Registration No. 333-40480
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------
POST EFFECTIVE AMENDMENT NO. 1 TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
--------------------
FX ENERGY, INC.
(Exact Name of Registrant as Specified in Its Charter)
NEVADA 1311 87-0504461
------ ---- ----------
(State or other (Primary Standard (I.R.S. Employer
jurisdiction of Industrial Identification
incorporation or Classification Number)
organization) Code Number)
3006 Highland Drive
Suite 206
Salt Lake City, Utah 84106
(801) 486-5555
(Address, including zip code, and telephone number, including area code, of
Registrant's principal executive offices)
David N. Pierce
3006 Highland Drive
Suite 206
Salt Lake City, Utah 84106
(801) 486-5555
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Copy to:
James R. Kruse
Kevin C. Timken
Kruse, Landa & Maycock, LLC
50 West Broadway
8th Floor
Salt Lake City, UT 84101
(801) 531-7090
fax: (801) 531-7091
Approximate date of commencement of proposed sale to the public: As soon as
practicable after the effective date of this registration statement.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, please check the following box: [X]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering: [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, please check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering: [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering: [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box: [ ]
The Registrant hereby amends this amendment to the registration statement
on such date or dates as may be necessary to delay its effective date until the
Registrant files a further amendment which specifically states that this
amendment to the registration statement will thereafter become effective in
accordance with Section 8(a) of the Securities Act of 1933, or until the
amendment to the registration statement becomes effective on such date as the
Securities and Exchange Commission, acting pursuant to Section 8(a) may
determine.
Post Effective Amendment to Prospectus dated July 10, 2000
FX ENERGY, INC.
- --------------------------------------------------------------------------------
This post effective amendment is a part of and should be read in
conjunction with our prospectus dated July 10, 2000.
- --------------------------------------------------------------------------------
Our prospectus dated July 10, 2000, is amended with the following
financial information as of June 30, 2000, and for the three and six-month
periods then ended and with the results of the action taken at our annual
stockholder meeting.
Item Page
-------------------------------------------------------------- ---------
Consolidated Balance Sheets................................. 2
Consolidated Statements of Operations....................... 4
Consolidated Statements of Cash Flows....................... 5
Notes to Consolidated Financial Statements.................. 6
Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 9
Action at Stockholder Meeting............................... 19
The date of this post effective amendment is August [__], 2000.
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June December
30, 2000 31, 1999
----------------- ------------------
ASSETS
Current assets:
Cash and cash equivalents..................................... $ 9,974,261 $ 1,619,237
Investment in marketable debt securities...................... 3,222,843 5,249,003
Accounts receivable:
Accrued oil sales........................................ 296,186 243,183
Interest receivable...................................... 86,909 86,723
Joint interest owners and others......................... 272,312 171,242
Advances to oil and gas ventures.............................. 587,534 --
Inventory..................................................... 54,160 66,361
Other current assets.......................................... 33,129 126,006
----------------- ------------------
Total current assets................................ 14,527,334 7,561,755
----------------- ------------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved................................................... 4,106,099 1,687,089
Unproved................................................. 955,307 1,382,880
Other property and equipment.................................. 2,856,116 2,652,102
----------------- ------------------
Gross property and equipment....................... 7,917,522 5,722,071
Less accumulated depreciation, depletion and amortization..... (3,268,895) (3,173,493)
----------------- ------------------
Net property and equipment......................... 4,648,627 2,548,578
----------------- ------------------
Other assets:
Certificates of deposit ...................................... 356,500 356,500
Other......................................................... 2,789 2,789
----------------- ------------------
Total other assets................................. 359,289 359,289
----------------- ------------------
Total assets.................................................. $ 19,535,250 $ 10,469,622
================= ==================
-- Continued --
The accompanying notes are an integral part of the
consolidated financial statements.
2
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
-- Continued --
June December
30, 2000 31, 1999
-------------------- --------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................ $ 1,890,521 $ 623,911
Accrued liabilities......................................... 3,395,131 1,478,862
-------------------- --------------------
Total current liabilities.............................. 5,285,652 2,102,773
-------------------- --------------------
Total liabilities...................................... 5,285,652 2,102,773
-------------------- --------------------
Commitments (Note 8)
Stockholders' equity:
Common stock, $.001 par value, 100,000,000 and
30,000,000 shares authorized as of June 30, 2000
and December 31, 1999, respectively; 17,838,575 and
14,849,003 shares issued and outstanding as of June
30, 2000 and December 31, 1999, respectively.............. 17,839 14,849
Notes receivable from officers.............................. (1,327,122) (1,370,873)
Additional paid-in capital.................................. 47,823,961 38,480,556
Accumulated deficit......................................... (32,265,080) (28,757,683)
-------------------- --------------------
Total stockholders' equity............................. 14,249,598 8,366,849
-------------------- --------------------
Total liabilities and stockholders' equity....................... $ 19,535,250 $ 10,469,622
==================== ====================
The accompanying notes are an integral part of the
consolidated financial statements.
3
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
For the three months ended For the six months ended
June 30, June 30,
------------------------------ ------------------------------
2000 1999 2000 1999
-------------- -------------- -------------- ---------------
Revenues:
Oil sales................................... $ 613,147 $ 360,044 $ 1,209,777 $ 593,752
Contract servicing......................... 312,193 91,254 385,931 178,797
-------------- -------------- -------------- ---------------
Total revenues....................... 925,340 451,298 1,595,708 772,549
-------------- -------------- -------------- ---------------
Operating costs and expenses:
Lease operating expenses.................... 251,977 178,568 536,969 414,637
Production taxes............................ 9,601 24,323 16,547 38,691
Geological and geophysical costs............ 680,483 160,994 1,164,892 340,826
Exploratory dry hole costs.................. 928,759 32,859 928,759 32,859
Impairment of unproved oil and gas properties 674,158 -- 674,158 --
Contract servicing costs.................... 259,164 80,512 334,429 133,386
Depreciation, depletion and amortization.... 94,279 125,960 181,347 252,389
General and administrative.................. 804,513 742,558 1,401,480 1,278,947
-------------- -------------- -------------- ---------------
Total operating costs and expenses... 3,702,934 1,345,774 5,238,581 2,491,735
-------------- -------------- -------------- ---------------
Operating loss................................... (2,777,594) (894,476) (3,642,873) (1,719,186)
-------------- -------------- -------------- ---------------
Other income (expense):
Interest and other income................... 115,655 105,243 249,600 207,434
Impairment of notes receivable from officers (109,266) -- (114,124) --
-------------- -------------- -------------- ---------------
Total other income................... 6,389 105,243 135,476 207,434
-------------- -------------- -------------- ---------------
Net loss......................................... $ (2,771,205) $ (789,233) $ (3,507,397) $ (1,511,752)
============== ============== ============== ===============
Basic and diluted net loss per common share...... $ (0.18) $ (0.06) $ (0.23) $ (0.11)
============== ============== ============== ===============
Basic and diluted weighted average number
of shares outstanding....................... 15,142,866 14,016,618 14,995,935 13,538,218
============== ============== ============== ===============
The accompanying notes are an integral part of the
consolidated financial statements.
4
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
For the six months ended June 30,
-------------------------------------
2000 1999
------------------ -----------------
Cash flows from operating activities:
Net loss............................................................ $ (3,507,397) $ (1,511,752)
Adjustments to reconcile net loss to net
cash used in operating activities:
Depreciation, depletion and amortization.................... 181,347 252,389
Impairment of unproved oil and gas properties............... 674,158 --
Impairment of notes receivable from officers................ 114,124 --
Interest income on officer loans............................ (70,373) (62,792)
Increase (decrease) from changes in working capital items:
Accounts receivable............................................. (154,259) (118,947)
Advances to oil and gas ventures................................ (587,534) (157,054)
Inventory....................................................... 12,201 2,441
Other current assets............................................ 92,877 (17,659)
Accounts payable and accrued liabilities........................ 882,879 (690,971)
------------------ -----------------
Net cash used in operating activities...................... (2,361,977) (2,304,345)
------------------ -----------------
Cash flows from investing activities:
Additions to oil and gas properties................................. (365,595) (210,249)
Additions to other property and equipment........................... (289,959) (63,438)
Additions to other assets........................................... -- (2,789)
Proceeds from sale of property interests............................ -- 6,000
Purchase of marketable debt securities.............................. (3,715,840) (5,459,874)
Proceeds from maturing marketable debt securities................... 5,742,000 1,957,000
------------------ -----------------
Net cash provided by (used in) investing activities........ 1,370,606 (3,773,350)
------------------ -----------------
Cash flows from financing activities:
Advances to officers................................................ - (597,563)
Proceeds from sale of common stock (net of offering costs........... 9,312,451 7,057,403
Proceeds from the exercise of warrants.............................. 33,944 --
------------------ -----------------
Net cash provided by (used in) financing activities....... 9,346,395 6,459,840
------------------ -----------------
Increase in cash and cash equivalents.................................... 8,355,024 382,145
Cash and cash equivalents at beginning of period......................... 1,619,237 1,811,780
------------------ -----------------
Cash and cash equivalents at end of period............................... $ 9,974,261 $ 2,193,925
================== =================
The accompanying notes are an integral part
of the consolidated financial statements
5
FX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1: Basis of Presentation
The interim financial data are unaudited; however, in the opinion of
the management of FX Energy, Inc. and Subsidiaries ("FX Energy" or the
"Company"), the interim data includes all adjustments, consisting only of normal
recurring adjustments, necessary for a fair presentation of the results for the
interim periods. The interim financial statements should be read in conjunction
with FX Energy's quarterly report on Form 10-Q for the three months ended March
31, 2000, and the annual report on Form 10-K for the year ended December 31,
1999, including the financial statements and notes thereto.
The consolidated financial statements include the accounts of FX Energy
and its wholly-owned subsidiaries and undivided interests in Poland. All
significant inter-company accounts and transactions have been eliminated in
consolidation. At June 30, 2000, FX Energy owned 100% of the voting stock of all
of its subsidiaries.
Certain balances in the 1999 financial statements have been
reclassified to conform to the current quarter presentation. These changes had
no effect on total assets, total liabilities, stockholders' equity or net loss.
Note 2: Income Taxes
FX Energy recognized no income tax benefit from the losses generated in
the first six months of 2000 and the first six months of 1999.
Note 3: Officer Loans
As of June 30, 2000, notes receivable and accrued interest from
officers, before an impairment allowance, totaled $2,106,759, with a due date of
on or before December 31, 2000. The notes receivable and accrued interest are
collateralized by 233,340 shares of FX Energy's common stock. In accordance with
"Accounting by Creditors for Impairment of a Loan," or SFAS 114, FX Energy has
recorded a cumulative impairment allowance of $779,637 as of June 30, 2000,
including $114,124 for the six months ended June 30, 2000, based on the value of
the underlying collateral.
In consideration for extending the term from December 31, 1999 through
December 31, 2000, the officers agreed that if the average closing price of the
common stock for five consecutive trading days results in a value of the
collateral equal to or above the total principal and accrued interest balances,
the officers will repay the loans within 45 days thereafter either in cash or by
tendering to the Company such number of shares which at the average closing
price for the previous five consecutive trading days equals the principal and
accrued interest then due.
The impairment allowance will continue to be adjusted quarterly based
on the market value of the collateral shares until the officer loans are deemed
paid in full.
Note 4: 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
6
of the weighted average number of common shares and the effect of dilutive
unexercised stock options and warrants and convertible preferred stock. Options
and warrants to purchase 4,146,167 shares of common stock at prices ranging from
$1.50 to $10.25 per share with a weighted average of $5.25 per share were
outstanding at June 30, 2000. Options and warrants to purchase 3,678,240 shares
of common stock at prices ranging from $1.50 to $10.25 per share with a weighted
average price of $5.17 per share were outstanding at June 30, 1999. No options
or warrants were included in the computation of diluted earnings per share for
the periods ended June 30, 2000 and 1999, because the effect would have been
antidilutive.
Note 5: Business Segments
FX Energy operates within two segments of the oil and gas industry: the
exploration and production segment ("E&P") and the contract servicing segment.
Mining, which consisted solely of gold exploration on FX Energy's Sudety Project
Area in Poland, has been discontinued and is not considered a reportable
business segment by FX Energy. Identifiable net property and equipment are
reported by business segment for management reporting and reportable business
segment disclosure purposes. Current assets, current liabilities and other
assets are not allocated to business segments for management reporting or
reportable business segment disclosure purposes.
Reportable business segment information for the three months ended June
30, 2000, the six months ended June 30, 2000 and as of June 30, 2000 follows:
Reportable Segments
------------------------------- Non- Non-
Contract Reportable Segmented
E&P Servicing Segments Items Total
--------------- -------------- -------------- -------------- --------------
Three months ended June 30, 2000:
Revenues................. $ 613,147 $ 312,193 $ -- $ -- $ 925,340
Net Loss (1)............. (1,949,913) (3,801) -- (817,491) (2,771,205)
Six months ended June 30, 2000:
Revenues................. 1,209,777 385,931 -- -- 1,595,708
Net Loss(2).............. (2,145,572) (56,514) -- (1,305,311) (3,507,397)
As of June 30, 2000:
Identifiable net property
and equipment(3)...... 3,834,464 676,576 -- 137,587 4,648,627
(1) Nonsegmented items include $804,513 of general and administrative expenses,
$115,655 of other income, $19,367 of corporate DD&A and an officer loan
impairment of $109,266.
(2) Nonsegmented items include $1,401,480 of general and administrative
expenses, $249,600 of other income, $39,307 of corporate DD&A and an
officer loan impairment of $114,124.
(3) Nonsegmented items include $137,587 of corporate office equipment, hardware
and software.
Reportable business segment information for the three months ended June
30, 1999, the six months ended June 30, 1999, and as of June 30, 1999 follows:
7
Reportable Segments
------------------------------- Non- Non-
Contract Reportable Segmented
E&P Servicing Segments Items Total
--------------- -------------- -------------- -------------- --------------
Three months ended June 30, 1999:
Revenues................. $ 360,044 $ 91,254 $ -- $ -- $ 451,298
Net Loss(1).............. (35,750) (70,193) (14,682) (668,608) (789,233)
Six months ended June 30, 1999:
Revenues................. 593,752 178,797 -- -- 772,549
Net Loss(2).............. (241,652) (116,458) (19,784) (1,133,858) (1,511,752)
As of June 30, 1999:
Identifiable net property
and equipment(3)...... 2,014,387 623,405 -- 193,760 2,831,552
(1) Nonsegmented items include $742,558 of general and administrative expenses,
$105,243 of other income and $31,293 of corporate DD&A.
(2) Nonsegmented items include $1,278,947 of general and administrative
expenses, $207,434 of other income and $62,345 of corporate DD&A.
(3) Nonsegmented items include $193,760 of corporate office equipment, hardware
and software.
Note 6: Supplemental Noncash Activity Disclosure
Noncash Investing Activities
During the six months ended June 30, 2000 and June 30, 1999, additions
to oil and gas properties included unproved property additions of $2,300,000 and
$197,000, respectively, financed by accrued liabilities.
Note 7: Private Placement of Securities
During June 2000, FX Energy completed a private placement of 2,969,000
shares of common stock that resulted in net proceeds of $9,312,451 ($10,391,500
gross). The proceeds from this placement are to be used to partially fund
current planned ongoing exploration and development activities in Poland and for
other general corporate purposes.
Note 8: Fences Project Area
On April 11, 2000, FX Energy signed an agreement with the Polish Oil
and Gas Company ("POGC") under which FX Energy will earn a 49% working interest
in approximately 300,000 gross acres in west central Poland (the "Fences"
project area) by spending $16.0 million for agreed drilling, seismic acquisition
and other related activities.
On June 28, 2000, FX Energy announced that the Kleka 11, the first well
drilled in the Fences project area, was an exploratory success after the well
tested a calculated open flow rate of 34.3 MMcf of gas per day from a
Rotliegendes sandstone reservoir.
8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Forward-Looking Information May Prove Inaccurate
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. Statements that describe FX Energy's future strategic
plans, goals or objectives are also forward-looking statements. FX Energy
intends the forward-looking statements to be covered by the safe harbor
provisions for forward-looking statements contained in Section 27A of the
Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities
Exchange Act of 1934.
Readers of this report are cautioned that any forward-looking
statements, including those regarding FX Energy or its management's current
beliefs, expectations, anticipations, estimations, projections, proposals, plans
or intentions, are not guarantees of future performance or results of events and
involve risks and uncertainties, such as:
o the future results of drilling individual wells and other
exploration and development activities;
o uncertainties regarding drilling potential and expected
results;
o the inability to estimate precisely the hydrocarbon potential
of any exploration prospect or the related risks;
o future variations in well performance as compared to initial
test data;
o future events that may result in the need for additional
capital;
o fluctuations in prices for oil and gas;
o uncertainties of certain terms to be determined in the future
relating to FX Energy's oil and gas interests, including
exploitation fees, royalty rates and other matters;
o future drilling and other exploration schedules and sequences
for various wells and other activities;
o uncertainties regarding estimates of hydrocarbon reserves,
production rates, accumulations and recoveries;
o uncertainties regarding future political, economic,
regulatory, fiscal, taxation and other policies in Poland;
o the future ability of FX Energy to attract strategic partners
to share the costs of exploration, exploitation, development
and acquisition activities; and
o future plans and the financial and technical resources of
strategic partners.
The forward-looking information is based on present circumstances and on FX
Energy's predictions respecting events that have not occurred, which may not
occur or which may occur with different consequences from those now assumed or
anticipated. Actual events or results may differ materially from those discussed
in the forward-looking statements. The forward-looking statements included in
this report are made only as of the date of this report. FX Energy is not
obligated to update such forward-looking statements to reflect subsequent events
or circumstances.
9
Introduction
FX Energy is an independent energy company engaged in the exploration,
development and production of oil and gas from properties located primarily in
the Republic of Poland. However, to date, all of FX Energy's production has been
from its United States producing properties. In the western United States, FX
Energy produces oil from fields in Montana and Nevada and has a drilling and
well servicing company in northern Montana and oil and gas exploration prospects
in several western states.
FX Energy conducts substantially all of its exploration and development
activities jointly with others and, accordingly, recorded amounts for FX
Energy's activities in Poland reflect only FX Energy's proportionate interest in
these activities.
FX Energy's results of operations may vary significantly from period to
period based on the factors discussed above and on other factors such as FX
Energy's exploratory and development drilling success. Therefore, the results of
any one period may not be indicative of future results.
FX Energy follows the successful efforts method of accounting for its
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 revenues determined on a property-by-property basis. The
impairment loss recognized equals the excess of net capitalized costs over the
related fair value, determined on a property-by-property basis. As a result of
the foregoing, FX Energy's results of operations for any particular period may
not be indicative of the results that could be expected over longer periods.
FX Energy has reviewed all 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, FX Energy believes
that none of these pronouncements will have a significant effect on current or
future earnings or operations.
Results of Operations by Business Segment
FX Energy operates within two segments of the oil and gas industry: the
exploration and production segment and the contract servicing segment. Mining,
which consisted solely of gold exploration on FX Energy's Sudety Project Area in
Poland, has been discontinued and is excluded from the following discussion.
Depreciation, depletion and amortization costs ("DD&A") directly associated with
their respective segments are detailed within the following discussion. General
and administrative costs ("G&A"), interest income, other income and officer loan
impairment are not allocated to individual operating segments for management or
segment reporting purposes and are discussed in their entirety following the
segment discussion.
10
Comparison of the second quarter of 2000 to the second quarter of 1999
Exploration and Production
A summary of the percentage change in oil revenues, average oil price,
production volumes and lifting cost per barrel for the second quarter of 2000
and 1999, as compared to their respective prior year's period ,is set forth in
the following table:
Quarter ended June 30,
-------------------------------------
2000 1999
----------------- -----------------
Oil revenues................................................ $ 613,000 $ 360,000
Percent change versus prior year's quarter................ +70% +32%
Average oil price........................................... $ 24.86 $ 14.22
Percent change versus prior year's quarter................ +75% +43%
Production volumes (bbls)................................... 24,668 25,323
Percent change versus prior year's quarter................ -3% -13%
Lifting cost per barrel..................................... $ 10.21 $ 7.05
Percent change versus prior year's quarter................ +45% -9%
Oil Revenues. Oil revenues were $613,000 during the second quarter of
2000, an increase of $253,000, as compared to $360,000 during the same period of
1999. During the second quarters of 2000 and 1999, FX Energy's oil revenues were
positively affected by increased oil prices and negatively affected by lower
production rates attributable to the natural production declines of FX Energy's
producing properties, as compared to their respective prior year period.
Lease Operating Costs. FX Energy's lease operating costs are composed
of normal recurring lease operating expenses ("LOE") and production taxes. Lease
operating costs were $262,000 during the second quarter of 2000, an increase of
$59,000, as compared to $203,000 during the same period of 1999. A comparative
discussion of each component of lease operating costs incurred during the second
quarter of 2000 and 1999 follows:
LOE costs were $252,000 during the second quarter of 2000, an increase
of $73,000, as compared to $179,000 during the same period of 1999. During the
second quarter of 2000, FX Energy incurred substantially more workover,
maintenance and repair costs as it completed work that had been postponed due to
low oil prices during 1999. During the second quarter of 1999, FX Energy
deferred workovers and reduced its LOE costs by redesigning the pattern of
injecting fluids into the Cut Bank Sand Unit, its principal producing property.
Production taxes were $10,000 during the second quarter of 2000, a
decrease of $14,000, as compared to $24,000 during the same period of 1999.
During the second quarters of 2000 and 1999, production taxes averaged
approximately 1.6% and 6.8% of oil revenues, respectively. During late 1999, the
state of Montana substantially reduced the production tax rate for stripper
wells, which in turn resulted in substantially lower production taxes for the
second quarter of 2000, as compared to the same period of 1999.
DD&A Expense - E&P. DD&A expense for producing properties was $18,000
for the second quarter of 2000, an increase of $4,000, as compared to $14,000
during the same period of 1999. The DD&A rate per barrel for the second quarter
of 2000 was $0.73, an increase of $0.19, as compared to
11
$0.54 during the same period of 1999. The DD&A rate increase for the second
quarter of 2000, as compared to the same period of 1999, was due principally to
a 29% reduction in estimated proved reserves as of December 31, 1999, as
compared to December 31, 1998.
Exploration Costs. FX Energy's exploration costs consist of geological
and geophysical costs ("G&G"), exploratory dry holes and nonproducing leasehold
impairments. Exploration costs were $2,283,000 during the second quarter of
2000, an increase of $2,089,000, as compared to $194,000 during the same period
of 1999. Exploration costs include $20,000 of G&G costs relating to gold
exploration in Poland during the second quarter of 1999, which are excluded from
the following discussion of each component of exploration costs.
G&G costs were $680,000 during the second quarter of 2000, an increase
of $539,000, as compared to $141,000 during the same period of 1999. During the
second quarter of 2000, FX Energy incurred approximately $561,000 of 2-D seismic
acquisition and other G&G related costs on its primary project areas in Poland.
During the second quarter of 1999, FX Energy's G&G costs were primarily covered
by Apache in accordance with the Apache Exploration Program terms. G&G costs
will continue to fluctuate from period to period, based on FX Energy's level of
exploratory activity in Poland and the respective cost participation percentage
of FX Energy's industry partners.
Exploratory dry hole costs were $929,000 during the second quarter of
2000, an increase of $896,000, as compared to $33,000 during the same period of
1999. During the second quarter of 2000, the Wilga 3 was determined to be an
exploratory dry hole after it tested the perimeter of the northwest section of
the Wilga field, an area where proved reserves were not assigned prior to
drilling. In accordance with Generally Accepted Accounting Principles, or
"GAAP," the Wilga 3 has been classified as an exploratory dry hole for
accounting purposes, although in industry parlance FX Energy previously referred
to the Wilga 3, the first well drilled near the Wilga 2 discovery well, as
either an appraisal or a developmental well. Under the terms of a recent
revision to the Apache Exploration Program, Apache covered one half of FX
Energy's 45% share of costs to drill the Wilga 3. All of the exploratory dry
hole costs incurred during the second quarter of 1999 were associated with the
Gladysze 1A, an exploratory dry hole drilled during 1997.
Nonproducing leasehold impairments were $674,000 during the second
quarter of 2000, as compared to no nonproducing leasehold impairments during the
second quarter of 1999. During the second quarter of 2000, FX Energy wrote off
$674,000 of nonproducing leasehold costs relating to the Williston Basin in
North Dakota, where it has no further exploration plans. Nonproducing leasehold
impairments will continue to vary from period to period based on FX Energy's
determination that capitalized costs of unproved properties, on a property by
property basis, are considered not to be realizable.
Contract Servicing
Contract Servicing Revenues. Contract servicing revenues were $312,000
during the second quarter of 2000, an increase of $221,000, as compared to
$91,000 for the same period of 1999. During the second quarter of 2000, FX
Energy performed substantially more contract services, as compared to the same
period of 1999. Contract servicing revenues will continue to fluctuate period to
period based on market conditions, the degree of emphasis on utilizing equipment
on Company owned properties and other factors.
Contract Servicing Costs. Contract servicing costs were $259,000 during
the second quarter of 2000, an increase of $178,000, as compared to $81,000 for
the same period of 1999. During the second
12
quarters of 2000 and 1999, contract servicing costs were 83% and 88%,
respectively, of contract servicing revenues. Contract servicing costs will
continue to fluctuate period to period based on the contract servicing revenues
generated, degree of emphasis on utilizing equipment on Company owned properties
and other factors.
DD&A Expense - Contract Servicing. DD&A expense for contract servicing
was $57,000 during the second quarter of 2000, a decrease of $24,000, as
compared to $81,000 during the same period of 1999, primarily due to capital
items being depreciated during the second quarter of 1999 subsequently becoming
fully depreciated prior to or during the second quarter of 2000.
Nonsegmented Information
G&A Costs. G&A costs were $805,000 during the second quarter of 2000,
an increase of $62,000, as compared to $743,000 for the same period of 1999.
During the second quarter of 2000, FX Energy incurred substantially more legal,
travel and other associated G&A costs as a result of its increased level of
activities in Poland, as compared to the same period of 1999. Through June 30,
2000, Apache has covered all of FX Energy's pro rata share of Apache's G&A costs
in Poland. Effective July 1, 2000, FX Energy will begin to pay approximately
32.5% of Apache's G&A costs in Poland, to be adjusted as each of Apache's
remaining drilling requirements is completed, up to a maximum of 50%. We expect
that our initial share of such costs will be approximately $600,000 per quarter.
DD&A Expense - Corporate. DD&A expense for corporate activities was
$19,000 during the second quarter of 2000, a decrease of $12,000, as compared to
$31,000 during the same period of 1999, primarily due to capital items being
depreciated during the first second quarter of 1999 subsequently becoming fully
depreciated prior to or during the second quarter of 2000.
Interest and Other Income. Interest and other income was $116,000
during the second quarter of 2000, an increase of $11,000, as compared to
$105,000 during the same period of 1999. During the second quarter of 2000, FX
Energy's cash and marketable debt securities average balances were relatively
unchanged, as compared to the same period of 1999.
Officer Loan Impairment. Officer loan impairment was $109,000 for the
second quarter of 2000, as compared to no officer loan impairment for the same
period of 1999. In accordance with SFAS 114, FX Energy recorded an officer loan
impairment of $109,000 for the second quarter of 2000. The notes receivable from
officers totaled $1,327,000 as of June 30, 2000, representing principal and
interest of $2,107,000 reduced by a cumulative impairment allowance of $780,000.
The notes receivable from officers are collateralized by 233,340 shares of FX
Energy's common stock. The impairment allowance will continue to be adjusted
quarterly based on the market value of the collateral shares.
