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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
Commission File Number: 0-25386
FX ENERGY, INC.
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(Exact name of registrant as specified in its charter)
Nevada 87-0504461
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206, Salt Lake City, Utah 84106
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: Telephone (801) 486-5555
Telecopy (801) 486-5575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, Par Value $0.001
Preferred Stock Purchase Rights
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(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers in response
to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes [ ] No [X]
State the aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price at which the
common equity was last sold, or the average bid and asked price of such common
equity, as of the last business day of the registrant's most recently completed
second fiscal quarter. As of June 30, 2002, the aggregate market value of the
voting and nonvoting common equity held by nonaffiliates of the registrant was
$36,259,913.
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 20,
2003, FX Energy had outstanding 17,708,025 shares of its common stock, par value
$0.001.
DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy Statement in
connection with the 2003 Annual Meeting of Stockholders is incorporated by
reference in response to Items 10 through 13 of Part III of this Annual Report.
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FX ENERGY, INC.
Form 10-K for the fiscal year ended December 31, 2002
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Table of Contents
Item Page
---- ----
Part I
-- Special Note on Forward-Looking Statements........................ 1
1 and 2 Business and Properties........................................... 2
3 Legal Proceedings................................................. 17
4 Submission of Matters to a Vote of Security Holders............... 17
Part II
5 Market for Registrant's Common Equity and Related
Stockholder Matters............................................. 18
6 Selected Financial Data........................................... 20
7 Management's Discussion and Analysis of Financial Condition
and Results of Operation........................................ 21
7A Quantitative and Qualitative Disclosures about Market Risk........ 33
8 Financial Statements and Supplementary Data....................... 33
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................ 34
Part III
10 Directors and Executive Officers of the Registrant................ 35
11 Executive Compensation............................................ 35
12 Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters................................. 35
13 Certain Relationships and Related Transactions.................... 35
14 Controls and Procedures........................................... 35
Part IV
15 Exhibits, Financial Statement Schedules and Reports
on Form 8-K..................................................... 37
-- Signatures........................................................ 41
-- Certifications.................................................... 42
-- Report of Independent Accountants................................ F-1
i
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SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS
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This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "will," "should," "expect,"
"anticipate," "estimate," "project," "propose," "plan," "intend" and similar
words and expressions. We intend that the forward-looking statements will be
covered by the safe harbor provisions for forward-looking statements contained
in Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Statements that describe our future strategic plans, goals
or objectives are also forward-looking statements.
Readers of this report are cautioned that any forward-looking
statements, including those regarding us or our management's current beliefs,
expectations, anticipations, estimations, projections, proposals, plans or
intentions, are not guarantees of future performance or results of events and
involve risks and uncertainties, such as:
o our future ability to attract industry or financial partners
to share the costs of exploration, exploitation, development
and acquisition activities;
o the cost of additional capital that we may require and
possible related restrictions on our future operating or
financing flexibility;
o future plans and the financial and technical resources of
industry or financial partners;
o future events that may result in the need for additional
capital;
o future drilling and other exploration schedules and sequences
for various wells and other activities;
o the future results of drilling individual wells and other
exploration and development activities;
o future variations in well performance as compared to initial
test data;
o the prices at which we may be able to sell oil or gas;
o fluctuations in prevailing prices for oil and gas;
o uncertainties of certain terms to be determined in the future
relating to our oil and gas interests, including exploitation
fees, royalty rates and other matters;
o uncertainties regarding future political, economic,
regulatory, fiscal, taxation and other policies in Poland; and
o other factors that are not listed above.
The forward-looking information is based on present circumstances and
on our predictions respecting events that have not occurred, 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 as a result of various factors, including the
risk factors detailed in this report. The forward-looking statements included in
this report are made only as of the date of this report.
1
PART I
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ITEMS 1 AND 2. BUSINESS AND PROPERTIES
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Introduction
We are an independent oil and gas company focused on exploration,
development and production opportunities in the Republic of Poland. In
association with our partner, the Polish Oil and Gas Company, or POGC, we were
the first western company to discover and produce gas in Poland. The cooperative
working environment in Poland allows us to operate effectively with in-country
operating and technical personnel, access geological and geophysical data
readily, and obtain other necessary support in Poland. We also produce oil and
have an oilfield services company in the United States.
We are focused on Poland because of its attractive oil and gas
exploration and production opportunities. In our view, these opportunities exist
because the country has only recently been open to foreign oil and gas
companies. As a result, its known productive areas are underexplored,
underdeveloped and underexploited today. Poland's heavy dependence on oil and
gas imports and its fiscal regime favorable to foreign investment reinforce the
attractiveness of Poland.
Strategy
We seek the potential rewards of high potential exploration
opportunities while endeavoring to minimize our exposure to the risks normally
associated with exploration. We compensate for our small size and limited
capital by leveraging our land position against the financial and technical
resources of larger industry partners. Our primary strategic relationship is
with POGC, a fully integrated oil and gas company owned by the Treasury of the
Republic of Poland. Our strategic alliance with POGC provides us with access to
important exploration data as well as technical and operational support. POGC is
a partner in substantially all of our ongoing activities in Poland, including
the Fences I and II project areas where POGC is the operator, Block 108 of the
Pomeranian project area where we are the operator, and the Wilga project area
where Apache Corporation is the operator. We believe that our relationship with
POGC will continue to provide additional opportunities in Poland.
We have shifted our focus away from pure exploration to concentrate on
underexplored acreage in productive fairways where we have the opportunity to
find significant gas reserves with lower risk. Our strategy is to:
o acquire large acreage positions in underexplored areas of
known production fairways, particularly where there has been
little or no exploration for many years;
o carry out an initial evaluation of the properties to provide
value uplift at low cost; and
o market these properties to industry on conventional farmout
terms.
We expect this strategy to allow us to more than recoup our costs, earn
a carried interest in the initial drilling phase without direct financial
exposure of our own, and retain the upside of a substantial interest in
potential reserves. We have a successful track record of arranging industry
farmouts in Poland in several different areas.
Project Areas
Our ongoing activities in Poland are conducted in five project areas:
Pomeranian, Wilga, and Fences I, II and III. Our focus today is on the three
Fences project areas, where the gas-bearing Rotliegendes sandstone reservoir
rock in Poland's Permian basin is a direct analog to the Southern North Sea, or
SNS, gas basin offshore England. Underpinning our focus on the three Fences
areas are the lack of exploration in these areas over the past two decades and
the availability of new geophysical technology that has proved successful in the
SNS.
Fences I is 265,000 acres (1,074 sq. km) in western Poland's Permian
basin where we hold a 49% interest. Several gas fields located in the Fences I
block are excluded or "fenced off" from our exploration acreage. These fields,
2
discovered by POGC between 1974 and 1982, produce from Rotliegendes sandstone
reservoirs and contain total recoverable reserves of over 500 Bcf of gas.
Fences II is 670,000 acres (2,715 sq. km) located north of and
contiguous with the Fences I block. The 450 Bcf Radlin field forms part of the
block's southern border. Under a January 2003 agreement, we have the right to
earn a 49% interest from POGC.
Fences III is 770,000 acres (3,122 sq. km) located approximately 25
miles south of Fences I. In March 2003, we reached agreement with the Ministry
of the Environment in Poland on final principal terms, subject to formal
documentation, for 100% of the exploration rights to the Fences III project
area. As with the Fences I block, several gas fields located in the Fences III
block are fenced off from the exploration acreage. These fields, discovered by
POGC between 1967 and 1976, produced from both Rotliegendes sandstone and
Zechstein carbonate reservoirs and contained total reserves of approximately 950
Bcf of gas. There has not been an exploration program on this acreage in more
than 25 years.
We signed a farmout agreement covering the Fences I block in January
2003, with CalEnergy Gas, the upstream gas business unit of MidAmerican Energy
Holdings Company, whereby CalEnergy Gas has the right, but not the obligation,
to earn a 24.5% interest by spending a total of $10.6 million, including the
cost to drill two wells, plus certain cash payments to us. We are in early stage
discussions with several SNS-experienced companies regarding Fences II and
Fences III.
The Fences I, II and III project areas (a total of 1.7 million gross
acres or 6,911 sq. km) are within an area of underexplored Rotliegendes
sandstone. Cumulative Rotliegendes discoveries in Poland amount to 5 Tcf
compared to 42 Tcf in the SNS. An exploration program to look for Rotliegendes
gas reserves has not been undertaken in Poland using the technology available
today, and no sustained exploration effort has been made in the three Fences
project areas for Rotliegendes gas fields in the last 20 years.
In addition to the Fences project areas, we hold a 45% interest in
Block 255, a 250,000 acre block where the Wilga #2 discovery well is located.
The well was tested and completed, but is not currently in production. We also
hold an 85% interest in a 227,000 acre block in the Pomeranian project area
where the Tuchola #6 discovery was drilled in 2001, and 100% interest in the
remaining approximately 2.0 million acres in the Pomeranian project area.
During the balance of 2003, we anticipate that CalEnergy Gas will drill
two wells in the Fences I project area. We will also be marketing the Fences II
project area to industry for farmout, and may see one well drilled in this area
in 2003. In addition, we will be evaluating and reprocessing seismic data, and
perhaps acquiring new seismic data, in the Fences III project area to prepare
for farming out. We also expect to advance our discussions with POGC concerning
the possible expansion of our joint interests in Poland.
Assumptions
References to us in this report include FX Energy, Inc., our
subsidiaries and the entities or enterprises organized under Polish law in which
we have an interest and through which we conduct our activities in that country.
All historical production and test data about Poland, excluding wells
in which we have participated, have been derived from information furnished by
either POGC or the Polish Ministry of Environmental Protection, Natural
Resources and Forestry unless noted otherwise.
3
The Republic of Poland
The Republic of Poland is located in 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. Gross domestic production had been strong and steady in 1993
through 2000, but fell back in 2001 and 2002 with slowdowns in domestic
investment and consumption and the persistent weakness in the European economy,
according to the CIA fact book on Poland. The contribution of the private sector
to gross domestic production rose from around 18% in 1989 to 39% in 1995 and 70%
in 1999, even though privatization has gone relatively slowly. Private-sector
nonagricultural employment rose from 14% of the labor force in 1989 to 61% in
1999. The Polish government credits foreign investment as a forceful growth
factor in successfully creating a stable free-market economy. According to the
Polish Foreign Investment Agency, cumulative foreign direct investment flow into
Poland is estimated to have aggregated approximately $62 billion from 1989
through mid-2002.
Since its transition to a market economy and a parliamentary democracy,
Poland has experienced significant economic growth and political change. Poland
has developed and is refining legal, tax and regulatory systems characteristic
of parliamentary democracies with interpretation and procedural safeguards. The
Polish government has generally taken steps to harmonize Polish legislation with
that of the European Union in anticipation of Poland's entry into the European
Union in 2004 and to facilitate interaction with European Union members. Since
1995, the Polish corporate income tax rate has been reduced each year, and now
stands at 27% of net income.
Poland has created an attractive legal framework and fiscal regime for
oil and gas exploration by actively encouraging investment by foreign companies
to offset its lack of capital to further explore its oil and gas resources. In
July 1995, Poland's Council of Ministers approved a program to restructure and
privatize the Polish petroleum sector. So far under this plan, a refinery
located in Plock has been privatized as a publicly-held company with its stock
trading on the London and Warsaw stock exchanges. We expect that the gas
distribution segments of POGC will be privatized next, followed by the
exploration, production and oilfield services segment. Increased participation
by Western companies using Western capital in the oil and gas sector is
consistent with the approved privatization policy.
Prior to becoming a parliamentary democracy during 1989, the
exploration and development of Poland's oil and gas resources were hindered by a
combination of foreign influence, a centrally-controlled economy, limited
financial resources, and a lack of modern exploration technology. As a result,
Poland is currently a net energy importer. Oil is imported primarily from
countries of the former Soviet Union and the Middle East, and gas is imported
primarily from Russia. In the early 1990s, the World Bank loaned Poland $250
million to fund the purchase of new exploration and drilling equipment for
Poland's oil and gas industry to help shift its domestic sources of energy
consumed from coal to oil and natural gas. The following table highlights
selected statistics obtained from the U.S. Department of Energy regarding the
oil and gas industry in Poland:
Oil Gas
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Proved reserves as of January 1, 2002....................... 114.9 MMBbls 5.1 Tcf
Average production per day during 2001...................... 14,000 Bbls per day 0.5 Bcf per day
Average imports per day during 2001......................... 420,000 Bbls per day 0.8 Bcf per day
During 1998, Poland joined NATO and has been invited to join the
European Union in 2004. In order to achieve member status in the European Union,
Poland must raise its environmental standards. In Poland, coal is the dominant
energy source, accounting for 65.4% of the country's annual energy consumption
as recently as 2000. Increased consumption of natural gas, as an alternative to
coal, is considered to be a key component in meeting the European Union's strict
environmental guidelines for its members. The demand for gas in Poland is
expected to increase in the future, primarily due to increased economic growth
coupled with the conversion to gas from coal as an energy source for power
plants.
4
Poland has crude oil pipelines serving the major refineries and a
network of gas pipelines serving major metropolitan, commercial, industrial and
gas production areas, including significant portions of our acreage. Poland has
a well-developed infrastructure of hard-surfaced roads and railways over which
we believe oil produced could be transported for sale. There are refineries in
Gdansk and Plock in Poland and one in Germany near the western Polish border
that we believe could process any crude oil we may produce in Poland. All
facilities and pipelines currently used to gather and transport oil and gas in
Poland are owned and operated by POGC.
Exploration, Development and Production Activities in Poland
Exploratory Activities in Poland
Our strategy is to bring industry partners into our projects in Poland
to provide the capital for early-stage exploration drilling. In January 2003, we
entered into a farmout agreement with CalEnergy Gas that allows it to spend a
total of $10.6 million by December 15, 2003, including the cost to drill two
wells plus certain cash payments to us, to earn a 24.5% interest (half of our
49% interest) in our Fences I project area. Full performance by CalEnergy Gas
would more than cover our $4.4 million obligation to POGC and complete our $16.0
million earning requirement for the Fences I project area. However, any such
payment to us is pledged to RRPV until the note, with a principal balance of
approximately $3.3 million, plus interest, has been satisfied in full. We are
seeking an industry partner for our Fences II project area, and following our
initial evaluation of the Fences III area, we plan to seek other industry
partners to join us.
Polish Exploration Rights
As of December 31, 2002, our oil and gas exploration rights in Poland
were comprised of the following gross acreage components:
Operator
----------------------------------------------- Total
FX Energy Apache POGC Acreage
--------------- --------------- --------------- ---------------
Project Area:
Fences I(1)............................... -- -- 265,000 265,000
Pomeranian(2)............................. 2,200,000 -- -- 2,200,000
Wilga(3).................................. -- 250,000 -- 250,000
--------------- --------------- --------------- ---------------
Total gross acreage..................... 2,200,000 250,000 265,000 2,715,000
=============== =============== =============== ===============
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(1) In April 2000, we entered into an agreement with POGC to earn 49% of POGC's
100% interest in the Fences I project area by spending $16.0 million of
exploration costs.
(2) We own a 100% interest in the Pomeranian project area, except for Block 108
(approximately 250,000 acres), where we own an 85% interest and POGC owns a
15% interest.
(3) We own a 45% interest, Apache owns a 45% interest and POGC owns a 10%
interest in the Wilga project area.
The foregoing table excludes 670,000 acres in the Fences II project area,
operated by POGC, in which we have the right to acquire a 49% interest under a
January 2003 agreement, and 770,000 acres in the Fences III project area, to be
operated by us, in which we will have the right to acquire 100% of the
exploration rights, subject to final documentation.
As we continue to explore and evaluate our acreage in Poland, we expect
to increasingly focus our operational and financial efforts on known productive
trends and recent discoveries. As we do so, we may elect not to retain our
interest in acreage that we determine carries a higher exploration risk.
Fences I Project Area
The Fences I project area consists of approximately 265,000 gross 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 the exploration acreage.
These fields, discovered by POGC between 1974 and 1982, produce from
5
Rotliegendes sandstone reservoirs with cumulative recoverable reserves of over
500 Bcf of gas. The Rotliegendes is the primary target horizon throughout most
of the Fences I project area, at depths from about 2,800 to 3,200 meters, except
along the extreme southwest portion where the target reservoir is carbonates of
the lower Permian.
In April 2000, we agreed to spend $16.0 million on exploration costs in
the Fences I project area to earn a 49% interest. When expenditures exceed $16.0
million, POGC will pay its 51% share of further costs. To date, we have incurred
expenditures of $10.6 million (including $4.4 million in accrued liabilities
payable to POGC on or before December 31, 2003) toward the $16.0 million
commitment, leaving a remaining work commitment of $5.4 million.
During 2000, we drilled the Kleka 11, our first Rotliegendes target,
which began producing in early 2001. During 2001, we drilled the Mieszkow 1, an
exploratory dry hole. The Mieszkow well demonstrated the need to apply modern
seismic processing and to assure careful handling of velocities in seismic
interpretation. In 2002, we reprocessed approximately 1,200 km of 2-D seismic
data that had not previously been processed with modern geophysical techniques,
covering most of the Fences area. POGC has since begun reprocessing some of the
3-D data in the Fences I area.
In January 2003, we entered into a Farmout Agreement with CalEnergy
Gas, the upstream gas business unit of MidAmerican Energy Holdings Company,
whereby CalEnergy Gas has the right, but not the obligation, to earn a 24.5%
interest by spending a total of $10.6 million, including the cost to drill two
wells plus certain cash payments to us, all to be completed by December 15,
2003. CalEnergy Gas also has the right to terminate participation after each of
the first two wells. However, if CalEnergy Gas completes all the earning
requirements, the work performed and payments will exceed our remaining
obligations to POGC to complete our earning requirements in the Fences I project
area. However, any such payment to us is pledged to RRPV until the note, with a
principal balance of approximately $3.3 million, plus interest, has been
satisfied in full.
Fences II Project Area
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 450 Bcf Radlin field
forms part of the Fences II southern border. Under a January 2003 agreement, we
have the right to earn a 49% interest from POGC, subject to satisfactory
completion of our obligations in Fences I. In early 2002, Conoco, Inc., Ruhrgas
and POGC drilled a dry hole in the northeast of the Fences II area. The well,
although dry, did confirm the presence of reservoir quality Rotliegendes
sandstone at a depth of more than 3,700 meters, which makes virtually the entire
block prospective for Rotliegendes subject to accurate geophysical resolution of
the trapping features.
A significant amount of geological and geophysical work was completed
by POGC and Conoco before Conoco's withdrawal from the project at the end of
2002. As a result, we were able immediately to begin marketing drill-ready
prospects in the Fences II project area. We plan to bring an industry partner
into the project as soon as possible, perhaps in time to drill in 2003. We are
currently gathering the abundant seismic data for evaluation and possible
reprocessing. Later this year, we may acquire new 2-D data to define additional
prospects for drilling.
Fences III Project Area
The Fences III project area is 770,000 acres (3,122 sq. km) located
approximately 25 miles south of Fences I. In March 2003, we reached agreement
with the Ministry of the Environment in Poland on final principal terms, subject
to formal documentation, for 100% of the exploration rights to the Fences III
project area. As with the Fences I block, several gas fields located in the
Fences III block are fenced off from the exploration acreage. These fields,
discovered by POGC between 1967 and 1976, produced from both Rotliegendes
sandstone and Zechstein carbonate reservoirs and contained total reserves of
approximately 950 Bcf of gas. There has not been an exploration program on this
acreage in 25 years.
We are currently gathering the seismic data, quite abundant in the
northern portion of the block, for evaluation, mapping and possible
6
reprocessing. We will have to carry out a geophysical exploration program to
identify leads and prospects that merit drilling. Subject to the availability of
funds, we will carry out this work before bringing in a partner. However, as we
hold 100% interest in the area, we have greater flexibility and could bring in a
partner to help with the geophysical costs if we so elected.
The Fences I, II and III project areas (a total of 1.7 million gross
acres or 6,911 sq. km) are all within an area of underexplored Rotliegendes
sandstone. Cumulative Rotliegendes discoveries in Poland amount to 5 Tcf
compared to 42 Tcf in the SNS. An exploration program focused on Rotliegendes
gas reserves has not been undertaken in Poland using the technology available
today, and no sustained exploration effort has been made in the three Fences
project areas for Rotliegendes gas fields in the last 20 years.
