit from
adjusting the valuation allowance related to this portion of the NOL
carryforward will be credited to additional paid-in capital.
Polish NOL
As of December 31, 2005, the Company had NOL carryforwards in Poland totaling
approximately $11,743,000, including $1,155,000, $5,016,000 and $415,000
generated in 2005, 2004 and 2003, 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,
-------------------------------------------
2005 2004 2003
------------- ------------- -------------
(In thousands)
Domestic....................................................... $ (5,199) $ (9,107) $ (1,820)
Foreign........................................................ (6,224) (3,513) (1,113)
------------- ------------- -------------
Total...................................................... $ (11,423) $ (12,620) $ (2,933)
============= ============= =============
Note 9: Stockholders' Equity
The Company received proceeds from the exercise of 668,066 stock options and
warrants of $4,054,646 during 2005.
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
F-19
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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 of $3.3 million 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.
Note 10: Stock Options and Warrants
Equity Compensation Plans
The Company's equity compensation consists of annual stock option and award
plans that are each subject to approval by the board of directors and are
subsequently presented for approval by the 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, 2005:
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 $ 7.50 --
1996 Stock Option and Award Plan................................ 500,000 3.97 53,833
1997 Stock Option and Award Plan................................ 500,000 6.44 12,234
1998 Stock Option and Award Plan................................ 500,000 5.80 3,000
1999 Stock Option and Award Plan................................ 500,000 4.14 10,000
2000 Stock Option and Award Plan................................ 600,000 2.51 10,667
2001 Stock Option and Award Plan................................ 600,000 3.22 8,999
2003 Long Term Incentive Plan................................... 800,000 6.64 74,000
2004 Long Term Incentive Plan................................... 1,000,000 3.17 521,050
-------------- --------------- -------------
Total......................................................... 5,500,000 $ 4.73 693,783
============== =============== =============
F-20
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The above table excludes 70,000 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 2005, 2004 and 2003:
2005 2004 2003
-------------------------- ---------------------------- -------------------------
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......... 3,851,733 $ 5.47 4,784,517 $ 4.42 4,544,017 $ 4.68
Granted................... 333,950 1.04 1,040,000 8.38 785,000 3.97
Exercised................. (620,066) 6.95 (1,743,701) 4.16 -- --
Canceled.................. (73,334) 8.27 (53,083) 4.26 (10,000) 4.66
Expired................... -- -- (176,000) 7.75 (534,500) 7.50
--------- --------- ---------
End of year............... 3,492,283 $ 4.73 3,851,733 $ 5.47 4,784,517 $ 4.42
========= ========= =========
Exercisable at year-end....... 2,270,685 $ 4.33 2,124,731 $ 4.67 3,474,270 $ 4.84
========= ========= =========
The weighted average fair value per share of options granted during 2005, 2004
and 2003 was $9.72, $4.00 and $1.90, respectively.
In November of 2005 the Company issued 298,050 restricted stock purchase rights
to employees resulting in deferred compensation of $3.1 million which will be
amortized ratably over the three year vesting period. Expense recognized during
2005 totaled $124,563.
The following table summarizes information about fixed stock options, including
restricted stock purchase rights, outstanding as of December 31, 2005:
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
- -------------------------------------- -------------------- --------------- --------------- ---------------
$0.00 - $2.40......... 750,949 4.92 $ 1.44 451,999 $ 2.40
$2.44 - $3.20......... 393,667 3.10 2.54 373,001 2.50
$3.98 - $3.98......... 652,000 4.82 3.98 417,674 3.98
$4.06 - $4.06......... 361,000 1.80 4.06 361,000 4.06
$5.75 - $7.38......... 363,167 0.90 5.85 356,501 5.84
$8.37 - $8.37......... 886,500 5.67 8.37 293,842 8.37
$9.00 - $10.65........ 85,000 5.66 9.37 16,668 9.00
--------------- ---------------
Total.......... 3,492,283 4.16 $ 4.72 2,270,685 $ 4.33
=============== ===============
Warrants
F-21
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The following table summarizes warrant activity for during 2005, 2004 and 2003:
2005 2004 2003
---------------------------- ----------------------------- ------------------------------
Number of Price Number of Price Number of Price
Shares Range Shares Range Shares Range
------------ -------------- -------------- -------------- ------------ -----------------
Warrants outstanding and
exercisable:
Beginning of year... 3,553,373 $3.60--$3.75 6,241,310 $3.60--$3.75 6,241,310 $3.60--$3.75
Exercised........... (48,000) $3.75 (2,687,937) $3.75 -- --
--------- --------- ---------
End of year......... 3,505,373 $3.60--$3.75 3,553,373 $3.60--$3.75 6,241,310 $3.60--$3.75
========= ========= =========
Note 11: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2005 and 2004 is as follows:
Quarter Ended
-------------------------------------------------------------
December 31 September 30 June 30 March 31
------------ ------------- ------------ ------------
(In thousands, except per share amounts)
2005:
Revenues....................... $ 1,555 $ 2,491 $ 1,003 $ 888
Net operating loss............. (6,804) (1,478) (1,724) (2,197)
Net loss....................... (6,576) (1,386) (1,570) (1,891)
Basic and diluted net loss per
common share................. $ (0.19) $ (0.04) $ (0.05) $ (0.05)
2004:
Revenues....................... $ 1,199 $ 970 $ 750 $ 887
Net operating loss............. (2,695) (1,571) (7,831) (1,052)
Net (loss) income.............. (2,449) (1,405) (7,736) (1,030)
Basic and diluted net loss per
common share................. $ (0.07) $ (0.05) $ (0.25) $ (0.04)
The net operating loss for the fourth quarter of 2005 includes $2.2 million of
gain associated with the recovery of previously expensed VAT and $4.4 million in
dry hole costs associated with the Sroda 5 and Lugi wells. 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.