Comparison of the first six months of 2000 to the first six months of
1999
Exploration and Production
A summary of the percentage change in oil revenues, average oil price
production volumes and lifting cost per barrel for the first six months of 2000
and 1999, as compared to their respective prior year's period, is set forth in
the following table:
13
Six months ended June 30,
-------------------------------------
2000 1999
----------------- -----------------
Oil revenues................................................ $ 1,210,000 $ 594,000
Percent change versus prior year's quarter................ +103% -2%
Average oil price........................................... $ 24.90 $ 11.44
Percent change versus prior year's quarter................ +118% +8%
Production volumes (Bbls)................................... 48,592 51,895
Percent change versus prior year's quarter................ -6% -9%
Lifting cost per barrel..................................... $ 11.05 $ 7.99
Percent change versus prior year's quarter................ +38% -9%
Oil Revenues. Oil revenues were $1,210,000 during the first six months
of 2000, an increase of $616,000 as compared to $594,000 during the same period
of 1999. During the first six months of 2000, FX Energy's oil revenues were
positively affected by increased oil prices, which were partially offset by
lower production rates attributable to the natural production declines of FX
Energy's producing properties. During the first six months of 1999, FX Energy's
oil revenues were positively affected by higher oil prices and negatively
affected by lower production rates attributable to the natural production
declines of FX Energy's producing properties.
Lease Operating Costs. Lease operating costs were $554,000 during the
first six months of 2000, an increase of $100,000, as compared to $454,000
during the same period of 1999. A comparative discussion of each component of
lease operating costs incurred during the first six months of 2000 and 1999
follows:
LOE costs were $537,000 during the first six months of 2000, an
increase of $122,000, as compared to $415,000 during the same period of 1999.
During the first six months of 2000, FX Energy incurred substantially more
workover, maintenance and repair costs as it completed work that had been
postponed due to low oil prices during 1999. During the first six months of
1999, FX Energy deferred workovers and reduced its LOE costs by redesigning the
pattern of injecting fluids into the Cut Bank Sand Unit, its principal producing
property.
Production taxes were $17,000 during the first six months of 2000, a
decrease of $22,000, as compared to $39,000 during the same period of 1999.
During the first six months of 2000 and 1999, production taxes averaged
approximately 1.4% and 6.6% of oil revenues, respectively. During late 1999, the
state of Montana substantially reduced the production tax rate for stripper
wells, which in turn resulted in substantially lower production taxes for the
first six months of 2000, as compared to the same period of 1999.
DD&A Expense - E&P. DD&A expense for producing properties was $34,000
for the first six months of 2000, an increase of $6,000, as compared to $28,000
during the same period of 1999. The DD&A rate per barrel for the first six
months of 2000 was $0.70, an increase of $0.16, as compared to $0.54 during the
same period of 1999. The DD&A rate increase for the first six months of 2000, as
compared to the same period of 1999, was due principally to a 29% reduction in
estimated proved reserves as of December 31, 1999, as compared to December 31,
1998.
Exploration Costs. Exploration costs were $2,768,000 during the first
six months of 2000, an increase of $2,394,000, as compared to $374,000 during
the same period of 1999. Exploration costs include $20,000 of G&G costs relating
to gold exploration in Poland during the first six months of 1999, which are
excluded from the following discussion of each component of exploration costs.
14
G&G costs were $1,165,000 during the first six months of 2000, an
increase of $844,000, as compared to $321,000 during the same period of 1999.
During the first six months of 2000, FX Energy incurred approximately $958,000
of 2-D seismic acquisition and other G&G related costs on its primary project
areas in Poland. During the first six months of 1999, FX Energy's G&G costs were
primarily covered by Apache in accordance with the Apache Exploration Program
terms. G&G costs will continue to fluctuate from period to period, based on FX
Energy's level of exploratory activity in Poland and the respective cost
participation percentage of FX Energy's industry partners.
Exploratory dry hole costs were $929,000 during the first six months of
2000, an increase of $896,000, as compared to $33,000 during the same period of
1999. During the first six months of 2000, the Wilga 3 was determined to be an
exploratory dry hole after it tested the perimeter of the northwest section of
the Wilga field, an area where proved reserves were not assigned prior to
drilling. In accordance with GAAP, the Wilga 3 has been classified as an
exploratory dry hole for accounting purposes, although in industry parlance FX
Energy previously referred to the Wilga 3, the first well drilled near the Wilga
2 discovery well, as either an appraisal or a developmental well. Under the
terms of a recent revision to the Apache Exploration Program, Apache covered one
half of FX Energy's 45% share of costs to drill the Wilga 3. All of the
exploratory dry hole costs incurred during the first six months of 1999 were
associated with the Gladysze 1A, an exploratory dry hole drilled during 1997.
Nonproducing leasehold impairments were $674,000 during the first six
months of 2000, as compared to no nonproducing leasehold impairments during the
first six months of 1999. During the first six months of 2000, FX Energy wrote
off $674,000 of nonproducing leasehold costs relating to the Williston Basin in
North Dakota, where it has no further exploration plans. Nonproducing leasehold
impairments will continue to vary from period to period based on FX Energy's
determination that capitalized costs of unproved properties, on a property by
property basis, are considered not to be realizable.
Contract Servicing
Contract Servicing Revenues. Contract servicing revenues were $386,000
during the first six months of 2000, an increase of $207,000, as compared to
$179,000 during the first six months of 1999. During the first six months of
2000, FX Energy performed substantially more contract services, as compared to
the same period of 1999. Contract servicing revenues will continue to fluctuate
period to period based on market conditions, the degree of emphasis on utilizing
equipment on Company owned properties and other factors.
Contract Servicing Costs. Contract servicing costs were $334,000 during
the first six months of 2000, an increase of $201,000, as compared to $133,000
for the same period of 1999. During the first six months of 2000 and 1999,
contract servicing costs were 87% and 75%, respectively, of contract servicing
revenues. Contract servicing costs will continue to fluctuate period to period
based on the contract servicing revenues generated, degree of emphasis on
utilizing equipment on Company owned properties and other factors.
DD&A Expense - Contract Servicing. DD&A expense for contract servicing
was $108,000 during the first six months of 2000, a decrease of $54,000, as
compared to $162,000 during the same period of 1999, primarily due to capital
items being depreciated during the first six months of 1999 subsequently
becoming fully depreciated prior to or during the first six months of 2000.
15
Nonsegmented Information
G&A Costs. G&A costs were $1,401,000 during the first six months of
2000, an increase of $122,000, as compared to $1,279,000 for the same period of
1999. During the first six months of 2000, FX Energy incurred substantially more
legal, travel and other associated G&A costs as a result of its increased level
of activities in Poland, as compared to the same period of 1999. Through June
30, 2000, Apache has covered all of FX Energy's pro rata share of Apache's G&A
costs in Poland. Effective July 1, 2000, FX Energy will begin to pay
approximately 32.5% of Apache's G&A costs in Poland, to be adjusted as each of
Apache's remaining drilling requirements is completed, up to a maximum of 50%.
We expect that our initial share of such costs will be approximately $600,000
per quarter.
DD&A Expense - Corporate. DD&A expense for corporate activities was
$39,000 during the first six months of 2000, a decrease of $23,000, as compared
to $62,000 during the same period of 1999, primarily due to capital items being
depreciated during the first six months of 1999 subsequently becoming fully
depreciated prior to or during the first six months of 2000.
Interest and Other Income. Interest and other income was $250,000
during the first six months of 2000, an increase of $43,000, as compared to
$207,000 during the same period of 1999. FX Energy's average cash and marketable
debt securities balances were higher during the first six months of 2000, as
compared to the same period of 1999. As a result, FX Energy earned $241,000 of
interest income during the first six months of 2000, an increase of $35,000, as
compared to $206,000 for the same period of 1999.
Officer Loan Impairment. Officer loan impairment was $114,000 for the
six months ended June 30, 2000, as compared to no officer loan impairment for
the same period of 1999. In accordance with SFAS No. 114, FX Energy recorded an
officer loan impairment of $114,000 for the first six months of 2000. The notes
receivable from officers totaled $1,327,000 as of June 30, 2000, representing
principal and interest of $2,107,000 reduced by a cumulative impairment
allowance of $780,000. The notes receivable from officers are collateralized by
233,340 shares of FX Energy's common stock. The impairment allowance will
continue to be adjusted quarterly based on the market value of the collateral
shares.
Financial Condition
Liquidity and Cash Flows
Working Capital. FX Energy's working capital was $9,242,000 as of June
30, 2000, an increase of $3,783,000, as compared to $5,459,000 at December 31,
1999. The increase was principally due to net proceeds of $9,312,000
($10,392,000 gross) from a private placement of 2,969,000 shares of FX Energy's
common stock during the second quarter of 2000, which was partially offset by a
net loss of $3,507,000 for the first six months of 2000 and approximately
$2,547,000 of capitalized costs incurred in Poland during the first six months
of 2000.
Cash Flows from Operating Activities. Net cash used in operating
activities was $2,362,000 during the first six months of 2000, an increase of
$58,000, as compared to $2,304,000 for the same period of 1999. During the first
six months of 2000 and 1999, FX Energy had net losses of $2,608,000 and
$1,322,000, respectively, before DD&A, impairments and interest income on
officer loans. Also, during the first six months of 2000 and 1999, FX Energy's
working capital items changed by an increase of $246,000 and a decrease of
$982,000, respectively.
Cash Flows from Investing Activities. Net cash provided by investing
activities was $1,371,000 during the first six months of 2000, as compared to
$3,773,000 used in investing activities for the same
16
period of 1999. During the first six months of 2000, FX Energy spent $119,000 to
upgrade its domestic producing properties, $247,000 on its Polish properties,
$274,000 on upgrading its contract servicing equipment, $16,000 on office
equipment, and realized a net amount $2,027,000 from maturing marketable debt
securities. During the first six months of 1999, FX Energy spent $73,000 on
upgrading its producing properties, a net amount of $131,000 on unproved
properties, $56,000 on upgrading its contract servicing equipment, $10,000 on
other assets and a net amount of $3,503,000 on purchasing marketable debt
securities.
Cash Flows from Financing Activities. Net cash provided by financing
activities was $9,346,000 during the first six months of 2000, an increase of
$2,886,000, as compared to $6,460,000 during the same period of 1999. During the
first six months of 2000, FX Energy realized net proceeds after offering costs
of $9,312,000 from the private placement of 2,969,000 shares of FX Energy's
common stock and $34,000 from the exercise of warrants to purchase 20,572 shares
of FX Energy's common stock. During the first six months of 1999, FX Energy
advanced two of its officers a total of $597,000 and realized net proceeds after
offering costs of $7,057,000 from the sale of 1,792,500 shares of FX Energy's
common stock.
Capital Requirements
As of June 30, 2000, FX Energy had $13.2 million of cash, cash
equivalents and marketable debt securities with no long-term debt. In order to
fully fund its current planned exploration and development activities, FX Energy
will need additional debt or equity capital during late 2000 or early 2001.
Fences Project Area. On April 11, 2000, FX Energy agreed to spend the
first $16.0 million of exploration and development costs on the Fences project
area to earn a 49% interest. FX Energy expects the $16.0 million will cover the
costs to drill five wells (approximately $2.5 million per well) and the
acquisition of approximately 200 square kilometers of 3-D seismic data
(approximately $3.5 million). After the first $16.0 million is spent, all costs
and net revenues will be shared 49% by FX Energy and 51% by POGC.
On June 28, 2000, FX Energy announced that the Kleka 11, the first
exploratory well drilled in the Fences project area, was an exploratory success
after the well tested a calculated open flow rate of 34.3 MMcf of gas per day
from a Rotliegendes sandstone reservoir. The Kleka 11 is located approximately
one kilometer from a pipeline. FX Energy expects to commence production from the
Kleka 11 by the end of 2000 or early 2001. The next well, the Mieszkow 1, is
expected to commence drilling during the third quarter of 2000. FX Energy
expects to utilize any net revenue it receives in the future from the Fences
project area to supplement its capital from other sources to further explore and
develop the Fences project area.
Wilga Project Area. During January 2000, Apache completed its
commitment to pay FX Energy's 45% share of costs to drill the Wilga 2, a
successful exploratory well which tested at an initial flow rate of 16.9 MMcf of
gas and 570 Bbls of condensate per day. On June 22, 2000, Apache agreed to cover
one half of FX Energy's share of costs to drill the Wilga 3 and Wilga 4 wells in
exchange for a release of Apache's commitment to cover FX Energy's share of
costs for one exploratory well in Poland. FX Energy will pay its 45% share of
costs for all further costs in the Wilga project area, including drilling
additional wells as warranted, which are expected to cost an average of
approximately $3.0 million gross per well ($1.4 million net per well) and the
construction of production facilities and pipelines during 2001 at a cost of
approximately $11.0 million gross ($5.0 million net).
17
On June 5, 2000, the Wilga 3 was determined to be an exploratory dry
hole, with an estimated net cost of $0.9 million, after the well encountered
Carboniferous sands and a Lower Devonian sand package that tested noncommercial
in a separate fault block from the Wilga 2 discovery well. The next well, the
Wilga 4, commenced drilling on June 17, 2000, on the opposite side of the Wilga
2 discovery well.
Subject to further success in the Wilga project area and completion of
a pipeline and production facilities, FX Energy anticipates receiving production
revenue from the Wilga field during 2001. FX Energy expects to utilize any net
revenue it receives in the future from the Wilga project area to supplement its
capital from other sources to further explore and develop the Wilga project
area.
Apache Exploration Program. During the remainder of 2000, FX Energy
expects to have substantially all of its share of exploration activities
relating to the Apache Exploration Program paid for by Apache. Apache is
required to cover FX Energy's share of costs to drill three exploratory wells
and the cost to shoot 350 kilometers of 2-D seismic data. During the second half
of 2000, FX Energy and Apache have scheduled to commence drilling one
exploratory well in each of the Warsaw West and Pomeranian project areas.
POGC Property Acquisition. FX Energy will need additional capital if it
is able to reach an agreement with POGC to purchase an interest in any of POGC's
exploration, appraisal, development or producing projects in Poland. FX Energy
may undertake such projects alone or in partnership with Apache or other
industry partners. FX Energy intends to seek additional capital that may be
required for such purposes through a variety of means, including the issuance of
debt and equity securities, project financing, bank financing or other financing
alternatives. FX Energy cannot assure that it will be able to obtain funds that
will enable it to participate in any such further acquisitions or joint
activities.
Other. FX Energy expects to incur minimal exploration expenditures on
its Baltic project area in Poland during the remainder of 2000 and 2001.
Similarly, FX Energy expects to incur minimal exploration, appraisal and
development expenditures on its domestic operations during the remainder of 2000
and 2001.
FX Energy may change the allocation of capital among the categories of
anticipated expenditures depending upon future events that it cannot predict.
For example, FX Energy may change the allocation of its expenditures based on
the actual results and costs of future exploration, appraisal, development,
production, property acquisition and other activities. In addition, FX Energy
may have to change its 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.
FX Energy may obtain funds for future capital investments from the sale
of additional securities, project financing, sale of partial property interests,
strategic alliances with other energy or financial partners or other
arrangements, all of which may dilute the interest of its existing stockholders
or its interest in the specific project financed.
FX Energy previously initiated discussions with a commercial lender for
a possible project loan secured by proved reserves that may be developed as a
result of its Wilga discovery. FX Energy now intends to expand those discussions
to include possible project loan financing for the Kleka discovery as well as
other possible discoveries. FX Energy cannot assure it can establish such a
credit facility. In any event, borrowed funds are not likely to be available
until significant reserves are established through additional drilling. If FX
Energy is able to obtain such a loan, amounts initially allocated to develop
those discoveries may be allocated to other operations in Poland.
18
ACTION AT STOCKHOLDER MEETING
On June 28, 2000, at the annual meeting of stockholders, the
stockholders re-elected Andrew W. Pierce, Jay W. Decker, and Jerzy B. Maciolek
as directors, each to serve a term of three years; approved the FX Energy, Inc.
1999 Stock Option and Award Plan; and approved the amendment to the FX Energy,
Inc. Articles of Incorporation increasing the capitalization to 100,000,000
shares of common stock.
19
[COMPANY LOGO]
Resale of 2,969,000 shares of common stock
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This prospectus relates to the resale of our shares of common stock by the
stockholders named under the caption "Selling Stockholders" on page 60. The
selling stockholders may offer and sell from time to time common stock using
this prospectus in transactions:
o on the Nasdaq National Market or otherwise;
o at market prices, which may vary during the offering period, or at
negotiated prices; and
o in ordinary brokerage transactions, in block transactions, in privately
negotiated transactions, or otherwise.
The selling stockholders will receive all of the proceeds from the sale of the
shares and will pay all underwriting discounts and selling commissions relating
to the sale of the shares. FX Energy has agreed to pay the legal, accounting,
printing and other expenses related to the registration of the sale of the
shares.
Our common stock is listed on the Nasdaq National Market under the symbol
"FXEN." On July 10, 2000, the last reported sale price of our common stock was
$5.06.
An investment in our shares involves certain risks. We urge you to read the
"Risk Factors" section beginning on page 6 and the rest of this prospectus
before making an investment decision.
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Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
The date of this prospectus is July 10, 2000.
Table of Contents
Page
About This Prospectus..........................................................i
Prospectus Summary.............................................................1
Risk Factors...................................................................6
Forward-Looking Statements....................................................12
Price Range of Common Stock and Dividend Policy...............................13
No Net Proceeds to Us.........................................................13
Capitalization................................................................14
Dilution......................................................................15
Selected Consolidated Financial Data..........................................16
Management's Discussion and Analysis of Financial
Condition and Results of Operations.........................................18
Business......................................................................29
The Republic of Poland........................................................45
Management ...................................................................47
Principal Stockholders........................................................55
Description of Capital Stock..................................................57
Selling Stockholders..........................................................60
Plan of Distribution..........................................................61
Where You Can Find Additional Information.....................................63
Legal Matters.................................................................63
Experts.......................................................................63
Glossary of Oil and Gas Terms.................................................64
Index to Financial Statements................................................F-1
About This Prospectus
As used in this prospectus, the terms "we," "us" and "our" refer to FX Energy,
Inc., a corporation organized under the laws of the state of Nevada, 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,
unless the context indicates a different meaning.
As used in this prospectus, "Bcf" means 1,000,000,000 cubic feet of natural gas,
"Bcfe" means 1,000,000,000 cubic feet of natural gas equivalent, "MBbls" means
1,000 barrels of crude oil, including condensate or natural gas liquids, "Mcf"
means 1,000 cubic feet of natural gas, "Mcfe" means 1,000 cubic feet of natural
gas equivalent using a ratio of 1 barrel of oil equals 6,000 cubic feet of
natural gas, "MMcf" means 1,000,000 cubic feet and "MMcfe" means 1,000,000 cubic
feet of natural gas equivalent. "Gross" acres and "gross" wells mean the total
number of acres or wells, as the case may be, in which an interest is owned,
either directly or through a subsidiary or other Polish enterprise in which we
have an interest. "Net" means, when referring to wells or acres, the fractional
ownership working interests we hold, either directly or through a subsidiary or
other Polish enterprise in which we have an interest, multiplied by the gross
wells or gross acres.
All historical production and test data about Poland, excluding wells in which
we have participated, have been derived from information furnished by either the
Polish Oil and Gas Company or the Polish Ministry of Environmental Protection,
Natural Resources and Forestry.
All production numbers set forth in this prospectus, whether amounts, costs,
revenues or otherwise, are reported net of royalties, unless otherwise
indicated.
-i-
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Prospectus Summary
This prospectus summary contains an overview of the information from this
prospectus, but may not contain all of the information that is important to you.
This prospectus includes specific terms of the offering of our common stock,
information about our business and financial data. We encourage you to read this
prospectus, including the "Risk Factors" section beginning on page 6, in its
entirety before making an investing decision. We have provided definitions for
some of the oil and gas industry terms used in this prospectus in the "Glossary
of Oil and Gas Terms" on page 64 of this prospectus.
FX Energy
We are an independent oil and gas company focused on exploration, development
and production opportunities in the Republic of Poland. We are the largest
foreign oil and gas exploration acreage holder in Poland with exploration rights
covering approximately 16.1 million gross acres. Our activities are conducted
under strategic alliances with Apache Corporation and the Polish Oil and Gas
Company, or POGC, which allow us to utilize the operating and technical
personnel of those companies, gain access to geological and geophysical data and
obtain other necessary support activities in Poland.
We are currently conducting oil and gas exploration activities with Apache in
Poland in areas where we and Apache jointly hold exploration rights, a program
to which we refer as the Apache Exploration Program. One of the wells drilled
under the Apache Exploration Program resulted in our first exploration success
in the Wilga project, which is located in the northwest portion of the Lublin
Basin project area. The Wilga 2 well tested at an initial flow rate of 16.9 MMcf
of gas per day and 570 Bbls of condensate from the Carboniferous at a depth of
approximately 2,800 meters. The Wilga 2 well was the first successful
exploration well drilled by a foreign operator in Poland. We own a 45% interest
in the 250,000 acre block in which the Wilga project is located, POGC owns 10%
and Apache owns 45% and is the operator.
The Wilga 2 was followed by the Wilga 3 well, which encountered good reservoir
rock in Carboniferous sands and a Lower Devonian sand package in a separate
fault block, but was determined to be a dry hole after test results did not
yield commercial quantities of oil or gas. We believe the absence of oil and gas
in the Wilga 3 is related to faulting and therefore does not alter the
expectation that the Wilga 2 discovery is indicative of a larger oil and gas
accumulation. The next well, the Wilga 4, commenced drilling on June 17, 2000,
at a location east of the Wilga 2 discovery, on the opposite side of the fault
from the Wilga 3. Subject to satisfactory results from the Wilga 4 and the 2-D
seismic data currently being shot, we intend to drill three additional wells
through early 2001 to begin to determine the extent of the Wilga accumulation or
the existence of other accumulations in the Wilga area. In anticipation of
further development in the Wilga project, we expect to begin design and
installation of production facilities and construction of an approximately 18
kilometer pipeline that will be designed with the capacity to support several
additional productive wells.
On April 11, 2000, we signed an agreement with POGC under which we will earn a
49% working interest in approximately 300,000 gross acres in the Fences project
area by spending $16.0 million on exploration and development activities. We
have identified several separate exploration prospects in the Fences project
area based on POGC's existing seismic data and adjacent productive areas. Our
first well in this project area, the Kleka 11, was announced as an exploratory
success on June 28, 2000, after the well tested a calculated open flow rate of
34.3 MMcf of gas per day from the Rotliegendes at a depth of approximately 3,000
meters. As part of our commitment, we plan to shoot 200 or more kilometers of
3-D seismic data and drill approximately four additional wells. After we
complete our work commitment, POGC will begin bearing its 51% of further costs.
POGC is the operator of the Fences project area, which we have referred to
previously as the Radlin project area.
Strategic Relationships
Apache. Apache Corporation is a leading independent exploration and production
company based in the U.S. with an equity market capitalization of over $5.5
billion as of June 2000. Apache has successful exploration programs in the
United States, Canada, Australia, Egypt, Poland and China. We and Apache have
established an area of mutual interest for oil and gas exploration and
development covering current and future holdings in most of Poland. Apache
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does not participate in our new 300,000 gross acre Fences project area or our
900,000 gross acre Baltic project area. In addition to our share of the costs in
the five exploratory wells and over 2,000 kilometers of seismic data gathered to
date in the Apache Exploration Program, Apache will cover our share of costs to
drill an equivalent of four additional exploratory wells, shoot and analyze
approximately 350 kilometers of 2-D seismic data and cover all general and
administrative costs under the Apache Exploration Program through June 30, 2000.
In addition, we and Apache may seek to acquire from POGC appraisal, development
or exploration projects on existing POGC discoveries, shut-in fields and
underdeveloped properties in Poland.
POGC. The Polish Oil and Gas Company, or POGC, is the largest holder of oil and
gas rights in Poland. POGC is a state-owned, integrated oil and gas company with
approximately 30,000 employees and over 6.0 Tcfe of reserves, according to
industry sources. Our strategic alliance with POGC provides us with access to
important exploration data as well as technical and operational support. We and
Apache have granted POGC an option to earn up to a one-third interest in our
Lublin, Pomeranian and Carpathian project areas, which cover approximately 8.6
million gross acres. In turn, POGC has granted us and Apache each the right to
earn up to a one-third interest in approximately 3.4 million POGC controlled
gross acres. As indicated above, we signed an agreement in April 2000 to
participate with POGC in the Fences project area. In addition, we are currently
pursuing proposals to acquire additional appraisal, development or exploration
projects on existing POGC discoveries. We believe that our relationship with
POGC may provide additional opportunities in Poland.
Business Strategy
Our strategy is to increase our reserves, production and cash flow through
exploration and development drilling. The principal components of our business
strategy are:
o Focus on Poland. We believe Poland is an attractive area in which to
conduct exploration activities because of its known productive basins,
limited oil and gas exploration and development in those basins and heavy
dependence on oil and gas imports. In addition, Poland's industrial
infrastructure combined with its fiscal regime favorable to foreign
investment reinforce the attractiveness of Poland.
o Leverage Our Exploration Success. Although we currently have no debt, when
we convert an exploration prospect into a development project, we intend to
fund the majority of exploitation costs with debt financing, if available.
o Balance Our Growth Profile. We intend to diversify our portfolio of
properties and our risk profile by adding additional development
opportunities to our inventory of high potential exploration projects. We
intend to seek the acquisition of proved reserves with additional
exploitation potential or proved reserves with infrastructure constraints.
We believe that our relationship with POGC may provide us access to such
opportunities in Poland.
o Expand Existing and Develop New Strategic Relationships. We intend to
expand our strategic relationships with Apache and POGC to obtain
operational assistance and to enhance our ability to pursue additional
opportunities in Poland. We may seek new strategic alliances with other
operating or financial partners to exploit fully our recent exploratory
success as well as any possible new ventures in Poland.
- --------------------------------------------------------------------------------
2
- --------------------------------------------------------------------------------
Exploration and Development Plan
Our current exploration and development plan consists of three primary
components:
o drilling and, if warranted, completing appraisal and development wells,
constructing production facilities and further exploring our Wilga project
area with Apache and POGC;
o fulfilling our $16.0 million commitment to earn our interest in the Fences
project area with POGC; and
o drilling (excluding completion costs, if any) the remaining exploration
wells to be funded by Apache under the Apache Exploration Program.
The following table sets forth our current exploration and development plan. The
capital expenditures included within the table are estimates based on
information currently available to us and are subject to being revised as
warranted. Actual capital expenditures may vary significantly from the estimated
amounts.
Interest
-------------------- Capital Expenditures
Net Estimated ------------------------------
Working Revenue(1) Date Total FX Share
-------------------- ---------- -------------- ---------------
(In millions)
Wilga Project(2).......................... 45% 42%
Wilga 3 well (drilled)(3).............. 1H 2000 $ 4.00 $ 0.90
Wilga 4 well (commenced)(3)............ 2H 2000 3.00 0.68
Seismic data........................... 2H 2000 0.53 0.24
Wilga 5 well........................... 2H 2000 3.00 1.35
Wilga 6 well........................... 2001 3.00 1.35
Wilga 7 well........................... 2001 3.00 1.35
Facilities/pipeline.................... 2001 11.11 5.00
-------------- ---------------
$27.64 $ 10.87
-------------- ---------------
Fences Project Area(2).................... 49% 46%
Kleka 11 well (drilled)................ 1H 2000 $ 2.50 $ 2.50
Mieszkow well.......................... 2H 2000 2.50 2.50
Boguszyn well.......................... 2H 2000 2.50 2.50
Donatowo well.......................... 2001 2.50 2.50
Zaniemysl well......................... 2001 2.50 2.50
Lugi well.............................. 2001 2.50 1.23
Seismic data........................... Various 3.50 3.50
-------------- ---------------
$18.50 $17.23
-------------- ---------------
Apache Exploration Program(2)............. 50% 47%
Pomeranian well(4)..................... 2H 2000 $ 3.50 $ --
Warsaw West well....................... 2H 2000 3.50 --
Carpathian well(4)..................... 2001 3.80 --
Seismic data........................... Various 6.30 0.15
-------------- ---------------
$17.10 $ 0.15
-------------- ---------------
Total................................ $63.24 $28.25
============== ===============
(1) Assuming the current base rate royalty of 6%.