Pomeranian Project Area
We are the operator and have a 100% interest in the Pomeranian project
area, except for Block 108, where we have an 85% interest and POGC has a 15%
interest. The Pomeranian project area is located in northwestern Poland and
consists of exploration rights covering approximately 2.2 million gross acres
lying along the underexplored northern edge of the Permian Basin in northwestern
Poland. The Pomeranian project area is relatively unexplored and has had little
oil and gas production. We believe portions of the Pomeranian project area may
be geologically similar to the producing trends along the southern edge of
Poland's Permian Basin. In the past, POGC provided us with existing seismic data
and well logs and cores from the Pomeranian project area for reprocessing and
analysis. During 2000 and 2001, we and our previous partners acquired
approximately 600 kilometers of new 2-D seismic data in the Pomeranian project
area and drilled two wells: the Tuchola 108-2 and the Chojnice 108-6. An
open-hole test on the Tuchola 108-2 resulted in a flow rate of 9.5 MMcf of gas
per day from the Main Dolomite Reef formation at a depth between 2,535 meters
and 2,595 meters. The Tuchola 108-2 well was subsequently completed in an
approximately 200 foot thick section of the Main Dolomite, but remains shut-in.
The Chojnice 108-6 was drilled at an offset location approximately three
kilometers northwest of the Tuchola 108-2 and was subsequently determined to be
an exploratory dry hole. We intend to farm out part of our interest to an
industry partner prior to conducting further exploratory activities on the
Pomeranian project area.
Wilga/Block 255 Project Area
The Wilga project area in central southeast Poland consists of
exploration rights on approximately 250,000 gross acres held by us, Apache and
POGC in Block 255, where the Wilga 2 discovery well is located. We have a 45%
working interest in the Wilga project area, which is operated by Apache. Initial
production tests on the Wilga 2 yielded a combined gross flow rate of 16.9 MMcf
of gas and 570 Bbls of condensate per day from the Carboniferous formation at a
depth of approximately 2,800 meters. During 2001, we and our partners
successfully completed an extended flow test on the Wilga 2, confirming that the
well is capable of quite high rates of production, but the well continues to be
shut-in. No further exploration is planned for the block at this time.
Polish Properties
Legal Framework
General Usufruct and Concession Terms
In 1994, Poland adopted the Geological and Mining Law, which specifies
the process for obtaining domestic exploration and exploitation rights. All of
our rights in Poland have been awarded pursuant to this law. Under the
Geological and Mining Law, the concession authority enters into oil, gas and
mining usufruct (lease) agreements that grant the holder the exclusive right to
explore or exploit the designated oil and gas or minerals for a specified period
under prescribed terms and conditions. The holder of the mining usufruct must
also acquire an exploration concession to obtain surface access to the
exploration area by applying to the concession authority and providing the
opportunity for comment by local governmental authorities.
The concession authority has granted us oil and gas exploration rights
on the Wilga and Pomeranian project areas, is expected to do so on the Fences
III project area in the near future, and has granted POGC oil and gas
7
exploration rights on the Fences I and II project areas. The agreements divide
these areas into blocks, generally containing approximately 250,000 acres each.
Concession licenses have been acquired for surface access to all areas that lie
within existing usufructs, except Fences III. The first three-year exploration
period begins after the date of the last concession signed under each respective
usufruct. We believe all material concession terms have been satisfied to date.
If commercially viable oil or gas is developed, the concession owner
would be required to apply for an exploitation concession, as provided by the
usufructs, generally with a term of 25 to 30 years or so long as commercial
production continues. Upon the grant of the exploitation concession, the
concession owner may become obligated to pay a fee, to be negotiated but
expected to be less than 1% of the market value of the estimated recoverable
reserves in place. The concession owner would also be required to pay a royalty
on any production, the amount of which will be set by the Council of Ministers,
within a range established by legislation for the mineral being extracted. The
royalty rate for gas is currently $0.03 per Mcf. This rate could be increased or
decreased by the Council of Ministers between $0.02 and $0.08 per Mcf (the
current statutory minimum and maximum royalty rate). Local governments will
receive 60% of any royalties paid on production. The holder of the exploitation
concession license must also acquire rights to use the land from the surface
owner. The usufruct owner could be subject to significant delays in obtaining
the consents of local authorities or satisfying other governmental requirements
prior to obtaining an exploitation concession.
Fences I Project Area
The Fences I project area consists of a single oil and gas exploration
concession controlled by POGC. Three producing fields lie within the concession
boundaries (Radlin, Kleka and Kaleje), but are excluded from the Fences I
project area. The concession is for a period of six years ending in September
2007 and carries a work requirement during the first three years of one
exploratory well, 70 square kilometers of 3-D seismic data, and reprocessing of
400 kilometers of 2-D seismic data. The seismic reprocessing requirement has
been completed.
Fences II Project Area
The Fences II project area consists of four oil and gas exploration
concessions controlled by POGC. The concessions have expiration dates ranging
from July 2004 to August 2007, with three-year extension rights. Remaining work
commitments in the aggregate include 70 kilometers of 3-D seismic, 250
kilometers of new 2-D seismic, 100 kilometers of seismic reprocessing and
drilling four wells.
Fences III Project Area
We expect that the formal agreement, when completed, for the Fences III
project area will provide for a single oil and gas exploration concession that
will be held by us. Several producing fields lie within the concession
boundaries, but are excluded from the Fences III project area. The concession
will be for a period of six years ending in mid-2009 and will carry a work
requirement during the first two years, which will not include any drilling.
Wilga/Block 255 Project Area
The Wilga project area consists of a single oil and gas exploration
concession controlled by Apache. The concession is for a period of six years
ending in August 2003, when the concession must be relinquished except for lands
within exploitation concessions or for which an application for an exploitation
concession has been filed. All work commitments have been completed.
Pomeranian Project Area
The Pomeranian project area consists of 10 oil and gas concessions
controlled by us. The concessions are for a period of six years ending in
December 2004, when the concession must be relinquished except for lands within
exploitation concessions or for which an application for an exploitation
concession has been filed. All work commitments have been completed except for
the drilling of one well in 2004.
8
As of December 31, 2002, all required usufruct/concession payments had
been made for each of the above project areas.
Production, Transportation and Marketing
Poland has crude oil pipelines traversing the country and a network of
gas pipelines serving major metropolitan, commercial, industrial and gas
production areas, including significant portions of our acreage. Poland has a
well-developed infrastructure of hard-surfaced roads and railways over which we
believe oil produced could be transported for sale. There are refineries in
Gdansk and Plock in Poland and one in Germany near the western Polish border
that we believe could process crude oil produced in Poland. Should we choose to
export any oil or gas we produce, we will be required to obtain prior
governmental approval.
During early 2001, we and POGC constructed a pipeline from the Kleka 11
well approximately four kilometers to POGC's Radlin field gas processing
facility and began selling gas produced to POGC at a price of $2.02 per MMBtu
under a five-year contract that may be terminated by us with a 90-day written
notice. The Kleka 11 is currently producing at a gross rate of approximately 1.0
MMcf of gas per day. As part of an agreement with POGC, we have agreed to assign
our interest in the Kleka 11 well, including amounts representing unpaid gas
sales, to POGC as partial settlement of the remaining obligation under our $16.0
million commitment to POGC. Accordingly, we will receive no net gas production
from the Kleka 11 well in 2003. See Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operation.
The following table sets forth our average net daily gas production,
average sales price and average production costs associated with our Polish gas
production during 2002 and 2001:
2002 2001
---- ----
Polish producing property data:
Average daily net gas production (Mcf)(1)..... 494 800
Average sales price per Mcf................... $ 1.58 $ 1.58
Average production costs per Mcf(2)........... $ 0.16 $ 0.16
- --------------------
(1) Consists solely of the Kleka 11 well, which began producing on February 22,
2001, and which we have now agreed to transfer to POGC. Production was
curtailed in 2002 to control the production of water.
(2) Production costs include lifting costs (electricity, fuel, water, disposal,
repairs, maintenance, pumper, transportation and similar items). Production
costs do not include such items as G&A costs, depreciation, depletion or
Polish income taxes.
We did not have any Polish oil or gas production during 2000.
9
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 2002 follows:
Average Daily Production
(Bbls) Average Average
---------------------------- Working Net Revenue
Gross Net Interest Interest
------------- -------------- -------------- --------------------
United States producing properties:
Montana:
Cut Bank............................ 257 220 99.5% 85.7%
Bears Den........................... 16 6 48.0 39.2
Rattlers Butte...................... 48 3 6.3 5.1
------------- --------------
Total............................. 321 229
------------- --------------
Nevada:
Trap Spring......................... 10 2 21.6 20.0
Munson Ranch........................ 40 14 36.0 34.1
Bacon Flat.......................... 36 4 16.9 12.5
------------- --------------
Total............................. 86 20
------------- --------------
Total United States producing
properties................... 407 249
============= ==============
In Montana, we operate the Cut Bank and Bears Den fields and have an
interest in the Rattlers Butte field, which is operated by an industry partner.
Production in the Cut Bank field commenced with the discovery of oil in the
1940s at an average depth of approximately 2,900 feet. The Southwest Cut Bank
Sand Unit, which is the core of our interest in the field, was originally formed
by Phillips Petroleum Company in 1963. An initial pilot waterflood program was
started in 1964 by Phillips and eventually encompassed the entire unit with
producing wells on 40 and 80-acre spacing. In the Cut Bank field, we own an
average working interest of 99.5% in 93 producing oil wells, 27 active injection
wells and one active water supply well. The Bears Den field was discovered in
1929 and has been under waterflood since 1990. In the Bears Den field, we own a
48% working interest in three active water injection wells and five producing
oil wells, which produce oil at a depth of approximately 2,430 feet. The
Rattlers Butte field was discovered during 1997. In the Rattlers Butte field, we
own a 6.3% working interest in two oil wells producing at a depth of
approximately 5,800 feet and one active water injection well.
In Nevada, we operate the Trap Spring and Munson Ranch fields and have
an interest in the Bacon Flat field, which is operated by an industry partner.
The Trap Spring field was discovered in 1976. In the Trap Spring field, we
produce oil from a depth of approximately 3,700 feet from one well, with a
working interest of 21.6%. The Munson Ranch field was discovered in 1988. In the
Munson Ranch field, we produce oil at an average depth of 3,800 feet from five
wells, with an average working interest of 36%. The Bacon Flat field was
discovered in 1981. In the Bacon Flat field, we produce oil from one well at a
depth of approximately 5,000 feet, with a 16.9% working interest.
10
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 2002, 2001 and 2000:
Years Ended December 31,
-------------------------------------
2002 2001 2000
----------- ----------- -----------
United States producing property data:
Average daily net oil production (Bbls).......................... 249 256 265
Average sales price per Bbl...................................... $21.19 $19.41 $26.14
Average production costs per Bbl(1).............................. $14.59 $14.50 $13.99
- ----------------------
(1) Production costs include lifting costs (electricity, fuel, water, disposal,
repairs, maintenance, pumper, transportation and similar items) and
production taxes. Production costs do not include such items as G&A costs,
depreciation, depletion, state income taxes or federal income taxes.
We sell oil at posted field prices to one of several purchasers in each
of our production areas. For the first half of 2002 and for the years ended
December 31, 2001 and 2000, more than 85% of our total oil sales were to CENEX,
a regional refiner and marketer. In June 2002, we began selling our Montana
production, which represents over 85% of our total oil sales, to Plains
Marketing Canada L.P. Posted prices are generally competitive among crude oil
purchasers. Our crude oil sales contracts may be terminated by either party upon
30 days' notice.
Oilfield Services - Drilling Rig and Well-Servicing Equipment
In Montana, we perform a variety of third-party contract oilfield
services, including drilling, workovers, location work, cementing and acidizing.
We currently have a drilling rig capable of drilling to a vertical depth of
6,000 feet, a workover rig, two service rigs, cementing equipment, acidizing
equipment and other associated oilfield servicing equipment. We first started
our oilfield servicing business in 1998 in an effort to increase our United
States revenues, which had been declining due to the depressed oil prices that
had occurred throughout that year.
Proved Reserves
Proved reserves are the estimated quantities of crude oil 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, 2002, of $25.00 per Bbl for oil in
the United States and $2.60 per Mcf of gas in Poland. The determination of oil
and gas reserves is based on estimates and is highly complex and interpretive,
as there are numerous uncertainties inherent in estimated quantities and values
of proved reserves, projecting future rates of production and timing of
development expenditures. The estimated present value, discounted at 10% per
annum, of the discounted future net cash flows, or PV-10 Value, was determined
in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities" and SEC
guidelines. Our proved reserve estimates are subject to continuing revisions as
additional information becomes available or assumptions change.
Estimates of our proved United States oil reserves were prepared by
Larry Krause Consulting, an independent engineering firm in Billings, Montana.
Estimates of our proved Polish gas reserves were prepared by Troy-Ikoda Limited,
an independent engineering firm in the United Kingdom. No estimates of our
proved reserves have been filed with or included in any report to any other
federal agency during 2002.
11
The following summary of proved reserve information as of December 31,
2002, represents estimates net to us only and should not be construed as exact:
United States Poland
---------------------------- --------------------------- Total
Oil PV-10 Value Gas PV-10 Value PV-10 Value
------------ --------------- ------------ -------------- ------------------
(MBbls) (In thousands) (MMcf) (In thousands) (In thousands)
Proved reserves:
Developed producing........ 1,015 $ 5,190 1,374 $ 1,066 $ 6,256
Undeveloped................ 27 190 2,836 3,774 3,964
------------ --------------- ------------ -------------- ------------------
Total.................... 1,042 $ 5,380 4,210 $ 4,840 $10,220
============ =============== ============ ============== ==================
Drilling Activities
The following table sets forth the exploratory wells that we drilled
during the years ended December 31, 2002, 2001 and 2000:
Years Ended December 31,
-------------------------------------------------------------------
2002 2001 2000
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- ---------- --------- ---------- --------- ----------
Discoveries:
United States....................... -- -- -- -- -- --
Poland.............................. -- -- 1.0 0.5 1.0 0.5
---------- ---------- --------- ---------- --------- ----------
Total............................. -- -- 1.0 0.5 1.0 0.5
---------- ---------- --------- ---------- --------- ----------
Exploratory dry holes:
United States....................... -- -- -- -- -- --
Poland.............................. -- -- 2.0 1.0 2.0 1.0
---------- ---------- --------- ---------- --------- ----------
Total............................. -- -- 2.0 1.0 2.0 1.0
---------- ---------- --------- ---------- --------- ----------
Total wells drilled................... -- -- 3.0 1.5 3.0 1.5
========== ========== ========= ========== ========= ==========
We did not drill any exploratory wells in 2002, and we did not drill
any development wells during 2002, 2001 or 2000.
Wells and Acreage
As of December 31, 2002, our producing gross and net well count
consisted of the following:
Number of Wells
------------------------
Gross Net
----------- -----------
Well count:
United States(1).................................................................. 118.0 107.2
Poland(2)......................................................................... 1.0 0.5
----------- -----------
Total........................................................................... 119.0 107.7
=========== ===========
- -------------------------
(1) All of our United States wells are producing oil wells. We have no gas
production in the United States.
(2) Includes only the Kleka 11, a producing gas
well which we have now agreed to transfer to POGC.
12
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas acreage as of December 31, 2002:
Developed Undeveloped
---------------------------- ----------------------------
Gross Net Gross Net
---------------------------- ----------------------------
United States:
North Dakota................................. -- -- 7,955 5,351
Montana...................................... 10,732 10,418 1,150 1,057
Nevada....................................... 400 128 37 16
------------- ------------- ------------- --------------
Total..................................... 11,132 10,546 9,142 6,424
------------- ------------- ------------- --------------
Poland: (1)(2)
Fences I project area(3)..................... 225 110 265,000 130,000
Wilga project area........................... 543 244 250,000 113,000
Pomeranian project area(4)................... -- -- 2,200,000 2,135,000
------------- ------------- ------------- --------------
Total Polish acreage..................... 768 354 2,715,000 2,378,000
------------- ------------- ------------- --------------
Total Acreage.................................. 11,900 10,900 2,724,142 2,384,424
============= ============= ============= ==============
- ------------------------
(1) All gross undeveloped Polish acreage is rounded to the nearest 50,000 acres
and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.
(2) Developed acreage in the Fences project areas is attributable only to the
Kleka 11 well, which we have now agreed to transfer to POGC. The net
acreage amount assumes we spend $16.0 million of exploration expenditures
to earn a 49% interest.
(3) Excludes acreage in which we may earn an interest under arrangements
reached after December 31, 2002.
(4) We own a 100% interest in the Pomeranian project area, except for Block 108
(approximately 250,000 acres), where we own an 85% interest.
Government Regulation
Poland
Our activities in Poland are subject to political, economic and other
uncertainties, including the adoption of new laws, regulations or administrative
policies that may adversely affect us or the terms of our exploration or
production rights; political instability and changes in government or public or
administrative policies; export and transportation tariffs and local and
national taxes; foreign exchange and currency restrictions and fluctuations;
repatriation limitations; inflation; environmental regulations and other
matters. These operations in Poland are subject to the Geological and Mining Law
dated as of September 4, 1994, and the Protection and Management of the
Environment Act dated as of January 31, 1980, which are the current primary
statutes governing environmental protection. Agreements with the government of
Poland respecting our areas create certain standards to be met regarding
environmental protection. Participants in oil and gas exploration, development
and production activities generally are required to (1) adhere to good
international petroleum industry practices, including practices relating to the
protection of the environment; and (2) prepare and submit geological work plans,
with specific attention to environmental matters, to the appropriate agency of
state geological administration for its approval prior to engaging in field
operations such as seismic data acquisition, exploratory drilling and field-wide
development. Poland's regulatory framework respecting environmental protection
is not as fully developed and detailed as that which exists in the United
States. We intend to conduct our operations in Poland in accordance with good
international petroleum industry practices and, as they develop, Polish
requirements.
As Poland continues to progress towards its stated goal of becoming a
member of the European Union, it is expected to pass further legislation aimed
at harmonizing Polish environmental law with that of the European Union.
13
United States
State and Local Regulation of Drilling and Production
Our exploration and production operations are subject to various types
of regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells and regulating the location of wells, the method
of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, and the plugging and abandoning of wells. Our
operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration
units and the density of wells that may be drilled and the unitization or
pooling of oil and gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely on voluntary pooling of lands and leases. In addition, state conservation
laws establish maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of gas and impose certain requirements regarding
the ratability of production.
Our oil production is affected to some degree by state regulations.
States in which we operate have statutory provisions regulating the production
and sale of oil and gas, including provisions regarding deliverability. Such
statutes and related regulations are generally intended to prevent waste of oil
and gas and to protect correlative rights to produce oil and gas between owners
of a common reservoir. Certain state regulatory authorities also regulate the
amount of oil and gas produced by assigning allowable rates of production to
each well or proration unit.
Environmental Regulations
The federal government and various state and local governments have
adopted laws and regulations regarding the control of contamination of the
environment. These laws and regulations may require the acquisition of a permit
by operators before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution resulting from
our operations. These laws and regulations may also increase the costs of
drilling and operation of wells. We may also be held liable for the costs of
removal and damages arising out of a pollution incident to the extent set forth
in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act
of 1990, or OPA `90. In addition, we may be subject to other civil claims
arising out of any such incident. As with any owner of property, we are also
subject to clean-up costs and liability for hazardous materials, asbestos or any
other toxic or hazardous substance that may exist on or under any of our
properties. We believe that we are in compliance in all material respects with
such laws, rules and regulations and that continued compliance will not have a
material adverse effect on our operations or financial condition. Furthermore,
we do not believe that we are affected in a significantly different manner by
these laws and regulations than our competitors in the oil and gas industry.
The Comprehensive Environmental Response, Compensation and Liability
Act, or CERCLA, also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources, and for the costs of certain
health studies. Furthermore, it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.
The Resource Conservation and Recovery Act, or RCRA, and regulations
promulgated thereunder govern the generation, storage, transfer and disposal of
hazardous wastes. RCRA, however, excludes from the definition of hazardous
wastes "drilling fluids, produced waters and other wastes associated with the
exploration, development, or production of crude oil, gas or geothermal energy."
14
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
exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent and costly handling, disposal and
clean-up requirements. The impact of any such changes, however, would not likely
be any more burdensome to us than to any other similarly situated company
involved in oil and gas exploration and production.
Federal and Indian Leases
A substantial part of our producing properties in Montana consist of
oil and gas leases issued by the Bureau of Land Management or by the Blackfeet
Tribe under the supervision of the Bureau of Indian Affairs. These activities
must comply with rules and orders that regulate aspects of the oil and gas
industry, including drilling and operating on leased land and the calculation
and payment of royalties to the federal government or the governing Indian
nation. Operations on Indian lands must also comply with applicable requirements
of the governing body of the tribe involved including, in some instances, the
employment of tribal members. We believe we are currently in full compliance
with all material provisions of such regulations.
Safety and Health Regulations
We must also conduct our operations in accordance with various laws and
regulations concerning occupational safety and health. Currently, we do not
foresee expending material amounts to comply with these occupational safety and
health laws and regulations. However, since such laws and regulations are
frequently changed, we are unable to predict the future effect of these laws and
regulations.