Note 12: 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 2005 and 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. There were no oil and gas sales in Poland during 2005, 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.
F-22
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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.
Information on the Company's operations by business segment for 2005, 2004 and
2003 is summarized as follows:
2005
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues(1).................................................... $ 3,805 $ 2,132 $ 5,937
Operating costs(2)............................................. (8,755) (1,689) (10,444)
DD&A expense.................................................. (511) (243) (754)
------------- ------------- -------------
Operating loss................................................ $ (5,461) $ 200 $ (5,261)
============= ============= =============
Identifiable net property and equipment:
Unproved properties - Poland................................... $ 161 $ -- $ 161
Unproved properties - Domestic................................. 143 -- 143
Proved properties - Poland..................................... 10,465 -- 10,465
Proved properties - Domestic................................... 3,139 -- 3,139
Equipment and other............................................ -- 396 396
------------- ------------- -------------
Total...................................................... $ 13,908 $ 396 $ 14,304
============= ============= =============
Net Capital Expenditures:
Property and equipment(3)...................................... $ 4,288 $ 264 $ 4,552
------------- ------------- -------------
Total...................................................... $ 4,288 $ 264 $ 4,552
============= ============= =============
- --------------------
(1) All E&P revenues were generated in the United States.
(2) E&P operating costs include $3,268,000 in geological and geophysical costs,
$4,363,000 in dry hole costs, a gain of $2,176,000 attributable to recovery
of previously expensed VAT and $491,000 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.
F-23
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
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:
$ 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 $191,000 in unproved
property costs in Poland.
F-24
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
A reconciliation of the segment information to the consolidated totals for 2005,
2004 and 2003 follows:
2005 2004 2003
------------- --------------- -------------
(In thousands)
Revenues:
Reportable segments...............................................$ 5,937 $ 3,806 $ 2,328
Non-reportable segments........................................... -- -- --
------------- --------------- -------------
Total revenues...................................................$ 5,937 $ 3,806 $ 2,328
============= =============== =============
Net loss:
Operating loss, reportable segments...............................$ (5,261) $ (2,293) $ (715)
Expense or (revenue) adjustments:
Corporate DD&A expense.......................................... (149) (88) (13)
General and administrative costs (G&A).......................... (6,592) (4,909) (3,253)
Amortization of deferred compensation (G&A)..................... (125) -- --
Stock compensation (G&A)........................................ (76) (5,859) --
------------- --------------- -------------
Total net operating loss...................................... (12,203) (13,149) (3,981)
Non-operating income (loss)..................................... 780 529 (752)
Cumulative effect of change in accounting principle............. -- -- 1,800
------------- --------------- -------------
Net loss.................................................$ (11,423) $ (12,620) $ (2,933)
============= =============== =============
Net property and equipment:
Reportable segments...............................................$ 14,304 $ 14,506 $ 4,948
Corporate assets.................................................. 336 328 125
------------- --------------- -------------
Net property and equipment.......................................$ 14,640 $ 14,834 $ 5,073
============= =============== =============
Property and equipment capital expenditures:
Reportable segments...............................................$ 4,552 $ 9,612 $ 202
Corporate assets.................................................. 158 296 63
------------- --------------- -------------
Total property and equipment capital expenditures................$ 4,710 $ 9,908 $ 265
============= =============== =============
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, 2005 and 2004, are summarized as follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
December 31, 2005:
Proved properties..........................................$ 4,991 $ 7,492 $ 12,483
Unproved properties........................................ 143 3,596 3,739
--------------- --------------- --------------
Total gross properties................................... 5,134 11,088 16,222
Less accumulated depreciation, depletion and amortization.. (1,852) (462) (2,314)
--------------- --------------- --------------
$ 3,282 $ 10,626 $ 13,908
=============== =============== ==============
December 31, 2004:
Proved properties..........................................$ 4,676 $ 2,119 $ 6,795
Unproved properties........................................ 47 9,087 9,134
--------------- --------------- --------------
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
=============== =============== ==============
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 (in thousands) for
2005, 2004 and 2003 were $2,462, $1,946 and $1,546, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities
during 2005, 2004 and 2003, whether capitalized or expensed, are summarized as
follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
Year ended December 31, 2005:
Acquisition of unproved properties.........................$ 95 $ 30 $ 125
Exploration costs.......................................... 683 9,809 10,492
Development costs.......................................... 366 520 886
--------------- --------------- ---------------
Total..................................................$ 1,144 $ 10,359 $ 11,503
=============== =============== ===============
Year ended December 31, 2004:
Acquisition of unproved properties.........................$ 40 $ 141 $ 181
Exploration costs.......................................... 103 11,752 11,855
Development costs.......................................... 490 -- 490
--------------- --------------- ---------------
Total..................................................$ 633 $ 11,893 $ 12,526
=============== =============== ===============
F-26
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
United States Poland Total
--------------- --------------- ---------------
(In thousands)
Year ended December 31, 2003:
Acquisition of unproved properties.........................$ -- $ 20 $ 20
Exploration costs.......................................... -- 523 523
Development costs.......................................... 191 -- 191
--------------- --------------- ---------------
Total..................................................$ 191 $ 543 $ 734
=============== =============== ===============
Impairment of Oil and Gas Properties
The Company has recorded impairment charges in its E&P segment related to proven
oil and gas properties as follows (in thousands):
2005 2004 2003
---- ---- ----
Impairment of proved properties $ -- $ -- $ 161
============= ============= =============
Exploratory dry hole costs
During 2005, the Company plugged and abandoned the Lugi, Sroda 5 and four wells
in the Inselberg and Radio prospects in Nevada, incurring total dry hole costs
of $5,065,586. 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.
Summary Oil and Gas Reserve Data (Unaudited)
Estimated Quantities of 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. 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, 2005,
of $51.11 per bbl for oil in the United States and $50.00 per bbl of oil and
$2.97 per Mcf of gas in Poland. The determination of oil and gas reserves is
based on estimates and is highly complex and interpretive, as there are numerous
uncertainties inherent in estimating quantities and values of proved reserves,
projecting future rates of production and timing of development expenditures.
The 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 RPS Energy,
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, 2005.......................... 408 -- -- 974
December 31, 2004.......................... 809 -- -- 1,011
December 31, 2003.......................... 991 -- -- 1,116
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, 2005:
Beginning of year......................... 809 111 -- 10,198
Extensions or discoveries................. -- -- -- 7,882
Acquisition of minerals in place.......... -- 98 -- 2,199
Revisions of previous estimates........... (322) -- -- (491)
Production................................ (79) -- -- --
--------------- --------------- --------------- ---------------
End of year........................... 408 209 -- 19,788
=============== =============== =============== ===============
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
Revisions of previous estimates........... 34 -- -- (250)
Production................................ (85) -- -- --
--------------- --------------- --------------- ---------------
End of year........................... 991 114 -- 3,960
=============== =============== =============== ===============
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, "Disclosures 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, 2005:
Future cash flows..........................................$ 20,833 $ 73,114 $ 93,947
Future production costs.................................... (12,808) (2,504) (15,312)
Future development costs................................... -- (7,658) (7,658)
Future income tax expense.................................. -- (7,742) (7,742)
--------------- --------------- ---------------
Future net cash flows ..................................... 8,025 55,210 63,235
10% annual discount for estimated timing of cash flows..... (2,189) (19,131) (21,320)
--------------- --------------- ---------------
Discounted net future cash flows...........................$ 5,836 $ 36,079 $ 41,915
=============== =============== ===============
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
=============== =============== ===============
F-29
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
The principal sources of changes in SMOG are detailed below:
Year Ended December 31,
--------------------------------------------
2005 2004 2003
------------- ------------- --------------
(In thousands)
SMOG sources:
Balance, beginning of year...................................... $ 18,225 $ 9,856 $ 10,220
Sale of oil and gas produced, net of production costs........... (1,343) (1,150) (732)
Net changes in prices and production costs...................... 14,423 3,816 607
Acquisition of minerals in place................................ 4,391 -- --
Extensions and discoveries, net of future costs................. 16,243 4,135 --
Changes in estimated future development costs................... (3,232) (638) (321)
Previously estimated development costs incurred during the year. 886 588 191
Revisions in previous quantity estimates........................ (4,384) (211) 26
Accretion of discount........................................... 1,823 986 1,022
Net change in income taxes...................................... (5,131) -- --
Changes in rates of production and other........................ 14 843 (1,157)
------------- ------------- --------------
Balance, end of year........................................ $ 41,915 $ 18,225 $ 9,856
============= ============= ==============
F-30