(2) Capital expenditures in the Wilga project area include completion costs,
which are included within facilities/pipeline costs. Capital expenditures
in the Fences project area and the Apache Exploration Program do not
include completion costs.
(3) Effective June 22, 2000, Apache agreed to cover one-half of our share of
costs to drill the Wilga 3 and Wilga 4 wells in exchange for a release of
Apache's commitment to cover our share of costs for one exploratory well in
Poland.
(4) Our interests could be reduced to as low as a 331/3% working interest and a
311/3% net revenue interest if POGC exercises its option to participate in
these exploratory wells.
Our Address
Our principal executive offices are located at 3006 Highland Drive, Suite 206,
Salt Lake City, Utah 84106, and our telephone number is (801) 486-5555.
- --------------------------------------------------------------------------------
3
- --------------------------------------------------------------------------------
The Offering
Common stock outstanding .....................................17,818,003 shares
Common stock to be offered by selling stockholders............2,969,000 shares
Nasdaq National Market symbol.................................FXEN
The number of outstanding shares shown above excludes an aggregate of 4,146,167
shares that may be issued on the exercise of options and warrants outstanding as
of July 10, 2000.
- --------------------------------------------------------------------------------
4
- --------------------------------------------------------------------------------
Summary Consolidated Financial Data
The summary historical consolidated financial data for each of the three fiscal
years in the period ended December 31, 1999 are derived from our audited
consolidated financial statements, which are included in this prospectus. The
historical financial information for the three months ended March 31, 2000 and
1999 and as of March 31, 2000 was derived from our unaudited consolidated
financial statements, which also are included in this prospectus. The unaudited
adjusted balance sheet data have been adjusted only to reflect our sale in June
2000, of 2,969,000 shares of common stock to the selling stockholders at a price
of $3.50 per share from which we received net proceeds of $9.3 million ($10.4
million gross), but does not reflect any other changes to our financial
condition subsequent to March 31, 2000. All amounts are in thousands, except per
share amounts.
Three Months Ended
March 31, Years Ended December 31,
------------------------- -------------------------------------
2000 1999 1999 1998 1997
------------ ------------ ------------ ------------ -----------
Statement of Operations Data
Revenues:
Oil sales....................................... $ 597 $ 234 $1,554 $ 1,124 $2,040
Drilling revenue................................ 73 88 865 323 496
Gain on sale of property interests.............. -- -- -- 467 272
------------ ------------ ------------ ------------ -----------
Total revenues................................ 670 322 2,419 1,914 2,808
------------ ------------ ------------ ------------ -----------
Operating Costs and Expenses:
Lease operating costs (1)....................... 292 252 962 1,046 1,239
Exploration costs (2)........................... 484 180 3,053 2,127 5,314
Producing property impairment................... -- -- -- 5,885 --
Drilling costs.................................. 75 53 642 240 329
Depreciation, depletion and amortization........ 87 126 494 672 635
General and administrative...................... 597 536 2,962 2,572 2,566
------------ ------------ ------------ ------------ -----------
Total operating costs and expenses............ 1,535 1,147 8,113 12,542 10,083
------------ ------------ ------------ ------------ -----------
Operating loss.................................... (865) (825) (5,694) (10,628) (7,275)
------------ ------------ ------------ ------------ -----------
Other income (expense):
Interest and other income....................... 134 102 511 506 662
Interest expense................................ -- -- (7) -- (83)
Impairment of notes receivable from officers.... (5) -- (666) -- --
------------ ------------ ------------ ------------ -----------
Total other income (expense).................. 129 102 (162) 506 579
------------ ------------ ------------ ------------ -----------
Net loss before extraordinary gain................ (736) (723) (5,856) (10,122) (6,696)
Extraordinary gain.............................. -- -- -- -- 3,076
------------ ------------ ------------ ------------ -----------
Net loss.......................................... $ (736) $ (723) $(5,856) $(10,122) $(3,620)
============ ============ ============ ============ ===========
Basic and diluted net loss per share:
Net loss before extraordinary gain.............. $(0.05) $(0.06) $ (0.41) $ (0.78) $ (0.53)
Extraordinary gain.............................. -- -- -- -- 0.24
------------ ------------ ------------ ------------ -----------
Net loss...................................... $(0.05) $(0.06) $ (0.41) $ (0.78) $ (0.29)
============ ============ ============ ============ ===========
Basic and diluted weighted average shares
outstanding.................................... 14,849 13,055 14,199 12,979 12,597
============ ============ ============ ============ ===========
March 31, 2000
-----------------------
Actual As Adjusted
----------- -----------
Balance Sheet Data:
Working capital...................................................................... $4,092 $13,392
Total assets......................................................................... 9,433 18,733
Long-term debt....................................................................... -- --
Stockholders' equity................................................................. $7,601 $16,901
(1) Includes lease operating expenses and production taxes.
(2) Includes geophysical and geological costs, exploratory dry hole costs and
nonproducing leasehold impairments.
- --------------------------------------------------------------------------------
5
Risk Factors
An investment in our common stock involves significant risks. You should
carefully consider the following risk factors before you decide to buy our
common stock. You should also carefully read and consider all the information we
have included in this prospectus before you decide to buy our common stock.
Risks Relating to our Business
Our success depends on our discovery of economic quantities of oil or gas
in Poland.
We do not currently have any oil or gas production in Poland and do not generate
sufficient revenues to cover our costs of operation. Our exploration program is
based on interpretations of geological and geophysical data. The factors listed
below, most of which are outside our control, may prevent us from establishing
commercial production or substantial reserves as a result of our exploration,
appraisal and development activities in Poland:
o we cannot assure that any well will encounter oil or gas;
o there is no way to know in advance of drilling and testing whether any
prospect encountering oil or gas will yield oil or gas in sufficient
quantities to cover drilling or completion costs or to be economically
viable;
o one or more appraisal wells are typically required to confirm the
commercial potential of any oil or gas discovery;
o we may continue to incur exploration costs in specific areas even if
initial appraisal wells are plugged and abandoned or, if completed for
production, do not result in production of commercial quantities; and
o drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including operating problems encountered during drilling,
weather conditions, compliance with governmental requirements and shortages
or delays in the delivery of equipment or availability of services.
We have committed to spend $16.0 million to earn an interest in the Fences
project area, which may require us to fulfill our commitment although initial
exploration may indicate that further exploration is not warranted.
We have limited control over our exploration and development activities in
Poland.
We rely to a significant extent on the expertise and financial capabilities of
our strategic partners, Apache and POGC. The failure of Apache or POGC to
perform its obligations under contracts with us would most likely have a
material adverse effect on us. In particular, we have prepared our exploration
budget through 2000 and into 2001, based on the funding to be provided by Apache
and, to a limited extent, POGC. In the future, we may become even more reliant
upon the expertise and financial capabilities of our strategic partners. Apache
has worldwide oil and gas interests outside of Poland in which we do not
participate. If Apache's separately-held interests should become more promising
to Apache than interests held with us in Poland, Apache may focus its efforts,
funds, expertise and other resources elsewhere. In addition, should our
relationship with Apache deteriorate or terminate, our oil and gas exploratory
programs in Poland may be delayed significantly. Although we have rights to
participate in exploration and development activities on some POGC controlled
acreage, we have no right to initiate such activities. Further, we have no
interest in the underlying agreements, licenses and grants from the Polish
agencies governing the exploration, exploitation, development or production of
acreage controlled by POGC. Thus, our program in Poland involving POGC
controlled acreage would be adversely affected if POGC should elect not to
pursue activities on such acreage, if the relationship between us, Apache or
POGC should deteriorate or terminate or if POGC or the government agencies
should fail to fulfill the requirements of or elect to terminate such
agreements, licenses or grants.
We may not achieve the results anticipated in placing our current or future
discoveries into production.
We may encounter delays in placing the Wilga project into production due to the
requirements to obtain rights-of-way for an approximately 18 kilometer pipeline
to connect to the POGC pipeline system, permits for construction of surface
facilities, equipment, installation and construction services and materials and
related
6
infrastructure components. We may also encounter similar delays regarding our
Kleka discovery in the Fences project area, which is approximately one kilometer
from a pipeline. In addition, our efforts to complete a gas purchase contract
with the transportation and storage division of POGC may also be delayed. Such
delays would correspondingly delay the commencement of cash flow from sales of
gas and may require us to obtain additional short-term financing pending
commencement of production. Further, we have designed the proposed surface
facilities and pipeline based on possible estimated results of additional
drilling. We cannot assure that additional drilling will establish additional
reserves or production that will provide an economic return for currently
planned expenditures for facilities. We may have to change our anticipated
expenditures if costs of placing a particular discovery into production are
higher, if the project is smaller or if the commencement of production takes
longer than expected.
We cannot assure the exploration models we have developed in Poland will
improve our chances of finding oil or gas in Poland.
We cannot assure the exploration models we, Apache and POGC have developed will
provide a useful or effective guide for selecting exploration prospects and
drilling targets. We will have to revise or replace these exploration models as
a guide to further exploration if ongoing drilling results do not confirm their
validity. These exploration models may be based on incomplete or unconfirmed
data and theories that have not been fully tested. The seismic data, other
technologies and the study of producing fields in the area do not enable us to
know conclusively prior to drilling that oil or gas will be present in
commercial quantities. We cannot assure that the analogies that we draw from
available data from other wells, more fully explored prospects or producing
fields will be applicable to our drilling prospects.
We cannot accurately predict the size of exploration targets or foresee all
related risks.
Notwithstanding the accumulation and study of 2-D and 3-D seismic data, drilling
logs, production information from established fields and other data, we cannot
predict accurately the oil or gas potential of individual prospects and drilling
targets or the related risks. Our predictions are only rough, preliminary
geological estimates of the forecasted volume and characteristics of possible
reservoirs and are not an estimate of reserves. In some cases, our estimates may
be based on a review of data from other exploration or producing fields in the
area that may not be similar to our exploration prospects. The oil or gas
potential of individual prospects can only be determined by several test wells
and long-term analysis of test data and history of any production.
We have had limited exploratory success in Poland.
We have participated in drilling eleven exploratory wells in Poland, including
the Wilga 4, which is currently underway. To date, we have had two exploratory
successes; the Wilga 2 and the Kleka 11. We have completed drilling six
exploratory wells with Apache and POGC as partners under terms of the Apache
Exploration Program, five of which were exploratory dry holes and one of which,
the Wilga 2, was an exploratory success. We have drilled one exploratory well
with POGC as our partner in the Fences project area, the Kleka 11, which was an
exploratory success. We have also drilled two exploratory dry holes on the
Baltic project area and participated in an exploratory dry hole in the
Carpathian project area. In addition, we participated in testing and appraising
two shut-in gas wells in the Lachowice area in Poland that did not result in
commercial production.
Privatization of POGC could affect our relationship and future
opportunities in Poland.
Our activities in Poland have benefited from our relationship with POGC, which
has provided us with exploration acreage and data under our agreements. We and
Apache continue to seek new exploration, exploitation and acquisition
opportunities with POGC. The Polish government has commenced the privatization
of POGC by selling POGC's refining and storage assets and has stated its intent
to privatize POGC's exploration and production operations. Such privatization
may result in new policies, strategies or ownership that could adversely affect
our existing relationship and agreements as well as any availability of
opportunities with POGC in the future.
7
Before we can commence production, we must construct infrastructure and
enter into marketing arrangements.
We and our partners will need to complete production and transportation
facilities as well as marketing arrangements relating to oil or gas that may be
produced from our acreage in Poland. We currently do not have any agreements to
transport or market our production in Poland. Therefore, our wells may be
shut-in until we are able to complete production facilities and marketing
arrangements.
We have a history of operating losses and may require additional capital in
the future to fund our operations.
From our inception in January 1989 through March 31, 2000, we have incurred
cumulative net losses of $29.5 million. We expect that our exploration
activities will continue to result in losses and that our accumulated deficit
will increase. We anticipate that we will incur losses through 2000 and possibly
beyond, depending on whether our exploration, appraisal, development and
property acquisition activities in Poland result in sufficient production to
cover related operating expenses.
Until sufficient cash flow from operations can be obtained, we expect we will
need additional capital to fully fund our ongoing planned exploration,
appraisal, development and property acquisition programs in Poland. We have no
current arrangement for any such additional financing, but may seek required
funds from the issuance of debt and equity securities, project financing,
strategic alliances or other arrangements. Obtaining additional financing may
dilute the interest of our existing stockholders or our interest in the specific
project being financed. We cannot assure that additional funds could be obtained
or, if obtained, would be on terms favorable to us. In addition to planned
activities in Poland, we may require funds for general corporate purposes after
the end of 2000 if we do not have positive cash flow from operations.
The loss of key personnel could have an adverse impact on our operations.
We rely on our officers and key employees and their expertise, particularly
David N. Pierce, President and Chief Executive Officer, Andrew W. Pierce,
Vice-President and Chief Operating Officer, and Jerzy B. Maciolek,
Vice-President of International Exploration, a Polish national who is
instrumental in assisting us in our operations in Poland. The loss of the
services of any of these individuals may materially and adversely affect us. We
have entered into employment agreements with Mr. David Pierce, Mr. Andrew
Pierce, Mr. Maciolek and other key executives. We do not maintain key man
insurance on any of our employees.
Oil and gas price decreases and volatility could adversely affect our
operations and our ability to obtain financing.
Oil and gas prices have been and are likely to continue to be volatile and
subject to wide fluctuations in response to the following factors:
o changes in the supply of and demand for oil and gas;
o market uncertainty;
o political conditions in international oil and gas producing regions;
o the extent of production and importation of oil and gas into existing or
potential markets;
o the level of consumer demand;
o weather conditions affecting production, transportation and consumption;
o the competitive position of oil or gas as a source of energy, as compared
with coal, nuclear energy, hydroelectric power and other energy sources;
o the availability, proximity and capacity of gathering systems, pipelines
and processing facilities;
o the refining capacity of prospective oil purchasers;
8
o the effect of government regulation on the production, transportation and
sale of oil and gas; and
o other factors beyond our control.
We have not entered into any agreements to protect us from price fluctuations
and may not do so in the future.
Our industry is subject to numerous operating risks. Insurance may not be
adequate to protect us against all these risks.
Our oil and gas drilling and production operations are subject to hazards
incidental to the industry. These hazards include blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
pollution, releases of toxic gas and other environmental hazards and risks.
These hazards can cause personal injury and loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage and
suspension of operations. To lessen the effects of these hazards, we maintain
insurance of various types to cover our domestic operations. We cannot assure
that the general liability insurance of $9.0 million carried by us or the $25.0
million carried by Apache, as the operator of the Apache Exploration Program,
can continue to be obtained on reasonable terms. POGC, as operator of the Fences
project area, is self-insured. The current level of insurance does not cover all
of the risks involved in oil and gas exploration, drilling and production. Where
additional insurance coverage does exist, the amount of coverage may not be
sufficient to pay the full amount of such liabilities. We may not be insured
against all losses or liabilities that may arise from all hazards because such
insurance is unavailable at economic rates, because of limitations on existing
insurance coverage or other factors. For example, we do not maintain insurance
against risks related to violations of environmental laws. We would be adversely
affected by a significant adverse event that is not fully covered by insurance.
Further, we cannot assure that we will be able to maintain adequate insurance in
the future at rates we consider reasonable.
Risks Relating to Conducting Business in Poland
Polish laws, regulations and policies may be changed in ways that could
adversely impact our business.
Our oil and gas exploration, development and production activities in Poland are
and will be subject to ongoing uncertainties and risks, including:
o possible changes in government personnel, the development of new
administrative policies and practices and political conditions in Poland
that may affect the administration of agreements with governmental agencies
or enterprises;
o possible changes to the laws, regulations and policies applicable to us and
our partners or the oil and gas industry in Poland in general;
o uncertainties as to whether the laws and regulations will be applicable in
any particular circumstance;
o uncertainties as to whether we will be able to enforce our rights in
Poland;
o uncertainty as to whether we will be able to demonstrate, to the
satisfaction of the Polish authorities, our, Apache's and POGC's compliance
with governmental requirements respecting exploration expenditures, results
of exploration, environmental protection matters and other factors;
o the inability to recover previous payments to the Polish government made
under the exploration rights or any other costs incurred respecting those
rights if we were to lose or cancel our exploration and exploitation rights
at any time;
o political instability and possible changes in government;
o export and transportation tariffs;
o local and national tax requirements; and
o expropriation or nationalization of private enterprises and other risks
arising out of foreign government sovereignty over our acreage in Poland.
9
Poland has a developing regulatory regime governing exploration and development,
production, marketing, transportation and storage of oil and gas. These
provisions were recently promulgated and are relatively untested. Therefore,
there is little or no administrative or enforcement history or established
practice that can aid us in evaluating how the regulatory regime will affect our
operations. It is possible that such governmental policies will change or that
new laws and regulations, administrative practices or policies or
interpretations of existing laws and regulations will materially and adversely
affect our activities in Poland. For example, Poland's laws, policies and
procedures may be changed to conform to the minimum requirements that must be
met before Poland is admitted as a full member of the European Union.
Our oil and gas operations are subject to rapidly changing environmental
laws and regulations that could negatively impact our operations.
Operations on our project areas are subject to environmental laws and
regulations in Poland that provide for restrictions and prohibitions on spills,
releases or emissions of various substances produced in association with oil and
gas exploration and development. Additionally, if significant quantities of gas
are produced with oil, regulations prohibiting the flaring of gas may inhibit
oil production. In such circumstances, the absence of a gas gathering and
delivering system may restrict production or may require significant
expenditures to develop such a system prior to producing oil and gas. We may be
required to prepare and obtain approval of environmental impact assessments by
governmental authorities in Poland prior to commencing oil or gas production,
transportation and processing functions.
We and our partners cannot assure that we have complied with all applicable laws
and regulations in drilling wells, acquiring seismic data or completing other
activities in Poland to date. More restrictive regulations or administrative
policies or practices may be adopted by the Polish government. The cost of
compliance with current regulations or any changes in environmental regulations
could require significant expenditures. Further, breaches of such regulations
may result in the imposition of fines and penalties, any of which may be
material. These environmental costs could have a material adverse effect on our
financial condition or results of operations in the future.
Certain risks of loss arise from our need to conduct transactions in
foreign currency.
The amounts in our agreements relating to our activities in Poland are normally
expressed and payable in United States dollars or equivalent Polish zlotys.
Conversions between United States dollars and Polish zlotys are made on the date
amounts are paid or received. In the future, our financial results and cash
flows in Poland may be affected by fluctuations in exchange rates between the
Polish zloty and the United States dollar. We have not hedged our foreign
currency activities in the past and have no future plans to do so. Currencies
used by us may not be convertible at satisfactory rates. In addition, the
official conversion rates between United States and Polish currencies may not
accurately reflect the relative value of goods and services available or
required in Poland. Further, inflation may lead to the devaluation of the Polish
zloty.
Under the Foreign Exchange Law, prior to making transfers of nonresident income
(such as dividends, interest, rent) abroad, a bank generally must be furnished
with documents evidencing title for the payment, as well as with a certificate
issued by the Polish tax authorities confirming the expiration of tax liability
in Poland or a foreign exchange permit releasing the transferor from this
obligation. If the income to be transferred is not subject to taxation in
Poland, a written declaration to this effect may be sufficient.
Given that the Foreign Exchange Law has come into effect recently and no
detailed rules and regulations under it have been issued to date by the Polish
authorities, the interpretation of the law's provisions will remain in the near
term subject to considerable uncertainty.
10
Risks Related to an Investment in our Common Stock
Our stockholder rights plan and bylaws discourage unsolicited takeover
proposals and could prevent you from realizing a premium for your common
stock.
We have a stockholder rights plan that may have the effect of discouraging
unsolicited takeover proposals. The rights issued under the stockholder rights
plan would cause substantial dilution to a person or group that attempts to
acquire us on terms not approved in advance by our board of directors. In
addition, our articles of incorporation and bylaws contain provisions that may
discourage unsolicited takeover proposals that stockholders may consider to be
in their best interests that include:
o provisions that members of the board of directors are elected and retire in
rotation; and
o the ability of the board of directors to designate the terms of, and to
issue new series of, preferred shares.
Together, these provisions and our stockholder rights plan may discourage
transactions that otherwise could involve payment to you of a premium over
prevailing market prices for your common shares.
Our common stock price has been extremely volatile and may continue to be.
Our common stock has traded as low as $3.87 and as high as $13.37 between
January 1, 1998 and July 10, 2000. Some of the factors leading to this
volatility include:
o the outcome of individual wells or the timing of exploration efforts in
Poland, as evidenced by significant price declines following the
announcement of exploratory dry holes in Poland and the significant price
and volume volatility following the announcement of our first successful
exploratory well in Poland;
o the results of other operations in which we have an interest in Poland;
o the potential sale by us of newly issued common stock to raise capital or
by existing stockholders of restricted securities;
o price and volume fluctuations in the general securities markets that are
unrelated to our results of operations;
o the investment community's view of companies with assets and operations
outside the United States in general and in Poland in particular;
o actions or announcements by Apache and POGC that may affect us;
o prevailing world prices for oil and gas;
o the potential of our current and planned activities in Poland; and
o changes in stock market analysts' recommendations respecting us, other oil
and gas companies or the oil and gas industry in general.
We may encounter additional exploration failures in Poland that will adversely
affect the trading prices for our common stock.
11
Forward-Looking Statements
This prospectus 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. Statements that describe our future strategic plans,
goals or objectives are also forward-looking statements. Any forward-looking
statements, including those regarding our or our management's current beliefs,
expectations, anticipations, estimations, projections, proposals, plans or
intentions, are not guarantees of future performance or results or events and
involve risks and uncertainties, such as those discussed in this prospectus.
The forward-looking statements are 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 and timing than 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 discussed in this prospectus. These cautionary statements are
intended to be applicable to all related forward-looking statements wherever
they appear in this prospectus. Any forward-looking statements are made only as
of the date of this prospectus, and we assume no obligation to update
forward-looking statements to reflect subsequent events or circumstances. We
intend any forward-looking statements to be covered by the safe harbor
provisions contained in Section 27A of the Securities Act and Section 21E of the
Exchange Act.
12
Price Range of Common Stock and Dividend Policy
The following table sets forth for the periods indicated the high and low
closing prices for our common stock as quoted under the symbol "FXEN" on the
Nasdaq National Market:
High Low
----------- ---------
1998:
First Quarter.................................... $10.50 $6.25
Second Quarter................................... 12.81 8.25
Third Quarter.................................... 9.50 5.63
Fourth Quarter................................... 10.13 6.50
1999:
First Quarter.................................... $ 9.75 $4.00
Second Quarter................................... 7.00 4.13
Third Quarter.................................... 9.43 6.31
Fourth Quarter................................... 7.00 4.00
2000:
First Quarter.................................... $ 9.13 $4.66
Second Quarter (through July 10)................. 8.31 4.44
On July 10, 2000, the closing price per share of our common stock on the Nasdaq
National Market was $5.06. As of July 10, 2000, there were approximately 4,200
beneficial owners of our common stock.
We have never paid cash dividends on our common stock and do not anticipate that
we will pay dividends in the foreseeable future. We intend to reinvest any
future earnings to further expand our business.
No Net Proceeds to Us
We will receive no proceeds from the sale of stock by the selling stockholders.
13
Capitalization
The following table sets forth as of March 31, 2000, our historical
capitalization, as adjusted to reflect the subsequent sale of 2,969,000 shares
to the selling stockholders in June 2000 for net proceeds of approximately $9.3
million ($10.4 million gross), but not adjusted to reflect any other changes to
our financial condition since that date.
This information should be read in conjunction with our consolidated financial
statements and related notes included elsewhere in this prospectus.
March 31, 2000
---------------------------
Actual As adjusted
-------------- -----------
(Unaudited, in thousands)
Long-term debt.................................................................. -- --
Stockholders' equity
Common stock, $.001 par value, 30,000,000 shares authorized. Issued and
outstanding: 14,849,003 shares as of March 31, 2000 and 17,818,003 as
adjusted..................................................................... $ 15 $ 18
Notes receivable from officers............................................... (1,400) (1,400)
Additional paid-in capital................................................... 38,481 47,778
Accumulated deficit.......................................................... (29,495) (29,495)
-------------- -----------
Total stockholders' equity................................................ 7,601 16,901
-------------- -----------
Total capitalization...................................................... $ 7,601 $16,901
============== ===========
The number of outstanding shares shown above excludes an aggregate of 4,146,167
shares that may be issued on the exercise of options and warrants outstanding as
of March 31, 2000.
14
Dilution
Our net tangible book value on March 31, 2000, as adjusted to reflect the
subsequent sale of 2,969,000 shares for net proceeds of approximately $9.3
million, but not adjusted to reflect any other changes in our financial
condition since that date, was approximately $16.9 million or $0.95 per share.
"Net tangible book value" is total assets minus the sum of liabilities and
intangible assets. "Net tangible book value per share" is net tangible book
value divided by the total number of shares outstanding before the offering.
The following table illustrates the dilution, or the difference between the
offering price per share, assuming an offering price equivalent to the trading
price on July 10, 2000, and the adjusted net tangible book value per share on
March 31, 2000.
Trading price on Ju1y 10, 2000................................................................ $5.06
Net tangible book value per share as of March 31, 2000, as adjusted to reflect subsequent
sale of 2,969,000 shares.................................................................. 0.63
----------
Dilution per share to purchasers in this offering............................................. $4.43
==========
15
Selected Consolidated Financial Data
The following consolidated financial data for each of the five fiscal years in
the period ended December 31, 1999, are derived from our audited consolidated
financial statements and related notes thereto, certain of which are included in
this prospectus. The historical financial information for the three months ended
March 31, 2000 and 1999, and as of March 31, 2000, was derived from our
unaudited consolidated financial statements, which also are included in this
prospectus. All amounts are in thousands, except per share amounts.