Title to Properties
We rely on sovereign ownership of exploration rights and mineral
interests by the Polish government in connection with our activities in Poland
and have not conducted and do not plan to conduct any independent title
examination. We regularly consult with our Polish legal counsel when doing
business in Poland.
Nearly all of our United States working interests are held under leases
from third parties. We typically obtain a title opinion concerning such
properties prior to the commencement of drilling operations. We have obtained
such title opinions or other third-party review on nearly all of our producing
properties, and we believe that we have satisfactory title to all such
properties sufficient to meet standards generally accepted in the oil and gas
industry. Our United States properties are subject to typical burdens, including
customary royalty interests and liens for current taxes, but we have concluded
that such burdens do not materially interfere with the use of such properties.
Further, we believe the economic effects of such burdens have been appropriately
reflected in our acquisition cost of such properties and reserve estimates.
Title investigation before the acquisition of undeveloped properties is less
thorough than that conducted prior to drilling, as is standard practice in the
industry.
Employees and Consultants
As of December 31, 2002, we had 28 employees, consisting of six in Salt
Lake City, Utah; 19 in Oilmont, Montana; one in Greenwich, Connecticut; and two
in Houston, Texas. Our employees are not represented by a collective bargaining
15
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.
Offices and Facilities
Our corporate offices, located at 3006 Highland Drive, Salt Lake City,
Utah, contain approximately 3,010 square feet and are rented at $2,960 per month
under a month-to-month agreement. In Montana, we own a 16,160 square foot
building located at the corner of Central and Main in Oilmont, where we utilize
4,800 square feet for our field office and rent the remaining space to unrelated
third parties for $875 per month. In Poland, we rent a small office suite for
$1,400 per month in Warsaw, at Al. Jana Pawla II 29, as an office of record in
Poland.
Oil and Gas Terms
The following terms have the indicated meaning when used in this
Report:
"Bcf" means billion cubic feet of natural gas.
"Bbl" means barrel of oil.
"Btu" means British thermal units.
"Carried" or "Carry" refers to an agreement under which one party
(carrying party) agrees to pay for all or a specified portion of costs
of another party (carried party) on a property in which both parties
own a portion of the working interest.
"Condensate" means a light hydrocarbon liquid, generally natural
gasoline (C5 to C10), that condenses to a liquid (i.e., falls out of
wet gas) as the wet gas is sent through a mechanical separator near the
well.
"Development well" means a well drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon known to
be productive.
"Exploratory well" means a well drilled to find and produce oil or gas
in an unproved area, to find a new reservoir in a field previously
found to be productive of oil or gas in another reservoir or to extend
a known reservoir.
"Field" means an area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic conditions.
"Gross" acres and "gross" wells means the total number of acres or
wells, as the case may be, in which an interest is owned, either
directly or though a subsidiary or other Polish enterprise in which we
have an interest.
"Horizon" means an underground geological formation that is the portion
of the larger formation that has sufficient porosity and permeability
to constitute a reservoir.
"MBbls" means thousand barrels of oil.
"Mcf" means one cubic foot of natural gas.
"MMBbls" means million barrels of oil.
"MMBtu" means million British thermal units, a unit of heat energy used
to measure the amount of heat that can be generated by burning gas or
oil.
16
"MMcf" means million cubic feet of natural gas.
"Net" means, when referring to wells or acres, the fractional ownership
working interests held by us, either directly or through a subsidiary
or other Polish enterprise in which we have an interest, multiplied by
the gross wells or acres.
"Proved reserves" means the estimated quantities of crude oil, gas and
gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. "Proved reserves"
may be developed or undeveloped.
"PV-10 Value" means the estimated future net revenue to be generated
from the production of proved reserves discounted to present value
using an annual discount rate of 10.0%. These amounts are calculated
net of estimated production costs and future development costs, using
prices and costs in effect as of a certain date, without escalation and
without giving effect to non property-related expenses, such G&A costs,
debt service, future income tax expense or depreciation, depletion and
amortization.
"Reservoir" means a porous and permeable underground formation
containing a natural accumulation of producible oil and/or gas that is
confined by impermeable rock or water barriers and that is distinct and
separate from other reservoirs.
"Tcf" means trillion cubic feet of natural gas.
- --------------------------------------------------------------------------------
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, 2002.
17
PART II
- --------------------------------------------------------------------------------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
Price Range of Common Stock and Dividend Policy
The following table sets forth for the periods indicated the high and
low closing prices for our common stock as quoted under the symbol "FXEN" on the
Nasdaq SmallCap Market:
Low High
--- ----
2003:
First Quarter (through March 20, 2003)........... $2.60 $3.54
2002:
Fourth Quarter................................... 2.24 3.04
Third Quarter.................................... 1.83 2.99
Second Quarter................................... 1.99 2.98
First Quarter.................................... 1.97 3.01
2001:
Fourth Quarter................................... 1.81 3.00
Third Quarter.................................... 2.55 3.20
Second Quarter................................... 2.91 6.20
First Quarter.................................... 3.50 5.94
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 20, 2003, we had approximately 4,100 stockholders.
Our common stock is currently traded on the Nasdaq SmallCap Market
under the symbol FXEN.
Recent Sales of Unregistered Securities
In August 2002, we granted to certain directors, executive officers and
key employees options to purchase an aggregate of 551,000 shares of common stock
at $2.40 per share at any time on or before seven years after the date of grant.
In June 2002, we issued to two persons an aggregate of 20,682 shares of
common stock as payment for services rendered. On the date of this transaction,
the market price for our common stock was approximately $2.15.
On March 13, 2003, we sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of
approximately $5.6 million after offering costs. Each share of preferred stock
is convertible into one share of common stock and one warrant to purchase one
share of common stock at $3.60 per share anytime between March 1, 2004, and
March 1, 2008. The preferred stock has a liquidation preference equal to the
sales price for the shares, which was $2.50 per share.
The net proceeds from the offering, plus our available cash, will be
used to reduce our obligation to RRPV by approximately $2.2 million (see
18
discussion of RRPV note amendment below), partially reduce our obligation to
POGC, fund ongoing geological and geophysical costs in Poland, and support
ongoing prospect marketing and general and administrative costs.
The foregoing transactions were the result of arm's-length negotiations
with accredited investors who were provided with our business and financial
information, including copies of our periodic reports as filed with the
Securities and Exchange Commission, and who were provided with the opportunity
to ask questions directly of our executive officers. Transactions involving the
issuances of stock to persons who, at the time of such transactions, were either
executive officers, directors, principal stockholders or other affiliates are
noted. In each case of the issuance of stock to affiliates, unless otherwise
noted, such affiliates purchased stock on the same terms at which stock was sold
to unrelated parties in contemporaneous transactions, and such transactions were
approved unanimously by the disinterested directors. In each instance, the
securities purchased were restricted securities taken for investment.
Certificates for all shares issued in the such transactions bore a restrictive
legend conspicuously on their face and stop-transfer instructions were noted
respecting such certificates on our stock transfer records. Each of the
foregoing transactions was effected in reliance on the exemption from
registration provided in Section 4(2) of the Securities Act of 1933 as
transactions not involving any public offering.
19
- --------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
The following selected consolidated financial data for the five years
ended December 31, 2002, are derived from our audited financial statements and
notes thereto, certain of which are included in this report. The selected
consolidated financial data should be read in conjunction with our Consolidated
Financial Statements and the Notes thereto included elsewhere in this report:
Years Ended December 31,
---------------------------------------------------------------
2002 2001 2000 1999 1998
----------- ------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales....................... $ 2,209 $ 2,229 $ 2,521 $ 1,554 $ 1,124
Oilfield services....................... 533 1,584 1,290 865 323
Gain on sale of property interests...... -- -- -- -- 467
----------- ------------ ------------ ------------ ------------
Total revenues........................ 2,742 3,813 3,811 2,419 1,914
----------- ------------ ------------ ------------ ------------
Operating costs and expenses:
Lease operating costs (1)............... 1,365 1,358 1,349 962 1,046
Exploration costs (2)................... 1,541 6,544 7,389 3,053 2,127
Proved property impairment (3).......... 1,038 -- -- -- 5,885
Oilfield services costs................. 540 1,301 1,084 642 240
Depreciation, depletion and
amortization.......................... 618 662 386 494 672
Amortization of deferred
compensation (G&A).................... 55 1,078 652 -- --
Apache Poland general and
administrative costs.................. -- 575 957 -- --
General and administrative.............. 2,440 883 2,654 2,962 2,572
----------- ------------ ------------ ------------ ------------
Total operating costs and expenses.. 7,597 12,401 14,471 8,113 12,542
----------- ------------ ------------ ------------ ------------
Operating loss............................ (4,855) (8,588) (10,660) (5,694) (10,628)
----------- ------------ ------------ ------------ ------------
Other income (expense):
Interest and other income............... 119 543 557 511 506
Interest expense........................ (1,189) (331) (2) (7) --
Impairment of notes receivable.......... -- (34) (738) (666) --
----------- ------------ ------------ ------------ ------------
Total other income (expense)........ (1,070) 178 (183) (162) 506
----------- ------------ ------------ ------------ ------------
Net loss.................................. $ (5,925) $ (8,410) $ (10,843) $ (5,856) $ (10,122)
=========== ============ ============ ============ ============
Basic and diluted net loss per share:
Net loss.............................. $ (0.34) $ (0.48) $ (0.66) $ (0.41) $ (0.78)
=========== ============ ============ ============ ============
Basic and diluted weighted average
shares outstanding...................... 17,641 17,673 16,435 14,199 12,979
- Continued -
20
Years Ended December 31,
-----------------------------------------------------------
2002 2001 2000 1999 1998
------------ ----------- ---------- ---------- -----------
(In thousands)
Cash Flow Statement Data:
Net cash used in operating activities............... $ (2,162) $ (3,248) $ (6,082) $ (2,984) $ (3,091)
Net cash provided by (used in) investing activities. (295) 326 (3,834) (3,678) 1,066
Net cash provided by (used in) financing activities. 5 5,000 9,375 6,469 (674)
Balance Sheet Data:
Working capital..................................... $ (9,150) $ 558 $ 616 $ 5,459 $ 3,965
Total assets........................................ 5,441 9,168 10,570 10,470 8,253
Long-term debt...................................... -- 4,907 -- -- --
Stockholders' equity................................ (4,869) 953 8,231 8,367 6,920
- -----------------------------
(1) Includes lease operating expenses and production taxes.
(2) Includes geophysical and geological costs, exploratory dry hole costs and
nonproducing leasehold impairments.
(3) Includes proved property write downs relating to our properties in the
United States and Poland.
- --------------------------------------------------------------------------------
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION
- --------------------------------------------------------------------------------
The following discussion of our historical financial condition and
results of operations should be read in conjunction with Item 6. "Selected
Consolidated Financial Data," our Consolidated Financial Statements and related
Notes contained in this report.
Introduction
As of December 31, 2002, we had approximately $700,000 of cash and cash
equivalents, a working capital deficit of approximately $9.2 million, and a
stockholders' deficit of approximately $4.9 million. In addition, we have a
remaining commitment of $5.6 million that must be spent by us (in addition to
payment of the $4.4 million to POGC, which is included in our accrued
liabilities at December 31, 2002), in order to complete our earning obligation
in our Fences project areas. These factors cause uncertainty about our ability
to continue as a going concern.
Since December 31, 2002, we have substantially improved our overall
financial position and prospects for achieving a sound financial condition by
obtaining $5.6 million in equity funding, reaching new terms respecting our
Fences 1 obligations, extending our RRPV obligation with revised terms and
entering into a farmout agreement with CalEnergy Gas under which it may provide
cash and drilling funds of up to $10.6 million. Our primary obligations through
the end of 2003 include $3.3 million principal amount plus interest due RRPV at
year end, $4.4 million plus interest due POGC at year end, $5.6 million of
Fences I work commitment, and approximately $1.8 million for general,
administrative and marketing expenses, for a total of approximately $16.0
million, plus any geological and geophysical costs we may wish to expend.
Offsetting these amounts, we have $3.8 million in available cash and may look
forward to other sources of funds including $10.6 million of work and cash that
may be realized under the CalEnergy Farmout Agreement, $0.6 million in accrued
Kleka 11 production revenue, and an amount to be determined (PV-10 value $1.1
million) for the future value of Kleka 11 production, for an approximate total
of approximately $16.0 million. In addition, we have the right to earn a 49%
interest in the Fences II project area and anticipate completing documentation
soon for a 100% interest in the Fences III project area. We believe we can
21
arrange with industry partners to trade a portion of our interest in these
properties for drilling funds and cash payments that will exceed our related
acquisition or earning and any related geological and geophysical costs.
Despite our financial condition, we believe these events have
substantially improved our ability to continue as a going concern.
Private Placement of Convertible Preferred Stock
On March 13, 2003, we sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of $5.6
million after offering costs. Each share of preferred stock is convertible into
one share of common stock and one warrant to purchase one share of common stock
at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The
preferred stock has a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.
The net proceeds from the offering, plus our available cash, were used
to reduce our obligation to RRPV (see discussion of RRPV note amendment below),
fund ongoing geological and geophysical costs in Poland, and support ongoing
prospect marketing and general and administrative costs.
CalEnergy Gas Agreement
In January 2003, we signed a farmout agreement with CalEnergy Gas
(Holdings) Ltd., an affiliate of MidAmerican Energy Holdings Company, for the
joint exploration of our Fences I project in Poland. Under the terms of the
agreement, CalEnergy Gas has the right, but not the obligation, to pay 100% of
the costs to drill an initial well, and by so doing, will earn a 24.5% interest
(50% of our interest) in that drilling prospect. Following the completion of the
initial well, CalEnergy Gas may elect to terminate the agreement or to drill a
second well. If CalEnergy Gas elects to drill a second well, it will pay us $1
million prior to drilling. CalEnergy Gas will pay 100% of the costs to drill a
second well to earn 24.5% interest in that prospect. Following the second well,
CalEnergy Gas has the option to acquire 24.5% (50% of our interest) of the
entire Fences project area by paying to us the sum of $10.6 million, less the
costs of drilling the first two wells and less the cost of any additional
geological and geophysical costs it has incurred on the Fences area. Any such
payment to us is pledged to RRPV, until its note, with a principal balance of
approximately $3.3 million, plus interest, has been satisfied in full. We expect
the net proceeds to us to be approximately $5.6 million before the end of 2003,
from which we will be obligated to pay RRPV.
All of the costs related to our 49% interest in the project area that
are paid for by CalEnergy Gas will be credited against the remaining $5.6
million obligation under our $16.0 million work obligation to POGC (see below).
CalEnergy Gas has received consent from POGC concerning the transfer of our
working interest according to the agreement terms, and RRPV has committed to
permit the transfer, free of any lien or encumbrance, of 50% of our interest to
CalEnergy Gas. We expect drilling to commence in the second quarter of 2003.
Fences I Settlement Agreement
On April 11, 2000, we agreed to spend $16.0 million of exploration
costs on the Fences project areas to earn a 49% interest. When expenditures
exceed $16.0 million, POGC will pay its 51% share of further costs. Through the
end of 2001, we had paid $6.7 million towards the $16.0 million commitment. As
of December 31, 2001, we had accrued $2,678,477 of additional costs pertaining
to the Fences project areas.
In late 2002, as part of our discussions with POGC concerning the
CalEnergy Gas agreement and the opportunity to participate with POGC in other
exploration projects, we reaffirmed our intent to fulfill the $16.0 million
commitment with POGC. In connection with this agreement, we agreed to recognize
in 2002, and pay at a future date, an additional $2.3 million of costs related
to prior exploration activities in the Fences project areas to POGC, $1.6
million of which will be credited towards the $16.0 million commitment. The 2002
amount includes $704,000 in interest costs related to our prior liabilities to
POGC, $433,000 in drilling costs, $418,000 in pipeline costs, $502,000 in
seismic costs, and $250,000 related to foreign exchange adjustments.
22
In addition, as part of our future payments towards the remaining
commitment, we have agreed to assign in 2003, as soon as is practicable, all of
our rights to the Kleka 11 well, including the amounts recorded as accounts
receivable for Kleka gas sales. Accordingly, at December 31, 2002, our
receivable from POGC in the amount of $606,986 was offset against the POGC
liability. The liability will be further offset in 2003 by the value of the
remaining gas reserves associated with the Kleka well, as determined by an
independent engineer. Lastly, we agreed to begin accruing interest on the past
due amount to POGC. The interest rate in effect at December 31, 2002, was 12.8%
per annum; the interest rate as of March 21, 2003, was 10.4%.
Rolls-Royce Power Ventures
In early 2003, we reached an agreement with RRPV to amend its 9.5%
Convertible Secured Note in the amount of $5.0 million (see Footnote 6 in the
financial statements). Our current liabilities at December 31, 2002, include the
$5.0 million principal balance, plus accrued interest of $392,000. The note is
secured by a lien on our Fences I and Wilga property interests and was repayable
in March 2003, unless converted to common stock at $5.00 per share or otherwise
amended.
In March 2003, following our successful private placement of
convertible preferred stock, we paid $2.2 million to RRPV. In return, RRPV
extended the maturity date of the note to December 31, 2003. We have also agreed
to pay 40% of the gross proceeds of any subsequent equity or debt offering
concluded prior to the amended maturity date to RRPV. We also agreed to assign
our rights to payments under the CalEnergy Gas agreement to RRPV, except for
those amounts related to drilling the two wells. All such payments will 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 us.
The loan amendment contains other terms and conditions, including an
increase in the interest rate on the note from 9.5% to 12% per annum effective
March 9, 2003, an extension of the conversion period until December 31, 2003,
with the conversion price being changed from $5.00 per share to $3.42 per share,
and an extension fee payment of $100,000.
Cost Reduction Measures
In mid-2002, we recognized that it would likely require an extended
period to consummate a farmout transaction with our Fences I project and our
ability to raise additional equity/debt would be restricted until such an
arrangement was in place. We further recognized the importance of reducing our
overhead expenses to conserve cash while in discussions with potential partners.
Effective July 1, 2002, we undertook several measures to reduce our ongoing
expenses. We cut the salaries of all key employees by 50% and did not replace
employees who left the Company. We also reduced the level of benefits available
to all employees. We cut other areas of overhead expenses where possible. In
addition to our overhead reductions, we significantly reduced the amount of
money designated for ongoing seismic and other exploration costs.
Summary
Despite our financial condition, because of the events described above,
we believe that we are well-positioned to obtain additional funding and continue
as a going concern. There can be no assurance that we will be able to obtain
additional financing or successfully complete the necessary steps to enable us
to continue as a going concern. If we are unable to obtain sufficient funds to
satisfy our future cash requirements, we may be forced to curtail operations
further, dispose of assets, issue securities to meet obligations, or seek
extended payment terms from our creditors. Such events would materially and
adversely affect our financial position and results of operations and result in
the dilution of the interests of existing stockholders.
23
Critical Accounting Policies
Oil and Gas Activities
We follow the successful efforts method of accounting for our oil and
gas properties. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves. If an
exploratory well has not found proved reserves, these costs plus the costs of
drilling the well are expensed. The costs of development wells are capitalized,
whether productive or nonproductive. Geological and geophysical costs on
exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are considered not to be realizable. An impairment loss is recorded if
the net capitalized costs of proved oil and gas properties exceed the aggregate
undiscounted future net cash flows determined on a property-by-property basis.
The impairment loss recognized equals the excess of net capitalized costs over
the related fair value, determined on a property-by-property basis. As a result
of the foregoing, our results of operations for any particular period may not be
indicative of the results that could be expected over longer periods.
Oil and Gas Reserves
Engineering estimates of our oil and gas reserves are inherently
imprecise and represent only approximate amounts because of the subjective
judgments involved in developing such information. There are authoritative
guidelines regarding the engineering criteria that have to be met before
estimated oil and gas reserves can be designated as "proved." Proved reserve
estimates are updated at least annually and take into account recent production
and technical information about each field. In addition, as prices and cost
levels change from year to year, the estimate of proved reserves also changes.
This change is considered a change in estimate for accounting purposes and is
reflected on a prospective basis in related depreciation rates.
Despite the inherent imprecision in these engineering estimates, these
estimates are used in determining depreciation expense and impairment expense
and in disclosing the supplemental standardized measure of discounted future net
cash flows relating to proved oil and gas properties. Depreciation rates are
determined based on estimated proved reserve quantities (the denominator) and
capitalized costs of producing properties (the numerator). Producing properties'
capitalized costs are amortized based on the units of oil or gas produced.
Therefore, assuming all other variables are held constant, an increase in
estimated proved reserves decreases our depreciation, depletion and amortization
expense. Also, estimated reserves are often used to calculate future cash flows
from our oil and gas operations, which serve as an indicator of fair value in
determining whether a property is impaired or not. The larger the estimated
reserves, the less likely the property is impaired.
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, general and administrative costs, or G&A, and other income
directly associated with their respective segments are detailed within the
following discussion. DD&A, G&A, amortization of deferred compensation (G&A),
interest income, other income, interest expense, impairment of notes receivable
from officers and other costs, which are not allocated to individual operating
segments for management or segment reporting purposes, are discussed in their
entirety following the segment discussion. A comparison of the results of
operations by business segment and the information regarding nonsegmented items
for the years ended December 31, 2002, 2001 and 2000, respectively, follows.
Further information concerning our business segments can be found in Note 13,
Business Segments, in the financial statements.
24
Exploration and Production Segment
A summary of the amount and percentage change, as compared to their
respective prior year period, for oil and gas revenues, average oil and gas
prices, oil and gas production volumes, and lifting costs per barrel and Mcf for
the years ended December 31, 2002, 2001 and 2000, is set forth in the following
table:
For the year ended December 31,
----------------------------------------------------------------------------
2002 2001 2000
-------------------------------------------------- -------------------------
Oil Gas Oil Gas Oil Gas
-------------------------------------- ----------- ------------ ------------
Revenues.............................. $1,924,000 $ 285,000 $ 1,835,000 $ 394,000 $ 2,521,000 $ --
Percent change versus prior year.... +4.9% -27.7% -28.0% +100% +62.2%
Average price (Bbls or Mcf)(1)........ $ 21.19 $ 1.58 $ 19.41 $1.58 $ 26.14 $ --
Percent change versus prior year.... +9.2% -- -25.8% +100% +70.3%
Production volumes (Bbls or Mcf)...... 90,817 180,407 94,522 249,661 96,416 --
Percent change versus prior year.... -3.9% -27.7% -1.9% +100% -4.8%
Lifting costs per Bbls or Mcf(2)...... $ 14.28 $ 0.16 $ 13.62 $ .16 $ 12.13 $ --
Percent change versus prior year.... +4.8% -- +12.3% -- +36.6%
- -----------------------
(1) The contract price for gas during 2002 and 2001, prior to adjusting for
actual physical content of Btu, was $2.02 per MMBtu.
(2) Lifting costs per barrel are computed by dividing the related lease
operating expenses by the total barrels of oil produced after royalties.
Lifting costs per Mcf of gas are computed by dividing the related lease
operating expenses by the total Mcf of gas produced before royalties.
Lifting costs do not include production taxes.
Oil Revenues. Oil revenues were $1.9 million, $1.8 million and $2.5
million for the years ended December 31, 2002, 2001 and 2000, respectively.
Essentially 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, the degree of
maintenance performed, and the declining production rates attributable to the
natural production declines of our producing properties.
Gas Revenues. Our gas revenues are derived solely from our Polish
producing operations. Gas revenues were $285,000 and $394,000 for the years
ended December 31, 2002 and 2001, respectively. There were no gas revenues
during 2000. The Kleka 11, our first producing well in Poland, began producing
during February 2001. During 2002 and 2001, gas produced by the Kleka 11 was
sold to POGC based on U.S. dollar pricing under a five-year contract, which may
be terminated by giving POGC a 90-day written notice. The decline in gas
production from 2001 to 2002 is the result of the operator choking back the well
to avoid any increase in water production.
Lease Operating Costs. Lease operating costs were $1.4 million for each
of the years ended December 31, 2002, 2001 and 2000. Operating costs rose
slightly from 2001 to 2002, as higher oil lifting costs offset lower oil and gas
production. Operating costs rose from 2000 levels in 2001 due to the
commencement of production from the Kleka well in Poland, as well as higher per
unit oil lifting costs.
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 $2.6 million, $6.5 million and $7.4 million for the years ended December
31, 2002, 2001 and 2000, respectively. Limited available capital in 2002 caused
us to sharply curtail our exploration activities in Poland. Subject to the
commencement of drilling activities under the CalEnergy Gas agreement and our
ability secure additional equity/debt financing, exploration costs will continue
to be curtailed in the near term.
G&G costs were $1.0 million, $2.9 million and $4.7 million for the
years ended December 31, 2002, 2001 and 2000, respectively. During 2002, most of
our G&G costs were spent on reprocessing and further analyzing the seismic data
on the Fences I area. During 2001, we spent approximately $1.8 million on
acquiring 3-D seismic data in the Fences project areas, $552,000 acquiring and
analyzing 2-D seismic data on the Pomeranian project area, and granted stock
options valued at $36,000 to a Polish consultant. During 2000, we spent
approximately $2.1 million on acquiring 3-D seismic data in the Fences project
areas, approximately $477,000 on acquiring and analyzing 2-D seismic data on the
25
Lublin Basin, Pomeranian and Warsaw West project areas, and granted stock
options valued at approximately $81,000 to a Polish consultant. Under terms of
the Poland 2001 Agreement Credit, Apache covered our share of additional G&G
costs totaling $53,000 and $19,000 during 2001 and 2000, respectively.
Exploratory dry-hole costs were $0, $3.1 million and $2.0 million for
the years ended December 31, 2002, 2001 and 2000, respectively. Due to our
capital limitations, we did not participate in any exploratory drilling in 2002.
During 2001, we incurred costs of $3.1 million pertaining to the Mieszkow 1 well
on the Fences project areas. In accordance with FASB No. 19, we have classified
the Mieszkow 1 as an exploratory dry hole for financial reporting purposes,
because further operations have been suspended since drilling, pending the
reprocessing and interpretation of 3-D seismic data in order to evaluate the
economic feasibility of additional drilling operations at the well site. During
2000, we drilled the Wilga 3 and Wilga 4 wells near our Wilga 2 discovery on the
Wilga project area, both of which were subsequently determined to be exploratory
dry holes. The two wells cost a net amount of $1.1 million and $900,000,
respectively, after Apache covered one-half of our 45% share of drilling costs
under terms of the Apache Exploration Program.
Impairments of oil and gas properties were $1.5 million, $584,000 and
$674,000 for the years ended December 31, 2002, 2001 and 2000, respectively.
During 2002, we incurred an impairment of $509,000 in costs associated with the
Tuchola 108-2 well. A preliminary open-hole test in early January 2001 on the
well resulted in a flow rate of 9.5 MMcf of gas per day from the Main Dolomite
Reef formation at a depth between 2,535 meters and 2,595 meters. The flow rate
was limited by the capacity of the surface equipment. The well was subsequently
completed in an approximately 200 foot thick section of the Main Dolomite, but
has since been shut-in pending a pipeline connection. Constrained capital has
prevented us from drilling the additional appraisal and development wells and
building the necessary infrastructure, and FASB No. 19 requires well costs to be
impaired if more than one year elapses from drilling to production. We also
recognized an impairment of $1.0 million in costs associated with the Kleka 11
well, where lower production profiles caused a downward revision in recoverable
future reserves.
During 2001, we incurred impairments of $525,000 for the Baltic project
area and $59,000 for the Warsaw West project area, both of which are located in
Poland in areas where we no longer have exploration plans. During 2000, we
incurred impairments of $674,000 for the Williston Basin in North Dakota, where
we also no longer have exploration plans. Impairments will vary from period to
period based on our determination that capitalized costs of unproved properties,
on a property-by-property basis, are not realizable.
Apache Poland G&A Costs. Apache Poland G&A costs consist of our share
of direct overhead costs incurred by Apache in Poland in accordance with the
terms of the Apache Exploration Program. Apache Poland G&A costs were $0,
$575,000 and $957,000 for the years ended December 31, 2002, 2001 and 2000.
During mid-2001, we began to narrow the focus of our ongoing exploratory efforts
relating to the Apache Exploration Program by including only the Pomeranian and
Wilga project areas and discontinued our exploratory activities on the Lublin
Basin, Warsaw West and Carpathian project areas. Prior to July 1, 2000, Apache
covered all of our pro rata share of Apache Poland G&A costs. Effective July 1,
2000, we began paying approximately 35% of Apache Poland G&A costs, to be
adjusted as each of Apache's remaining drilling requirements were completed.
Apache has since completed its remaining drilling requirements, and we are now
responsible only for our 45% share of Apache Poland G&A costs relating to
ongoing, jointly conducted activities in the Wilga project area in Poland for
which Apache is the operator, subject to a preapproved annual budget. In
addition to the above amounts, Apache covered our share of additional Apache
Poland G&A costs totaling $464,000 and $33,000 during 2001 and 2000,
respectively, under terms of the Poland 2001 Agreement Credit.
26
Poland 2001 Agreement Credit. Under an amendment to the Apache
Exploration Program effective January 1, 2001, referred to as the Poland 2001
Agreement, Apache agreed to issue to us a credit that included Apache covering
$932,000 of our share of joint costs in Poland (other than carried costs) in
return for the release of Apache's commitment to cover our share of costs to
shoot 339 kilometers of 2-D seismic data in the Carpathian project area. During
2001 and 2000, we used the entire Poland 2001 Agreement Credit, as shown below:
Poland 2001 Agreement Credit
-----------------------------------------------
2001 2000 Total
--------------- --------------- ---------------
Cost category:
Geological and geophysical costs......................... $ 53,000 $ 19,000 $ 72,000
Exploratory dry hole costs............................... 25,000 (3,000) 22,000
Apache Poland general and administrative costs........... 464,000 33,000 497,000
Leasehold costs.......................................... -- 65,000 65,000
Tuchola 108-2 completion costs........................... 276,000 -- 276,000
--------------- --------------- ---------------
Total.................................................. $ 818,000 $ 114,000 $ 932,000
=============== =============== ===============
DD&A Expense - Producing Operations. DD&A expense for producing
properties was $281,000, $322,000 and $73,000 for the years ended December 31,
2002, 2001 and 2000, respectively. DD&A expense incurred during 2002 and 2001
includes approximately $205,000 and $258,000, respectively, or $1.03 per Mcf of
gas produced, associated solely with the Kleka 11 well that began producing in
Poland during February 2001. DD&A expense declined from 2001 to 2002 due to
reduced production from the well. There was no DD&A expense associated with
Poland during 2000. The DD&A rate per barrel for oil produced in the United
States was $0.89, $0.69 and $0.76 during 2002, 2001 and 2000, respectively. The
differences between the DD&A rates per barrel from year to year are primarily
the result of changes in oil reserve estimates computed as of December 31 of
each year.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $0.5
million, $1.6 million and $1.3 million for the years ended December 31, 2002,
2001 and 2000, respectively. Oilfield services revenues increased from 2000 to
2001 due to improved market conditions and an increased emphasis on using our
oilfield servicing equipment for contract third-party services rather than
servicing company-owned properties. Conversely, the contract drilling industry
was significantly curtailed in the area where we operate in 2002, and our
revenues declined sharply as a result. Oilfield services revenues will continue
to fluctuate from period to period based on market demand, weather, the number
of wells drilled, downtime for equipment repairs, the degree of emphasis on
using our oilfield services equipment on our company-owned properties and other
factors.
Oilfield Servicing Costs. Oilfield services costs were $0.5 million,
$1.3 million and $1.1 million for the years ended December 31, 2002, 2001 and
2000, respectively, or 100%, 82% and 84% of oilfield servicing revenues,
respectively. Oilfield services costs as a percentage of oilfield services
revenues were relatively flat during 2001, as compared to 2000. During 2002,
oilfield servicing costs were a higher percentage of oilfield services revenues,
as compared to 2001, due to increased maintenance and repair costs associated
with our oilfield servicing equipment. In general, oilfield servicing costs are
directly associated with oilfield services revenues. As such, oilfield services
costs will continue to fluctuate period to period based on the number of wells
drilled, revenues generated, weather, downtime for equipment repairs, the degree
of emphasis on 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 $310,000, $308,000 and $247,000 for the years ended December 31, 2002, 2001
and 2000, respectively. We spent $116,000, $248,000 and $779,000 on upgrading
our oilfield servicing equipment during 2002, 2001 and 2000, respectively.
Nonsegmented Items
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $55,000, $1.1 million and $652,000 during the years ended
December 31, 2002, 2001 and 2000, respectively. On April 5, 2001, we extended
27
the term of options to purchase 125,000 shares of our common stock that were to
expire during 2001 for a period of two years, with a one-year vesting period. On
August 4, 2000, we extended the term of options and warrants to purchase 678,000
shares of our common stock that were to expire during 2000 for a period of two
years, with a one-year vesting period. In accordance with FIN 44 "Accounting for
Certain Transactions involving Stock Compensation," we incurred noncash deferred
compensation costs of $1.8 million, including $219,000 for the April 5, 2001,
option extension and $1.6 million for the August 4, 2000, option extension, to
be amortized over their respective one-year vesting periods from the date of
extension. The deferred costs have all been amortized as of December 31, 2002.
G&A Costs - Corporate. G&A costs were $2.4 million, $883,000, and $2.7
million for the years ended December 31, 2002, 2001 and 2000, respectively.
During 2001, G&A costs were $1.8 million lower than 2000 G&A costs, primarily
due to the Company writing off $1.7 million of compensation that was accrued as
of December 31, 2000. Without the write-offs, G&A costs during 2001 would have
been approximately $3.5 million. During 2002, in recognition of our limited
resources, we aggressively pursued the cost reduction measures described
earlier, resulting in costs lower than 2001, excluding the $1.7 million
write-off during that year, and actual 2000 costs.
Interest and Other Income - Corporate. Interest and other income was
$119,000, $514,000 and $557,000 for the years ended December 31, 2002, 2001 and
2000, respectively. Our cash, cash equivalent and marketable debt securities
balances were $0.7 million, $3.2 million and $2.4 million as of December 31,
2002, 2001 and 2000, respectively. Lower cash balances and interest rates in
2002 and 2001 reduced our interest income in both years. During the years ended
December 31, 2002 and 2001, we recorded other income of $93,000 and $341,000,
respectively, pertaining to amortizing an option premium resulting from granting
RRPV an option to purchase gas from our properties in Poland.
Interest Expense. Interest expense was $1.2 million, $331,000 and
$2,000 for the years ended December 31, 2002, 2001 and 2000, respectively.
During, 2002 and 2001, we recorded $93,000 and $341,000, respectively, of
imputed interest expense relating to our financing arrangement with RRPV. On
March 9, 2002, we began to accrue interest on the $5.0 million RRPV obligation
at an annual rate of 9.5%.
Impairment of Notes Receivable. Impairment of notes receivable was $0,
$34,000, and $738,000 for the years ended December 31, 2002, 2001 and 2000,
respectively. In accordance with SFAS No. 114 "Accounting by Creditors for
Impairment of a Loan," the notes receivable carrying value must be adjusted at
the end of each reporting period to reflect the market value of the underlying
collateral. On November 8, 2000, a former employee exercised an option to
purchase 52,000 shares of our common stock at a price of $3.00 per share. The
former employee elected to pay for the cost of the exercise by signing a full
recourse promissory note with us for $156,000. Terms of the note receivable
included a three-year term with annual principal payments of $52,000 plus
interest accrued at 9.5%. On November 8, 2001, the former employee surrendered
52,000 shares of our common stock in return for cancellation of the note
receivable. We recorded a loss of $34,060 on the transaction and the acquisition
of 52,000 shares of common stock at a price of $2.63 per share, the closing
price of our stock on November 8, 2001. Also during 2000, two of our officers
surrendered collateral shares to us in return for the cancellation of the notes
receivable from those officers that were outstanding on December 28, 2000. The
officers' notes included principal and interest of $2.2 million reduced by a
cumulative impairment allowance of $1.4 million based on the market value of
233,340 shares of the our common stock held as collateral. As a result of the
transaction, we recorded the acquisition of 233,340 shares of treasury stock at
a cost of $773,000. There were no notes receivable or related impairments
thereof in 2002.
Income Taxes. We incurred net losses of $5.9 million, $8.4 million and
$10.8 million for the years ended December 31, 2002, 2001 and 2000,
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.
28
Liquidity and Capital Resources
As of December 31, 2002, we had approximately $700,000 of cash and cash
equivalents, a working capital deficit of approximately $9.2 million, and a
stockholders' deficit of approximately $4.9 million. In addition, we have a
remaining work commitment of $5.6 million that must be spent by us (in addition
to payment of the $4.4 million to POGC, which is included in our accrued
liabilities at December 31, 2002) in order to complete our earning obligation in
our Fences project areas. Our financial position as of December 31, 2002, raises
uncertainty about our ability to continue as a going concern.
We have made significant progress in several areas toward improving our
liquidity and capital resources discussed in detail at the beginning of this
MD&A section. We raised $5.6 million from the recent sale of equity securities,
we extended the due dates on the RRPV note and the accrued liability to POGC, we
arranged to reduce our liability to POGC by the value of our interest in the
Kleka 11 well, and we signed a farmout agreement with CalEnergy Gas that, if
CalEnergy Gas fully earns half our interest in Fences I, will result in $10.6
million of work commitments performed and cash paid to us. In addition, we
recently obtained the right to earn a 49% interest in the Fences II project area
and anticipate completing documentation soon for a 100% interest in the Fences
III project area. We believe we can arrange with industry partners to trade a
portion of our interest in these properties for drilling funds and cash payments
that will exceed our related costs. Although, notwithstanding these measures,
there remains uncertainty about our ability to continue as a going concern, we
believe the prospect of eliminating that uncertainty during the current year has
been substantially improved.
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities, and agreements with industry
partners that funded our share of costs in certain exploratory activities in
order to earn an interest in our properties. The continuation of our exploratory
efforts in Poland is dependent on our ability to raise additional capital or to
farm out our properties. The availability of such capital or farmouts will
affect the timing, pace, scope and amount of our future capital expenditures. If
we are unable to arrange farmouts for the Fences II and Fences II project areas,
or having done so, if the results of operations there are disappointing, or if
CalEnergy Gas's drilling program is unsuccessful, or if CalEnergy Gas elects not
to pursue that drilling program, or if other disappointing events should occur,
there can be no assurance that we will be able to secure additional partners or
obtain additional equity or debt financing. We may also not be able to further
reduce expenses or successfully complete other steps to continue as a going
concern. If we are unable to obtain sufficient funds to satisfy our future cash
requirements, we may be forced to curtail operations, dispose of assets, or seek
extended payment terms from our vendors. Such events would materially and
adversely affect our financial position and results of operations.
We may seek to obtain additional funds for future capital investments
from strategic alliances with other energy or financial partners, the sale of
additional securities, project financing, sale of partial property interests, or
other arrangements, all of which may dilute the interest of our existing
stockholders or our interest in the specific project financed. We may change the
allocation of capital among the categories of anticipated expenditures depending
upon future events that we cannot predict. For example, we may change the
allocation of our expenditures based on the actual results and costs of future
exploration, appraisal, development, production, property acquisition and other
activities. In addition, we may have to change our anticipated expenditures if
costs of placing any particular discovery into production are higher, if the
field is smaller, or if the commencement of production takes longer than
expected.
Working Capital (current assets less current liabilities). Our working
capital was $(9.2) million as of December 31, 2002, a decrease of $9.7 million
from December 31, 2001. In accordance with the terms of our RRPV loan agreement,
the entire principal amount of $5.0 million, plus accrued interest, was due on
March 9, 2003, unless RRPV earlier converted the loan to restricted common stock
at $5.00 per share, the market value of our common stock at the time the terms
with RRPV were finalized. Accordingly, the entire balance of the RRPV note,
along with interest accrued through December 31, 2002, is shown as a current
liability on the balance sheet. As discussed above, we reached an agreement with
RRPV to extend the maturity date of the loan until December 31, 2003.
29
Our current liabilities also include $4.4 million of costs related to
our Fences project in Poland. In 2000, we agreed to spend $16.0 million of
exploration costs on this project area, which is owned and operated by POGC, in
order to earn a 49% interest. As of December 31, 2002, we have made cash
payments of approximately $6.7 million pertaining to the required $16.0 million,
in addition to the amount accrued at year-end.
Operating Activities. We used net cash of $2.1 million, $3.1 million
and $6.1 million in our operating activities during 2002, 2001 and 2000,
respectively, primarily as a result of the net losses incurred in those years.
The declining use of cash in operations is also a reflection of a systematic
reduction in exploration costs, as our resources have become limited over time.
Investing Activities. We used net cash of $295,000 in investing
activities during 2002, received net cash of $326,000 from our investing
activities during 2001, and used net cash of $3.9 million in investing
activities during 2000. During 2002, the bulk of cash used was for upgrading our
producing oil and gas properties and our well-servicing equipment. During 2001,
our capital expenditures for producing properties and well-servicing equipment
were offset by $1.3 million in maturing marketable debt securities. During 2000,
we spent $7.7 million on various additions to both proved and unproved
properties, and spent $779,000 on additions to oilfield servicing equipment. We
also received a net of $4.0 million net from transactions in marketable debt
securities.