Three Months Ended
March 31, Years Ended December 31,
--------------------- ------------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
- ------------------------------------------------------------- ------------------------------------------------------
Statement of Operations Data
Revenues:
Oil sales........................... $ 597 $ 234 $ 1,554 $ 1,124 $ 2,040 $ 2,346 $ 1,981
Drilling revenue.................... 73 88 865 323 496 75 111
Gain on sale of property interests.. -- -- -- 467 272 -- 75
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total revenues.................... 670 322 2,419 1,914 2,808 2,421 2,167
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Costs and Expenses:
Lease operating costs (1)........... 292 252 962 1,046 1,239 1,225 1,272
Exploration costs (2)............... 484 180 3,053 2,127 5,314 3,716 862
Producing property impairment....... -- -- -- 5,885 -- -- --
Drilling costs...................... 75 53 642 240 329 154 141
Depreciation, depletion and
amortization...................... 87 126 494 672 635 558 503
General and administrative.......... 597 536 2,962 2,572 2,566 1,715 1,466
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating costs and expenses 1,535 1,147 8,113 12,542 10,083 7,368 4,244
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating loss........................ (865) (825) (5,694) (10,628) (7,275) (4,947) (2,077)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Other income (expense):
Interest and other income........... 134 102 511 506 662 370 98
Interest expense.................... -- -- (7) -- (83) (333) (448)
Impairment of notes receivable from
officers.......................... (5) -- (666) -- -- -- --
Minority interest: noncash
dividends (3)..................... -- -- -- -- -- -- (93)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total other income (expense)...... 129 102 (162) 506 579 37 (443)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net loss before extraordinary gain.... (736) (723) (5,856) (10,122) (6,696) (4,910) (2,520)
Extraordinary gain.................. -- -- -- -- 3,076 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net loss.............................. $ (736) $ (723) $ (5,856) $(10,122) $ (3,620) $ (4,910) $ (2,520)
========== ========== ========== ========== ========== ========== ==========
Basic and diluted net loss per share:
Net loss before extraordinary gain.. $ (0.05) $ (0.06) $ (0.41) $ (0.78) $ (0.53) $ (0.49) $ (0.47)
Extraordinary gain.................. -- -- -- -- 0.24 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net loss:......................... $ (0.05) $ (0.06) $ (0.41) $ (0.78) $ (0.29) $ (0.49) $ (0.47)
========== ========== ========== ========== ========== ========== ==========
Basic and diluted weighted average
shares outstanding:.................. 14,849 13,055 14,199 12,979 12,597 10,018 5,389
========== ========== ========== ========== ========== ========== ==========
16
Three Months Ended
March 31, Years Ended December 31,
--------------------- ------------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Flow Statement Data
Net cash used in operating activities... $(1,008) $(720) $(3,745) $(3,109) $(5,881) $(3,651) $ (1,030)
Net cash provided by (used in) investing
activities.......................... 2,643 (54) (2,916) 1,083 368 (7,005) (1,489)
Net cash provided by (used in) financing
activities.......................... -- -- 6,469 (674) 1,679 18,259 2,974
As of December 31,
------------------------------------------------------
As of March 31, 2000 1999 1998 1997 1996 1995
--------------------- ---------- ---------- ---------- ---------- ----------
Balance Sheet Data (Actual)
Working capital (deficit)........... $4,092 $ 5,459 $ 3,965 $ 8,494 $ 13,843 $ (278)
Total assets........................ 9,433 10,470 8,253 18,555 2,294 10,039
Long-term debt...................... -- -- -- -- 1,500 3,359
Stockholders' equity................ 7,601 8,367 6,920 17,612 20,908 5,224
(1) Includes lease operating expenses and production taxes.
(2) Includes geophysical and geological costs, exploratory dry hole costs and
nonproducing leasehold impairments.
(3) Noncash dividend on FX Producing convertible preferred stock.
17
Management's Discussion and Analysis of Financial Condition
and Results of Operations
You should read the following discussion and analysis in conjunction with our
consolidated financial statements included in this prospectus. The following
information contains forward-looking statements. See "Forward-Looking
Statements." Our activities are subject to significant risks. See "Risk
Factors."
Overview
We are an independent energy company engaged in the exploration, development and
production of oil and gas from properties located primarily in the Republic of
Poland. However, to date, all of our revenue from oil and gas production has
been from our United States producing properties. In the western United States,
we produce oil from fields in Montana and Nevada and have a drilling and well
servicing company in northern Montana and oil and gas exploration prospects in
several western states.
We conduct substantially all of our exploration and development activities in
Poland jointly with others and, accordingly, recorded amounts for our activities
in Poland reflect only our proportionate interest in these activities.
Our results of operations may vary significantly from year to year based on the
factors discussed in "Risk Factors" above and on other factors such as our
exploratory and development drilling success. Therefore, the results of any one
year may not be indicative of future results.
We follow the successful efforts method of accounting for our oil and gas
properties. Under this method of accounting, all property acquisition costs and
costs of exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves. If an
exploratory well has not found proved reserves, 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 revenues determined on a property-by-property basis. The
impairment loss recognized equals the excess of net capitalized costs over the
related fair value, determined on a property-by-property basis. As a result of
the foregoing, our results of operations for any particular period may not be
indicative of the results that could be expected over longer periods.
We have reviewed all recently issued, but not yet adopted, accounting standards
in order to determine their effects, if any, on our results of operations or
financial position. Based on that review, we believe that none of these
pronouncements will have a significant effect on current or future earnings or
operations.
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: exploration and
production and contract servicing. Depreciation, depletion and amortization
costs directly associated with the exploration and production and contract
servicing segments are detailed within the following discussion. General and
administrative costs, interest income, other income, interest expense and
officer loan impairment are not allocated to individual operating segments for
management or segment reporting purposes and are discussed in their entirety
following the segment discussion.
18
Three months ended March 31, 2000 compared to the three months ended March
31, 1999
Exploration and Production Segment
Oil Revenues. Oil revenues were $597,000 during the first quarter of 2000, an
increase of $363,000, as compared to $234,000 during the same period of 1999.
During the first quarter of 2000, our oil revenues were positively affected by
higher oil prices and negatively affected by lower production rates attributable
to the natural production declines of our producing properties. During the first
quarter of 1999, our oil revenues were adversely affected by depressed oil
prices and lower production rates attributable to the natural production
declines of our producing properties. A summary of the percentage change in oil
revenues, average oil price and oil production for first quarter of 2000 and
1999, as compared to their respective prior year's period, is set forth on the
following table:
Quarter ended March 31,
--------------------------------------
2000 1999
------------------ ------------------
Oil revenues............................................................... $597,000 $234,000
Percent change versus prior year's quarter............................... +155% -30%
Average oil price.......................................................... $ 24.94 $ 8.80
Percent change versus prior year's quarter............................... +184% -22%
Production volumes (Bbls).................................................. 23,924 26,572
Percent change versus prior year's quarter............................... -10% -10%
Lease Operating Costs. Our lease operating costs are composed of normal
recurring lease operating expenses and production taxes. Lease operating costs
were $292,000 during the first quarter of 2000, an increase of $42,000, as
compared to $250,000 during the same period of 1999.
Lease operating expense was $285,000 during the first quarter of 2000, an
increase of $49,000, as compared to $236,000 during the same period of 1999.
During the first quarter of 2000, we increased our lease operating expense to
cover various repair and maintenance items that were previously deferred due to
low oil prices. As a result, lifting costs were $11.91 per barrel during the
first quarter of 2000, an increase of $3.03, as compared to $8.88 during the
first quarter of 1999. During the first quarter of 1999, we reduced our lease
operating expense by redesigning the pattern of injecting fluids into the Cut
Bank Sand Unit, our principal producing property, and deferred major repairs and
maintenance items due to depressed oil prices.
Production taxes were $7,000 during the first quarter of 2000, a decrease of
$7,000, as compared to $14,000 during the same period of 1999. Production taxes
averaged approximately 1.2% and 6.1% of oil revenues during the first quarters
of 2000 and 1999, respectively. During late 1999, the state of Montana
substantially reduced the production tax rate for stripper wells, which in turn
resulted in substantially less production taxes for the first quarter of 2000,
as compared to the same period of 1999.
Depreciation, Depletion and Amortization Expense - Exploration and Production.
Depreciation, depletion and amortization expense for producing properties was
$16,000 for the first quarter of 2000, an increase of $2,000, as compared to
$14,000 during the same period of 1999. The depreciation, depletion and
amortization expense rate per barrel for the first quarter of 2000 was $0.67, an
increase of $0.14, as compared to $0.53 during the same period of 1999. We
utilize the units-of-production method to calculate our depreciation, depletion
and amortization expense for producing properties. As such, the depreciation,
depletion and amortization expense rate may vary year to year based on net
capitalized costs and the volumes of reserves reported in the current year's
reserve report, as compared to the prior year. The reserve report as of December
31, 1999 reflected proved reserves of 1.1 million barrels of oil, 0.4 million
barrels less than the 1.5 million barrels of oil reported as of December 31,
1998.
Exploration Costs. Our exploration costs consist of geological and geophysical
costs, exploratory dry holes and nonproducing leasehold impairments. Exploration
costs were $484,000 during the first quarter of 2000, an increase of $304,000,
as compared to $180,000 during the same period of 1999.
19
Geological and geophysical costs were $484,000 during the first quarter of 2000,
an increase of $304,000, as compared to $180,000 during the same period of 1999.
During the first quarter of 2000, we spent $162,000 reprocessing seismic data on
the Pomeranian project area, $108,000 reprocessing seismic data on the Warsaw
West project area, $74,000 for travel and related expenses and $140,000 on other
geological and geophysical activities. During the first quarter of 1999,
geological and geophysical costs were comprised primarily of $75,000 for the
Polish Lowlands Study, $65,000 for travel and related expenses and $40,000 for
other geological and geophysical activities. Geological and geophysical costs
will continue to fluctuate from period to period, based on our level of
exploratory activity in Poland and the respective cost participation percentage
of our industry partners.
We had no exploratory dry hole costs during the first quarters of 2000 and 1999.
During late 1998, we participated in drilling two exploratory dry holes, the
Czernic 277-2 and the Poniatowa 317-1, on the Lublin Basin project area in
Poland, both of which were subsequently determined to be exploratory dry holes
during February 1999. The Czernic 277-2 and the Poniatowa 317-1 were each
counted as exploratory wells under the Apache Exploration Program. As such,
Apache covered all of our pro rata share of costs for each well.
There were no nonproducing leasehold impairments during the first quarters of
2000 and 1999. As of March 31, 2000, we had capitalized unproved property costs
of $1.399 million, including $692,000 domestically and $707,000 in Poland. In
accordance with generally accepted accounting principles, an impairment charge
will be recognized, determined on a property-by-property basis, in the event we
determine any capitalized unproved property costs are not recoverable following
unsuccessful exploratory drilling or other factors. Nonproducing leasehold
impairments will continue to vary from period to period based on our
determination that capitalized costs of unproved properties, on a
property-by-property basis, are not realizable.
Contract Servicing Segment
Contract Servicing Revenues. We had contract servicing revenues of $74,000
during the first quarter of 2000, a decrease of $14,000, as compared to $88,000
for the first quarter of 1999. During the first quarters of 2000 and 1999, our
drilling rig was idle, and all revenues were generated by our well servicing
equipment. Contract servicing revenue will continue to fluctuate from period to
period based on whether our drilling rig is active, the degree of emphasis on
utilizing equipment on our own properties, the number of wells drilled, the
amount of retained working interest, if any, and other factors.
Contract Servicing Costs. Contract servicing costs were $75,000 during the first
quarter of 2000, an increase of $22,000, as compared to $53,000 for the same
period of 1999. During the first quarter of 2000, our well and servicing
equipment generated a gross profit of 25% on direct costs of $55,000 and
incurred downtime maintenance costs of $20,000 associated with our drilling rig.
During the first quarter of 1999, our well and servicing equipment generated a
gross profit of 39% on direct costs of $53,000, and the drilling rig was idle.
Contract servicing costs will continue to fluctuate from period to period based
on whether our drilling rig is active, the degree of emphasis on utilizing
equipment on our own properties, the number of wells drilled, the amount of
retained working interest, if any, and other factors.
Depreciation, Depletion and Amortization Expense - Contract Servicing.
Depreciation, depletion and amortization expense for contract servicing was
$51,000 during the first quarter of 2000, a decrease of $30,000, as compared to
$81,000 during the same period of 1999. Depreciation, depletion and amortization
expense for contract servicing was lower during the first quarter of 2000, as
compared to the same quarter of 1999, due to capital items being depreciated in
the first quarter of 1999 subsequently becoming fully depreciated prior to the
first quarter of 2000.
Nonsegmented Information
Depreciation, Depletion and Amortization Expense - Corporate. Depreciation,
depletion and amortization expense for corporate activities was $20,000 during
the first quarter of 2000, a decrease of $11,000, as compared to $31,000 during
the same period of 1999. Depreciation, depletion and amortization expense for
corporate activities was lower during the first quarter of 2000, as compared to
the same quarter of 1999, due to capital items being depreciated in the first
quarter of 1999 subsequently becoming fully depreciated prior to the first
quarter of 2000.
20
General and Administrative Costs. General and administrative costs were $597,000
during the first quarter of 2000, an increase of $61,000, as compared to
$536,000 for the same period of 1999. During the first quarter of 2000, we
incurred substantially more travel and other associated costs, as compared to
the same period of 1999. General and administrative costs are expected to be
higher in future periods as we begin to pay for part of our pro rata share of
Apache's general and administrative costs in Poland beginning in July 2000.
Interest and Other Income. Interest and other income was $134,000 during the
first quarter of 2000, an increase of $32,000, as compared to $102,000 during
the same period of 1999. Our cash and marketable debt securities balance was
$5.346 million as of March 31, 2000, $1.499 million more than the balance of
$3.847 million as of March 31, 1999. As a result of higher average cash and
marketable debt securities balances during the first quarter of 2000, as
compared to the same period of 1999, we earned $126,000 of interest income
during the first quarter of 2000, an increase of $34,000, as compared to $92,000
for the same period of 1999.
Officer Loan Impairment. Officer loan impairment was $5,000 for the quarter
ended March 31, 2000, as compared to no officer loan impairment for the same
period of 1999. In accordance with Statement of Financial Accounting Standards
No. 114, "Accounting by Creditors for Impairment of a Loan," we recorded an
additional impairment allowance of $5,000 for the quarter ended March 31, 2000.
The notes receivable from officers totaled $1.4 million as of March 31, 2000,
including principal and interest of $2.07 million, reduced by an impairment
allowance of $670,000. The notes receivable from officers are collateralized by
233,340 shares of our common stock. The impairment allowance will continue to be
adjusted quarterly based on the market value of the collateral shares.
Comparison of years ended December 31, 1999, 1998 and 1997
Exploration and Production Segment
Oil Revenues. Oil revenues were $1.554 million, $1.124 million and $2.04 million
for the years ended December 31, 1999, 1998 and 1997, respectively. During these
three years, our oil revenues fluctuated primarily due to volatile oil prices.
Our oil revenues during three years were also negatively affected by lower
production rates attributable to the natural production declines of our
producing properties and the increased utilization of our well servicing
equipment on third-party properties rather than our own properties during 1998
and 1999. A summary of the percentage change in oil revenues, average oil price
and oil production for 1999, 1998 and 1997, as compared to their respective
prior year, is set forth on the following table:
Year Ended December 31,
------------------------------------------------------
1999 1998 1997
----------------- ----------------- -----------------
Oil revenues................................................. $1,554,000 $1,124,000 $2,040,000
Percent change versus prior year........................... +38.26% -44.90% -13.04%
Average oil price............................................ $ 15.35 $ 9.78 $ 16.16
Percent change versus prior year........................... +56.95% -39.48% -10.42%
Production volumes (Bbls).................................... 101,275 114,909 126,271
Percent change versus prior year........................... -11.87% -9.00% -2.88%
Gain on Sale of Property Interests. There was no gain on sale of property
interests for the year ended December 31, 1999. We recognized a gain on sale of
property interests of $467,000 and $272,000 for the years ended December 31,
1998 and 1997, respectively. During 1998, Apache paid us $500,000 in initial
cash consideration relating to our participation in the Carpathian project area,
which was offset by $33,000 of associated costs. During 1997, we received
$450,000 from Apache in initial cash consideration relating to our participation
in the Lublin Basin project area, which was offset by $344,000 of associated
costs and $95,000 from the purchase of Lubex Petroleum Company, a wholly-owned
Polish exploration subsidiary. The 1997 gain on sale of property interests also
includes $71,000 relating to our mining operations, which are excluded from the
discussion of the results of operations by business segment. The amount of gain
on sale of property interests will continue to vary from year to year, depending
on the timing of completed deals and the amount of up-front cash consideration,
if any.
21
Lease Operating Costs. Lease operating costs were $962,000, $1.046 million and
$1.239 million for the years ended December 31, 1999, 1998 and 1997,
respectively, or $9.50, $9.11 and $9.82, respectively, per barrel.
Lease operating expenses were $899,000, $966,000 and $1.094 million for the
years ended December 31, 1999, 1998 and 1997, respectively. During these years,
we performed only routine maintenance on our producing properties and deferred
workovers in an effort to control operating costs. Lifting costs per barrel
(exclusive of production taxes) were relatively flat during 1999, 1998 and 1997,
amounting to $8.88, $8.41 and $8.66 per barrel, respectively.
Production taxes were $63,000, $80,000 and $145,000 for the years ended December
31, 1999, 1998 and 1997, respectively. During 1999, production taxes decreased
to an average of approximately 4.1% of annual oil revenues, as compared to 7.0%
during 1998 and 1997, primarily due to a reduction in the production tax rate on
stripper wells by the state of Montana. The decrease in the amount of production
taxes from year to year is also directly associated with the fluctuation of oil
prices and decreased oil production from year to year. Refer to the table in
"Exploration and Production Segment- Oil Revenues" for the percentage
fluctuations in the average oil price and oil production for 1999, 1998 and
1997.
Depreciation, Depletion and Amortization Expense - Producing Operations.
Depreciation, depletion and amortization expenses for producing properties were
$51,000, $231,000 and $261,000 for the years ended December 31, 1999, 1998 and
1997, respectively. The depreciation, depletion and amortization expense rate
per barrel was $0.50 during 1999, a decrease of $1.51, as compared to 1998. The
decrease is directly attributable to the $5,885,000 write down of our domestic
proved developed oil and gas properties during 1998, which resulted in a
substantially lower depreciable property basis during 1999. The depreciation,
depletion and amortization expense rate per barrel was relatively constant at
$2.01 and $2.07 for 1998 and 1997, respectively.
Domestic Proved Property Impairment. There were no proved domestic proved
property impairments for the years ended December 31, 1999 or 1997. For the year
ended December 31, 1998, we incurred a domestic proved developed property
impairment of $5.885 million due to low oil prices and our decision to focus our
resources on Poland. As of December 31, 1998, our PV-10 value for our domestic
proved properties was approximately $472,000, consisting solely of proved
developed reserves. In accordance with generally accepted accounting principles,
we recorded total impairment expense of $5.885 million for the year ended
December 31, 1998, which represented the difference between the net book value
of our domestic proved developed properties and the related fair value,
determined on a property-by property basis, as of December 31, 1998.
Exploration Costs. Exploration costs were $3.053 million, $2.127 million and
$5.314 million for the years ended December 31, 1999, 1998 and 1997,
respectively. Geological and geophysical costs of $31,000 and $29,000 incurred
during the years ended December 31, 1999 and 1998, respectively, relate to gold
exploration in Poland, which management does not consider to be a material
business segment. Accordingly, gold exploration is excluded from the following
discussion.
Geological and geophysical costs were $1.928 million, $2.08 million and $1.684
million during the years ended December 31, 1999, 1998 and 1997, respectively.
During 1999, we spent approximately $310,000 reprocessing seismic data on the
Pomeranian and Warsaw West project areas, granted stock options valued at
approximately $119,000 to a Polish consultant and spent approximately $374,000
evaluating potential property acquisitions from POGC. During 1998, we incurred
approximately $400,000 of cost relating to our share of the Lublin Basin project
area seismic acquisition program with Apache and $75,000 relating to a
geological and geophysical study. During 1997, we completed a seismic survey on
Wola, a POGC Concession in the Carpathian project area, costing $210,000. From
January 1, 1997 through December 31, 1999, we spent an average amount of
approximately $1.402 million annually relating to reprocessing 2-D seismic data
and the wages and associated expenses for employees and consultants directly
engaged in geological and geophysical activities. Geological and geophysical
costs are expected to continue at current or higher levels as we increase our
exploratory efforts in Poland and continue to spend a limited amount on our
exploratory acreage in the western United States.
22
Exploratory dry hole costs were $1.001 million, $17,000 and $3.478 million for
the years ended December 31, 1999, 1998 and 1997, respectively. During 1999, we
participated in drilling three exploratory dry holes in Poland. Two of these
wells were exploratory wells under the Apache Exploration Program. As such,
Apache covered all of our pro rata share of costs for these wells. We retained
and paid for a 5% interest in the Andrychow 6 well, an exploratory dry hole on
the Carpathian project area of southern Poland, which cost $99,000. On the
Lachowice Farm-in, we spent $869,000 to recomplete one well and test another.
Also, during 1999, we spent $33,000 associated with an exploratory dry hole
drilled during 1997. During 1998, we participated in drilling two exploratory
dry holes in Poland on the Lublin Basin project area. Both wells were plugged
and abandoned during the first quarter of 1999 and counted as exploratory wells
under the Apache Exploration Program. As such, Apache covered all of our pro
rata share of costs for each well. All of the exploratory dry hole costs
recorded during 1998 were associated with wells drilled prior to 1998. During
1997, we drilled four exploratory dry holes; two in Poland and two in the
western United States. In Poland, we drilled two wells in the Baltic project
area, both of which were exploratory dry holes, at a cost of $3.096 million. In
the western United States, we drilled one well in central Montana at a cost of
$222,000 and one in Nevada at a cost of $160,000.
Nonproducing leasehold impairments were $93,000 and $152,000 for the years ended
December 31, 1999 and 1997. There were no nonproducing leasehold impairments
during the year ended December 31, 1998. During 1999, we wrote off $72,000
relating to the Lachowice Farm-in and $21,000 pertaining to a prospect in
Nevada. During 1997, we wrote off $45,000 relating to a prospect in central
Montana, $78,000 relating to a prospect in Nevada and $29,000 relating to a
prospect in Wyoming. Nonproducing leasehold impairments will vary from period to
period based on our determination that capitalized costs of unproved properties,
on a property-by property basis, are not realizable.
Extraordinary Gain - Baltic Project Area. There were no extraordinary gains
during the years ended December 31, 1999 and 1998, respectively, as compared to
$3.076 million for the year ended December 31, 1997. As of December 31, 1996, we
had $1.5 million of long-term debt associated with advances received from
RWE-DEA relating to RWE-DEA's commitment to earn a 50% interest in our Baltic
project area. During 1997, RWE-DEA advanced us an additional $1.576 million,
bringing the total amount of such advances to $3.076 million, all of which we
recorded as notes payable prior to the Polish government approving RWE-DEA's
participation in our Baltic project area. On June 30, 1997, after the Polish
government had approved RWE-DEA's participation in the Baltic project area,
RWE-DEA elected not to earn an interest in our Baltic project area. We were not
contractually obligated to repay any funds previously advanced by RWE-DEA.
Accordingly, we eliminated the long-term debt associated with the RWE-DEA
advances and recognized an extraordinary gain of $3.076 million for the year
ended December 31, 1997.
Contract Servicing Operations
Contract Servicing Revenues. Contract servicing revenues were $865,000, $323,000
and $496,000 for the years ended December 31, 1999, 1998 and 1997, respectively.
During 1999, we focused our drilling and well servicing equipment on third-party
contract servicing in an effort to increase our domestic revenues rather than
utilizing our drilling and well servicing equipment on company-owned properties.
During 1998, our contract servicing revenues consisted of $262,000 from
third-party contract drilling and well servicing work conducted in the third and
fourth quarters as we began to shift the primary focus of utilizing our drilling
and well servicing equipment from our own properties to third-party contract
servicing. During 1997, we drilled two wells on a day work contract basis
resulting in contract servicing revenues of $496,000 and a gross profit before
depreciation, depletion and amortization costs of $167,000. We retained a
working interest in each of the two wells drilled. The $167,000 gross operating
profit before depreciation, depletion and amortization costs helped offset the
combined working interest cost of $242,000 that we incurred on the two wells.
Contract servicing revenues will continue to fluctuate year to year based on the
number, timing, retained working interest of wells drilled and the degree of
emphasis on utilizing drilling and well servicing equipment on our company-owned
properties.
Contract Servicing Costs. Contract servicing costs were $642,000, $240,000 and
$329,000 for the years ended December 31, 1999, 1998 and 1997, respectively.
During these years, contract servicing costs were 74.2%, 74.4% and 66.3% of
contract servicing revenues, respectively. Contract servicing costs are directly
associated with
23
contract servicing revenues. As such, contract servicing costs will continue to
fluctuate year to year based on revenues generated, the number of wells drilled,
timing and the degree of emphasis on utilizing drilling and well servicing
equipment on our own properties.
Depreciation, Depletion and Amortization Expense - Contract Servicing.
Depreciation, depletion and amortization expenses for contract servicing were
$334,000, $322,000 and $289,000 for the years ended December 31, 1999, 1998 and
1997, respectively. We spent $138,000, $156,000 and $210,000 on upgrading our
drilling and well servicing equipment during 1999, 1998 and 1997, respectively.
Depreciation, depletion and amortization expenses were progressively higher year
to year due to prior year capital additions being depreciated in succeeding
years.
Nonsegmented Information
Depreciation, Depletion and Amortization Expense - Corporate. Depreciation,
depletion and amortization expenses for corporate activities were $110,000,
$118,000 and $85,000 for the years ended December 31, 1999, 1998 and 1997,
respectively. Depreciation, depletion and amortization expenses during 1999 were
$8,000 less, as compared to the same period of 1998, primarily due to less
capital additions during 1999, coupled with equipment purchased during 1996 and
1997 becoming fully depreciated during 1999. We spent $20,000, $85,000 and
$205,000 during 1999, 1998 and 1997, respectively, on software, hardware and
office equipment utilized primarily for corporate purposes.
General and Administrative Costs. General and administrative costs were $2.962
million, $2.572 million and $2.566 million for the years ended December 31,
1999, 1998 and 1997, respectively. During 1999, general and administrative costs
were $390,000 higher, as compared to the same period of 1998, due to higher
payroll and other related costs associated with our increasing emphasis on
expanding our activities in Poland. General and administrative costs incurred
during 1998 were substantially unchanged as compared to 1997. General and
administrative costs are expected to be higher in future periods as we begin to
pay for part of our pro rata share of Apache's general and administrative costs
in Poland beginning in July 2000.
Interest and Other Income. Interest and other income were $512,000, $506,000 and
$662,000 for the years ended December 31, 1999, 1998 and 1997, respectively. Our
cash, cash equivalent and marketable debt securities balances were $6.868
million, $4.742 million and $8.453 million as of December 31, 1999, 1998 and
1997, respectively. The average cash and marketable securities balances during
1999 were relatively unchanged, as compared to the same period of 1998. Interest
and other income were lower in 1998, as compared to 1997, due to lower average
cash and marketable debt security balances during 1998, as compared to the same
period of 1997. We earned interest income of $499,000, $492,000 and $616,000
during 1999, 1998 and 1997, respectively. Interest income associated with
officers' notes receivable was $134,000 and $64,000 during 1999 and 1998,
respectively.
Interest Expense. Interest expense was $8,000 and $83,000 for the years ended
December 31, 1999 and 1997, respectively. We had no interest expense for the
year ended December 31, 1998. During 1999, we incurred $8,000 of interest
expense primarily relating to the settlement of an audit by the Blackfeet Tribe
pertaining to the Cut Bank Field. During 1997, we incurred interest expense of
$83,000. We had long-term debt associated with RWE-DEA of $1.5 million as of
December 31, 1996 and received $1.576 million in additional funding from RWE-DEA
during the first six months of 1997, all of which was recorded as long-term
debt. However, upon RWE-DEA's election not to earn an interest in the Baltic
project area on June 30, 1997, we eliminated our long-term debt associated with
RWE-DEA and recognized an extraordinary gain of $3.076 million. As of December
31, 1999 and 1998, we had no long-term debt.
Officer Loan Impairment. As of December 31, 1999, notes receivable and accrued
interest from officers, before impairment, totaled $2.036 million, with a due
date of on or before December 31, 2000 (as extended). The notes receivable and
accrued interest are collateralized by 233,340 shares of our common stock. In
accordance with SFAS No. 114, "Accounting by Creditors for Impairment of a
Loan," we recorded an impairment allowance of $666,000 as of December 31, 1999,
based on the value of the underlying collateral. The impairment allowance will
be adjusted quarterly based on the market value of the collateral shares.