Financing Activities. We received net cash of $4,500, $5.0 million and
$9.4 million from our financing activities during 2002, 2001 and 2000,
respectively. During 2001, we received $5.0 million pertaining to our RRPV loan
and gas purchase option agreement. Also, during 2001, we acquired 52,000 shares
of common stock at a cost of $137,000 in a noncash transaction. During 2000, we
received net proceeds of $9.3 million ($10.4 million gross) from the private
placement of 2,969,000 shares of our common stock, and received $103,000 in cash
and $156,000 in the form of a full recourse promissory note secured by 52,000
shares of our common stock from the exercise of options and warrants to purchase
95,572 shares of our common stock. Also, during 2000, we acquired 233,340 shares
of treasury stock at a cost of $773,000 in a noncash transaction
Contractual Obligations and Contingent Liabilities and Commitments
The following is a summary of our significant contractual obligations
and commitments as of December 31, 2002 (in thousands):
Contractual Obligations and Commitments Due by December 31, 2003
--------------------------------------- ------------------------
(In thousands)
Note Payable (RRPV).......................... $ 5,000 plus interest(1)
Fences I work commitment(2).................. 5,600
Cash payment to POGC(2)...................... 4,400 plus interest
------------------------
Total.................................. $ 15,000 plus interest(1)
=========================
- --------------------
(1) In March 2003, we paid RRPV $2.2 million, which reduced the balance due to
approximately $3.3 million, plus interest.
(2) The Fences I work commitment and the cash payment to POGC are required in
order for us to meet our commitment to earn a 49% interest in the Fences I
project area.
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 partners 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.
30
Risk Factors
Our business is subject a number of material risks, including the
following:
o Our success depends on our discovery of commercial quantities
of oil or gas in Poland. To date in Poland, our exploration
efforts have resulted in one producing well (the Kleka 11,
which we have recently agreed to transfer to POGC), two
discoveries (the Wilga 2 and Tuchola 108-2, both shut-in), and
12 exploratory dry holes. Our success will depend on our
ability to generate drilling prospects that result in the
discovery of commercial quantities of oil or gas and the
establishment of reserves. We cannot predict whether any
prospect we identify may contain reserves, whether we can
assemble the financial and other resources to complete
drilling or other exploration, or whether any gas or oil we
discover can be produced and marketed commercially.
o We will continue to require additional capital. We will rely
principally on proceeds from the sale of securities and
farmout or other industry-sharing arrangements for planned
exploration, appraisal, development and property acquisition
programs in Poland. Obtaining additional financing may dilute
the interest of our existing stockholders or our interest in
the specific project being financed. We cannot assure that
additional funds could be obtained or, if obtained, would be
on terms favorable to us.
o Funding activities may limit our activities. Our capital
expenditure budget for 2003 for the payment of POGC,
completion of earning requirements in Fences I, repayment of
RRPV, geophysical and geological work, and prospect marketing
and other operating costs exceeds our current resources.
Therefore, we will be able to complete our planned activities
only if we are able to obtain additional financing. If we
cannot obtain required additional financing, we may be forced
to curtail our activities sharply in order to continue.
o Our loan agreement with RRPV restricts our flexibility. We
have encumbered certain of our property interests in Poland to
secure repayment of the remaining $3.3 million balance, plus
interest, due RRPV by December 31, 2003. Unless converted to
common stock at $3.42 per share, we may have to raise
additional capital to repay the loan. The loan will have to be
repaid notwithstanding our other cash requirements or the
potentially greater financial return from other expenditures.
In addition, our agreements with RRPV contain financial and
operating covenants that are customary for transactions of
this nature, including limitations on additional indebtedness.
Our agreement with RRPV also specifies usual and customary
events of default.
o We face a number of other risks, including:
- Continuing world political instability and the threat
or existence of armed hostilities involving the
United States and major oil and gas producers may
adversely affect our ability to obtain required
financing, enter into farmout or other exploration
arrangements with industry partners, or complete
planned exploration.
- The exploration models, tools and concepts we are
applying in Poland have not been fully tested in that
geological setting, which increases exploration risk
and cost.
- We cannot accurately predict the oil or gas potential
of any prospect, test or discovery.
- We will continue to be dependent on the technical
expertise and financial resources of our exploration
partners in Poland, particularly CalEnergy Gas and
POGC, who act as the operators of specific projects.
- Our activities in Poland are subject to uncertainties
related to its governmental policies and Poland's
continuing economic growth and the implementation of
its long-term privatization strategy.
31
New Accounting Pronouncements
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." SFAS No. 143 is effective for us beginning January 1,
2003. The most significant impact of this standard to us will be a change in the
method of accruing for site restoration costs. Under SFAS No. 143, the fair
value of asset retirement obligations will be recorded as liabilities when they
are incurred, which are typically at the time the assets are installed. Amounts
recorded for the related assets will be increased by the amount of these
obligations. Over time, the liabilities will be accreted for the change in their
present value and the capitalized costs will be depreciated over the useful
lives of the related assets. We are currently evaluating the impact of adopting
SFAS No. 143.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liabilities
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). This statement
requires that a liability for costs associated with an exit or disposal activity
be recognized and measured initially at fair value only when the liability is
incurred. SFAS No. 146 will be effective for exit or disposal activities that
are initiated after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation Transition and Disclosure." This statement amends FASB
Statement No. 123, or SFAS No. 123, "Accounting for Stock-Based Compensation,"
to provide alternative methods of transition for an entity that voluntarily
changes to the fair value based method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the disclosure provisions of SFAS
No. 123 to require prominent disclosure in both annual and interim financial
statements about the effects on reported net income of an entity's accounting
policy decisions with respect to stock-based employee compensation. As we will
continue to account for stock-based compensation according to APB 25, adoption
of SFAS No. 148 will require us to provide prominent disclosures about the
effects of SFAS No. 123 on reported income and will require disclosure of these
affects in the interim financial statements as well. SFAS No. 148 is effective
for the financial statements for fiscal years ending after December 15, 2002,
and subsequent interim periods. We believe that the adoption of this standard
will have no material impact on our operating results and financial position.
In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"),
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others, which expands on the accounting
guidance of Statements Nos. 5, 57, and 107 and incorporates without change the
provisions of FASB Interpretation No. 34, which is being superseded. This
interpretation requires a guarantor to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. In addition, guarantors are required to make significant
new disclosures, even if the likelihood of the guarantor making payments under
the guarantee is remote. The interpretation's disclosure requirements are
effective for the Company as of December 31, 2002. The recognition requirements
of FIN 45 are to be applied prospectively to guarantees issued or modified after
December 31, 2002. The Company has no significant guarantees and the adoption of
this interpretation did not have a material impact on the Company's financial
statements.
In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),
Consolidation of Variable Interest Entities. The objective of this
interpretation is to provide guidance on how to identify a variable interest
entity and determine when the assets, liabilities, noncontrolling interests and
results of operations of a variable interest entity need to be included in a
company's consolidated financial statements. A company that holds variable
interests in an entity will need to consolidate the entity if the company's
interest in the variable interest entity is such that the company will absorb a
majority of the variable interest entity's expected losses and/or receive a
majority of the entity's expected residual returns, if they occur. The
provisions of this interpretation became effective upon issuance. As of December
31, 2002, the Company did not have any variable interest entities that will be
subject to FIN 46.
We have reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on our results
of operations or financial position. Based on that review, we believe that none
of these pronouncements will have a significant effect on current or future
earnings or operations.
32
- --------------------------------------------------------------------------------
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
- --------------------------------------------------------------------------------
Price Risk
Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.
Our gas production in Poland is currently being sold to POGC based on
U.S. dollar pricing under a five-year contract that may be terminated by us with
a 90-day written notice. The limited volume and single source of our gas
production means we cannot assure uninterruptible production or production in
amounts that would be meaningful to industrial users, which may depress the
price we may be able to obtain. There is currently no competitive market for the
sale of gas in Poland. Accordingly, we expect that the prices we receive for the
gas we produce will be lower than would be the case in a competitive setting and
may be lower than prevailing western European prices, at least until a fully
competitive market develops in Poland.
We currently do not engage in any hedging activities or have any
derivative financial instruments to protect ourselves against market risks
associated with oil and gas price fluctuations, although we may elect to do so
if we achieve a significant amount of production in Poland.
Foreign Currency Risk
We have entered into various agreements in Poland, primarily in U.S.
dollars or the U.S. dollar equivalent of the Polish zloty. We conduct our
day-to-day business on this basis as well. The Polish zloty is subject to
exchange rate fluctuations that are beyond our control. We do not currently
engage in hedging transactions to protect ourselves against foreign currency
risks, nor do we intend to do so in the foreseeable future.
- --------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
Our financial statements, including the accountant's report, are
included beginning at page F-1 immediately following the signature page of this
report.
33
- --------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------
We have not disagreed on any items of accounting treatment or financial
disclosure with our auditors.
34
PART III
- --------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2003 annual
meeting of stockholders under the caption "Election of Directors: Executive
Officers, Directors and Nominees" and "Compliance with Section 16(a) of the
Exchange Act" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2003 annual
meeting of stockholders under the caption "Election of Directors: Executive
Compensation" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2003 annual
meeting of stockholders under the caption "Election of Directors: Security
Ownership of Certain Beneficial Owners and Management" is incorporated herein by
reference.
- --------------------------------------------------------------------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2003 annual
meeting of stockholders under the caption "Election of Directors: Certain
Relationships and Related Transactions" is incorporated herein by reference.
- --------------------------------------------------------------------------------
ITEM 14. CONTROLS AND PROCEDURES
- --------------------------------------------------------------------------------
Disclosure controls are procedures that are designed with an objective
of ensuring that information required to be disclosed in our periodic reports
filed with the SEC, such as this Annual Report on Form 10-K, is recorded,
processed, summarized and reported within the time periods specified by the SEC.
Disclosure controls are also designed with an objective of ensuring that such
35
information is accumulated and communicated to our management, including the
Chief Executive Officer and Chief Financial Officer, in order to allow timely
consideration regarding required disclosures.
The evaluation of our disclosure controls by the Chief Executive
Officer and Chief Financial Officer included a review of the controls'
objectives and design, the operation of the controls, and the effect of the
controls on the information presented in this Annual Report. Our management,
including the Chief Executive Officer and Chief Financial Officer, does not
expect that disclosure controls can or will prevent or detect all errors and all
fraud, if any. A control system, no matter how well designed and operated, can
provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Also, projections of any evaluation of the disclosure
controls and procedures to future periods are subject to the risk that the
disclosure controls and procedures may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
Based on their review and evaluation as of a date within 90 days of the
filing of this Form 10-K, and subject to the inherent limitations all as
described above, our Chief Executive Officer and Chief Financial Officer have
concluded that our disclosure controls and procedures (as defined in Rules
13a-14 and 15d-14 under the Securities Exchange Act of 1934) are effective. They
are not aware of any significant changes in our disclosure controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
36
PART IV
- --------------------------------------------------------------------------------
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
(a) The following documents are filed as part of this report or
incorporated herein by reference.
1. Financial Statements. See the following beginning at page F-1:
Page
-----
Report of Independent Accountants........................... F-1
Consolidated Balance Sheets as of December 31, 2002
and 2001.................................................. F-2
Consolidated Statements of Operations for each of the
Three Years Ended December 31, 2002, 2001 and 2000,
respectively.............................................. F-3
Consolidated Statements of Cash Flows for each of the
Three Years Ended December 31, 2002, 2001 and 2000,
respectively.............................................. F-5
Consolidated Statements of Stockholders' Equity (Deficit)
for each of the Three Years Ended December 31, 2002, 2001
and 2000, respectively.................................... F-6
Notes to the Consolidated Financial Statements.............. F-7
2. Supplemental Schedules. The Financial Statement schedules have
been omitted because they are not applicable or the required
information is otherwise included in the accompanying Financial
Statements and the notes thereto.
3. Exhibits. The following exhibits are included as part of this
report:
SEC
Exhibit Reference
Number* Number Title of Document Location
- ---------- ----------- ------------------------------------------------------------------------- -----------------
Item 3. Articles of Incorporation and Bylaws
- -------------------------------------------------------------------------------------------------
3.01 3 Restated and Amended Articles of Incorporation Incorporated by
Reference(1)
3.02 3 Bylaws Incorporated by
Reference(2)
Item 4. Instruments Defining the Rights of Security Holders
- -------------------------------------------------------------------------------------------------
4.01 4 Specimen Stock Certificate Incorporated by
Reference(2)
4.02 4 Form of Designation of Rights, Privileges, and Preferences of Series A Incorporated by
Preferred Stock Reference(3)
4.03 4 Form of Rights Agreement dated as of April 4, 1997, between FX Energy, Incorporated by
Inc. and Fidelity Transfer Corp. Reference(3)
4.04 4 Form of Designation of Rights, Privileges, and Preferences of 2003 This filing
Series Convertible Preferred Stock
4.05 4 Specimen Stock Certificate for 2003 Series Convertible Preferred Stock This filing
37
SEC
Exhibit Reference
Number* Number Title of Document Location
- ---------- ----------- ------------------------------------------------------------------------- -----------------
Item 10. Material Contracts
- -------------------------------------------------------------------------------------------------
10.05 10 Mining Usufruct Agreement between the State Treasury of the Republic of Incorporated by
Poland and Lubex Petroleum Company Sp. z o.o. dated December 20, Reference(4)
1996, relating to concession blocks 255 and others (Wilga)
10.10 10 Mining Usufruct Agreement between the State Treasury of the Republic of Incorporated by
Poland and FX Energy Poland Sp. z o.o. and Partners, commercial Reference(5)
partnership, dated October 30, 1997, related to concession blocks 85,
86, 87, 88, 89, 105,108, 109, 129 and 149 in northwestern Poland
(Pomeranian)
10.26 10 Frontier Oil Exploration Company 1995 Stock Option and Award Plan** Incorporated by
Reference(6)
10.27 10 Form of FX Energy, Inc. 1996 Stock Option and Award Plan** Incorporated by
Reference(4)
10.28 10 Form of FX Energy, Inc. 1997 Stock Option and Award Plan** Incorporated by
Reference(7)
10.29 10 Form of FX Energy, Inc. 1998 Stock Option and Award Plan** Incorporated by
Reference(7)
10.30 10 Employment Agreements between FX Energy, Inc. and each of David Pierce Incorporated by
and Andrew Pierce, effective January 1, 1995** Reference(2)
10.31 10 Amendments to Employment Agreements between FX Energy, Inc. and each of Incorporated by
David Pierce and Andrew Pierce, effective May 30, 1996** Reference(8)
10.32 10 Form of Stock Option with related schedule (D. Pierce and A. Pierce)** Incorporated by
Reference(2)
10.33 10 Form of Stock Option granted to D. Pierce and A. Pierce** Incorporated by
Reference(2)
10.34 10 Form of Non-Qualified Stock Option with related schedule** Incorporated by
Reference(6)
10.39 10 Employment Agreement between FX Energy, Inc. and Jerzy B. Maciolek** Incorporated by
Reference(8)
10.40 10 Addendum to Employment Agreement between FX Energy, Inc. and Jerzy B. Incorporated by
Maciolek** Reference(9)
10.41 10 Second Addendum to Employment Agreement between FX Energy, Inc. and Incorporated by
Jerzy B. Maciolek** Reference(9)
10.42 10 Employment Agreement between FX Energy, Inc. and Scott J. Duncan** Incorporated by
Reference(9)
10.43 10 Form of Indemnification Agreement between FX Energy, Inc. and certain Incorporated by
directors, with related schedule** Reference(4)
10.44 10 Form of Option granted to executive officers and directors, with Incorporated by
related schedule** Reference(4)
10.52 10 Form of Indemnification Agreement between FX Energy, Inc. and certain Incorporated by
directors, with related schedule** Reference(7)
38
SEC
Exhibit Reference
Number* Number Title of Document Location
- ---------- ----------- ------------------------------------------------------------------------- -----------------
10.53 10 Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Incorporated by
Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Reference(10)
Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to
Fences project area
10.55 10 Option extensions with related schedules** Incorporated by
Reference(11)
10.57 10 US$5,000,000 9.5% Convertible Secured Note dated as of March 9, 2001 Incorporated by
Reference(12)
10.58 10 Form of Pledge Agreement FX Energy Poland Sp. z o.o. and Rolls Royce Incorporated by
Power Ventures Limited dated March 9, 2001, and related schedules Reference(12)
10.59 10 Sales / Purchase Agreement Special Provisions between Plains Marketing This filing
Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002
10.60 10 Form of Non-Qualified Stock Option awarded August 14, 2002, with This filing
related schedule**
10.61 10 Description of compensation arrangement with Thomas B. Lovejoy and This filing
outside directors**
10.62 10 Agreement Regarding Cooperation within the Poznan Area (Fences II) This filing
entered into January 8, 2003, by and between Polskie Gornictwo Naftowe
i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.
10.63 10 Settlement Agreement Regarding the Fences Area entered into January 8, This filing
2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and
FX Energy Poland Sp. z o.o.
10.64 10 Farmout Agreement Entered into by and between FX Energy Poland This filing
Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. Covering the "Fences
Area" in the Foresudetic Monocline made as of January 9, 2003
10.65 10 Letter Agreement between Rolls-Royce Power Ventures Limited and FX This filing
Energy, Inc. dated February 6, 2003
10.66 10 Amendment Agreement No. 1 to 9.5% Convertible Secured Note between FX This filing
Energy, Inc. and Rolls-Royce Power Ventures Limited dated March 10, 2003
Item 21 Subsidiaries of the Registrant
- -------------------------------------------------------------------------------------------------
21.01 21 Schedule of Subsidiaries Incorporated by
Reference(9)
Item 23 Consents of Experts and Counsel
- -------------------------------------------------------------------------------------------------
23.01 23 Consent of PricewaterhouseCoopers LLP, independent accountants This filing
23.02 23 Consent of Larry D. Krause, Petroleum Engineer This filing
23.03 23 Consent of Troy-Ikoda Limited, Petroleum Engineers This filing
39
SEC
Exhibit Reference
Number* Number Title of Document Location
- ---------- ----------- ------------------------------------------------------------------------- -----------------
Item 99 Miscellaneous
- ---------- ----------- -------------------------------------------------------------------------
99.01 99 Certification of Principal Executive Officer This filing
99.02 99 Certification of Principal Financial Officer This filing
- --------------------------------
* 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.
(1) Incorporated by reference from the proxy statement respecting the 1997
annual meeting of stockholders.
(2) Incorporated by reference from the registration statement on Form SB-2, SEC
File No. 33-88354-D.
(3) Incorporated by reference from the report on Form 8-K dated April 4, 1997.
(4) Incorporated by reference from the annual report on Form 10-KSB for the
year ended December 31, 1996.
(5) Incorporated by reference from the quarterly report on Form 10-QSB for the
quarter ended September 30, 1997.
(6) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended September 30, 1995.
(7) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 1999.
(8) Incorporated by reference from the registration statement on Form S-1, SEC
File No.333-05583.
(9) Incorporated by reference from the annual report on Form 10-KSB for the
year ended December 31, 1997.
(10) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended March 31, 2000.
(11) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended September 30, 2000.
(12) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 2000.
(b) Reports on Form 8-K.
During the quarter ended December 31, 2002, we filed the following item
on Form 8-K:
Date of Event Reported Item(s) Reported
--------------------------- ------------------------------------------
October 28, 2002 Item 5. Other Events
40
- --------------------------------------------------------------------------------
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.
Dated: March 26, 2003 FX ENERGY, INC. (Registrant)
/s/ David N. Pierce
------------------------------
David N. Pierce, President and
Chief Executive Officer
Dated: March 26, 2003 /s/ Thomas B. Lovejoy
------------------------------
Thomas B. Lovejoy
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Dated: March 26, 2003
/s/ David N. Pierce
----------------------------
David N. Pierce, Director
/s/ Andrew W. Pierce
----------------------------
Andrew W. Pierce, Director
----------------------------
Jerzy B. Maciolek, Director
/s/ Thomas B. Lovejoy
----------------------------
Thomas B. Lovejoy, Director
/s/ Scott J. Duncan
----------------------------
Scott J. Duncan, Director
/s/ Peter L. Raven
----------------------------
Peter L. Raven, Director
/s/ Clay Newton
----------------------------
Clay Newton, Director
41
CERTIFICATIONS
I, David N. Pierce, certify that:
1. I have reviewed this annual report on Form 10-K of FX Energy, Inc.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 26, 2003
/s/ David N. Pierce
- -----------------------------
David N. Pierce
Principal Executive Officer
42
CERTIFICATIONS
I, Thomas B. Lovejoy, certify that:
1. I have reviewed this annual report on Form 10-K of FX Energy, Inc.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 26, 2003
/s/ Thomas B. Lovejoy
- ----------------------------
Thomas B. Lovejoy
Principal Financial Officer
43
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors
of FX Energy, Inc. and its subsidiaries:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of cash flows and of stockholders' equity
present fairly, in all material respects, the financial position of FX Energy,
Inc., and its subsidiaries (the "Company") at December 31, 2002 and 2001, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2 to the
consolidated financial statements, the Company has suffered recurring losses and
negative cash flows from operations that raise substantial doubt about its
ability to continue as a going concern. Management's plans in regard to these
matters are also described in Note 2. The consolidated financial statements do
not include any adjustments that might result from the outcome of this
uncertainty.
/s/ PricewaterhouseCoopers LLP
Salt Lake City, Utah
March 13, 2003
F-1
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2002 and 2001
2002 2001
----------------- ----------------
ASSETS
Current assets:
Cash and cash equivalents............................................................ $ 705,012 $ 3,157,427
Receivables:
Accrued oil sales................................................................ 238,236 478,857
Joint interest and other receivables............................................. 36,893 49,075
Inventory............................................................................ 84,262 87,260
Other current assets................................................................. 95,726 95,004
----------------- ----------------
Total current assets......................................................... 1,160,129 3,867,623
----------------- ----------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved........................................................................... 4,754,377 4,789,252
Unproved......................................................................... 154,261 655,523
Other property and equipment......................................................... 3,683,226 3,587,433
----------------- ----------------
Gross property and equipment..................................................... 8,591,864 9,032,208
Less accumulated depreciation, depletion and amortization............................ (4,685,487) (4,090,293)
----------------- ----------------
Net property and equipment................................................... 3,906,377 4,941,915
----------------- ----------------
Other assets:
Certificates of deposit.............................................................. 356,500 356,500
Deposits............................................................................. 18,072 2,789
----------------- ----------------
Total other assets........................................................... 374,572 359,289
----------------- ----------------
Total assets............................................................................. $ 5,441,078 $ 9,168,827
================= ================
-Continued-
The accompanying notes are an integral part of these consolidated financial statements
F-2
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2002 and 2001
-Continued-
2002 2001
----------------- ----------------
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable..................................................................... $ 376,264 $ 492,306
Accrued liabilities.................................................................. 4,933,393 2,816,561
Note payable......................................................................... 5,000,000 --
----------------- ----------------
Total current liabilities.................................................... 10,309,657 3,308,867
Long-term debt:
Note payable......................................................................... -- 4,906,916
----------------- ----------------
Total liabilities............................................................ 10,309,657 8,215,783
----------------- ----------------
Commitments (Note 7)
Stockholders' equity (deficit):
Preferred stock, $.001 par value, 5,000,000 shares authorized as of
December 31, 2002 and 2001; no shares outstanding................................ -- --
Common stock, $.001 par value, 100,000,000 shares authorized as of December 31,
2002 and 2001; 17,651,917 and 17,913,575 shares issued as of
December 31, 2002 and 2001, respectively......................................... 17,652 17,914
Treasury stock, at cost, 0 and 233,340 shares as of December 31, 2002 and
2001, respectively............................................................... -- (909,815)
Deferred compensation from stock option modifications................................ -- (54,688)
Additional paid in capital........................................................... 49,049,025 49,910,078
Accumulated deficit.................................................................. (53,935,256) (48,010,445)
----------------- ----------------
Total stockholders' equity (deficit) ........................................ (4,868,579) 953,044
----------------- ----------------
Total liabilities and stockholders' equity (deficit) .................................... $ 5,441,078 $ 9,168,827
================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2002, 2001 and 2000
2002 2001 2000
---------------- ----------------- ----------------
Revenues:
Oil and gas sales.................................................. $ 2,208,916 $ 2,229,064 $ 2,520,779
Oilfield services.................................................. 533,438 1,583,811 1,290,055
---------------- ----------------- ----------------
Total revenues................................................. 2,742,354 3,812,875 3,810,834
---------------- ----------------- ----------------
Operating costs and expenses:
Lease operating expenses........................................... 1,365,454 1,358,304 1,348,399
Geological and geophysical costs................................... 1,030,660 2,909,270 4,679,391
Exploratory dry hole costs......................................... -- 3,051,334 2,034,206
Impairment of oil and gas properties............................... 1,547,860 583,855 674,158
Oilfield services costs............................................ 539,783 1,300,713 1,084,129
Depreciation, depletion and amortization........................... 617,937 661,644 385,807
Amortization of deferred compensation (G&A)........................ 54,688 1,077,547 652,489
Apache Poland general and administrative costs..................... -- 575,303 956,936
Other general and administrative costs (G&A)....................... 2,440,528 882,985 2,654,430
---------------- ----------------- ----------------
Total operating costs and expenses............................. 7,596,910 12,400,955 14,469,945
---------------- ----------------- ----------------
Operating loss......................................................... (4,854,556) (8,588,080) (10,659,111)
---------------- ----------------- ----------------
Other income (expense):
Interest and other income.......................................... 118,961 542,824 557,080
Interest expense................................................... (1,189,216) (330,816) (2,422)
Impairment of notes receivable..................................... -- (34,060) (738,177)
---------------- ----------------- ----------------
Total other income (expense)................................... (1,070,255) 177,948 (183,519)
---------------- ----------------- ----------------
Net loss.............................................................. $ (5,924,811) $ (8,410,132) $ (10,842,630)
================ ================= ================
Basic and diluted net loss per share................................... $ (0.34) $ (.48) $ (.66)
================ ================= ================
Basic and diluted weighted average number of shares
Outstanding........................................................ 17,641,335 17,672,684 16,435,436
================ ================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-4
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2002, 2001 and 2000
2002 2001 2000
---------------- ----------------- ----------------
Cash flows from operating activities:
Net loss........................................................... $ (5,924,811) $ (8,410,132) $ (10,842,630)
Adjustments to reconcile net loss to net cash used in
Operating activities:
Depreciation, depletion and amortization................... 617,937 661,644 385,807
Impairment of oil and gas properties....................... 1,547,860 583,855 674,158
Impairment of notes receivable............................. -- 34,060 738,177
Accrued interest income from notes receivable.............. -- (14,820) (140,359)
Gain (loss) on property dispositions....................... -- (28,864) --
Exploratory dry hole costs................................. -- 3,051,334 2,034,206
Common stock and stock options issued for services......... 44,000 35,653 80,813
Amortization of deferred compensation (G&A)................ 54,688 1,077,547 652,489
Increase (decrease) from changes in working capital items:
Receivables.................................................... 252,803 (101,280) 74,496
Inventory...................................................... 2,998 660 (21,559)
Other current assets........................................... (722) (14,691) 45,693
Accounts payable and accrued liabilities....................... 1,243,345 (122,696) 236,757
---------------- ----------------- ----------------
Net cash used in operating activities...................... (2,161,902) (3,247,730) (6,081,952)
---------------- ----------------- ----------------
Cash flows from investing activities:
Additions to oil and gas properties................................ (161,195) (754,500) (6,988,314)
Additions to other property and equipment.......................... (118,535) (245,414) (812,340)
Net change in other assets......................................... (15,283) -- --
Proceeds from sale of property interests........................... -- 44,040 --
Purchase of marketable debt securities............................. -- -- (6,314,990)
Proceeds from marketable debt securities........................... -- 1,281,993 10,282,000
---------------- ----------------- ----------------
Net cash provided by (used) in investing activities............ (295,013) 326,119 (3,833,644)
---------------- ----------------- ----------------
Cash flows from financing activities:
Proceeds from loan and gas purchase option agreement............... -- 5,000,000 --
Proceeds from issuance of common stock, net of offering costs...... -- -- 9,272,453
Proceeds from exercise of stock options and warrants............... 4,500 -- 102,944
---------------- ----------------- ----------------
Net cash provided by financing activities...................... 4,500 5,000,000 9,375,397
---------------- ----------------- ----------------
Net increase or (decrease) in cash and cash equivalents................ (2,452,415) 2,078,389 (540,199)
Cash and cash equivalents at beginning of year......................... 3,157,427 1,079,038 1,619,237
---------------- ----------------- ----------------
Cash and cash equivalents at end of year............................... $ 705,012 $ 3,157,427 $ 1,079,038
================ ================= ================
The accompanying notes are an integral part of these consolidated financial statements
F-5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity (Deficit)
For the years ended December 31, 2002, 2001 and 2000
Common Stock Notes and Notes Deferred
------------------- Interest Receivable Compensation Total
Par Value Receivable From Stock from Additional Stockholders'
Shares $.001 Per Treasury from Option Stock Option Paid in Accumulated Equity
Issued Share Stock Officers Exercise Modifications Capital Deficit (Deficit)
----------- ------- --------- ----------- --------- ----------- ----------- ------------ -----------
Balance as of
December 31, 1999 14,849,003 $14,849 -- $(1,370,873) -- -- $38,480,556 $(28,757,683) $ 8,366,849
Sale of common stock,
net of offering costs 2,969,000 2,969 -- -- -- -- 9,269,484 -- 9,272,453
Exercise of stock
options and warrants 95,572 96 -- -- -- -- 258,848 -- 258,944
Interest on notes
receivable -- -- -- (140,359) -- -- -- -- (140,359)
Impairment of notes
receivable from
officers -- -- -- 738,177 -- -- -- -- 738,177
233,340 shares tendered
for payment of notes
receivable and
accrued interest -- -- $(773,055) 773,055 -- -- -- -- --
Recourse note from
stock option exercise -- -- -- -- $(156,000) -- -- -- (156,000)
Deferred compensation
from stock option
modifications -- -- -- -- -- $(1,565,974) 1,565,974 -- --
Amortization of
deferred compensation -- -- -- -- -- 652,489 -- -- 652,489
Options issued for
services -- -- -- -- -- -- 80,813 -- 80,813
Net loss for year -- -- -- -- -- -- -- (10,842,630) (10,842,630)
----------- ------- --------- ----------- --------- ----------- ----------- ------------ -----------
Balance as of
December 31, 2000 17,913,575 17,914 (773,055) -- (156,000) (913,485) 49,655,675 (39,600,313) 8,230,736
Interest on notes
receivable -- -- -- -- (14,820) -- -- -- (14,820)
Impairment of notes
receivable -- -- -- -- 34,060 -- -- -- 34,060
52,000 shares tendered
for payment of notes
receivable and
accrued interest -- -- (136,760) -- 136,760 -- -- -- --
Deferred compensation
from stock option
modifications -- -- -- -- -- (218,750) 218,750 -- --
Amortization of
deferred compensation -- -- -- -- -- 1,077,547 -- -- 1,077,547
Options issued for
services -- -- -- -- -- -- 35,653 -- 35,653
Net loss for year -- -- -- -- -- -- -- (8,410,132) (8,410,132)
----------- ------- --------- ----------- --------- ----------- ----------- ------------ -----------
Balance as of
December 31, 2001 17,913,575 17,914 (909,815) -- -- (54,688) 49,910,078 (48,010,445) 953,044
----------- ------- --------- ----------- --------- ----------- ----------- ------------ -----------
Retirement of treasury
stock (285,340) (285) 909,815 -- -- -- (909,530) -- --
Amortization of
deferred compensation -- -- -- -- -- 54,688 -- -- 54,688
Common stock issued
for services 20,682 20 -- -- -- -- 43,980 -- 44,000
Exercise of stock
options 3,000 3 -- -- -- -- 4,497 -- 4,500
Net loss for year -- -- -- -- -- -- -- (5,924,811) (5,924,811)
----------- ------- --------- ----------- --------- ----------- ----------- ------------ -----------
Balance as of
December 31, 2002 17,651,917 $17,652 $ -- $ -- $ -- $ -- $49,049,025 $(53,935,256) $(4,868,579)
=========== ======= ======== =========== ========= ========== =========== ============ ===========
The accompanying notes are an integral part of these consolidated financial statements
F-6
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
Organization
FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively
referred to hereinafter as the "Company") is an independent energy company with
activities concentrated within the upstream oil and gas industry. In Poland, the
Company has projects involving the exploration and exploitation of oil and gas
prospects with the Polish Oil and Gas Company ("POGC") and other industry
partners. In the United States, the Company produces oil from fields in Montana
and Nevada and has an oilfield services company in northern Montana that
performs contract drilling and well servicing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries and the Company's undivided interests in Poland.
All significant inter-company accounts and transactions have been eliminated in
consolidation. At December 31, 2002, the Company owned 100% of the voting common
stock or other equity securities of its subsidiaries.
Cash Equivalents
The Company considers all highly-liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents.
Concentration of Credit Risk
The majority of the Company's receivables are within the oil and gas industry,
primarily from the purchasers of its oil and gas, fees generated from oilfield
services and its industry partners. The receivables are not collateralized. To
date, the Company has experienced minimal bad debts. The majority of the
Company's cash and cash equivalents is held by three financial institutions in
Utah, Montana and New York.
Inventory
Inventory consists primarily of tubular goods and production related equipment
and is valued at the lower of average cost or market.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and
gas operations. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether an individual well has found proved reserves.
If it is determined that an exploratory well has not found proved reserves, the
costs of the well are expensed. The costs of development wells are capitalized
whether productive or nonproductive. Geological and geophysical costs on
exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are not considered to be realizable. Depletion, depreciation and
amortization ("DD&A") of capitalized costs of proved oil and gas properties is
provided on a property-by-property basis using the unit-of-production method.
The computation of DD&A takes into consideration dismantlement, restoration and
abandonment costs and the anticipated proceeds from equipment salvage. The
estimated dismantlement, restoration and abandonment costs are expected to be
substantially offset by the estimated residual value of lease and well
equipment. Effective January 1, 2003 under SFAS 143, the carrying amount of
assets will be increased by their respective retirement obligations. An
F-7
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
impairment loss is recorded if the net capitalized costs of proved oil and gas
properties exceed the aggregate undiscounted future net revenues determined on a
property-by-property basis. The impairment loss recognized equals the excess of
net capitalized costs over the related fair value determined on a
property-by-property basis. Gains and losses are recognized on sales of entire
interests in proved and unproved properties. Sales of partial interests are
generally treated as a recovery of costs and any resulting gain or loss is
recorded as other income.
Other Property and Equipment
Other property and equipment, including oilfield servicing equipment, is stated
at cost. Depreciation of other property and equipment is calculated using the
straight-line method over the estimated useful lives (ranging from 3 to 40
years) of the respective assets. The costs of normal maintenance and repairs are
charged to expense as incurred. Material expenditures that increase the life of
an asset are capitalized and depreciated over the estimated remaining useful
life of the asset. The cost of other property and equipment sold, or otherwise
disposed of, and the related accumulated depreciation are removed from the
accounts and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis
with accumulated depreciation, is summarized as follows:
December 31, Estimated
---------------------------- Useful Life
2002 2001 (in years)
------------- ------------- -------------
(In thousands)
Other property and equipment:
Oilfield servicing equipment................................... $ 2,824 $ 2,730 6
Trucks......................................................... 262 262 5
Building....................................................... 96 96 40
Office equipment and furniture................................. 501 499 3 to 6
------------- -------------
Total cost 3,863 3,587
============= =============
Accumulated depreciation (2,819) (2,502)
============= =============
Net property and equipment................................. $ 864 $ 1,085
============= =============
Supplemental Disclosure of Cash Flow Information
Non-cash investing and financing transactions not reflected in the consolidated
statements of cash flows include the following:
Year Ended December 31,
-----------------------------------
2002 2001 2000
---------- ----------- -----------
(In thousands)
Non-cash investing transactions:
Additions to properties included in current liabilities................ $ 851 $ 999 $ --
Non-cash consideration received from the sale of equipment............. -- -- 23
---------- ----------- -----------
Total.............................................................. $ 851 $ 999 $ 23
========== =========== ===========
Non-cash financing transactions:
Shares tendered for payment of notes receivable and accrued interest... $ -- $ 137 $ 773
Recourse note receivable from stock option exercise.................... -- -- 156
---------- ----------- -----------
Total.............................................................. $ -- $ 137 $ 929
========== =========== ===========
Supplemental disclosure of cash paid for interest and income taxes:
Year Ended December 31,
-----------------------------------
2002 2001 2000
---------- ----------- -----------
(In thousands)
Supplemental disclosure:
Cash paid during the year for interest................................ $ 1 $ 2 $ 2
Cash paid during the year for income taxes............................ -- -- --
F-8
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Revenue Recognition
Revenues associated with oil and gas sales are recorded when the title passes
and are net of royalties. Oilfield service revenues are recognized when the
related service is performed.
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board ("APB") Opinion No. 25
and related interpretations. Nonemployee stock-based compensation is accounted
for using the fair value method in accordance with SFAS No. 123 "Accounting for
Stock-based Compensation."
As of December 31, 2002, the Company had 5,544,017 options outstanding under
stock option and award plans as well as from other individual grants. The
Company applies APB Opinion No. 25 and related interpretations in accounting for
options granted under the stock option and award plans and for other option
agreements. Had compensation cost for the Company's options been determined
based on the fair value at the grant dates consistent with SFAS No. 123, the
Company's net loss and loss per share would have been increased to the pro forma
amounts indicated in the following table:
2002 2001 2000
------------- ------------- -------------
(In thousands, except per share amounts)
Net loss:
Net loss, as reported.............................................. $ (5,925) $ (8,410) $ (10,843)
Add: stock-based employee compensation expense included in
reported net loss, net of related tax effects.................... 55 1,078 652
Less: Total stock-based employee compensation expense
determined under the fair value based method for all awards,
net of related tax effects....................................... (1,125) (1,515) (1,890)
------------- ------------- -------------
Pro forma net loss............................................ $ (6,995) $ (8,847) $ (12,081)
============= ============= =============
Basic and diluted net loss per share:
As reported................................................... $ (0.34) $ (0.48) $ (0.66)
Pro forma..................................................... (0.40) (0.50) (0.74)
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 2002,
2001 and 2000 is estimated on the date of grant using the Black-Scholes option
pricing model. The following weighted-average assumptions were utilized for the
Black-Scholes valuation: (1) expected volatility of 90% for 2002, 78% to 83% for
2001 and 80% to 87% for 2000; (2) expected lives ranging from four to seven
years; (3) risk-free interest rates at the date of grant ranging from 3.26% to
4.24%; and, (4) dividend yield of zero for each year.
Income Taxes
Deferred income taxes are provided for the difference between the tax basis of
an asset or liability and its reported amount in the financial statements. Such
difference may result in taxable or deductible amounts in future years when the
reported amount of the asset or liability is recovered or settled, respectively.
Reclassifications
Certain balances in the 2001 and 2000 financial statements have been
reclassified to conform to the current year presentation. These changes had no
effect on total assets, total liabilities, stockholders' equity or net loss.
F-9
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Foreign Operations
The Company's investments and operations in Poland are comprised of U.S. Dollar
expenditures.
Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates with regard to the consolidated financial statements
include the unaudited estimates of proved oil and gas reserve quantities and the
related future net cash flows.
Net Loss Per Share
Basic earnings per share is computed by dividing the net loss by the weighted
average number of common shares outstanding. Diluted earnings per share is
computed by dividing the net loss by the sum of the weighted average number of
common shares and the effect of dilutive unexercised stock options and warrants
and convertible preferred stock.
Outstanding options and warrants as of December 31, 2002, 2001 and 2000 were as
follows:
Options and
Warrants Price Range
------------ ---------------
Balance sheet date:
December 31, 2002.................... 5,544,017 $1.50 - $10.25
December 31, 2001.................... 5,785,585 $1.50 - $10.25
December 31, 2000.................... 4,572,917 $1.50 - $10.25
The Company had a net loss in 2002, 2001 and 2000. The above options and
warrants were not included in the computation of diluted earnings per share for
2002, 2001 or 2000 because the effect would have been antidilutive.
Note 2: Liquidity and Capital Resources
The accompanying consolidated financial statements have been prepared assuming
the Company will continue as a going concern and do not include any adjustments
to reflect the possible future effects on the recoverability of assets and
liquidation of liabilities that may result from this uncertainty. The Company
has incurred substantial operating losses and negative cash flows from
operations since inception and had an accumulated deficit of approximately $54
million at December 31, 2002. These matters raise substantial doubt about the
Company's ability to continue as a going concern. To date, the Company has
financed its operations principally through the sale of equity securities,
issuance of debt securities and through agreements with industry partners that
funded the Company's share of costs in certain exploratory activities in order
to earn an interest in the Company's properties.
As of December 31, 2002, the Company had $705,012 of cash and cash equivalents,
negative working capital of $(9,149,528) including debt due to Rolls Royce Power
Ventures ("RRPV") with a principal amount of $5.0 million due on or before March
9, 2003. In addition, the Company has agreed to spend $16.0 million of
exploration costs on the Fences I project area to earn a 49.0% interest. Through
the end of 2002, the Company had paid $6.7 million towards the $16.0 million
commitment, leaving a remaining cash commitment to POGC of $9.3 million.