24
Income Taxes. We incurred net losses after extraordinary gains of $5.856
million, $10.122 million and $3.62 million for the years ended December 31,
1999, 1998 and 1997, respectively, which can be carried forward to offset future
taxable income. SFAS No. 109 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 tax benefit in our consolidated
statement of operations for these years.
Net Loss. We incurred net losses of $5.856 million, $10.122 million and $3.62
million for the years ended December 31, 1999, 1998 and 1997, respectively. The
net loss in 1999 was due principally to $3.054 million of exploration costs, an
officer loan impairment of $666,000 and $2.962 million of general and
administrative costs. The net loss in 1998 was due principally to a domestic
proved property impairment of $5.885 million, geological and geophysical costs
of $2.109 million and a 44.9% decline in oil prices coupled with a 9.0% decline
in oil production. The net loss in 1997 was due principally to geological and
geophysical costs of $1,684,000, an exploratory dry hole costing $1,262,000
drilled without an outside partner and leasehold impairments of $152,000.
Liquidity and Capital Resources
Historically, we have relied primarily on proceeds from the sale of equity
securities to fund our operating and investing activities. During 1999, 1998 and
1997, we received net proceeds of $7.067 million, $166,000 and $253,000,
respectively, from the sale of our common stock. In June 2000, we received net
proceeds of approximately $9.3 million ($10.4 million gross) from the sale of
2,969,000 shares of our common stock in private transactions. We also benefit
from funds provided by industry partners.
Working Capital
We had working capital of $5.459 million, $3.965 million and $8.494 million as
of December 31, 1999, 1998 and 1997, respectively. Working capital as of
December 31, 1999 was $1.494 million higher, as compared to the end of 1998,
primarily due to net proceeds of $7.067 million from the private placement of
1,792,500 shares and the exercise of options to purchase 2,000 shares of common
stock, which was offset by a $5.856 million net loss during 1999. Working
capital as of December 31, 1998 was $4.529 million lower, as compared to the end
of 1997, primarily due to cash used in operating and financing activities of
$3.783 million and additions to properties of $441,000 during 1998.
Our working capital was $4.092 million as of March 31, 2000, a decrease of
$1.367 million, as compared to $5.459 million at December 31, 1999. The decrease
was due principally to a net loss before depreciation, depletion and
amortization costs of $649,000 and net additions to property and equipment of
$645,000 during the first quarter of 2000. Our working capital has increased
significantly since March 31, 2000, as a result of the sale of 2,969,000 shares
of our common stock for net proceeds of $9.3 million ($10.4 million gross)
during June 2000.
Operating Activities
We used net cash of $3.745 million, $3.109 million, and $5.881 million in our
operating activities during 1999, 1998 and 1997, respectively, primarily as a
result of the net losses incurred in those years. During 1999, 1998 and 1997, we
spent $4.195 million, $3.978 million, and $6.024 million, respectively, on
operating activities exclusive of working capital adjustments. Working capital
adjustments reduced cash used in operating activities by $450,000, $869,000 and
$143,000 during 1999, 1998 and 1997, respectively.
Net cash used in operating activities was $1.008 million during the first
quarter of 2000, an increase of $288,000, as compared to $720,000 for the same
period of 1999. We used net cash in operating activities before changes in
working capital items of $678,000 and $624,000 during the first quarters of 2000
and 1999, respectively. Cash used to fund changes in working capital items was
$330,000 and $96,000 during the first quarters of 2000 and 1999, respectively.
25
Investing Activities
We used net cash of $2.916 million in investing activities during 1999, and
received net cash from investing activities of $1.083 million and $368,000
during 1998 and 1997, respectively. During 1999, we spent $603,000 on additions
to properties, equipment and other assets, received $6,000 from the sale of
property interests and spent a net amount of $2.319 million relating to
investing in marketable debt securities. During 1998, we spent $441,000 on
additions to properties and equipment, received $513,000 of proceeds from the
sale of property interests and equipment and received a net amount of $1.011
million relating to investing in marketable debt securities. During 1997, we
spent a net amount of $1.506 million on additions to properties and other
assets, received $353,000 from the sale of property interests and equipment,
advanced an employee $15,000 in relocation costs and received a net amount of
$1.536 million relating to investing in marketable debt securities.
Our investing activities provided net cash of $2.643 million during the first
quarter of 2000, as compared to using net cash of $54,000 during the same period
of 1999. During the first quarter of 2000, we spent $322,000 on drilling the
Wilga 3 well in Poland, $44,000 to upgrade our domestic properties, $16,000 on
annual concession fees for the Baltic project area in Poland, $16,000 on office
equipment and a net amount of $116,000 to upgrade our drilling and well
servicing equipment and realized a net amount of $3.157 million from investing
in marketable debt securities. During the first quarter of 1999, we spent
$31,000 on upgrading our producing properties, spent $33,000 on annual
concession fees relating to the Baltic project area, received $3,000 from the
sale of a partial property interest in the Williston Basin of North Dakota,
spent $8,000 to upgrade our drilling well servicing equipment, spent $5,000 to
upgrade our corporate office equipment, spent $3,000 on other assets and
realized a net amount of $23,000 from investing in marketable debt securities.
Financing Activities
We received net cash of $6.469 million from our financing activities during
1999, used net cash of $674,000 in our financing activities during 1998, and
received net cash of $1.679 million from our financing activities during 1997.
During 1999, we advanced $598,000 to two officers, received net proceeds of
$7.054 million from a private placement of 1,792,500 shares of common stock and
$13,000 from the exercise of options on 2,000 shares of common stock. During
1998, we advanced $840,000 to officers and received $166,000 in cash and a full
recourse note receivable of $250,000 from the exercise of warrants and options
on 382,622 shares of common stock. During 1997, we advanced $150,000 to an
officer, realized $1.576 million in advances from RWE-DEA relating to
exploration of its Baltic project area and $253,000 from the exercise of
warrants and options on 159,334 shares of common stock.
No cash was used in financing activities during the first quarter of 2000, as
compared to $98,000 used in the same period of 1999. During the first quarter of
1999, we advanced two of our officers a total of $98,000. As of April 8, 1999,
we had no further commitment to advance additional funds to the officers.
Subsequent to March 31, 2000, financing activities provided net proceeds of
approximately $9.3 million ($10.4 million gross) from the sale of 2,969,000
shares of our common stock.
In the past, our strategic partners have provided a substantial amount of the
capital required under our exploration agreements with them, and we expect they
may continue to do so in the future. For instance, in 1997, Apache committed to
cover our 50% share of an exploration program in Poland estimated to cost $60.0
million gross ($30.0 million net). Apache had covered approximately $40.0
million of those gross costs through December 31, 1999, and is committed to
covering our share of costs to drill the equivalent of four additional wells,
shoot 350 kilometers of 2-D seismic data and a portion of our share of Apache's
overhead in Poland during 2000. Other industry partners have previously covered
approximately $2.9 million of our share of costs in other projects during the
last five years.
Capital Requirements
We had $5.3 million of cash, cash equivalents and marketable debt securities
with no long-term debt as of March 31, 2000. During June 2000, we sold 2,969,000
shares of our common stock for net proceeds of approximately $9.3
26
million ($10.4 million gross). However, to fully fund our planned activities, we
will need additional capital during late 2000 or early 2001.
Fences Project Area. We have agreed to spend $16.0 million of exploration and
development costs on the Fences project area to earn a 49% interest. We expect
the $16.0 million will cover the costs to drill the Kleka 11 ($2.5 million net
and gross) and approximately four additional wells ($10.0 million net and gross)
and to acquire approximately 200 square kilometers of 3-D seismic data ($3.5
million net and gross) to supplement the 3-D seismic data already acquired by
POGC. After the first $16.0 million, all costs and net revenues will be shared
49% by us and 51% by POGC. We and POGC are currently discussing the schedule for
operations to be conducted during the balance of 2000 and 2001.
Based on initial test results from the Kleka 11 well, we expect revenues from
this field by late 2000.
Wilga Project Area. On June 5, 2000, the Wilga 3 was determined to be an
exploratory dry hole with an estimated net cost of approximately $0.9 million
($4.0 million gross). The Wilga 3 was drilled to define the perimeter of the
northwest section of the Wilga field, an area where proved reserves were not
assigned prior to drilling. In accordance with Generally Accepted Accounting
Principles, or "GAAP," the Wilga 3 will be classified as an exploratory dry hole
for accounting purposes, although in our industry parlance we have previously
referred to the Wilga 3, the first well drilled near the Wilga 2 discovery well,
as either an appraisal or a developmental well. The next well, the Wilga 4,
commenced drilling on June 17, 2000. Effective June 22, 2000, Apache agreed to
cover one-half of our share of costs to drill the Wilga 3 and Wilga 4 wells in
exchange for a release of Apache's commitment to cover our share of costs for
one exploratory well in Poland. Additional wells may be drilled thereafter. We
estimate each additional well in the Wilga project area will cost an average of
approximately $3.0 million gross ($1.4 million net). Assuming successful
drilling results and available funding, we anticipate completing production
facilities and pipelines during 2001, at a cost of approximately $11.0 million
gross ($5.0 million net).
Based on our exploration success in the Wilga project and our planned completion
of production facilities, we anticipate receiving production revenue from the
Wilga field in 2001. We expect these revenues will supplement our capital from
other sources to be used for further development of the Wilga field.
Apache Exploration Program. During the remainder of 2000 and 2001, we expect to
have substantially all of our share of exploration activities relating to the
Apache Exploration Program paid for by Apache. During the second half of 2000,
we and Apache have scheduled to commence drilling one exploratory well in each
of the Warsaw West and Pomeranian project areas. During 2001, we and Apache
expect to commence drilling one exploratory well in the Carpathian project area.
Apache will cover our share of costs to drill all three wells. In addition,
Apache has committed to covering our share of costs to shoot 350 kilometers of
2-D seismic data in the Carpathian project area.
Property Acquisition. We will need additional capital if we are able to reach an
agreement with POGC to purchase appraisal, development or exploration projects
on existing POGC discoveries, shut-in fields and underdeveloped properties in
Poland. Capital may be required to pay costs of acquisition, the installation of
production infrastructure and the implementation of a long-term exploitation
program. We may undertake such projects alone or under our arrangement with
Apache. We may seek additional capital that may be required for such purposes
through a variety of means, including the issuance of debt and equity
securities, project financing, bank financing or other financing alternatives.
We cannot assure that we will be able to obtain funds that will enable us to
participate in any such further acquisitions or joint activities.
Other. We expect to incur minimal exploration expenditures on our Baltic project
area in Poland during the remainder of 2000 and 2001. Similarly, we expect to
incur minimal exploration, appraisal and development expenditures on our
domestic operations during the remainder of 2000 and 2001.
We may change the allocation of capital among the categories of anticipated
expenditures depending upon future events that we cannot predict. For example,
we may change the allocation of our expenditures based on the actual results and
costs of future exploration, appraisal, development, production, property
acquisition and other activities.
27
In addition, we may have to change our anticipated expenditures if costs of
placing any particular discovery into production are higher, if the field is
smaller or if the commencement of production takes longer than expected.
We may obtain funds for future capital investments from the sale of additional
securities, project financing, sale of partial property interests, strategic
alliances with other energy or financial partners or other arrangements, all of
which may dilute the interest of our existing stockholders or our interest in
the specific project financed.
We previously initiated discussions with a commercial lender for a possible
project loan secured by proved reserves that may be developed as a result of our
Wilga discovery. We now intend to expand those discussions to include possible
project loan financing for the Kleka discovery as well as possible other
discoveries. We cannot assure we can establish such a credit facility. In any
event, borrowed funds are not likely to be available until significant reserves
are established through additional drilling. If we are able to obtain such a
loan, amounts initially allocated to develop those discoveries may be allocated
to other operations in Poland.
28
Business
We are an independent oil and gas company focused on exploration, development
and production opportunities in the Republic of Poland. We are the largest
foreign oil and gas exploration acreage holder in Poland with exploration rights
covering approximately 16.1 million gross acres. Our activities are conducted
under strategic alliances with Apache and POGC, which allow us to utilize the
operating and technical personnel of those companies, gain access to geological
and geophysical data and obtain other necessary support activities in Poland.
We are currently conducting oil and gas exploration activities with Apache in
Poland in areas where we and Apache jointly hold exploration rights, a program
to which we refer as the Apache Exploration Program. One of the wells drilled
under the Apache Exploration Program resulted in our first exploration success
in the Wilga project, which is located in the northwest portion of the Lublin
Basin project area. The Wilga 2 well tested at an initial flow rate of 16.9 MMcf
of gas per day and 570 Bbls of condensate from the Carboniferous at a depth of
approximately 2,800 meters. The Wilga 2 well was the first successful
exploration well drilled by a foreign operator in Poland. We own a 45% interest
in the 250,000 acre block in which the Wilga project area is located, POGC owns
10% and Apache owns 45% and is the operator.
The Wilga 2 was followed by the Wilga 3, which encountered good reservoir rock
in Carboniferous sands and a Lower Devonian sand package in a separate fault
block, but was determined to be a dry hole after test results did not yield
commercial quantities of oil or gas. We believe the absence of oil and gas in
the Wilga 3 is related to faulting and therefore does not alter the expectation
that the Wilga 2 discovery is indicative of a larger oil and gas accumulation.
The next well, the Wilga 4, commenced drilling on June 17, 2000, at a location
east of the Wilga 2 discovery, on the opposite side of the fault from the Wilga
3. Subject to satisfactory results from the Wilga 4 and the 2-D seismic data
currently being shot, we intend to drill three additional wells through early
2001 to begin to determine the extent of the Wilga accumulation or the existence
of other accumulations in the Wilga area. In anticipation of further development
in the Wilga project, we expect to begin design and installation of production
facilities and construction of an approximately 18 kilometer pipeline that will
be designed with the capacity to support several additional productive wells.
On April 11, 2000, we signed an agreement with POGC under which we will earn a
49% working interest in approximately 300,000 gross acres in the Fences project
area by spending $16.0 million on exploration and development activities. We
have identified several separate exploration prospects in the Fences project
area based on POGC's existing seismic data and adjacent productive areas. Our
first well in this project area, the Kleka 11, was announced as an exploratory
success on June 28, 2000, after the well tested a calculated open flow rate of
34.3 MMcf of gas per day from the Rotliegendes at a depth of approximately 3,000
meters. As part of our commitment, we plan to shoot 200 or more kilometers of
3-D seismic data and drill approximately four additional wells. After we
complete our work commitment, POGC will begin bearing its 51% of further costs.
POGC is the operator of the Fences project area.
29
Areas of Exploration
The following table shows the acreage in which we have or have the option to
acquire an interest.
Acreage
-------------------------------------------------------------
FX Energy /
Project Area Apache AMI POGC FX Energy Total
- ---------------------------------------------------- -------------- ---------- ----------- -------------
(in millions)
Lublin(1)........................................ 5.0(2) 0.6(3) -- 5.6
Pomeranian....................................... 2.2(2) 1.3(3) -- 3.5
Carpathian....................................... 1.4(2) 1.5(3) -- 2.9
Warsaw West...................................... 2.9 -- -- 2.9
Baltic........................................... -- -- 0.9 0.9
Fences........................................... -- 0.3(4) -- 0.3
--------------- -------------- -------------- ---------------
Total......................................... 11.5 3.7 0.9 16.1
=============== ============== ============== ===============
(1) The Wilga project is located on a 250,000 acre block included within our
Lublin Basin project area.
(2) Apache operates the FX Energy/Apache AMI acreage. We and Apache each have a
50% interest in this exploration area, subject to pro rata reduction upon
exercise by POGC of its option to participate in this area for up to a
331/3% interest on a 250,000 acre block-by-block basis.
(3) POGC operates this acreage. We and Apache each have an option to
participate in this POGC exploration area for up to a 331/3% interest.
(4) On April 11, 2000, we signed an agreement with POGC to earn a 49% interest
in this area by spending $16.0 million on exploration activities.
30
Exploration and Development Plan
Our current exploration and development plan consists of three primary
components:
o drilling and, if warranted, completing appraisal and development wells and
constructing production facilities in our Wilga project area with Apache
and POGC;
o fulfilling our $16.0 million commitment to earn our interest in the Fences
project area with POGC; and
o drilling (excluding completion costs, if any) the remaining exploration
wells to be funded by Apache under the Apache Exploration Program.
The following table sets forth our current exploration and development plan. The
capital expenditures included within the table are estimates based on
information currently available to us and are subject to being revised as
warranted. Actual capital expenditures may vary significantly from the estimated
amounts.
Interest
--------------------
Net Estimated Capital Expenditures
------------------------------
Working Revenue(1) Date Total FX Share
-------------------- ---------- -------------- --------------
(In millions)
Wilga Project(2)........................... 45% 42%
Wilga 3 well (drilled)(3)............... 1H 2000 $ 4.00 $ 0.90
Wilga 4 well (commenced) (3)............ 2H 2000 3.00 0.68
Seismic data............................ 2H 2000 0.53 0.24
Wilga 5 well............................ 2H 2000 3.00 1.35
Wilga 6 well............................ 2001 3.00 1.35
Wilga 7 well............................ 2001 3.00 1.35
Facilities/pipeline..................... 2001 11.11 5.00
-------------- --------------
$27.64 $10.87
-------------- --------------
Fences Project Area(2)..................... 49% 46%
Kleka 11 well (drilled)................. 1H 2000 $ 2.50 $ 2.50
Mieszkow well........................... 2H 2000 2.50 2.50
Boguszyn well........................... 2H 2000 2.50 2.50
Donatowo well........................... 2001 2.50 2.50
Zaniemysl well.......................... 2001 2.50 2.50
Lugi well............................... 2001 2.50 1.23
Seismic data............................ Various 3.50 3.50
-------------- --------------
$18.50 $17.23
-------------- --------------
Apache Exploration Program(2).............. 50% 47%
Pomeranian well(4)...................... 2H 2000 $ 3.50 $ --
Warsaw West well........................ 2H 2000 3.50 --
Carpathian well(4)...................... 2001 3.80 --
Seismic data............................ Various 6.30 0.15
-------------- --------------
$17.10 $ 0.15
-------------- --------------
Total................................. $63.24 $28.25
============== ==============
(1) Assuming the current base rate royalty of 6%.
(2) Capital expenditures in the Wilga project area include completion costs,
which are included within facilities/pipeline costs. Capital expenditures
in the Fences project area and the Apache Exploration Program do not
include completion costs.
(3) Effective June 22, 2000, Apache agreed to cover one-half of our share of
costs to drill the Wilga 3 and Wilga 4 wells in exchange for a release of
Apache's commitment to cover our share of costs for one exploratory well in
Poland.
(4) Our interests could be reduced to as low as a 331/3% working interest and a
311/3% net revenue interest if POGC exercises its option to participate in
these exploratory wells.
31
Recent Developments
Wilga Project/Lublin Basin Project Area
The Wilga project area is located in the northwest portion of the Lublin Basin
project area. In the 1960s, a Polish geological institute drilled the Wilga 1, a
stratigraphic test well, as part of a scientific survey and encountered several
gas and oil shows at the lower Carboniferous and upper Devonian. Based on
reprocessed and additional seismic data, we identified what we believe to be the
top of the Wilga structure approximately 5 kilometers northeast of the Wilga 1,
where in January 2000, we drilled the Wilga 2 well. This well tested at an
initial flow rate of 16.9 MMcf of gas per day and 570 Bbls of condensate from
the Carboniferous at a depth of approximately 2,800 meters. The Wilga 2 well was
the first successful exploration well drilled by a foreign operator in Poland.
The next well, the Wilga 3, was drilled from the same pad as the Wilga 2. The
Wilga 3 encountered good reservoir rock in Carboniferous sands and a Lower
Devonian sand package in a separate fault block, but was determined to be a dry
hole after test results did not yield commercial quantities of oil or gas. We
believe the absence of oil and gas in the Wilga 3 is related to faulting and
therefore does not alter the expectation that the Wilga 2 discovery is
indicative of a larger oil and gas accumulation. The next well, the Wilga 4,
commenced drilling on June 17, 2000, at a location east of the Wilga 2
discovery, on the opposite side of the fault from the Wilga 3. Effective June
22, 2000, Apache agreed to cover one-half of our share of costs to drill the
Wilga 3 and Wilga 4 wells in exchange for a release of Apache's commitment to
cover our share of costs for one exploratory well in Poland.
Subject to satisfactory results from the Wilga 4 well, we anticipate scheduling
three additional wells to be drilled through early 2001, subject to further
collection and analysis of 2-D seismic data and satisfactory results from
drilling. The drilling locations will be selected to begin to determine the
extent of the Wilga accumulation or the existence of other accumulations in the
Wilga area. We estimate each of these wells will cost approximately $3.0 million
gross, for an aggregate cost of approximately $12.0 million gross ($4.7 million
net, as adjusted for Apache covering one-half of our share of costs to drill the
Wilga 4). We own a 45% interest in the 250,000 acre block in which the Wilga
project is located, POGC owns 10% and Apache owns 45% and is the operator.
If further drilling and testing are consistent with results from the Wilga 2
well, we plan to work with Apache and POGC to design and install surface
production facilities and an approximately 18 kilometer pipeline to connect the
Wilga wells to POGC's pipeline system in early 2001. Initially, surface
facilities will be modular for ease of expansion, and pipeline capacity will be
capable of supporting the production from several additional wells. Before
beginning construction, which we expect will take approximately four months, we
must obtain permits and a pipeline right-of-way. We estimate these facilities
will cost approximately $11.0 million gross ($5.0 million net). A gas purchase
agreement with an adjustable price based on the price movements of European
heating oil is now being negotiated with the transportation and storage division
of POGC. We anticipate initial production from the Wilga field to commence
during 2001.
The Fences Project Area
The Fences project area comprises approximately 300,000 acres in a region of
west central Poland where POGC has recently had several significant exploratory
successes utilizing 3-D seismic data and applying western technology. POGC has
discovered four fields that are adjacent to or surrounded by the Fences project
area that are excluded from the Fences project area acreage. POGC currently has
allocated a limited amount of funds for exploration in this area. Due to our
close strategic relationship with POGC and our performance record to date in
Poland, POGC invited us to fund and participate in further exploration of the
Fences project area.
On April 11, 2000, we signed an agreement with POGC under which we will earn a
49% working interest in approximately 300,000 gross acres in the Fences project
area by spending $16.0 million on exploration and development activities. We
have identified several separate exploration prospects in our project area based
on POGC's existing seismic data and adjacent productive areas. Our first well in
this project area, the Kleka 11, was announced as an exploratory success on June
28, 2000, after the well tested a calculated open flow rate of 34.3 MMcf of gas
per day from the Rotliegendes at a depth of approximately 3,000 meters. As part
of our commitment, we plan to shoot 200 or more kilometers of 3-D seismic data
and drill approximately four additional wells. After we
32
complete our work commitment, POGC will begin bearing its 51% of further costs.
POGC is the operator of the Fences project area, which we have previously
referred to as the Radlin project area.
Our Strategic Partners
We implement our strategy in Poland through agreements and relationships with
POGC and Apache. Historical data and technical and operational support from
POGC, combined with financial support and technical and operational expertise
from Apache, provide a solid base for major exploration efforts in several
different geographical and geologically diverse areas of Poland.
The Apache Exploration Program
We conduct our Apache Exploration Program under our agreements with Apache that
establish an area of mutual interest covering our current and future holdings
throughout the entire country of Poland, except for the 300,000 gross acre
Fences project area and our 900,000 gross acre Baltic project area. The area of
mutual interest covers our oil and gas exploration, production, development and
acquisition activities through December 2000 or completion of Apache's
exploratory well commitment, whichever comes later.
Under terms of the Apache Exploration Program, Apache has either agreed to or
completed the following primary terms:
o Apache must pay our pro rata share of costs to drill the equivalent of
nine exploratory wells in Poland. To date, Apache has covered our
share of costs to drill five exploratory wells. Two exploratory wells
are scheduled to be drilled during the second half of 2000 and one
during 2001. In addition, effective June 22, 2000, Apache agreed to
cover one-half of our share of costs to drill the Wilga 3 and Wilga 4
wells in exchange for a release of Apache's commitment to cover our
share of costs for one exploratory well;
o Apache must pay our pro rata share of costs to shoot 2,722 kilometers
of 2-D seismic data, including 1,650 kilometers of 2-D seismic data in
the Lublin Basin project area completed during 1998, 300 kilometers in
the Pomeranian project area, and 422 kilometers in the Warsaw West
project area completed during early 2000 and 350 kilometers of 2-D
seismic data in the Carpathian project area that is scheduled to be
completed during mid-2000;
o Apache has committed to pay all of our pro rata share of $855,000 in
concession and usufruct fees during the first three years in the
Lublin Basin project area and the Carpathian project area;
o Apache must pay all of our pro rata share of annual training costs
during the first three years in the Lublin Basin project area ($80,000
per year) and the Carpathian project area ($15,000 per year);
o Apache may not charge us for any of our pro rata share of Polish
general and administrative costs through June 30, 2000. Thereafter,
Apache may charge us for 30% of its Polish general and administrative
costs, increased by 5% upon completing each of its four remaining
drilling requirements, up to a maximum of 50%;
o Apache paid us $500,000 during 1998 and $450,000 during 1997;
o We and Apache must offer each other a 50% interest in any new
exploration, appraisal, development, property acquisition or other
agreement entered into by either party within the area of mutual
interest during all of 1999 and 2000 or the completion of Apache's
nine exploratory well commitment, whichever is later; and
o Apache is the operator of all areas controlled by us and Apache within
the area of mutual interest.
Our POGC Relationship
We and Apache have granted to POGC the right to participate with up to a
one-third interest, on a 250,000 acre block-by-block basis, in oil and gas
exploration on 8.6 million gross acres in Poland controlled by us and Apache,
which excludes our 300,000 acre Fences project area, our 900,000 acre Baltic
project area and our 2.9 million acre
33
Warsaw West project area. In turn, POGC has granted to us and Apache each the
right to participate, with up to a one-third interest each, in oil and gas
exploration of an aggregate of approximately 3.4 million POGC controlled gross
acres in the vicinity of our Lublin, Pomeranian and Carpathian project areas.
To date, seven exploratory wells (one exploratory success and six exploratory
dry holes) have been drilled on acreage subject to these terms, including five
exploratory wells in which Apache paid for our pro rata share of costs under
terms of the Apache Exploration Program. POGC participated in each of these
wells for various amounts ranging from 5% to 331/3%.
At POGC's invitation, we also agreed in April 2000, to spend $16.0 million to
earn a 49% interest in the 300,000 acre Fences project area in western Poland.
Apache declined to exercise its right to participate in the Fences project area.
During the latter part of 1999, we and Apache conducted discussions and
negotiations toward a proposed acquisition by us and Apache of certain producing
properties from POGC. Progress toward such an acquisition recently has slowed,
but we believe all the parties remain interested in completing an acquisition.
Exploration Acreage Overview - Apache Exploration Program
Lublin Basin
The 5.6 million acre Lublin Basin project area in central southeast Poland
consists of exploration rights on approximately 5.0 million gross acres held by
us and Apache and options to participate in 600,000 acres controlled by POGC. We
and Apache have an option to participate, with up to a one-third interest each,
in the exploration of the POGC option acreage. In turn, POGC has the option to
participate in the exploration of the acreage that we and Apache hold, with up
to a one-third interest, by participating in the first exploratory well on each
250,000 acre block.
The Lublin Basin has been explored extensively by POGC in recent years,
resulting in the discovery of five fields. Additional wells drilled by POGC in
the Lublin Basin have also encountered oil or gas shows. Seismic data analyzed
to date and correlated with data from drilling logs and core samples from
previous wells show a number of exploration leads within the area covered by the
Lublin Basin project area. We and Apache have acquired over 2,000 kilometers of
new 2-D seismic data and reprocessed over 5,400 kilometers of existing 2-D
seismic data on the Lublin Basin project area to date. The seismic data, along
with well log and core analysis data, were used to pick the first five
exploratory well sites jointly drilled by us, Apache and POGC in the Lublin
Basin project area.