Subsequent to December 31, 2002, the Company has amended its loan agreement with
RRPV (see Note 6) and raised approximately $5.6 million through the sale of its
convertible preferred stock (see Note 17). In addition, the Company entered into
a Farmout Agreement with CalEnergy Gas whereby CalEnergy Gas has the right, but
not the obligation, to earn a 24.5% interest (50% of the Company's interest) in
the Fences I project area by spending a total of $10.6 million, including the
cost to drill two wells plus certain cash payments to the Company, all to be
F-10
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
completed by December 15, 2003. CalEnergy Gas also has the right to terminate
participation after each of the first two wells. However, if CalEnergy Gas
completes all the earning requirements, the work performed and payments will
exceed the Company's remaining obligations to POGC to complete its earning
requirements in the Fences I project area.
The Company's long-term success or failure is largely dependent on the outcome
of its exploration, production and acquisition activities in Poland. The
Company's ability to continue its ongoing oil and gas activities in Poland is
dependent on accessing additional capital directly or through further farmouts.
The availability of such capital will effect the timing, pace, scope and amount
of the Company's future capital expenditures. There can be no assurance the
Company will be able to obtain additional financing, reduce expenses or
successfully complete other steps to continue as a going concern. If the Company
is unable to obtain sufficient funds to satisfy its cash requirements, it may be
forced to curtail operations, dispose of assets or seek extended payment terms
from its vendors. Such events would materially and adversely affect the
Company's financial position and results of operations.
Note 3: Investment in Marketable Debt Securities
The Company follows the provisions of SFAS No. 115 "Accounting for Certain
Investments in Debt and Equity Securities." The Company's marketable debt
securities with remaining contractual maturities of less than twelve months are
classified as available for sale. The Company had no investment in debt and
equity securities at December 31, 2002.
Note 4: Performance Bond Deposits
As of December 31, 2002 and 2001, the Company had a replacement bond to a
federal agency in the amount of $463,000, which was collateralized by
certificates of deposit totaling $231,500. In addition, there are certificates
of deposit totaling $125,000 covering performance bonds in other states.
Note 5: Accrued Liabilities
The Company's accrued liabilities as of December 31, 2002 and 2001 were
comprised of the following:
December 31,
----------------------------
2002 2001
------------- -------------
(In thousands)
Accrued liabilities:
Exploratory dry hole costs................................................... $ 880 $ 880
Drilling costs............................................................... 433 --
Seismic costs................................................................ 1,859 1,798
Pipeline costs .............................................................. 502 --
Interest payable, POGC ...................................................... 704 --
Interest payable, RRPV ...................................................... 392 --
Other costs.................................................................. 163 139
------------- -------------
Total.................................................................... $ 4,933 $ 2,817
============= =============
Note 6: Notes Payable
On March 9, 2001, the Company signed a $5.0 million, 9.5% loan agreement and gas
purchase option agreement with RRPV. The proceeds from the loan were used for
exploration and development of additional gas reserves in Poland. The loan was
interest free for the first year. In consideration for the loan, the Company
granted RRPV an option to purchase up to 17 Mmcf of gas per day from the
Company's properties in Poland, subject to availability, exercisable on or
before March 9, 2002. The option to purchase gas from the Company's Polish
properties was not exercised by RRPV. In accordance with the loan agreement, the
entire principal amount plus accrued interest is due on or before March 9, 2003,
unless RRPV elects to convert the loan to restricted common stock at $5.00 per
share, the market value of the Company's common stock at the time the terms with
RRPV were finalized, on or before March 9, 2003. As collateral for the loan, the
Company granted RRPV a lien on most of the Company's Polish property interests.
F-11
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
For financial reporting purposes, the Company imputed interest expense for the
first year at 9.5%, or $433,790, to be amortized ratably over the one-year
interest free period beginning March 9, 2001 and recorded an option premium of
$433,790 pertaining to granting RRPV an option to purchase gas from the
Company's properties in Poland, to be amortized ratably to other income over the
one-year option period.
In March, 2003, following a private placement of convertible preferred stock,
the Company paid $2.2 million to RRPV. In return, RRPV extended the maturity
date of the note to December 31, 2003. The Company has also agreed to pay 40% of
the gross proceeds of any subsequent equity or debt offering concluded prior to
the amended maturity date to RRPV. The Company also agreed to assign its rights
to payments under the CalEnergy Gas agreement to RRPV, except for those amounts
relating to the two wells required to be drilled under the agreement. All such
payments will 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 loan amendment contains other terms and conditions, including an increase in
the interest rate on the note from 9.5% to 12% per annum effective March 9,
2003, an extension of the conversion period until December 31, 2003, with the
conversion price being changed from $5.00 per share to $3.42 per share, and an
extension fee payment of $100,000.
Note 7: Commitments
Fences I Project Area
On April 11, 2000, the Company signed an agreement with POGC under which the
Company will earn a 49.0% working interest in approximately 265,000 gross acres
in west central Poland (the "Fences I" project area) by spending $16.0 million
for agreed drilling, seismic acquisition and other related activities.
During 2000, the Company paid $6,689,432 to POGC under the agreement, including
$4,586,063 for drilling activities and $2,103,369 for 3-D seismic activities,
leaving a remaining commitment of $9,310,568. During 2002 and 2001, the Company
did not make any additional cash payments to POGC relating to this agreement. As
of December 31, 2001, the Company had accrued $2,678,477 of additional costs
pertaining to the Fences project area $16.0 million commitment, including
$880,121 for drilling activities and $1,798,356 for 3-D seismic activities.
During 2002, the Company reaffirmed its intent to fulfill its $16 million
commitment with POGC. In connection with this agreement, the Company agreed to
recognize and pay at a future date an additional $2,306,627 of costs related to
prior exploration activities in the Fences I area to POGC, $1,602,902 of which
will be credited towards the $16 million commitment. The 2002 amount includes
$703,725 in interest costs related to the Company's prior liabilities to POGC,
$432,875 in drilling costs, $417,653 in seismic costs, $502,244 in pipeline
costs, and $250,130 related to foreign exchange adjustments. As part of its
future payment, the Company agreed to assign in 2003 all of its right to the
Kleka well, including the amounts recorded as accounts receivable for Kleka gas
sales. Accordingly, at December 31, 2002, the Company's account receivable from
POGC in the amount of $606,986 was offset against the POGC liability. The
Company further agreed to begin accruing interest on the past due amount to
POGC. The interest rate in effect at December 31, 2002 was 12.8%. The interest
rate changed on January 1, 2003, to 10.4%.
Apache Exploration Program
The Apache Exploration Program consists of various agreements signed between the
Company and Apache Corporation ("Apache") during 1997 through 2001. The initial
primary terms of the Apache Exploration Program included a commitment by Apache
to cover the Company's share of costs to drill ten exploratory wells, to acquire
2,000 kilometers of 2-D seismic and cover the Company's share of other specified
costs to earn a fifty-percent interest in the Company's Lublin Basin and
Carpathian project areas. As of December 31, 2000, Apache had completed all of
its requirements under the terms of the Apache Exploration Program.
F-12
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 8: Income Taxes
The Company recognized no income tax benefit from the losses generated during
2002, 2001 and 2000. The components of the net deferred tax asset as of December
31, 2002 and 2001 are as follows:
December 31,
----------------------------
2002 2001
------------- -------------
(In thousands)
Deferred tax liability:
Property and equipment basis differences...................................... $ (370) $ (349)
Deferred tax asset:
Net operating loss carryforwards:
United States............................................................. 12,475 12,174
Poland.................................................................... 4,224 3,893
Oil and gas properties........................................................ 1,795 1,218
Options issued for services................................................... 610 143
Other......................................................................... 10 10
Valuation allowance........................................................... (18,744) (17,089)
------------- -------------
Total..................................................................... $ -- $ --
============= =============
The change in the valuation allowance during 2002, 2001 and 2000 is as follows:
Year Ended December 31,
-------------------------------------------
2002 2001 2000
------------- ------------- -------------
(In thousands)
Valuation allowance:
Balance, beginning of year..................................... $ (17,089) $ (16,113) $ (12,848)
Decrease due to property and equipment basis differences....... (577) 136 109
Increase due to net operating loss............................. (632) (1,956) (2,931)
Other.......................................................... (446) 844 (443)
------------- ------------- -------------
Total...................................................... $ (18,744) $ (17,089) $ (16,113)
============= ============= =============
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, 2002 and 2001.
United States NOL
At December 31, 2002, the Company had net operating loss ("NOL") carryforwards
in the United States of approximately $33,446,000 available to offset future
taxable income, of which approximately $18,749,000 expires from 2008 through
2012 and 14,697,000 expires subsequent to 2018. The utilization of the NOL
carryforwards against future taxable income in the United States may become
subject to an annual limitation if there is a change in ownership. The NOL
carryforwards in the United States include $6,326,000 relating to tax deductions
resulting from the exercise of stock options. The tax benefit from adjusting the
valuation allowance related to this portion of the NOL carryforward will be
credited to additional paid-in capital.
Polish NOL
As of December 31, 2002, the Company had NOL carryforwards in Poland totaling
approximately $11,324,600, including $882,262, $1,925,220 and $5,734,913
generated in 2002, 2001 and 2000, respectively. The NOL carryforwards may be
carried forward five years in Poland. However, no more than fifty-percent of the
NOL carryforwards for any given year may be applied against Polish income in
succeeding years.
F-13
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The domestic and foreign components of our net loss are as follows:
Year Ended December 31,
-------------------------------------------
2002 2001 2000
------------- ------------- -------------
(In thousands)
Domestic....................................................... $ (3,570) $ (1,585) $ (4,295)
Foreign........................................................ (2,355) (6,825) (6,548)
------------- ------------- -------------
Total...................................................... $ (5,925) $ (8,410) $ (10,843)
============= ============= =============
Note 9: Private Placement of Common Stock
During 2000, the Company completed a private placement of 2,969,000 shares of
common stock that resulted in net proceeds of $9,272,453 ($10,391,500 gross).
The proceeds from this placement were used to partially fund ongoing exploration
and development activities in Poland and for general corporate purposes.
Note 10: Stock Options and Warrants
Equity Compensation Plans
The Company's equity compensation consists of annual Stock Option and Award
Plans that are each subject to approval by the Board of Directors and are
subsequently presented for approval by the shareholders at each of the Company's
annual meetings. As of the date of this report, no options had been issued under
the 2002 Stock Option and Award Plan.
The following table summarizes information regarding the Company's stock option
and award plans as of December 31, 2002:
Weighted Number of
Number of Average Shares
Shares Exercise Available
Authorized Price of for Future
Under Plan Outstanding Issuance
Shares
------------- --------------- -------------
Equity compensation plans approved by shareholders:
1995 Stock Option and Award Plan................................ 500,000 $ 8.38 --
1996 Stock Option and Award Plan................................ 500,000 6.65 14,500
1997 Stock Option and Award Plan................................ 500,000 7.79 57,400
1998 Stock Option and Award Plan................................ 500,000 6.46 12,000
1999 Stock Option and Award Plan................................ 500,000 4.40 5,333
2000 Stock Option and Award Plan................................ 600,000 2.44 31,750
2001 Stock Option and Award Plan................................ 600,000 2.40 230,000
------------- --------------- -------------
Total......................................................... 3,700,000 $ 6.09 350,983
============= =============== =============
The above table excludes 1,195,000 options that have been granted outside of
shareholder approved option plans.
All stock option and award plans are administered by a committee (the
"Committee") consisting of the board of directors or a committee thereof. At its
discretion, the Committee may grant stock, incentive stock options ("ISOs") or
non-qualified options to any employee, including officers. In addition to the
options granted under the stock option plans, the Company also issues
non-qualified options outside the stock option plans. The granted options have
terms ranging from five to seven years and vest over periods ranging from the
date of grant to three years. Under terms of the stock option award plans, the
Company may also issue restricted stock. The Company has not issued any stock
awards through the date of this report under the terms of the above stock option
and award plans.
F-14
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The following table summarizes fixed option activity for 2002, 2001 and 2000:
2002 2001 2000
-------------------------- ------------------------ -------------------------
Weighted Weighted Weighted
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
Shares Price Shares Price Shares Price
------------- ----------- ----------- ----------- ------------ -----------
Fixed Options Outstanding:
Beginning of year......... 4,785,585 $ 4.87 4,322,917 $ 5.15 3,896,501 $ 5.25
Granted................... 551,000 2.40 501,750 2.44 501,750 4.06
Exercised................. (3,000) 1.50 -- -- (75,000) 3.00
Canceled.................. (114,568) 6.00 (33,082) 5.00 (334) 8.63
Expired................... (675,000) 2.61 (6,000) 5.75 -- --
------------- ----------- ------------
End of year........... 4,544,017 $ 4.68 4,785,585 $ 4.87 4,322,917 $ 5.15
============= =========== ============
Exercisable at year-end....... 3,515,867 $ 5.41 3,669,356 $ 5.28 2,744,183 $ 5.61
============= =========== ============
The weighted average fair value per share of options granted during 2002, 2001
and 2000 was $1.80, $1.16 and $2.56, respectively. The above table excludes
shares that would be issued to RRPV should they exercise the option to convert
their debt to stock as described in Note 6.
The following table summarizes information about fixed stock options outstanding
as of December 31, 2002:
Outstanding Exercisable
------------------------------------------------------ -------------------------------
Weighted Average
Number of Remaining Weighted Number of Weighted
Exercise Options Contractual Life Average Options Average
Price Range Outstanding (in years) Exercise Price Exercisable Exercise Price
-------------------------------------- -------------------- --------------- -------------- ---------------
$1.50 - $3.00......... 2,155,750 3.70 $ 2.72 1,284,923 $ 2.93
$4.06 - $6.75......... 1,288,100 3.68 5.37 1,130,777 5.55
$7.25 - $10.25........ 1,100,167 1.87 8.51 1,100,167 8.51
--------------- -------------------- --------------- -------------- ---------------
Total.......... 4,544,017 3.25 $ 4.87 3,515,867 $ 5.52
=============== ==================== =============== ============== ===============
The above table excludes shares that would be issued to RRPV should they
exercise the option to convert their debt to 1,000,000 shares of stock as
described in Note 6.
Warrants
The following table summarizes changes in outstanding and exercisable warrants
during 2002, 2001 and 2000:
2002 2001 2000
--------------------------- --------------------------- ---------------------------
Number of Price Number of Price Number of Price
Shares Range Shares Range Shares Range
------------ -------------- ------------ -------------- ------------ --------------
Warrants outstanding:
Beginning of year... 100,000 $ 3.00 250,000 $ 3.00 - $6.90 270,572 $1.65 - $6.90
Exercised........... -- -- -- -- (20,572) 1.65
Expired............. (100,000) $ 3.00 (150,000) $ 6.90 -- --
----------- ---------- ------------
End of year....... -- $ -- 100,000 $ 3.00 250,000 $3.00 - $6.90
=========== ========== ============
Option and Warrant Extensions
On August 5, 2001, the Company extended the term of options and warrants to
purchase 125,000 shares of the Company's common stock that were to expire during
2001 for a period of two years, with a one-year vesting period. In accordance
with FIN 44 "Accounting for Certain Transactions Involving Stock Compensation,"
the Company incurred deferred compensation costs of $218,750 applicable to an
officer and a non-officer, to be amortized to expense over the one-year vesting
period.
F-15
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
On August 4, 2000, the Company extended the term of options and warrants to
purchase 678,000 shares of the Company's common stock that were to expire during
2000 for a period of two years, with a one-year vesting period. The Company
incurred deferred compensation costs of $1,565,974, including $1,188,332
covering the intrinsic value applicable to officers and employees and $377,642
covering the fair market value calculated using the Black-Scholes model for a
consultant, which was amortized to expense over the one-year vesting period.
These options have now expired.
Note Receivable from Stock Option Exercises
On November 8, 2000, a former employee exercised an option to purchase 52,000
shares of the Company's common stock at a price of $3.00 per share. The former
employee elected to pay for the cost of the exercise by signing a full recourse
promissory note with the Company for $156,000. Terms of the note receivable
included a three-year term with annual principal payments of $52,000 plus
interest accrued at 9.5%. On November 8, 2001, the former employee surrendered
52,000 shares of the Company's common stock in return for cancellation of the
note receivable. The Company recorded a loss of $34,060 on the transaction and
the acquisition of 52,000 shares of common stock at a price of $2.63 per share,
the closing price of the Company's stock on November 8, 2001.
Note 11: Related Party Transactions
Notes Receivable from Officers
On February 17, 1998, two of the Company's officers exercised options to
purchase 300,000 shares of the Company's common stock at $1.50 per share that
were scheduled to expire on May 6, 1998. The officers paid for the cost of
exercising the options by utilizing a contractual bonus of $100,000 each issued
to them during 1997 and signing a full recourse note payable to the Company for
$125,000 each with interest accrued at 7.7%. On April 10, 1998, in consideration
of the agreement of the two officers to not sell the Company's common stock in
market transactions, the Company agreed to advance the officers, on a
non-recourse basis, additional funds to cover their tax liabilities and other
considerations. As of December 31, 1999, the officers had been advanced a total
amount of $1,837,920. The carrying value of the notes receivable from officers
was $773,055 as of December 28, 2000, including principal of $1,837,920 and
accrued interest of $338,824, which was reduced by an impairment allowance of
$1,403,689 based on the market value of 233,340 shares of the Company's common
stock held as collateral. On December 28, 2000, the officers surrendered the
collateralized shares to the Company in return for the cancellation of the notes
receivable from officers and the Company recorded 233,340 shares of treasury
stock at a cost of $773,055.
Note 12: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2002 and 2001 is as follows:
Quarter Ended
---------------------------------------------------------------------------
December 31 September 30 June 30 March 31
----------------- ----------------- ------------------ ------------------
(In thousands, except per share amounts)
2002:
Revenues....................... $ 708 $ 977 $ 607 $ 450
Net operating loss............. (2,833) (271) (751) (1,000)
Net loss....................... (3,664) (373) (870) (1,018)
Basic and diluted net loss per
common share................. $ (0.21) $ (0.02) $ (0.05) $ (0.06)
2001:
Revenues....................... $ 635 $ 1,174 $ 1,363 $ 641
Net operating loss............. (3,254) (1,283) (1,855) (2,196)
Net loss....................... (3,251) (1,195) (1,807) (2,157)
Basic and diluted net loss per
common share................. $ (0.19) $ (0.07) $ (0.10) $ (0.12)
F-16
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The net operating loss for the fourth quarter of 2002 includes $1,547,860 in
property impairment costs, and $703,725 and $502,244 in interest and seismic
costs, respectively, incurred in connection with a revision of the Company's
agreement with POGC relative to the Fences I project area. The net operating
loss for the fourth quarter of 2001 includes $3,048,137 in dry hole costs and
$525,355 in property impairment costs.
Note 13: Business Segments
The Company operates within two business segments of the oil and gas industry:
exploration and production ("E&P") and oilfield services. The Company's revenues
associated with its E&P activities are comprised of oil sales from its producing
properties in the United States and oil and gas sales from its producing
properties in Poland. Over 85.0% of the Company's oil sales in the United States
were to Cenex during 2000, 2001 and the first half of 2002. During the second
half of 2002, over 85% of the Company's oil sales were to Plains Marketing
Canada, LP. During 2002 and 2001, all of the Company's oil and gas sales in
Poland were to POGC. There were no oil and gas sales in Poland during 2000. The
Company believes the purchasers of its oil and gas production could be replaced,
if necessary, without a loss in revenue. E&P operating costs are comprised of:
(1) exploration costs (geological and geophysical costs, exploratory dry holes,
non-producing leasehold impairments and Apache Poland G&A costs (in 2000)), and,
(2) lease operating costs (lease operating expenses and production taxes).
Substantially all exploration costs are related to the Company's operations in
Poland. Substantially all lease operating costs are related to the Company's
domestic production.
The Company's revenues associated with its oilfield services segment are
comprised of contract drilling and well servicing fees generated by the
Company's oilfield servicing equipment in Montana. Oilfield servicing costs are
comprised of direct costs associated with its oilfield services.
DD&A directly associated with a respective business segment is disclosed within
that business segment. The Company does not allocate current assets, corporate
DD&A, general and administrative costs, amortization of deferred compensation,
interest income, interest expense, impairment of notes receivable from officers,
other income or other expense to its operating business segments for management
and business segment reporting purposes. All material inter-company transactions
between the Company's business segments are eliminated for management and
business segment reporting purposes.
Information on the Company's operations by business segment for 2002, 2001 and
2000 is summarized as follows:
2002
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues (1)................................................... $ 2,209 $ 533 $ 2,742
Cash operating costs........................................... (2,396) (540) (2,936)
Non-cash operating costs....................................... (1,545) -- (1,545)
------------- ------------- -------------
Operating income or (loss) before DD&A expense............. (1,732) (7) (1,739)
DD&A expense.................................................. (281) (310) (591)
------------- ------------- -------------
Operating loss................................................ $ (2,013) $ (317) $ (2,330)
============= ============= =============
Identifiable net property and equipment:
Unproved properties - Poland.................................. $ 146 $ -- $ 146
Unproved properties - Domestic................................. 8 -- 8
Proved properties - Poland..................................... 1,931 -- 1,931
Proved properties - Domestic................................... 957 -- 957
Equipment and other............................................ -- 791 791
------------- ------------- -------------
Total...................................................... $ 3,042 $ 791 $ 3,833
============= ============= =============
Net Capital Expenditures:
Property and equipment(2) $ 1,012 $ 116 $ 1,128
------------- ------------- -------------
Total...................................................... $ 1,012 $ 116 $ 1,128
============= ============= =============
- -------------------------
(1) E&P revenues include $1,924,000 generated in the United States and
$285,000 generated in Poland.
(2) E&P includes $418,000 of pipeline costs, $586,000 of proved property
additions and $8,000 of unproved property additions.
F-17
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
2001
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues (1)................................................... $ 2,229 $ 1,584 $ 3,813
Cash operating costs........................................... (5,751) (1,300) (7,051)
Non-cash operating costs (2)................................... (2,727) -- (2,727)
------------- ------------- -------------
Operating income or (loss) before DD&A expense............. (6,249) 284 (5,965)
DD&A expense.................................................. (322) (308) (630)
------------- ------------- -------------
Operating loss................................................ $ (6,571) $ (24) $ (6,595)
============= ============= =============
Identifiable net property and equipment:
Unproved properties - Poland.................................. $ 648 $ -- $ 648
Unproved properties - Domestic................................. 8 -- 8
Proved properties - Poland..................................... 2,324 -- 2,324
Proved properties - Domestic................................... 877 -- 877
Equipment and other............................................ -- 985 985
------------- ------------- -------------
Total...................................................... $ 3,857 $ 985 $ 4,842
============= ============= =============
Net Capital Expenditures:
Property and equipment(3)...................................... $ 1,745 $ 248 $ 1,993
------------- ------------- -------------
Total...................................................... $ 1,745 $ 248 $ 1,993
============= ============= =============
- -----------------------
(1) E&P revenues include $1,815,000 generated in the United States and
$414,000 generated in Poland.
(2) E&P includes accrued exploratory dry hole costs of $880,000, accrued
3-D seismic costs of $1,799,000, stock options issued for services
valued at $36,000, a $572,000 credit pertaining to reversing accrued
compensation and an impairment charge of $584,000 for unproved Polish
properties.
(3) E&P includes a $894,000 of exploratory dry hole costs, $320,000 of
proved property additions and $531,000 of unproved property additions.
2000
-------------------------------------------
Oilfield
E&P Services Total
------------- ------------- -------------
(In thousands)
Operations summary:
Revenues........................................................$ 2,521 $ 1,290 $ 3,811
Cash operating costs............................................ (8,710) (1,084) (9,794)
Non-cash operating costs (1).................................... (983) -- (983)
------------- ------------- -------------
Operating income or (loss) before DD&A expense.............. (7,172) 206 (6,966)
DD&A expense.................................................... (73) (247) (320)
------------- ------------- -------------
Operating loss..................................................$ (7,245) $ (41) $ (7,286)
============= ============= =============
Identifiable net property and equipment:
Unproved properties - Poland (2)...............................$ 3,014 $ -- $ 3,014
Unproved properties - Domestic.................................. 18 -- 18
Proved properties - Poland...................................... 2,429 -- 2,429
Proved properties - Domestic.................................... 623 -- 623
Equipment and other............................................. -- 1,045 1,045
------------- ------------- -------------
Total.......................................................$ 6,084 $ 1,045 $ 7,129
============= ============= =============
Net Capital expenditures:
Property and equipment (3)......................................$ 6,988 $ 780 $ 7,768
------------- ------------- -------------
Total.......................................................$ 6,988 $ 780 $ 7,768
============= ============= =============
- ------------------------
(1) E&P includes stock options valued at $81,000 issued to a Polish citizen
for consulting services, accrued bonuses of $228,000 and a
non-producing property impairment of $674,000.
(2) E&P includes $2,157,000 relating to the Mieszkow 1, which was in the
process of being drilled as of December 31, 2000 and was subsequently
determined to be an exploratory dry hole during 2001.
(3) E&P includes $2,034,000 of costs that were reclassed to exploratory dry
hole expense, $2,631,000 of proved property additions and $2,323,000 of
unproved property additions.
F-18
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
A reconciliation of the segment information to the consolidated totals for 2002,
2001 and 2000 follows:
2002 2001 2000
------------- ------------- -------------
(In thousands)
Revenues:
Reportable segments...............................................$ 2,742 $ 3,813 $ 3,811
Non-reportable segments........................................... -- -- --
------------- ------------- -------------
Total revenues...................................................$ 2,742 $ 3,813 $ 3,811
============= ============= =============
Operating loss:
Reportable segments...............................................$ (2,333) $ (6,595) $ (7,286)
Expense or (revenue) adjustments:
Corporate DD&A expense.......................................... (27) (32) (66)
Amortization of deferred compensation (G&A)..................... (55) (1,078) (652)
General and administrative expenses............................. (2,440) (883) (2,654)
Other........................................................... -- -- (1)
------------- ------------- -------------
Total net operating loss......................................$ (4,855) $ (8,588) $ (10,659)
============= ============= =============
Net property and equipment:
Reportable segments...............................................$ 3,833 $ 4,842 $ 7,129
Corporate assets.................................................. 76 100 126
------------- ------------- -------------
Net property and equipment.......................................$ 3,909 $ 4,942 $ 7,255
============= ============= =============
Property and equipment capital expenditures:
Reportable segments...............................................$ 1,128 $ 1,993 $ 7,768
Corporate assets.................................................. 2 6 33
------------- ------------- -------------
Net property and equipment capital expenditures..................$ 1,130 $ 1,999 $ 7,801
============= ============= =============
Note 14: 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, 2002 and 2001 are summarized as follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
December 31, 2002:
Proved properties..........................................$ 2,360 $ 2,394 $ 4,754
Unproved properties........................................ 8 146 154
--------------- --------------- ---------------
Total gross properties................................... 2,368 2,540 4,908
Less accumulated depreciation, depletion and amortization.. (1,404) (462) (1,866)
--------------- --------------- ---------------
Total...............................................$ 964 $ 2,078 $ 3,042
=============== =============== ===============
December 31, 2001:
Proved properties..........................................$ 2,208 $ 2,581 $ 4,789
Unproved properties........................................ 8 648 656
--------------- --------------- ---------------
Total gross properties................................... 2,216 3,229 5445
Less accumulated depreciation, depletion and amortization.. (1,331) (257) (1,588)
--------------- --------------- ---------------
Total...............................................$ 885 $ 2,972 $ 3,857
=============== =============== ===============
F-19
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Results of Operations
Results of operations are reflected in Note 13, Business Segments. There is no
tax provision as the Company is not subject to any federal or local income taxes
due to its operating losses. Total production costs for 2002, 2001 and 2000 were
$1,365,454, $1,358,304 and $1,348,399, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities
during 2002, 2001 and 2000, whether capitalized or expensed, are summarized as
follows:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
Year ended December 31, 2002:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
Unproved............................................... -- 8 8
Exploration costs.......................................... -- 1,031 1,031
Development costs.......................................... 153 851 1,004
--------------- --------------- ---------------
Total..................................................$ 153 $ 1,890 $ 2,043
=============== =============== ===============
Year ended December 31, 2001:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
Unproved............................................... -- 525 525
Exploration costs.......................................... -- 6,542 6,542
Development costs.......................................... 319 2 321
--------------- --------------- ---------------
Total..................................................$ 319 $ 7,069 $ 7,388
=============== =============== ===============
Year ended December 31, 2000:
Acquisition of properties:
Proved.................................................$ -- $ -- $ --
Unproved............................................... -- 21 21
Exploration costs (1)...................................... 692 11,200 11,892
Development costs.......................................... 202 -- 202
--------------- --------------- ---------------
Total..................................................$ 894 $ 11,221 $ 12,115
=============== =============== ===============
- ---------------------
(1) Includes $2,429,000 relating to the Kleka 11, which was categorized as
proved property as of December 31, 2000.
Impairment of Unproved Oil and Gas Properties
During 2002, 2001, and 2000 the Company recorded impairment expenses of
$1,547,860, $583,855 and $674,158, respectively.
Exploratory dry hole costs
During 2001, for financial reporting purposes, the Company classified the
Mieszkow 1 as an exploratory dry hole, and recorded exploratory dry hole costs
of $3,051,871, including cash expenditures of $2,171,750 and accrued costs of
$880,121.
F-20
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Note 15: Summary Oil and Gas Reserve Data (Unaudited)
Estimated Quantities of Proved Reserves
Proved reserves are the estimated quantities of crude oil which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reserves under existing economic and operating
conditions. The Company's proved oil and gas reserve quantities and values are
based on estimates prepared by independent reserve engineers in accordance with
guidelines established by the Securities and Exchange Commission. Operating
costs, production taxes and development costs were deducted in determining the
quantity and value information. Such costs were estimated based on current costs
and were not adjusted to anticipate increases due to inflation or other factors.
No price escalations were assumed and no amounts were deducted for general
overhead, depreciation, depletion and amortization, interest expense and income
taxes. The proved reserve quantity and value information is based on the
weighted average price on December 31, 2002 of $25.00 per bbl for oil in the
United States and $2.60 per MCF of gas in Poland. The determination of oil and
gas reserves is based on estimates and is highly complex and interpretive, as
there are numerous uncertainties inherent in estimated quantities and values of
proved reserves, projecting future rates of production and timing of development
expenditures. The estimates are subject to continuing revisions as additional
information becomes available or assumptions change.
Estimates of the Company's proved domestic reserves were prepared by Larry
Krause Consulting, an independent engineering firm in Billings, Montana.
Estimates of the Company's proved Polish reserves were prepared by Troy-Ikoda
Limited, an independent engineering firm in the United Kingdom. The following
unaudited summary of proved developed reserve quantity information represents
estimates only and should not be construed as exact:
Crude Oil Natural Gas
-------------------------------- --------------------------------
United States Poland United States Poland
--------------- --------------- --------------- ---------------
(in thousand barrels of oil) (In millions of cubic feet)
Proved Developed Reserves:
December 31, 2002......................... 1,015 -- -- 1,374
December 31, 2001......................... 1,075 -- -- 2,167
December 31, 2000......................... 1,161 -- -- --
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, 2002:
Beginning of year....................... 1,100 114 -- 5,010
Extensions or discoveries............... -- -- -- --
Revisions of previous estimates......... 33 -- -- (620)
Production.............................. (91) -- -- (180)
--------------- --------------- --------------- ---------------
End of year......................... 1,042 114 -- 4,210
=============== =============== =============== ===============
December 31, 2001:
Beginning of year....................... 1,220 -- -- 2,381
Extensions or discoveries............... -- 114 -- 2,844
Revisions of previous estimates......... (26) -- -- 35
Production.............................. (94) -- -- (250)
--------------- --------------- --------------- ---------------
End of year......................... 1,100 114 -- 5,010
=============== =============== =============== ===============
December 31, 2000:
Beginning of year....................... 1,080 -- -- --
Extensions and discoveries.............. -- -- -- 2,381
Revisions of previous estimates......... 236 -- -- --
--------------- --------------- --------------- ---------------
Production.............................. (96) -- -- --
=============== =============== =============== ===============
End of year......................... 1,220 -- -- 2,381
=============== =============== =============== ===============
F-21
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
Standardized Measure of Discounted Future Net Cash Flows ("SMOG") and
Changes Therein Relating to Proved Oil Reserves
Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities."
Certain information concerning the assumptions used in computing the valuation
of proved reserves and their inherent limitations are discussed below. The
Company believes such information is essential for a proper understanding and
assessment of the data presented. The assumptions used to compute the proved
reserve valuation do not necessarily reflect the Company's expectations of
actual revenues to be derived from those reserves nor their present worth.
Assigning monetary values to the reserve quantity estimation process does not
reduce the subjective and ever-changing nature of such reserve estimates.
Additional subjectivity occurs when determining present values because the rate
of producing the reserves must be estimated. In addition to errors inherent in
predicting the future, variations from the expected production rates also could
result directly or indirectly from factors outside the Company's control, such
as unintentional delays in development, environmental concerns and changes in
prices or regulatory controls. The reserve valuation assumes that all reserves
will be disposed of by production. However, if reserves are sold in place,
additional economic considerations also could affect the amount of cash
eventually realized. Future development and production costs are computed by
estimating expenditures to be incurred in developing and producing the proved
oil reserves at the end of the period, based on period-end costs and assuming
continuation of existing economic conditions. A discount rate of 10.0% per year
was used to reflect the timing of the future net cash flows. The discounted
future net cash flows for the Company's Polish reserves are based on a gas and
condensate sales contracts the Company has with POGC.
The components of SMOG are detailed below:
United States Poland Total
--------------- --------------- ---------------
(In thousands)
December 31, 2002:
Future cash flows........................................ $ 26,049 $ 10,964 $ 37,013
Future production costs.................................. (16,254) (455) (16,709)
Future development costs................................. (115) (1,800) (1,915)
Future income tax expense................................ -- -- --
--------------- --------------- ---------------
Future net cash flows ................................... 9,680 8,709 18,389
10% annual discount for estimated timing of cash flows... (4,300) (3,869) (8,169)
--------------- --------------- ---------------
Discounted net future cash flows......................... $ 5,380 $ 4,840 $ 10,220
=============== =============== ===============
December 31, 2001:
Future cash flows......................................... $ 13,922 $ 7,749 $ 21,671
Future production costs................................... (9,464) (425) (9,889)
Future development costs.................................. (73) (1,390) (1,463)
Future income tax expense................................. -- -- --
--------------- --------------- ---------------
Future net cash flows .................................... 4,385 5,934 10,319
10% annual discount for estimated timing of cash flows.... (2,213) (2,520) (4,733)
--------------- --------------- ---------------
Discounted net future cash flows.......................... $ 2,172 $ 3,414 $ 5,586
=============== =============== ===============
December 31, 2000:
Future cash flows......................................... $ 26,025 $ 3,532 $ 29,557
Future production costs................................... (16,216) (476) (16,692)
Future development costs.................................. (195) -- (195)
Future income tax expense................................. -- -- --
--------------- --------------- ---------------
Future net cash flows .................................... 9,614 3,056 12,670
10% annual discount for estimated timing of cash flows.... (4,705) (545) (5,250)
--------------- --------------- ---------------
Discounted net future cash flows.......................... $ 4,909 $ 2,511 $ 7,420
=============== =============== ===============
F-22
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
The principal sources of changes in SMOG are detailed below:
Year Ended December 31,
-------------------------------------------
2002 2001 2000
------------- ------------- -------------
(In thousands)
SMOG sources:
Balance, beginning of year......................................$ 5,586 $ 7,420 $ 5,460
Sale of oil and gas produced, net of production costs........... (843) (871) (1,172)
Net changes in prices and production costs...................... 4,890 (2,241) (159)
Extensions and discoveries, net of future costs................. -- 1,330 2,511
Changes in estimated future development costs................... (251) (686) (53)
Previously estimated development costs incurred during
the year.................................................... 586 321 202
Revisions in previous quantity estimates........................ 270 59 (31)
Accretion of discount........................................... 559 742 546
Net change in income taxes...................................... -- -- --
Changes in rates of production and other........................ (577) (488) 116
------------- ------------- -------------
Balance, end of year........................................$ 10,220 $ 5,586 $ 7,420
============= ============= =============
Note 16: New Accounting Pronouncements
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement
Obligations." SFAS No. 143 is effective for the Company beginning January 1,
2003. The most significant impact of this standard to the Company will be a
change in the method of accruing for site restoration costs. Under SFAS No. 143,
the fair value of asset retirement obligations will be recorded as liabilities
when they are incurred, which are typically at the time the assets are
installed. Amounts recorded for the related assets will be increased by the
amount of these obligations. Over time the liabilities will be accreted for the
change in their present value and the initial capitalized costs will be
depreciated over the useful lives of the related assets. The Company is
evaluating the impact of adopting No. SFAS 143.
In June 2002, the FASB issued Statement No. 146 ("SFAS 146"), "Accounting for
Costs Associated with Exit or Disposal Activities." SFAS 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liabilities
Recognition for Certain employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). This Statement
requires that a liability for costs associated with an exit or disposal activity
be recognized and measured initially at fair value only when the liability is
incurred. SFAS 146 will be effective for exit or disposal activities that are
initiated after December 31, 2002. Management believes that the adoption of this
standard will have no material impact on the Company's operating results and
financial position.
In December 2002, the FASB issued Statement No. 148 ("SFAS 148"), "Accounting
for Stock-Based Compensation Transition and Disclosure." This Statement amends
FASB Statement No. 123 ("SFAS 123"); "Accounting for Stock-Based Compensation,"
to provide alternative methods of transition for an entity that voluntarily
changes to the fair value based method of accounting for stock-based employee
compensation. In addition, SFAS 148 amends the disclosure provisions of SFAS 123
to require prominent disclosure in both annual and interim financial statements
about the effects on reported net income of an entity's accounting policy
decisions with respect to stock-based employee compensation. As FX Energy will
continue to account for stock-based compensation according to APB 25, adoption
of SFAS 148 will require FX Energy to provide prominent disclosures about the
effects of SFAS 123 on reported income and will require disclosure of these
affects in the interim financial statements as well. SFAS 148 is effective for
the financial statements for fiscal years ending after December 15, 2002 and
subsequent interim periods. Management believes that the adoption of this
standard will have no material impact on the Company's operating results and
financial position.
F-23
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
- Continued -
In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others, which expands on the accounting guidance
of Statements No. 5, 57, and 107 and incorporates without change the provisions
of FASB Interpretation No. 34, which is being superseded. This Interpretation
requires a guarantor to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing the guarantee. In
addition, guarantors are required to make significant new disclosures, even if
the likelihood of the guarantor making payments under the guarantee is remote.
The Interpretation's disclosure requirements are effective for the Company as of
December 31, 2002. The recognition requirements of FIN 45 are to be applied
prospectively to guarantees issued or modified after December 31, 2002. The
Company has no significant guarantees and the adoption of this interpretation
did not have a material impact on the Company's financial statements.
In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"), Consolidation
of Variable Interest Entities. The objective of this interpretation is to
provide guidance on how to identify a variable interest entity and determine
when the assets, liabilities, noncontrolling interests and results of operations
of a variable interest entity need to be included in a company's consolidated
financial statements. A company that holds variable interests in an entity will
need to consolidate the entity if the company's interest in the variable
interest entity is such that the company will absorb a majority of the variable
interest entity's expected losses and/or receive a majority of the entity's
expected residual returns, if they occur. The provisions of this interpretation
became effective upon issuance. As of December 31, 2002, the Company did not
have any variable interest entities that will be subject to FIN 46.
The Company has reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on its results
of operations or financial position. Based on that review, the Company believes
that none of these pronouncements will have a significant effect on current or
future earnings or operations.
Note 17: Subsequent Events
Private Placement of Convertible Preferred Stock
On March 13, 2003, the Company sold 2,250,000 shares of 2003 Series Convertible
Preferred Stock in a private placement of securities, raising a total of $5.6
million after offering costs. Each share of preferred stock is convertible into
one share of common stock and one warrant to purchase one share of common stock
at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The
preferred stock has a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.
The net proceeds from the offering, plus the Company's available cash, were used
to reduce the obligation to RRPV,, fund ongoing geological and geophysical costs
in Poland, and to support ongoing prospect marketing and general and
administrative costs.
Amendment of RRPV Note Payable
In March, 2003, following the private placement of convertible preferred stock,
the Company paid $2.2 million to RRPV. In return, RRPV extended the maturity
date of the note to December 31, 2003. The Company has also agreed to pay 40% of
the gross proceeds of any subsequent equity or debt offering concluded prior to
the amended maturity date to RRPV. The Company also agreed to assign its rights
to payments under the CalEnergy Gas agreement to RRPV, except for those amounts
relating to the two wells required to be drilled under the agreement. All such
payments will 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 loan amendment contains other terms and conditions, including an increase in
the interest rate on the note from 9.5% to 12% per annum effective March 9,
2003, an extension of the conversion period until December 31, 2003, with the
conversion price being changed from $5.00 per share to $3.42 per share, and an
extension fee payment of $100,000.
F-24