The first four exploratory wells under the Apache Exploration Program, all
drilled within the Lublin Basin project area during 1999, were nonproductive. In
accordance with terms of the Apache Exploration Program, Apache covered all of
our share of costs for all four wells. As discussed under "Recent Developments,"
on January 25, 2000, the Wilga 2, the fifth well in the Apache Exploration
Program, was announced as an exploratory success. Initial production tests
indicated a combined flow rate of 16.9 MMcf of gas and 570 Bbls of condensate
per day from the Carboniferous at a depth of approximately 2,800 meters. In
accordance with the Apache Exploration Program terms, Apache has paid all of our
45% share of costs to drill the Wilga 2. Apache has agreed to pay one-half of
our 45% share of costs to drill the Wilga 3 (dry hole) and the Wilga 4
(now drilling). We will pay 45% of all other costs incurred in the Wilga project
area.
Pomeranian
The 3.5 million acre Pomeranian project area is located in northwestern Poland
and consists of exploration rights on 2.2 million gross acres held by us and
Apache and options on 1.3 million gross acres controlled by POGC. We and Apache
have an option to participate, with up to a one-third interest each, in the
exploration of the POGC option acreage. In turn, POGC has the option to
participate in the exploration of the acreage we and Apache hold, with up to a
one-third interest, by participating in the first exploratory well on each
250,000 acre block. The Pomeranian project area lies along the underexplored
northern edge of the Permian trend in northwestern Poland. Although
34
POGC has made a few, mostly small oil and gas discoveries in this region, there
still has been relatively little exploration and no significant oil and gas
production to date. Stratigraphic test wells drilled by the Polish government
have reported oil and gas shows. POGC has made available to us and Apache the
existing seismic data and well logs and cores from the Pomeranian project area
for reprocessing and analysis. We believe portions of the Pomeranian project
area may be geologically similar to the BMB field to the southwest on which POGC
has drilled approximately 22 commercial wells on a 3-D seismic-defined
structure.
Since 1997, we and Apache have reprocessed existing seismic data and reviewed
logs and cores made available by POGC. This study resulted in a number of
exploration leads on which we gathered approximately 300 kilometers of
additional 2-D seismic data in early 2000. After final processing and
interpretation, we and Apache plan to drill our first exploratory well on this
acreage during the second half of 2000. Our share of costs in this first well
will be covered by Apache.
Warsaw West
The 2.9 million acre Warsaw West project area is located adjacent to the
northwest section of our Lublin Basin project area in central Poland and
consists of exploration rights on 2.9 million gross acres held by us and Apache.
POGC has no option to participate in the Warsaw West project area.
There has been no oil and gas production from the Warsaw West project area. We
and Apache have recently completed gathering approximately 422 kilometers of 2-D
seismic data and plan to drill one exploratory well during the second half of
2000 on the Warsaw West project area. Under terms of the Apache Exploration
Program, Apache covered our share of costs to shoot approximately 422 kilometers
of 2-D seismic data and will cover our share of costs in the first exploratory
well.
Carpathian
The 2.9 million acre Carpathian project area is located in southern Poland and
comprises exploration rights on 1.4 million gross acres held by us and Apache
and options on 1.5 million gross acres controlled by POGC. We and Apache have an
option to participate, with up to a one-third interest each, in the exploration
of the POGC option acreage. In turn, POGC has the option to participate in the
exploration of the acreage that we and Apache own, with up to a one-third
interest, by participating in the first exploratory well on each 250,000 acre
block.
Oil and gas were first discovered in the Carpathian area in 1854. A limited
number of deep wells drilled in recent years by POGC evidence additional
possible reservoir potential within the area. Over the past few years, there
have been several new oil and gas discoveries in the Carpathian region.
Potential producing horizons within the Carpathian are Jurassic, Miocene,
Cretaceous and Devonian.
During 1999, we elected to participate with a 5% interest in drilling the
Andrychow 6, an exploratory well operated by POGC on its option acreage in
southern Poland. The well tested a Devonian formation and was determined to be
an exploratory dry hole during December 1999.
During the second quarter of 1999, we and Apache commenced testing and
recompletion operations on the Lachowice Farm-in, an undeveloped gas discovery
on a POGC concession located within the Carpathian project area. Under terms of
the agreement, we and Apache agreed to pay the costs of testing three shut-in
wells and, if warranted, additional wells and production infrastructure in order
to earn a one-third interest each in the project. The test results from this
project did not warrant constructing gathering and processing facilities. On May
4, 2000, we and Apache each turned the project back to POGC and terminated the
Lachowice Farm-in.
We and Apache have identified several leads in the Carpathian project area based
on reprocessed existing seismic data and are scheduled to acquire approximately
350 kilometers of 2-D seismic data and drill our first exploratory well in the
Carpathian project area during 2001. Under terms of the Apache Exploration
Program, Apache will pay our share of costs to shoot approximately 350
kilometers of 2-D seismic data and drill the first exploratory well.
35
POGC Exploration Acreage
The Fences
The Fences project area comprises approximately 300,000 acres in a region of
west central Poland where POGC has recently had several significant exploratory
successes utilizing 3-D seismic data and applying western technology. POGC has
discovered four productive fields that are adjacent to or surrounded by the
Fences project area but are excluded from the Fences project area acreage. POGC
currently has allocated limited funds for exploration in this area. Due to our
close strategic relationship with POGC and our performance record to date in
Poland, POGC invited us to fund and participate in further exploration of the
Fences project area. We have previously referred to this project as the Radlin
project area, the name of one of the POGC productive fields in the area.
On April 11, 2000, we signed an agreement with POGC under which we will earn a
49% working interest in approximately 300,000 gross acres in the Fences project
area by spending $16.0 million on exploration and development activities. We
have identified several separate exploration prospects in our project area based
on POGC's existing seismic data and adjacent producing areas. Our first well in
this project area, the Kleka 11, was announced as an exploratory success on June
28, 2000, after the well tested a calculated open flow rate of 34.3 MMcf of gas
per day from the Rotliegendes at a depth of approximately 3,000 meters. As part
of our commitment, we plan to shoot 200 or more kilometers of 3-D seismic data
and drill approximately four additional wells. After we complete our work
commitment, POGC will begin bearing its 51% of further costs. POGC is the
operator of the Fences project area.
Possible Additional Acquisition, Appraisal, Development and Exploration
Projects
We and Apache have reviewed additional acquisition, appraisal, development and
exploration projects for possible joint development and production operations on
existing POGC discoveries, shut-in fields and underdeveloped properties in
Poland. During the latter part of 1999, we and Apache conducted discussions and
negotiations toward a proposed acquisition by us and Apache of certain
properties from POGC. Progress toward a possible acquisition recently has
slowed, but we believe all the parties remain interested in resuming discussions
and completing an acquisition.
Other Polish Project Areas
Baltic Project Area
The Baltic project area, which was our first concession in Poland, is located
onshore near the Baltic Sea and consists of exploration rights covering
approximately 900,000 net acres in northern Poland. The Baltic project area is
part of the Baltic Platform geological region that covers the southeastern
portion of the Baltic Sea, portions of the bordering onshore areas of northern
Poland and areas to the northeast in the Kaliningrad district of Russia,
Lithuania and Latvia. Approximately 34 onshore and offshore fields have been
discovered in the Baltic Platform. Industry sources report that four of the
largest fields in this region have produced an aggregate of over 150 MMBbls of
high-grade oil through 1994.
During 1997, we drilled two wells in the Baltic project area. Neither of the
wells yielded commercial quantities of oil and gas. We hold a 100% interest and
have no further work commitment. There are no current plans to conduct
exploratory work in the Baltic project area during 2000. However, recent
reported Cambrian successes in southern Kaliningrad near the Polish border and
developments in our Fences and Wilga project areas may encourage industry
interest in participating with us in this concession.
Sudety Project Area
On July 26, 1999, Homestake Mining Company completed its two-year, $1.1 million
minimum exploration commitment and terminated its agreement with us to jointly
explore for gold on our Sudety Project Area in southwestern Poland. We have
discontinued further gold exploration in the Sudety project area.
36
Legal Framework for our Polish Operations
In 1994, Poland adopted the Geological and Mining Law, which specifies the
process for obtaining domestic exploration and exploitation rights. All of our
rights in Poland have been awarded pursuant to this law. Under the Geological
and Mining Law, the concession authority enters into oil, gas and mining
usufruct agreements that grant the holder the exclusive right to explore for and
exploit the designated oil and gas or minerals for a specified period under
prescribed terms and conditions. The holder of the mining usufruct must also
acquire an exploration concession to obtain surface access to the exploration
area by applying to the concession authority and providing the opportunity for
comment by local governmental authorities. If a commercially viable discovery is
made in an exploration concession area, it is necessary for the holder of the
exploration concession license to obtain an exploitation concession license for
a specific term by then applying to the concession authority and negotiating
with local government authorities. The holder of a usufruct and exploration and
exploitation concession licenses must also acquire rights to use the land from
the surface owner.
The concession authority has granted us oil and gas exploration rights on the
Lublin Basin, Carpathian, Pomeranian and Baltic project areas, granted Apache
oil and gas exploration rights on the Warsaw West project area and granted POGC
oil and gas exploration rights on the Fences project area and POGC option
acreage. The agreements divide these areas into blocks, generally containing
approximately 250,000 acres each. Concession licenses have been acquired for
surface access to all areas that lie within existing usufructs. For concessions
owned by us and/or Apache, 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.
For concessions owned by us and/or Apache, each of the oil and gas usufructs
divides exploration rights into successive exploration phases expiring in three
and six years, respectively, after the grant of the last concession agreements
covered by the applicable usufruct. A number of exploratory wells are required
to be drilled during the first three-year and second three-year exploration
phases, a minimum amount of 2-D seismic acquisition must be completed (except in
the Baltic project area), and other expenditures must be made, all as set forth
in the applicable usufructs, in order to retain an interest in each usufruct.
The dates of the last concession signed and work commitments for each of the
usufructs owned by us and/or Apache are set forth in the following table:
Work Commitment
-------------------------------------------------------------
First Three- Second Three- 2-D
No. of Date of Last Year Phase Year Phase Seismic
Project Area Blocks(1) Concession Drilling Drilling(2) Acquisition
- ---------------------- ---------- -------------- ---------------- ------------------------- ----------------
Lublin Basin:
Vistula........... 8 08/08/97 One well One well per block 500 km
Lublin Middle..... 7 06/30/98 Two wells One well per block 500 km
Block 298......... 1 06/30/98 One well Two wells in usufruct 150 km
Komarow........... 11 03/04/98 Two wells One well per block 500 km
Carpathian.......... 12 12/31/98 One well Two wells in usufruct 350 km
Pomeranian.......... 10 12/31/98 One well Two wells in usufruct 600 km
Warsaw West(3)...... 13 11/13/98 One well Two wells in usufruct 1,500 km
Baltic.............. 11 03/07/96 One well One well in usufruct None
(1) The Baltic project area includes one block that is approximately half the
size of the other blocks. The Komarow usufruct includes three extra partial
blocks adjacent to the border of Poland and the Ukraine.
(2) The drilling commitments in a block or area may be terminated by
relinquishing such block or area at the end of the first three-year phase.
(3) The 2-D seismic acquisition requirements for the Warsaw West project area
include 1,000 kilometers during the first three-year exploration period and
500 kilometers during the second three-year exploration period. 2-D seismic
acquisition requirements for all other areas apply to the first three-year
exploration period only.
37
We may relinquish our interest in any usufruct at any time without having to
fulfill any remaining work commitments if we determine the oil and gas potential
does not warrant further holding or exploration costs.
As of March 31, 2000, we had completed shooting all of the required 2-D seismic
data on the Lublin Basin project area, drilled one exploratory well on the
Vistula usufruct, one exploratory well on the Lublin Middle usufruct and two
exploratory wells on the Baltic usufructs. We have also participated in drilling
four other exploratory wells on the above project areas that were on concessions
controlled by POGC and did not count towards the above referenced work
commitments.
The annual training fees for Polish citizens and the estimated aggregate other
fixed concession and usufruct fees over the respective usufruct's six-year
exploration term, including the net amounts payable by us and Apache, are set
forth in the following table:
Concession and Usufruct Fees
Training Fees -------------------------------------------------
Project Area (1) Per Year (2) Gross (3) Net FX Net Apache
---------------------------------------------- ---------------- ----------------- -------------- ---------------
Lublin Basin:
Vistula..................................... $ 25,000 $ 220,000 -- $ 220,000
Lublin Middle............................... 25,000 224,000 -- 224,000
Block 298................................... 5,000 51,000 -- 51,000
Komarow..................................... 25,000 200,000 -- 200,000
Carpathian.................................... 15,000 160,000 -- 160,000
Pomeranian.................................... 25,000 250,000 $125,000 125,000
Warsaw West................................... 25,000 390,000 97,500 292,500
Baltic........................................ 25,000 200,000 200,000 --
---------------- ----------------- -------------- ---------------
Total..................................... $170,000 $1,695,000 $422,500 $1,272,500
================ ================= ============== ===============
(1) There are no training, concession or usufruct fees applicable to the Fences
project area.
(2) On the Lublin Basin and the Carpathian usufructs, Apache has committed to
cover all training fees during the first three-year exploration period. We
must cover our pro rata share of training fee costs on the Lublin and
Carpathian usufructs during the second three-year exploration period. On
the Carpathian, Pomeranian and Warsaw West usufructs, we must cover our pro
rata share of training fees for the entire exploration period. On the
Baltic project area, we must cover all training fees for the entire
exploration period.
(3) As of July 10, 2000, all the required concession and usufruct costs in the
Lublin Basin, Carpathian, Pomeranian and Warsaw West project areas had been
fully paid. The Baltic usufruct includes payments of $33,333 per year over
six years beginning March 7, 1996.
The Fences project area consists of portions of three exploratory oil and gas
concessions (Koscian-Serem, Solec-Jarocin and Jaraczewo-Pogorzela concessions)
controlled by POGC. Three producing areas are included within the three
exploratory oil and gas concession boundaries (Radlin, Kleka and Kaleje
exploitation concessions), but are excluded from the Fences project area. A
fourth producing area, the Jarocin area, is adjacent to the Fences project area
in a different POGC concession. The following table sets forth the exploration
terms of each exploratory oil and gas concession:
Six Year Exploration Period Optional
----------------------------------
Concession Beginning End Extension
- ---------------------------------------------------------------- ---------------- ----------------- --------------
Koscian-Serem................................................... 9/28/95 9/28/01 3 years
Solec-Jarocin................................................... 4/30/96 4/30/02 3 years
Jaraczewo-Pogorzela............................................. 11/19/96 11/19/02 3 years
We believe POGC has paid all required usufruct and concession fees and completed
all material work commitments to date for the three exploratory oil and gas
concessions included within the Fences project area.
If commercially viable oil or gas is developed, the concession owner would be
required to apply for an exploitation concession, as provided by the usufructs,
with a term of 30 years and so long thereafter as commercial production
continues. Upon the grant of the exploitation concession, the concession owner
may become obligated to pay a fee, to be negotiated within the range of 0.01% to
0.50% of the market value of the estimated recoverable reserves in place,
payable in five equal annual installments. The concession owner would also be
required to pay a royalty on any production, the amount of which will be set by
the concession authority, within a range established on the base royalty rate
for the mineral being extracted. The base royalty rate for oil and gas is
currently 6%, but could be increased unilaterally to up to 10% (the current
statutory maximum base royalty rate) by the Council of Ministers. The concession
authority can set the royalty rate for any particular commercial production in a
range between 50% and 150% of the base royalty rate, depending on the economic
viability of such operation, but not to exceed the statutory maximum rate.
Therefore, with the current base rate of 6% for oil and gas, the concession
authority could
38
establish the royalty rate between 3% and 9%. If, however, the base rate is
increased to 10%, the current statutory maximum, the royalty rate would be
between 5% and 15%. The royalty rate may vary for different producing fields and
may be changed from time to time during the productive life of a field. Local
governments will receive 60% of any royalties paid on production. The concession
owner could be subject to significant delays in obtaining the consents of local
authorities or satisfying other governmental requirements prior to obtaining an
exploitation license.
Polish Joint Venture Structure. Within the framework of the Apache Exploration
Program, Apache is the operator on areas controlled jointly by us and Apache.
POGC is the operator on areas controlled by POGC. Even though we, Apache and
POGC will conduct our activities jointly, we have agreed to treat our respective
interests and obligations as separate, such that each company is responsible for
providing its own funding for joint activities and is entitled to take and sell
its share of oil and gas independently of the others. Customary western industry
standard joint operating agreement terms, modified somewhat to conform to Polish
technical requirements, govern the parties' respective actions, rights and
obligations.
We and Apache have each created Polish subsidiaries to carry out our joint
projects in Poland. We have created several wholly-owned spolka z o. s., a form
of limited liability company, to hold all of our interests in Poland. For
example, in the Vistula area in the western portion of the Lublin Basin project
area containing eight exploration blocks, we and Apache are each 50% beneficial
participants in a Polish limited liability company (the "Lublin LLC"), all of
the title ownership of which has been assigned by us to the Lublin LLC, subject
to the terms of the participation agreement. Prior to undertaking long-term
production, an exploitation license must be applied for. The exploitation
license will be owned by a newly created Polish entity that reflects the true
beneficial ownership interests of all parties.
In other instances, we and Apache have paired our interests in Poland into
several spolka jawnas, a form of registered joint operation, to hold record
title to the various usufructs and concessions. For example, we and Apache are
each 50% participants in a Polish spolka jawna that has been awarded usufructs
and exploration concessions covering 16 exploration blocks in the Lublin Basin,
the Carpathian and the Pomeranian project areas.
In the Fences project area, we and POGC will form a jointly owned Polish
operating company that will hold record of title and operate the concessions
included in the Fences project area in accordance with our respective beneficial
property interests.
The ownership structure in Poland may be altered by us, Apache and POGC from
time to time in response to developments in the Polish legal system to most
accurately reflect their various agreements regarding jointly owned projects in
Poland.
Domestic Properties and Activities
Domestic Production
We currently produce oil domestically in Montana and Nevada. All of our
producing properties, except for an exploratory discovery during 1997, were
purchased during 1994. 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. 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. As of May 31, 2000, we had no producing activities outside the United
States.
During 1999, we had average daily production of 460 gross Bbls (279 net). Our
average sales price per Bbl was $15.35, with an average production cost per
barrel of $9.50. We sell oil at posted field prices to one of several purchasers
in each of our production areas. During the last three years, over 85% of our
total oil sales was to CENEX, a regional refiner and marketer. Posted prices are
published and are generally competitive among the various purchasers. The crude
oil sales contracts may be terminated by either party upon 30 days' notice.
39
Domestic Oil Reserves
All of our oil properties containing proved oil reserves are located in Montana
and Nevada. All information set forth in this document regarding proved
reserves, related future net revenues and PV-10 Value is taken from the report
of Larry D. Krause, independent petroleum engineer, Billings, Montana. In
accordance with SEC guidelines, our estimates of future net revenues from our
proved reserves and the PV-10 Value were made using a sales price of $22.37, the
weighted average oil sales price as of December 31, 1999, the date of such
estimate, and held constant throughout the life of the properties. No estimates
of reserves have been filed with or included in any report to any other federal
agency during 1999.
Our estimated proved reserves by reserve category as of December 31, 1999 are
detailed in the following table:
December 31, 1999
--------------------------
Oil (Bbl) PV-10 Value
------------ ------------
Developed Producing..................................................................... 738,790 $3,386,483
Developed Nonproducing.................................................................. 341,162 2,073,667
------------ ------------
Total Developed......................................................................... 1,079,952 $5,460,150
============ ============
Domestic Nonproducing Acreage
During 1996 and 1997, we acquired 16,875 acres of undeveloped oil and gas leases
in the Williston Basin area of North Dakota. The Williston Basin area has
established oil and gas production from numerous zones, including the
Mississippian, Devonian, Silurian and Ordovician. We have identified several
leads over our acreage and intend to pursue a strategic alliance with an
industry partner to jointly explore the acreage.
Drilling Rig and Well Servicing Equipment
In Montana, we have a drilling rig capable of drilling to a vertical depth of up
to 6,000 feet, two well servicing rigs and other associated oilfield equipment.
Historically, prior to late 1998, we utilized our drilling rig and well
servicing equipment primarily on our producing oil properties in Montana. During
late 1998, we shifted our emphasis away from our properties to third-party
contract work in an effort to increase our domestic revenues.
Drilling Activities
The following table sets forth the wells drilled and completed by us during
1999, 1998 and 1997:
Years Ended December 31,
----------------------------------------------------------------
1999 1998 1997
--------------------- --------------------- -------------------
Gross Net Gross Net Gross Net
---------- ---------- --------- ---------- --------- --------
Development Wells:
Producing.................................... -- -- -- -- -- --
Nonproducing................................. -- -- -- -- -- --
---------- ---------- --------- ---------- --------- --------
Total.................................. -- -- -- -- -- --
========== ========== ========= ========== ========= ========
Exploratory Wells:
Discoveries:
Poland.................................... 1.0 0.5 -- -- -- --
United States............................. -- -- -- -- 1.0 0.1
Exploratory Dry Holes:
Poland.................................... 5.0 1.6 -- -- 2.0 1.5
United States............................. -- -- -- -- 2.0 1.3
---------- ---------- --------- ---------- --------- --------
Total.................................. 6.0 2.1 -- -- 5.0 2.9
========== ========== ========= ========== ========= ========
40
The above table does not include the Kleka 11, Wilga 2, Wilga 3 and Wilga 4
wells. During the first half of 2000, the Kleka 11 and Wilga 2 were exploratory
successes (0.5 net each), the Wilga 3 was an exploratory dry hole (0.5 net) and
drilling commenced on the Wilga 4 (0.5 net) on June 17, 2000.
Wells and Acreage
As of December 31, 1999, we had 114 gross and 108 net producing oil wells, all
of which are located in Montana and Nevada.
The following table sets forth our gross and net acres of developed and
undeveloped oil and gas leases as of December 31, 1999:
Developed Acreage Undeveloped Acreage
------------------------ -----------------------------
Gross Net Gross Net
------------------------ -----------------------------
United States:
North Dakota............................................ -- -- 16,875 16,875
Montana................................................. 10,732 10,418 1,150 1,057
Nevada.................................................. 400 128 37 16
----------- ----------- ------------- -------------
Total................................................ 11,132 10,546 18,062 17,948
----------- ----------- ------------- -------------
Poland:(1)...............................................
Apache Exploration Program(2)
Lublin Basin......................................... -- -- 5,000,000 2,500,000
Carpathian........................................... -- -- 1,400,000 700,000
Pomeranian........................................... -- -- 2,200,000 1,100,000
Warsaw West.......................................... -- -- 2,900,000 1,450,000
----------- ----------- ------------- -------------
Total............................................... -- -- 11,500,000 5,750,000
Baltic Project Area.................................... -- -- 900,000 900,000
----------- ----------- ------------- -------------
Total Polish acreage................................. -- -- 12,400,000 6,650,000
Total Acreage(3)..................................... 11,132 10,546 12,418,062 6,667,948
=========== =========== ============= =============
(1) All Polish acreage is rounded to the nearest 100,000 acres.
(2) Gives effect to 50% beneficial ownership of Apache in the Lublin Basin,
Carpathian, Pomeranian and Warsaw West project areas under our joint
exploration arrangements with Apache under the Apache Exploration Program.
Does not give effect to options on POGC controlled areas containing
approximately 600,000 acres in the Lublin Basin project area, 1.5 million
acres in the Carpathian project area and 1.3 million acres in the
Pomeranian project area under the POGC option agreements.
(3) Excludes the 300,000 acre Fences project area where we signed an agreement
with POGC on April 11, 2000, to earn a 49% interest by paying for the first
$16.0 million of exploration costs.
Operational Hazards and Insurance
We are engaged in the drilling and production of oil and gas, and as such, our
operations are subject to the usual hazards incident to the industry. These
hazards include blowouts, cratering, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, pollution, releases of toxic gas and other
environmental hazards and risks. These hazards can cause personal injury and
loss of life, severe damage to and destruction of property and equipment,
pollution or environmental damage and suspension of operations.
To lessen the effects of these hazards, we maintain insurance of various types
to cover our domestic operations and maintain general liability coverage for our
activities in Poland. We have $9.0 million of general liability insurance.
Apache, as the operator of the Apache Exploration Program, is carrying $25.0
million of general liability insurance for joint operations on Polish areas in
which we and Apache have interests. We have elected to be included on Apache's
well control insurance policy for all jointly drilled wells to date in Poland.
POGC, as operator of the Fences project area, is self-insured. Our seismic and
drilling contractors are required to maintain insurance coverage for operations
by them in Poland. There can be no assurance that we, Apache or POGC will be
able to continue to obtain insurance coverage for current or future activities
in Poland, or that any insurance obtained will provide coverage customary in
either the industry or in the United States, or be comparable to the insurance
now maintained by us, Apache and POGC, or be on favorable terms or at premiums
that are reasonable. This insurance, moreover,
41
does not cover all of the risks involved in oil and gas exploration, drilling
and production and, if coverage does exist, may not be sufficient to pay the
full amount of such liabilities. We may not be insured against all losses or
liabilities that may arise from all hazards because such insurance may not be
available at economic rates, the respective insurance policies may have limited
coverage and other factors. For example, insurance against risks related to
violations of environmental laws is not maintained. The occurrence of a
significant adverse event that is not fully covered by insurance could have a
materially adverse effect on us. Further, we cannot assure that we will be able
to maintain adequate insurance in the future at rates we consider reasonable.
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, as well as the Act of January 31, 1994, concerning the Protection and
Management of the Environment, which are the primary statutes governing
environmental protection. Agreements with the government of Poland respecting
our project 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 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 that our operations in Poland will be designed to meet good international
petroleum industry practices and, as they develop, Polish requirements.
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, 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 natural gas wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amounts of oil and natural gas we can produce from our wells and to
limit the number of wells or the locations that we can drill.
Production of any oil and gas by us is affected to some degree by state
regulations, some of which regulate 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 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
42
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. 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 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 are our
competitors in the oil and gas industry.
The Comprehensive Environmental Response, Compensation and Liability Act, 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. 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 damages or 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 and regulations promulgated
thereunder govern the generation, storage, transfer and disposal of hazardous
wastes. This law, 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, natural gas or geothermal
energy." Because of this exclusion, many of our operations are exempt from these
regulations. Nevertheless, we must comply with these regulations for any of our
operations that do not fall within the exclusion.
The Oil Pollution Act of 1990 and regulations promulgated pursuant thereto
impose a variety of regulations on responsible parties related to the prevention
of oil spills and liability for damages resulting from such spills. The Oil
Pollution Act of 1990 establishes strict liability for owners of facilities that
are the site of a release of oil into "waters of the United States." While
liability more typically applies to facilities near substantial bodies of water,
at least one district court has held that 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 natural 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 Montana producing properties is operated under oil and
gas leases issued by the Bureau of Land Management or by certain Indian nations
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 currently comply with all material
provisions of such regulations.
43
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
consult with 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 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 our 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 July 10, 2000, we had 36 employees, consisting of eight in Salt Lake City,
Utah; 25 in Oilmont, Montana; one in Greenwich, Connecticut; and two in Houston,
Texas. None of our employees is represented by a collective bargaining
organization, and we consider our relationship with our employees to be
satisfactory. In addition to our employees, we regularly engage technical
consultants to provide specific geological, geophysical and other professional
services.
Offices and Facilities
Our approximately 3,010 square feet of executive office space located at 3006
Highland Drive, Suite 206, Salt Lake City, Utah, are rented at $2,960 per month
under a month-to-month agreement. We own a 16,160 square foot office building
located at the corner of Central and Main in Oilmont, Montana. We use 4,800
square feet for our field office and rent the remaining space to unrelated third
parties for $875 per month. We rent a small office suite for $1,400 per month in
Warsaw, Poland, at Al. Jana Pawla II 29, as an office of record in Poland.
Legal Proceedings
We are not a party to any material legal proceedings, and to our knowledge, no
such legal proceedings have been threatened against us.
44
The Republic of Poland
The Republic of Poland, with a population of about 40 million people, peacefully
asserted its independence in 1989 and adopted a new constitution that
established a parliamentary democracy. Poland's comprehensive economic reform
programs and stabilization measures implemented since 1989 have enabled it to
move toward a free market economy that is currently one of the fastest growing
in eastern Europe, with annual growth rates of 5% to 7%, even though recent
growth has slowed somewhat. Poland experienced relatively high levels of
inflation in the early 1990s, but inflation has fallen to less than 12% and 10%
per annum during 1998 and 1999, respectively. Demand growth appears strong with
a growing economy and a commitment to convert power plants from lignite to gas
in order to meet the clean air standards required for European Union membership.
Poland recently joined NATO and is poised to join the European Union within the
next few years. Poland's international trade has also undergone significant
progress. Its economic ties have turned from the east to the west, with most of
its current international trade with the countries of the European Union. The
Polish government credits foreign investment as a forceful growth factor,
generating over one third of the country's total investment and acting as a
powerful restraint on unemployment. Cumulating foreign direct investment flows
to Poland aggregated $38.9 billion through the end of 1999. The Polish Foreign
Investment Agency, or PAIZ, expects Poland to receive $10.0 to $12.0 billion of
foreign direct investment during 2000, compared to $8.3 billion for 1999 and
$10.0 billion in 1998. German companies were the largest foreign investors in
Poland with a cumulative $6.1 billion, followed by U.S. companies with $5.2
billion and France with $2.4 billion. PAIZ reports that, as of the end of 1999,
the largest foreign investors are South Korea's Daewoo Group ($1.6 billion),
Italy's Fiat ($1.5 billion) and France's Vivendi ($1.2 billion). Almost half of
cumulative foreign direct investment was in production ($17.3 billion), of which
$4.6 billion was for food production and $4.4 billion was for vehicle
production. Other significant categories include financial services ($7.7
billion), trade and repair services ($3.4 billion) and construction ($1.9
billion).
Since the 1850s when oil was first commercially produced in Poland, in excess of
122 MMBbls of oil and 2.6 Tcf of gas in the southeastern Carpathian region and
24 MMBbls of oil and 2.3 Tcf of gas in the southwestern Polish Lowlands have
been produced to date. Over the last several decades, the exploration and
development of Poland's oil and gas resources have been hindered by a
combination of foreign influence, a centrally controlled economy, limited
financial resources and a lack of modern exploration technology. Poland
currently imports approximately 98% of its oil, primarily from countries of the
former Soviet Union and the Middle East, and approximately 60% of its natural
gas, primarily from countries of the former Soviet Union. Poland is about the
size of New Mexico and contains approximately 77.3 million acres. As of July 10,
2000, we have exploration rights to approximately 16.1 million of those acres.
Poland has crude oil pipelines traversing the country and a network of gas
pipelines serving major cities, commercial and industrial areas and many gas
production areas, including significant portions of our exploratory 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. We
will most likely incur substantial expenditures for constructing and operating
facilities to gather and transport any oil and gas produced from our properties,
including the recently discovered Wilga field.
Since its relatively recent transition to a market economy and pluralistic
political system, Poland is continuing to experience significant political
changes and economic growth. Poland has developed and is refining legal and
regulatory systems characteristic of parliamentary democracies with
interpretation and procedural safeguards to ensure the rule of law.
Poland's legal framework and fiscal regime for oil and gas production are
attractive, as Poland has intentionally sought to entice foreign companies to
offset its own lack of sufficient capital to develop the country's oil and gas
resources.
45
The Polish government is currently negotiating with the European Union regarding
Poland's application to become a member state of the European Union. The Polish
government has generally taken steps to harmonize Polish legislation with that
of the European Union in anticipation of Poland's entry into the European Union
and to facilitate interaction with European Union members.
In July 1995, Poland's Council of Ministers approved a program to restructure
and privatize the Polish petroleum sector. Although no single program or
specific timeline has been established for privatizing the exploration and
production divisions of POGC, the increased participation by Western companies
using Western capital to undertake oil and gas exploration and to develop and
produce existing reserves is consistent with the approved privatization policy.
The Polish corporate income tax rate is 30% for 2000 and 28% for 2001. Further
reductions in the income tax rate of 2% per year may be enacted down to a rate
of 22%. In some circumstances, tax relief may be available for certain
qualifying capital investments which provide deductions during the initial years
of operation.
46
Management
General
Our articles of incorporation provide that the board of directors shall be
divided into three classes, with each class as equal in number as practicable.
One class is to be elected each year for a three-year term. Officers serve at
the pleasure of the board of directors.
Executive Officers and Directors
The following table sets forth our directors, executive officers and other
significant employees, their ages, all offices and positions with our company
and each respective term of directorship as of July 10, 2000.
Term
Name Age Expires Title
---- --- ------- -----
David N. Pierce............ 53 2002 Chairman of the Board, President
and Chief Executive Officer(1)
Andrew W. Pierce........... 52 2000 Vice-President, Chief Operations
Officer and Director(1)
Scott J. Duncan............ 51 2001 Vice-President, Secretary and
Director
Thomas B. Lovejoy.......... 64 2001 Vice-Chairman, Chief Financial
Officer and Director(2)
Jerzy B. Maciolek.......... 49 2000 Vice-President, International
Exploration and Director
Dennis L. Tatum............ 39 2002 Vice-President, Treasurer and
Director
Peter L. Raven............. 61 2002 Director(1)(2)
Jay W. Decker.............. 48 2000 Director(1)(2)
Dennis B. Goldstein........ 54 2001 Director(1)(2)
- -----------------------
(1) Member of the Rights Redemption Committee. See "Description of Capital
Stock-Preferred Stock."
(2) Member of the Compensation and Audit Committees.
David N. Pierce has been our president, director and chairman since 1992.
Previously, he was president and director of our predecessor, Frontier
Exploration Company, co-founded with his brother, Andrew W. Pierce, in January
1989, which was acquired by us in 1992. Mr. Pierce is a graduate of Princeton
University and Stanford Law School.
Andrew W. Pierce has been our vice-president and director since 1992.
Previously, he was vice-president and director of our predecessor, Frontier
Exploration Company, co-founded with his brother, David N. Pierce, in January
1989, which was acquired by us in 1992.
Scott J. Duncan has been our vice-president and director since May 1993, and
served as treasurer between 1993 and 1998 and secretary since 1998. Mr. Duncan
was a financial consultant to us from our inception in 1992 through April 1993,
when he became a full-time employee. Scott Duncan is a graduate of the
University of Utah School of Business.
Thomas B. Lovejoy has been our vice-chairman of the board of directors and a
consultant to us since 1995. Mr. Lovejoy has been the principal of Lovejoy
Associates, Inc., Greenwich, Connecticut, which provides financial strategic
advice respecting private placements, mergers and acquisitions since 1992. Mr.
Lovejoy has been a director of Scaltech, Inc., Houston, Texas, a processor of
petroleum refinery oil waste since 1993. From 1989 to 1992, Mr. Lovejoy was the
managing director and head of the Natural Resource, Mining and Utility Groups of
Prudential Securities, Inc., and from 1980 to 1988, he was managing director and
head of the Energy and Natural Resources Group of Paine Webber, Inc., New York
City. Mr. Lovejoy received a B.S. from the Massachusetts Institute of Technology
and an M.B.A. from Harvard Business School.
47
Jerzy B. Maciolek has been employed by us since September 1995, and since that
time has been instrumental in our exploration efforts in Poland. Jerzy Maciolek
is a member of the advisory board of POGC. Prior to his employment with us, Mr.
Maciolek was a private consultant for over five years, including consulting on
the oil and gas potential of Poland and Kazakhstan, translating and interpreting
geological and geophysical information for several integrated oil and gas
potential reports on Poland and Kazakhstan and developing applied integrated
geophysical interpretations over gold mines in Nevada, California and Mexico. He
has provided consulting services to us regarding exploration projects in the
western United States and Poland since 1992. Mr. Maciolek obtained a M.S. degree
in exploration geophysics from the Mining and Metallurgy Academy in Krakow,
Poland.
Dennis L. Tatum is our vice-president and treasurer. Mr. Tatum joined us in
March 1997 as controller prior to becoming treasurer in December 1998. From 1989
to 1997, he was employed by Zilkha Energy, Houston, Texas, a private oil and gas
firm with interests in the Gulf of Mexico, where he was instrumental in
overseeing joint ventures. Mr. Tatum received a B.B.A. in accounting from the
University of Texas at Tyler in 1983 and a CPA certificate from the state of
Texas in 1984.
Peter L. Raven is a retired former president of American Ultramar. From 1957
through 1985, he held various positions with Ultramar, PLC, London, England, a
fully integrated oil and gas company, and its U.K. and U.S. subsidiaries,
including chief financial officer of Ultramar, PLC. From 1985 through 1988, he
was executive vice-president, and from 1988 through 1992, president of American
Ultramar. Mr. Raven is a graduate of the Downside School in England, the
Institute of Chartered Accountants in 1962, and the Harvard Business School
Advanced Management Program in 1987.
Jay W. Decker has been president of Patina Oil & Gas Corporation, an independent
oil company, Denver, Colorado, since March 1998, and director of our company
since May 1996. From September 1995 through March 1998, he was executive
vice-president and a director of Hugoton Energy Corporation, Denver, Colorado,
an independent oil company. From 1989 until its merger into Hugoton, Mr. Decker
was president and chief executive officer of Consolidated Oil & Gas, Inc.,
Denver, Colorado. Mr. Decker received a B.S. degree from the University of
Wyoming.
Dennis B. Goldstein is corporate counsel, assistant secretary and manager of
land services for Homestake Mining Company, San Francisco, California, a large
international gold mining company, where he has been employed since 1976. Mr.
Goldstein is a graduate of Brown University and Stanford University Law School,
was a Graduate Fellow in comparative law at the University of Florence, Italy,
and attended the Stanford Executive Program at Stanford University's Graduate
School of Business.
Committees of the Board
There are three committees of the Board of Directors: the Audit Committee, the
Compensation Committee and the Rights Redemption Committee. The members of the
each of these committees are indicated in the previous table.
Certain Relationships and Related Transactions
Unless otherwise indicated, the terms of the following transactions between
related parties were not determined as a result of arm's length negotiations.
Consulting Agreements
From 1997 through April 1999, we engaged Lovejoy and Associates, a consulting
company owned by Thomas B. Lovejoy, one of our directors, to advise us
respecting future financing alternatives and possible sources of debt and equity
financing, with particular emphasis on funding for our Poland activities and our
relationship with the investment community. Under this arrangement, we paid
Lovejoy and Associates $120,000, $200,000 and $60,000 during 1997, 1998 and
1999, respectively. During 1999, the consulting agreement was terminated when
Mr. Lovejoy became our chief financial officer. We engage Dennis B. Goldstein to
provide special legal services from time to time at an hourly rate, not to
exceed an aggregate of $60,000 per year.
48
Officer Loans
On February 17, 1998, two of our executive officers and directors, David N.
Pierce and Andrew W. Pierce, exercised options expiring May 1998 to purchase
300,000 shares of common stock at $1.50 per share. Each of those officers paid
the cost of exercising the options by using a bonus credit of $100,000 awarded
to him during 1997 and signing a full recourse note payable to us for $125,000,
bearing interest at 7.7%. On April 10, 1998, in consideration of the agreement
of the two officers to refrain from selling common stock in market transactions,
we agreed to advance the officers, on a nonrecourse basis, additional funds to
cover their tax liabilities and other amounts. As of December 31, 1999, the
notes receivable and accrued interest totaled $2,036,385. We have no commitment
to advance additional funds to the officers.
In consideration of extending the term of the loans from December 31, 1999
through December 31, 2000, the officers agreed that if the average closing price
of the common stock for five consecutive trading days results in a value of the
collateral equal to or above the total principal and accrued interest balances,
the officers will repay the loans within 45 days either in cash or by tendering
to us that number of shares which, at the average closing price for the previous
five consecutive trading days, equals the principal and interest then accrued.
The notes receivable and accrued interest are collateralized by 233,340 shares
of common stock. In accordance with SFAS No. 114, "Accounting by Creditors for
Impairment of a Loan," we recorded an impairment allowance of $670,371 as of
March 31, 2000, based on the value of the underlying collateral. We will adjust
the impairment allowance quarterly based on the market value of the collateral
shares.
49
Executive Compensation
Summary compensation
The following table sets forth for our last three fiscal years the annual and
long-term compensation earned by, awarded to or paid to the person who was our
chief executive officer and each of our four other highest compensated executive
officers as of the end of the last fiscal year (the "Named Executive Officers").
Long Term Compensation
----------------------------------
Annual Compensation Awards Payouts
------------------------------------- ----------------------- ---------
Other Restricted Securities All Other
Year Annual Stock Underlying LTIP Compen-
Name and Ended Bonus Compen- Award(s) Options/ Payouts sation
Principal Position Dec 31 Salary ($) ($) (1) sation ($) ($) SARs(#)(5) ($) ($)(6)
- --------------------- -------- ----------- ----------- ------------ ---------- ----------- --------- -----------
David N. Pierce..... 1999 $197,466 $242,983 $ -- -- 60,000 -- 7,409
President (CEO) 1998 185,600 185,760 100,000(2) -- 60,000 -- --
1997 153,256 185,760 -- -- 55,000 -- --
Andrew W. Pierce.... 1999 $146,951 $151,307 $ -- -- 50,000 -- 9,228
Vice-President 1998 134,400 115,200 100,000(2) -- 50,000 -- --
(COO) 1997 114,267 115,200 -- -- 45,000 -- --
Thomas B. Lovejoy... 1999 $146,951 $151,307 $ --(4) -- 50,000 -- 5,878
Vice-Chairman 1998 -- -- --(4) -- -- -- --
(CFO) 1997 -- -- --(4) -- -- -- --
Scott J. Duncan..... 1999 $114,806 $118,209 $ -- -- 50,000 -- 7,325
Vice President 1998 105,000 90,000 -- -- 50,000 -- --
Secretary 1997 88,750 90,000 -- -- 45,000 -- --
Jerzy B. Maciolek... 1999 $146,951 $151,307 $100,000(3) -- 50,000 -- 7,149
Vice-President 1998 134,400 115,200 100,000(3) -- 50,000 -- --
Exploration 1997 113,600 115,200 -- -- 45,000 -- --
- --------------------------
(1) All 1999 bonuses were approved by our board of directors on November 1,
1999 and accrued as of December 31, 1999. 25% of the accrued bonus was paid
on February 15, 2000.
(2) During 1998, David N. Pierce and Andrew W. Pierce applied a $100,000 bonus,
which was awarded to them during 1997, against their exercise of stock
options to purchase 150,000 shares each. See "Certain Relationships and
Related Transactions."
(3) During 1998 and 1999, Jerzy B. Maciolek was awarded a $100,000 bonus each
year to be used against future stock option exercises or payable in cash in
the event his employment with us is terminated. At the end of 1999, Mr.
Maciolek had not used the $200,000 bonus.
(4) Excludes $60,000, $200,000 and $120,000 paid during 1999, 1998 and 1997,
respectively, to Lovejoy and Associates, a consulting firm owned by Mr.
Lovejoy, prior to Mr. Lovejoy becoming our chief financial officer during
1999.
(5) Includes stock options only.
(6) Consists of our contributions under our 401(k) plan. No material benefits
are payable on retirement under this plan, which was initiated in 1999.
50
Option/SAR Grants in Last Fiscal Year
The following table sets forth information respecting all individual grants of
options and stock appreciation rights ("SARs") made during the last completed
fiscal year to our Named Executive Officers.
Number
of % of Total
Securities Options/SARs Potential Realizable Value at
Underlying Granted to Assumed Rates of Share Price
Options/SARs Employees Exercise or Appreciation for Option Term ($)
Granted During Fiscal Base Price Expiration ---------------------------------
Name (no.)(1) Year(1) ($/share) Date 5% 10%
- ----------------------- --------------- --------------- ------------- ------------- --------------- ---------------
David N. Pierce 60,000 14.0% $5.750 11/01/06 $140,520 $327,360
Andrew W. Pierce 50,000 11.6 5.750 11/01/06 117,100 272,800
Thomas B. Lovejoy 50,000 11.6 5.750 11/01/06 117,100 272,800
Scott J. Duncan 50,000 11.6 5.750 11/01/06 117,100 272,800
Jerzy B. Maciolek 50,000 11.6 5.750 11/01/06 117,100 272,800
- ---------------------------
(1) Includes stock options only.
51
Aggregate Option/SAR Exercises in Last Fiscal Year and Year-End Option/SAR
Values
The following table sets forth information respecting the exercise of options
and SARs during the last completed fiscal year by our Named Executive Officers
and the fiscal year-end values of unexercised options and SARs.
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money Options/SARs at
Options/SARs at FY End FY End
Shares (no.) ($)
Acquired on Value Exercisable/ Exercisable/
Name Exercise (no.) Realized ($) Unexercisable Unexercisable(1)
- ------------------------- ---------------- -------------- ------------------------ ------------------------------
David N. Pierce -- -- 706,667 / 118,333(2) $ 1,425,000 / $ --
Andrew W. Pierce -- -- 661,667 / 98,333(3) 1,306,250 / --
Thomas B. Lovejoy -- -- 461,667 / 98,333(4) 831,250 / --
Scott J. Duncan -- -- 151,667 / 98,333(5) 118,750 / --
Jerzy B. Maciolek -- -- 361,668 / 148,332(6) 581,250 / --
- -------------------------
(1) Based on the closing sales price for the common stock of $5.06 on December
31, 1999.
(2) Consists of options to purchase 500,000 shares of common stock becoming
exercisable in installments of 100,000 shares per year commencing June 1,
1995, at an exercise price of $3.00 per share, expiring June 9, 2004;
100,000 shares of common stock at an exercise price of $3.00 per share,
expiring October 5, 2000; 50,000 shares of common stock at an exercise
price of $8.875 per share expiring November 4, 2001; 55,000 shares of
common stock becoming exercisable in installments of 18,333 shares per year
commencing December 1, 1998, at an exercise price of $6.625 per share,
expiring November 30, 2004; 60,000 shares of common stock becoming
exercisable in installments of 20,000 shares per year commencing November
10, 1999, at an exercise price of $8.625 per share, expiring November 10,
2005; and 60,000 shares of common stock becoming exercisable in
installments of 20,000 shares per year commencing November 1, 2000, at an
exercise price of $5.75 per share, expiring November 1, 2006.
(3) Consists of options to purchase 500,000 shares of common stock becoming
exercisable in installments of 100,000 shares per year commencing June 1,
1995, at an exercise price of $3.00 per share, expiring June 9, 2004;
50,000 shares of common stock at an exercise price of $3.00 per share,
expiring October 5, 2000; 65,000 shares of common stock at an exercise
price of $8.875 per share, expiring November 4, 2001; 45,000 shares of
common stock becoming exercisable in installments of 15,000 shares per year
commencing on December 1, 1998, at an exercise price of $6.625 per share,
expiring November 30, 2004; 50,000 shares of common stock becoming
exercisable in installments of 16,667 shares per year commencing on
November 10, 1999, at an exercise price of $8.625 per share, expiring
November 10, 2005; and 50,000 shares of common stock becoming exercisable
in installments of 16,667 shares per year commencing November 1, 2000, at
an exercise price of $5.75 per share, expiring November 1, 2006.
(4) Consists of options to purchase 150,000 shares of common stock becoming
exercisable on August 3, 1995, at an exercise price of $3.00 per share,
expiring August 3, 2000; 100,000 shares of common stock becoming
exercisable on August 3, 1995, at an exercise price of $3.00 per share,
expiring August 3, 2001; 100,000 shares of common stock becoming
exercisable on August 3, 1995, at an exercise price of $3.00 per share,
expiring August 3, 2002; 65,000 shares of common stock at an exercise price
of $8.875 per share, expiring November 4, 2001; 45,000 shares of common
stock becoming exercisable in installments of 15,000 shares per year
commencing on December 1, 1998, at an exercise price of $6.625 per share,
expiring November 30, 2004; 50,000 shares of common stock becoming
exercisable in installments of 16,667 shares per year commencing on
November 10, 1999, at an exercise price of $8.625 per share, expiring
November 10, 2005; and 50,000 shares of common stock becoming exercisable
in installments of 16,667 shares per year commencing November 1, 2000, at
an exercise price of $5.75 per share, expiring November 1, 2006.
(5) Includes options to purchase 50,000 shares of common stock at an exercise
price of $3.00 expiring October 5, 2000; 55,000 shares of common stock at
an exercise price of $8.875 per share, expiring November 4, 2001; 45,000
shares of common stock becoming exercisable in installments of 15,000
shares per year commencing December 1, 1998, at an exercise price of $6.625
per share, expiring November 30, 2004; 50,000 shares of common stock
becoming exercisable in installments of 16,667 shares per year commencing
on November 10, 1999, at an exercise price of $8.625 per share, expiring
November 10, 2005; and 50,000 shares of common stock becoming exercisable
in installments of 16,667 shares per year commencing November 1, 2000, at
an exercise price of $5.75 per share, expiring November 1, 2006.
(6) Includes options to purchase 150,000 shares of common stock at any time
through August 30, 2000, at an exercise price of $1.50; 65,000 shares of
common stock at an exercise price of $8.875 per share through November 4,
2001; 50,000 shares of common stock becoming exercisable in installments of
16,667 shares per year commencing on May 12, 1998, at an exercise price of
$8.25 per share, expiring May 11, 2004; 100,000 shares of common stock
becoming exercisable in installments of 33,333 shares per year commencing
on July 18, 1998, at an exercise price of $7.25 per share, expiring July
17, 2004; 45,000 shares of common stock becoming exercisable in
installments of 15,000 shares per year commencing December 1, 1998, at an
exercise price of $6.625 per share, expiring November 30, 2004; 50,000
shares of common stock becoming exercisable in installments of 16,667 per
year commencing on November 10, 1999, at an exercise price of $8.625 per
share, expiring November 10, 2005; and 50,000 shares of common stock
becoming exercisable in installments of 16,667 shares per year commencing
November 1, 2000, at an exercise price of $5.75 per share, expiring
November 1, 2006.
52
Directors' Compensation
We pay our nonemployee directors $18,000 per year and have historically granted
them stock options to purchase our common stock. We also reimburse our directors
for costs they incur in attending meetings of the board of directors and our
committees. We do not pay any separate compensation to employees who serve on
the board of directors.
During 1999, we paid Lovejoy and Associates, a consulting firm owned by Thomas
B. Lovejoy, $60,000 prior to Mr. Lovejoy becoming our chief financial officer;
we paid Peter L. Raven a cash fee of $18,000 and granted him seven-year options
to purchase 10,000 shares of common stock at $5.75 per share; we paid Jay W.
Decker a cash fee of $18,000 and granted him seven-year options to purchase
10,000 shares of common stock at $5.75 per share; and we paid Dennis B.
Goldstein a cash fee of $16,500 and granted him seven-year options to purchase
16,000 shares of common stock at a weighted average exercise price of $6.13 per
share. The exercise prices of the foregoing options are equal to the market
price of the common stock as of the date of each grant.
Employment Agreements, Termination of Employment and Change in Control
We have entered into executive employment agreements with each of the executive
officers named in the Summary Compensation Table, except for Thomas B. Lovejoy.
Each employment agreement is for a three-year term and is automatically extended
for an additional year on the anniversary date of such agreement. Annual
salaries during 2000 are David N. Pierce, $218,568; Andrew W. Pierce, Thomas B.
Lovejoy and Jerzy B. Maciolek, $162,655 each, and Scott J. Duncan, $127,075. In
addition, the executive officers may receive such bonuses or incentive
compensation as the board of directors or compensation committee may deem
appropriate. Each agreement provides that the board of directors or compensation
committee may increase the base salary under the agreements at the beginning of
each year, with such increases to be at least 7.5% for David N. Pierce, Andrew
W. Pierce and Scott J. Duncan. Each executive officer is entitled under his
employment agreement to certain continuation of compensation in the event the
agreement is terminated upon death or disability or if we terminate the
agreement other than for cause.
In addition to the foregoing terms, Mr. Maciolek's employment agreement provides
for annual bonuses of $100,000, payable in cash, stock or options, as may be
determined by the board of directors or the compensation committee, based on the
progress of projects on which Mr. Maciolek is primarily engaged. On each of May
12, 1998, 1999 and 2000, Mr. Maciolek received a bonus in the form of a $100,000
credit that may be applied against the exercise of his options to purchase
common stock or be paid in cash if his employment with us is terminated.
Each executive employment agreement provides that, on the occurrence of a change
of control event, the employee may terminate the agreement. In the event of such
termination, the employee is entitled to a termination payment equal to 150% of
his annual salary (100% in the case Jerzy B. Maciolek) and the value of
previously granted employee benefits. Additionally, we are required to maintain
certain benefits and, in the case of David N. Pierce, Andrew W. Pierce and Scott
J. Duncan, repurchase outstanding options. Options held by Jerzy B. Maciolek
will immediately vest on such termination. For purposes of the foregoing, a
change of control shall exist on any of the following events: (i) our sale of
all or substantially all of our assets; (ii) a transaction or series of
transactions resulting in a single person or group of persons under common
control owning 25% of the outstanding common stock; (iii) a change in the
composition of the board of directors so that more than 50% of the directors are
persons neither nominated nor elected by the board of directors or any
authorized committee; (iv) our decision to terminate our business and liquidate
our assets; or (v) a merger or consolidation in which our existing stockholders
own less than 50% of the outstanding voting shares of the surviving entity.
Options Granted to Officers, Directors, Employees and Consultants
We currently have outstanding options to purchase an aggregate of 3,896,501
shares that have been granted to our officers, directors, employees and
consultants. Of such options, 587,334 contain vesting limitations contingent on
continuing association with us. These options are exercisable at prices ranging
between $1.50 and $10.25 per share. Options issued to executive officers and
directors contain terms providing that in the event of a change in control as
53
described above and at the election of the option holder, the unexercised
options will be canceled, and we will pay to the option holder an amount equal
to the number of unexercised options multiplied by the amount by which the fair
market value of the common stock as of the date preceding the change of control
event exceeds the option exercise price. The grants of options to officers and
directors were not the result of arm's length negotiations.
54
Principal Stockholders
The following table sets forth, as of July 10, 2000, the name, address and
shareholdings of each person who owns of record, or was known by us to own
beneficially, 5% or more of the common stock currently issued and outstanding;
the name and shareholdings of each director; and the shareholdings of all
executive officers and directors as a group. Unless otherwise indicated, all
shares consist of common stock, and the named person or group owns all such
shares beneficially and of record. Options include only vested amounts; unvested
options are excluded.
Directors and Principal Stockholders
Percentage of
Beneficial Owner Nature of Ownership Amount(1) Ownership(2)
David N. Pierce................................... Common Stock 200,493(3) 1.1%
Options 706,667(6) 3.8
-------------
Total 907,160 4.9
Andrew W. Pierce.................................. Common Stock 200,500 1.1
Options 661,667(6) 3.6
-------------
Total 862,167 4.7
Scott J. Duncan................................... Common Stock 175,500(5) 1.0
Options 151,667(6) 0.8
-------------
Total 327,167 1.8
Thomas B. Lovejoy................................. Common Stock 527,367(4) 3.0
Options 461,667(6) 2.5
-------------
Total 989,034 5.4
Jerzy B. Maciolek................................. Options 378,334(6) 2.1
Dennis L. Tatum................................... Common Stock 2,500 --
Options 46,801(6) 0.3
-------------
Total 49,301 0.3
Peter L. Raven.................................... Common Stock 40,000 0.2
Options 12,000(6) 0.1
-------------
Total 52,000 0.3
Jay W. Decker..................................... Options 12,000(6) 0.1
Dennis B. Goldstein............................... Common Stock 5,400(7) --
Options 2,000 --
-------------
Total 7,400 --
All Executive Officers............................ Common Stock 1,151,760 6.5
and Directors as a Options 2,432,803 12.0
------------- -----------------
Group (9 persons) Total 3,584,563 17.8
=============
- -----------------------------
(1) Except as otherwise noted, shares are owned beneficially and of record, and
such record stockholder has sole voting, investment and dispositive power.
(2) Calculations of total percentages of ownership outstanding for each
individual assume the exercise of currently vested options held by that
individual to which the percentage relates. Percentages calculated for
totals of all executive officers and directors as a group assume the
exercise of all vested options held by the indicated group.
(3) Includes 48,000 shares held by David N. Pierce as custodian for minor
children. Mr. Pierce is deemed to hold or share voting and dispositive
power over all of such shares. Excludes 19,000 shares held by Mr. Pierce's
wife, Mary Phillips, and 23,000 held by Mary Phillips as custodian for an
adult child, of which Mr. Pierce disclaims beneficial ownership.
55
(4) Includes 41,000 shares held in trust for the benefit of Thomas B. Lovejoy's
children, 49,500 shares held in Mr. Lovejoy's IRA account, 10,000 shares
held by Mr. Lovejoy's spouse's IRA account and 210,000 shares held by
Lovejoy Associates, Inc. (of which Mr. Lovejoy is sole owner). Mr. Lovejoy
is deemed to hold dispositive power over all of such shares. Mr. Lovejoy's
address is 48 Burying Hill Road, Greenwich CT 06831.
(5) Includes 123,000 shares held by Scott J. Duncan jointly with his wife,
Cathy H. Duncan; 7,000 shares held solely by Cathy H. Duncan and 48,000
shares held by Cathy Duncan as custodian for minor children. Mr. Duncan is
deemed to hold or share voting and dispositive power over all of such
shares.
(6) These vested options give the holders the right to acquire shares of common
stock at prices ranging from $1.50 to $10.25 per share with various
expiration dates ranging from August 2000 to December 2006.
(7) Includes 400 shares held by Dennis B. Goldstein as custodian for a minor
child. Mr. Goldstein is deemed to hold or share voting and dispositive
power over all of such shares.
56
Description of Capital Stock
We are authorized to issue 30,000,000 shares of common stock, $0.001 par value,
and 5,000,000 shares of preferred stock (including 500,000 shares of Series A
Preferred Stock), $0.001 par value. The board of directors has proposed to the
stockholders at the 2000 annual meeting an amendment to the articles of
incorporation to increase the authorized common stock to 100,000,000 shares.
Common Stock
As of July 10, 2000, we had 17,818,003 shares of common stock issued and
outstanding. The holders of common stock are entitled to one vote per share on
each matter submitted to a vote at any meeting of stockholders. Holders of
common stock do not have cumulative voting rights, and therefore, a majority of
the outstanding shares voting at a meeting of stockholders is able to elect the
entire board of directors, and if they do so, minority stockholders would not be
able to elect any members to the board of directors. Our bylaws provide that a
majority of our issued and outstanding shares constitutes a quorum for
stockholders' meetings, except with respect to certain matters for which a
greater percentage quorum is required by statute.
Our stockholders have no preemptive rights to acquire additional shares of
common stock or other securities. Our common stock is not subject to redemption
and carries no subscription or conversion rights. In the event of liquidation of
our company, the shares of common stock are entitled to share equally in
corporate assets after satisfaction of all liabilities and the payment of any
liquidation preferences.
Holders of common stock are entitled to receive such dividends as the board of
directors may from time to time declare out of funds legally available for the
payment of dividends. We seek growth and expansion of our business through the
reinvestment of profits, if any, and do not anticipate that we will pay
dividends on the common stock in the foreseeable future. In certain cases,
common stockholders may not receive dividends, if and when declared by the board
of directors, until we have satisfied our obligations to any preferred
stockholders.
As of July 10, 2000, we had reserved for issuance on exercise of options and
warrants at exercise prices ranging from $1.50 to $10.25 an aggregate of
4,146,167 shares of common stock consisting of 3,124,347 shares issuable on the
exercise of outstanding options and warrants with a weighted average exercise
price of $5.25 per share, and 1,021,820 shares issuable on the exercise of
options previously granted but not yet exercisable at a weighted exercise price
of $6.90 per share.
The board of directors has authority to authorize the offer and sale of
additional securities without the vote of or notice to existing stockholders,
and it is likely that additional securities will be issued to provide future
financing. The issuance of additional securities could dilute the percentage
interest and per share book value of existing stockholders, including persons
purchasing common stock in this offering.
Preferred Stock
Under our articles of incorporation, our board of directors is authorized,
without stockholder action, to issue preferred stock in one or more series and
to fix the number of shares and rights, preferences and limitations of each
series. Among the specific matters that may be determined by the board of
directors are the dividend rate, the redemption price, if any, conversion
rights, if any, the amount payable in the event of any voluntary liquidation or
dissolution of our company and voting rights, if any.
Series A Preferred Stock
We are authorized to issue 500,000 shares of Series A Preferred Stock. Such
preferred stock is nonredeemable and subordinate to any other series of our
Preferred Stock which may at any time be issued. We currently do not have any
Preferred Stock outstanding. The Series A Preferred Stock is authorized for
issuance pursuant to the preferred
57
stock purchase rights that trade with the common stock, as described below. Each
share of Series A Preferred Stock is entitled to receive, when, as and if
declared, a dividend in an amount equal to one hundred times the cash dividend
declared on each share of common stock and one hundred times any noncash
dividends declared with respect to each share of common stock, in like kind,
other than a dividend payable in shares of common stock. In the event of
liquidation, the holder of each share of Series A Preferred Stock shall be
entitled to receive a liquidation payment in an amount equal to one hundred
times the liquidation payment made per share of our common stock. Each share of
Series A Preferred Stock has one hundred votes, voting together with the common
stock and not as a separate class, unless otherwise required by law or our
articles of incorporation. In the event of any merger, consolidation or other
transaction in which shares of our common stock are exchanged, each share of
Series A Preferred Stock is entitled to receive one hundred times the amount
received per share of our common stock.
Each share of our common stock includes one right (a Right) which entitles the
registered holder to purchase from us one one-hundredth (1/100) of a share of
Series A Preferred Stock at an exercise price of $100 per Right, subject to
adjustment to prevent dilution. Initially the Rights will not be exercisable,
certificates for the Rights will not be issued and, unless and until the Rights
become exercisable, they will be transferred with and only with the shares of
common stock. The Rights are exercisable on the Separation Date, which will
occur on the earlier of (i) ten calendar days following a public announcement
that certain persons or groups have acquired 20% or more of our outstanding
voting shares, (ii) ten calendar days following the commencement or public
announcement of the intent of any person to acquire 20% or more of our
outstanding voting shares; or (iii) such later date as may be fixed by the board
of directors. Following the Separation Date, certificates representing the
Rights will be mailed to holders of record of common stock and thereafter such
certificates alone will evidence the Rights. If any person acquires more than
20% of our outstanding common stock or we engage in certain business
combinations, other than pursuant to a tender or exchange offering for all
shares of common stock approved by the board of directors, the Rights become
exercisable for common stock, in lieu of Series A Preferred Stock, by paying one
half of the exercise price of the Right for a number of shares of our common
stock having an aggregate market price equal to such exercise price. Any Rights
that are or were beneficially owned by a person who has acquired 20% or more of
the outstanding common stock will become void.
We may redeem the Rights at $.01 per Right at any time until ten business days
after public announcement that a person has acquired 20% or more of the
outstanding shares of common stock, provided that the redemption is approved by
our Rights Redemption Committee, a committee consisting of at least three
continuing directors, a majority of whom is not our employees. The Rights will
expire on April 4, 2007, unless earlier redeemed by us. Unless the Rights have
been previously redeemed, all shares of common stock issued by us will include
Rights. As long as the Rights are redeemable, the Rights Redemption Committee,
without further stockholder approval may, except with respect to the exercise
price or expiration date of the Rights, amend the Rights in any matter that, in
the opinion of the board of directors, does not materially adversely affect the
interests of holders of the Rights.
The Stockholder Rights Agreement contemplates that we will reserve a sufficient
number of authorized but unissued shares of common stock to permit the exercise
in full of the Rights granted to the current stockholders should these Rights
become exercisable. Because of the number of authorized but unissued shares, as
compared to the number of shares that will be outstanding after the offering,
the number of shares of common stock presently authorized may be insufficient to
permit exercise in full of the Rights upon the occurrence of a triggering event.
Consequently, the effectiveness of the Stockholder Rights Agreement may be
impaired if an insufficient number of shares is authorized and reserved for
issuance upon the exercise of Rights under the agreement.
Certain Article and Bylaw Provisions
Our articles of incorporation divide the members of the board of directors into
three classes of directors, with each class to be as nearly equal in number of
directors as possible, serving staggered, three-year terms. Our articles of
incorporation also provide that directors may be removed, with or without cause,
by a two-thirds majority of the stockholders at a meeting called for that
purpose and that any resulting vacancies can be filled by only a vote of a
majority of the directors remaining in office.
58
Our bylaws permit stockholders to nominate a person for election as a director
or bring other matters before a stockholder meeting only if written notice of
such intent is provided to us at least 30 days prior to the meeting. Such notice
of intent to nominate a person for election as a director is required to set
forth the same kind of information respecting such nominee as would be required
under the proxy rules of the SEC, including the written consent of the nominee
to serve as a director, if elected, and the name and address of the stockholder
making the nomination, as well as the number of shares of stock owned by such
stockholder. In the case of other proposed business, the notice must set forth a
brief description of each matter proposed, the name and address of the
stockholder proposing the matter, the number of shares of stock owned by such
stockholder and any material interest of such stockholder in such matter.
Nevada law provides that a merger or consolidation, sale or similar transaction
involving all or substantially all of our assets, the issuance of securities
having an aggregate value equal to 5% or more of the aggregate market of all our
outstanding shares or the reclassification, recapitalization or similar
transaction involving an "interested stockholder" (as defined), within three
years after the stockholder became interested, cannot be completed unless such
transaction is approved by our board of directors. After the expiration of three
years after a person becomes an interested stockholder, a transaction cannot be
completed with the interested stockholder unless it is approved by the board of
directors or a majority of the outstanding voting power not beneficially owned
by the interested stockholder, unless certain "fair price" provisions are met.
Such fair price provisions generally require that the amount of cash and the
market value of the consideration to be received per share by all holders of our
outstanding common stock not beneficially owned by the interested stockholder be
at least equal to the higher of the price per share paid by the interested
stockholder or the market value on the date of announcement of the proposed
combination. For purposes of these provisions, an interested stockholder is one
who beneficially owns, directly or indirectly, 10% or more of the voting power
of our outstanding stock.
The foregoing provisions may tend to deter any potential unfriendly offers or
other efforts to obtain control of us that are not approved by our board of
directors and thereby deprive the stockholders of opportunities to sell shares
of common stock at prices higher than the prevailing market price. On the other
hand, these provisions may tend to assure continuity of management and corporate
policies and to induce any person seeking control of us or a business
combination with us to negotiate on terms acceptable to our then elected board
of directors.
59
Selling Stockholders
This prospectus relates to the resale of 2,969,000 shares of our common stock by
the selling stockholders. The following table provides certain information
concerning the resale of shares of common stock by the selling stockholders and
assumes that all shares offered by the selling stockholders will be sold. We
will not receive any proceeds from the resale of the common stock by the selling
stockholders.
Common Stock
---------------------------------------------------------------------
Beneficially Beneficially
Owned Before Offering Owned After Offering
--------------------------- Number ---------------------------
Selling Stockholder Number Percent to be Sold Number Percent
------------------- ------ ------- ---------- ------ -------
Cumberland Benchmarked Partners, L.P.................... 270,000 1.5 270,000 -- --
Longview Partners....................................... 220,000 1.2 220,000 -- --
Longview Partners A, L.P................................ 20,000 * 20,000 -- --
Longview Partners B, L.P................................ 140,000 * 140,000 -- --
Longview Partners C, L.P................................ 50,000 * 50,000 -- --
Spindrift Partners, L.P................................. 800,000 4.5 800,000 -- --
Spindrift Partners (Bermuda) L.P........................ 200,000 1.1 200,000 -- --
CastleRock Partners, L.P................................ 563,480 3.2 563,480 -- --
CastleRock Partners II, L.P............................. 54,110 * 54,110 -- --
CastleRock Fund, Ltd.................................... 232,410 1.3 232,410 -- --
Edith N. Bacon.......................................... 10,000 * 10,000 -- --
Eric K. Bacon........................................... 11,000 * 10,000 1,000 *
Robin B. Greenwood...................................... 10,000 * 10,000 -- --
Peter J. Lagemann....................................... 2,000 * 2,000 -- --
Carter P. Thacher....................................... 32,000 * 32,000 -- --
Ironman Energy Capital, L.P............................. 130,000 * 130,000 -- --
Longwood Partners, LP................................... 175,000 1.0 175,000 -- --
Daniel V. Drake......................................... 80,000 * 25,000 55,000 *
Talmor Capital Management, L.L.C........................ 125,000 * 25,000 100,000 *
-------------
Total.............................................. 2,969,000
=============
- ----------------------------
* Less than 1%.
60
Plan of Distribution
The selling stockholders may from time to time offer any or all of their shares
in one or more of the following transactions (which may include block
transactions):
o on Nasdaq;
o in the over-the-counter market;
o through short sales of shares;
o in negotiated transactions other than in such markets;
o by pledge to secure debts and other obligations;
o in connection with the writing of nontraded and exchange-traded put
and call options, in hedge transactions, in covering previously
established short positions and in settlement of other transactions in
standardized or over-the-counter options; or
o in any combination of any of the above transactions.
The selling stockholders may sell their shares at market prices prevailing at
the time of sale, at prices related to such prevailing market prices, at
negotiated prices or at fixed prices. The selling stockholders may sell their
shares directly to purchasers or to or through broker-dealers, which may act as
agents or principals. The selling stockholders may compensate broker-dealers in
the form of commissions, discounts or selling concessions. The broker-dealers
may also receive compensation from any purchaser of the shares for whom the
broker-dealers acts as agent or to whom it sells as a principal.
The selling stockholders may also resell all or a portion of their shares in
open market transactions in reliance on Rule 144 under the Securities Act, as
long as they meet the criteria and comply with the requirements of that rule.
The selling stockholders have advised us that they have not entered into any
agreements, understandings or arrangements with any underwriters or
broker-dealers regarding the sale of their shares, and we do not intend to enter
into any arrangement with any underwriter or coordinating broker-dealer with
respect to sales of the shares by the selling stockholders.
The selling stockholders and any broker-dealers that participate in the
distribution of their shares may be deemed to be "underwriters" within the
meaning of section 2(11) of the Securities Act. Any commissions received by such
broker-dealers and any profits realized on the resale of shares by them may be
considered underwriting discounts and commissions under the Securities Act. We
have agreed to indemnify each selling stockholder against certain liabilities,
including liabilities arising under the Securities Act and, alternatively, to
contribute toward amounts paid by the selling stockholders due to such
liabilities. The selling stockholders may agree to indemnify any agent, dealer
or broker-dealer that participates in sales of the shares against certain
liabilities, including liabilities arising under the Securities Act.
The selling stockholders may be subject to the prospectus delivery requirements
of the Securities Act and to applicable provisions of and regulations under the
Exchange Act that may limit the timing of their purchases and sales of our
shares.
We are required to pay all costs, expenses and fees incident to the registration
of the shares, including fees and disbursements of counsel to the selling
stockholders, and the selling stockholders are required to pay any brokerage
commissions or similar selling expenses incurred by them in connection with the
sales of their shares.
As used in this prospectus, "selling stockholders" includes donees, pledges,
transferees or other successors in interest who are selling shares they received
after the date of this prospectus from a selling stockholder named in this
prospectus as a gift, pledge, partnership distribution or other nonsale related
transfer.
61
Upon being notified by a selling stockholder that the selling stockholder has
entered into a material arrangement with a broker-dealer for the sale of the
selling stockholder's shares through a block trade, special offering, exchange
distribution or secondary distribution or a purchase by a broker or dealer, we
will file a supplement to this prospectus, if required by Rule 424(b) under the
Securities Act, disclosing certain information about the arrangement and the
sale of the shares involved. In addition, upon being notified by a selling
stockholder that a donee, pledgee, transferee or other successor-in-interest
intends to sell more than 500 shares, we will file an appropriate supplement to
this prospectus.
62
Where You Can Find Additional Information
We have filed with the Securities and Exchange Commission a registration
statement on Form S-1 under the Securities Act for the common stock sold in this
offering. This prospectus does not contain all of the information set forth in
the registration statement and the accompanying exhibits and schedules. For
further information about us and our common stock, we refer you to the
registration statement and the accompanying exhibits and schedules. Statements
contained in this prospectus regarding the contents of any contract or any other
document to which we refer are not necessarily complete. In each instance,
reference is made to the copy of the contract or document filed as an exhibit to
the registration statement, and each statement is qualified in all respects by
that reference. Copies of the registration statement and the accompanying
exhibits and schedules may be inspected without charge at the public reference
facilities maintained by the Securities and Exchange Commission at room 1024,
450 Fifth Street, N.W., Washington, D.C. 20549 and at the regional offices of
the Securities and Exchange Commission located at Seven World Trade Center,
Suite 1300, New York, New York 10048 and Citicorp Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60661. Copies of these materials may be
obtained at prescribed rates from the public reference room of the Securities
and Exchange Commission at room 1024, 450 Fifth Street, N.W., Washington, D.C.
20549. You may obtain information on the operation of the public reference room
by calling the Securities and Exchange Commission at 1-800-SEC-0330. The
Securities and Exchange Commission maintains a web site that contains reports,
proxy and information statements and other information regarding registrants
that file electronically with the Securities and Exchange Commission. The
address of the site is http://www.sec.gov.
We are subject to the reporting requirements of the Securities Exchange Act of
1934, and we file annual, quarterly and special reports, proxy statements and
other information with the Securities and Exchange Commission. You may read and
copy any document that we file at the Securities and Exchange Commission's
public reference rooms in Washington, D.C., New York, New York, and Chicago,
Illinois. Please call the Securities Exchange Commission at 1-800-SEC-0330 for
further information on the public reference rooms. Our SEC filings are also
available to you free of charge at the Securities Exchange Commission's web site
at http://www.sec.gov. The common stock is traded under the symbol "FXEN" on the
Nasdaq National Market. Material filed by us can be inspected at the offices of
the National Association of Securities Dealers, Inc., Reports Section, 1735 K
Street, N.W., Washington, D.C. 20006.
Legal Matters
Certain legal matters respecting the validity under the Nevada Revised Statutes
of the common stock to be sold by the selling stockholders have been passed upon
for us by Kruse, Landa & Maycock, L.L.C.
Experts
The consolidated financial statements as of December 31, 1999 and 1998 and for
each of the three years in the period ended December 31, 1999 included in this
Form S-1 have been so included in reliance upon the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in auditing and accounting.
The estimated reserve evaluations and related calculations of Larry D. Krause,
independent petroleum engineer, respecting our domestic reserves included in
this prospectus have been included herein in reliance upon the authority of Mr.
Krause as an expert in petroleum engineering.
63
Glossary of Oil and Gas Terms
"Bpd" means barrels of oil per day.
"Bbl" means barrel of oil.
"Bcf" means billion cubic feet of natural gas.
"Bcfe" means billion cubic feet of natural gas equivalent using a ratio of one
barrel of oil to 6,000 cubic feet of natural gas.
"Carried" 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, that
condenses to a liquid (i.e., falls out of wet gas) as the wet gas is sent
through a mechanical separator near the well.
"Development well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
"Exploratory well" means a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
"Field" means an area consisting of single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic conditions.
"Gross" acres and "gross" wells means the total number of acres or wells, as the
case may be, in which an interest is owned, either directly or through a
subsidiary or other Polish enterprise in which we have an interest.
"MBbls" means thousand barrels of oil.
"MMBbls" means million barrels of oil.
"MMcfe" means million cubic feet of natural gas equivalent using a ratio of one
barrel of oil to 6,000 cubic feet of gas.
"MMcf" means million cubic feet of natural gas.
"MMBOE" means million barrels of oil equivalent.
"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, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. "Proved reserves" may be developed or
undeveloped.
"PV-10 Value" means the estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. 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 nonproperty
related expenses such as general and administrative costs, debt service, future
income tax expense or depreciation, depletion and amortization.
"Reservoir" means a porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and that is distinct and separate from other
reservoirs.
64
"Step-out" means a well drilled outside well locations offsetting a producing
well but within the possible or probable extent of a reservoir.
"Stratigraphic test" means a drilling effort, geologically directed, to obtain
information pertaining to a specific geologic condition. Stratigraphic test
wells are customarily drilled without the intention of completing for oil or gas
production.
"Tcf" means trillion cubic feet of natural gas.
65
Index to Financial Statements
Page
Consolidated Balance Sheets as of March 31, 2000 and
December 31, 1999........................................................F-2
Consolidated Statements of Operations for the Three Months
Ended March 31, 2000 and 1999............................................F-4
Consolidated Statements of Cash Flows for the Three Months
Ended March 31, 2000 and 1999............................................F-5
Notes to Consolidated Financial Statements.................................F-6
Report of PricewaterhouseCoopers LLP, Independent Accountants..............F-9
Consolidated Balance Sheets as of December 31, 1999 and 1998...............F-10
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997.........................................F-12
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997.........................................F-13
Consolidated Statements of Stockholders' Equity for the Years
Ended December 31, 1999, 1998 and 1997...................................F-14
Notes to Consolidated Financial Statements.................................F-15
F-1
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March December
31, 2000 31, 1999
--------------- ---------------
ASSETS
Current assets:
Cash and cash equivalents.............................................. $ 3,254,304 $ 1,619,237
Investment in marketable debt securities............................... 2,091,908 5,249,003
Accounts receivable:
Accrued oil sales.................................................... 293,499 243,183
Interest receivable.................................................. 29,788 171,242
Joint interest owners and others..................................... 62,152 86,723
Advances to oil and gas ventures....................................... 13,192 --
Inventory.............................................................. 70,844 66,361
Other current assets................................................... 106,894 126,006
--------------- ---------------
Total current assets............................................... 5,922,581 7,561,755
--------------- ---------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved............................................................... 2,175,442 1,687,089
Unproved............................................................. 1,398,546 1,382,880
Other property and equipment........................................... 2,793,510 2,652,102
--------------- ---------------
Gross property and equipment....................................... 6,367,498 5,722,071
Less accumulated depreciation, depletion and amortization.............. (3,216,824) (3,173,493)
--------------- ---------------
Net property and equipment......................................... 3,150,674 2,548,578
--------------- ---------------
Other assets:
Certificates of deposit................................................ 356,500 356,500
Other.................................................................. 2,789 2,789
--------------- ---------------
Total other assets................................................. 359,289 359,289
--------------- ---------------
Total assets............................................................. $ 9,432,544 $ 10,469,622
============= =============
-- Continued --
The accompanying notes are an integral part of the
consolidated financial statements.
F-2
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
-- Continued --
March December
31, 2000 31, 1999
--------------- ---------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable....................................................... $ 712,379 $ 623,911
Accrued liabilities.................................................... 1,118,675 1,478,862
--------------- ---------------
Total current liabilities.......................................... 1,831,054 2,102,773
--------------- ---------------
Total liabilities.................................................. 1,831,054 2,102,773
--------------- ---------------
Stockholders' equity:
Common stock, $.001 par value, 30,000,000 shares
authorized, 14,849,003 issued and outstanding as of
March 31, 2000 and December 31, 1999................................. 14,849 14,849
Notes receivable from officers......................................... (1,400,040) (1,370,873)
Additional paid-in capital............................................. 38,480,556 38,480,556
Accumulated deficit.................................................... (29,493,875) (28,757,683)
--------------- ---------------
Total stockholders' equity........................................... 7,601,490 8,366,849
--------------- ---------------
Total liabilities and stockholders' equity............................... $ 9,432,544 $ 10,469,622
=============== ===============
The accompanying notes are an integral part of the
consolidated financial statements.
F-3
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
For the three months ended
March 31,
----------------------------------------
2000 1999
----------------- -----------------
Revenues:
Oil sales............................................ $ 596,630 $ 233,708
Drilling revenue..................................... 73,738 87,543
----------------- -----------------
Total revenues................................... 670,368 321,251
----------------- -----------------
Operating costs and expenses:
Lease operating expenses............................. 284,992 236,069
Production taxes..................................... 6,946 14,368
Geological and geophysical costs..................... 484,409 179,832
Drilling costs....................................... 75,265 52,874
Depreciation, depletion and amortization............. 87,068 126,429
General and administrative........................... 596,967 536,389
----------------- -----------------
Total operating costs and expenses............... 1,535,647 1,145,961
----------------- -----------------
Operating loss......................................... (865,279) (824,710)
----------------- -----------------
Other income (expense):
Interest and other income............................ 134,254 102,191
Interest expense..................................... (308) --
Impairment of notes receivable from officers......... (4,859) --
----------------- -----------------
Total other income............................... 129,087 102,191
----------------- -----------------
Net loss............................................... $ (736,192) $ (722,519)
================= =================
Basic and diluted net loss per common share............ $ (.05) $ (.06)
================= =================
Basic and diluted weighted average number
of shares outstanding................................ 14,849,003 13,054,503
================= =================
The accompanying notes are an integral part of the
consolidated financial statements.
F-4
FX ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
For three months ended
March 31,
---------------------------------------
2000 1999
----------------- -----------------
Cash flows from operating activities:
Net loss........................................................... $ (736,192) $ (722,519)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization....................... 87,068 126,429
Impairment of notes receivable from officers................... 4,859 --
Interest income on officer loans............................... (34,026) (28,340)
Increase (decrease) from changes in working capital items:
Accounts receivable.............................................. 115,709 10,700
Advances to oil and gas ventures................................. (13,192) --
Inventory........................................................ (4,483) 1,621
Other current assets............................................. 19,112 (4,214)
Accounts payable and accrued liabilities......................... (447,223) (103,484)
----------------- -----------------
Net cash used in operating activities.......................... (1,008,368) (719,807)
----------------- -----------------
Cash flows from investing activities:
Additions to oil and gas properties................................ (382,475) (65,036)
Additions to other property and equipment.......................... (131,185) (12,382)
Additions to other assets.......................................... -- (2,789)
Proceeds from sale of property interests........................... -- 3,000
Purchase of marketable debt securities............................. (1,384,905) (1,041,915))
Proceeds from maturing marketable debt securities.................. 4,542,000 1,065,000
----------------- -----------------
Net cash provided by (used in) investing activities.............. 2,643,435 (54,122)
----------------- -----------------
Cash flows from financing activities:
Advances to officers............................................... -- (97,810)
----------------- -----------------
Net cash used in financing activities............................ -- (97,810)
----------------- -----------------
Increase (decrease) in cash and cash equivalents..................... 1,635,067 (871,739)
Cash and cash equivalents at beginning of period..................... 1,619,237 1,811,780
----------------- -----------------
Cash and cash equivalents at end of period........................... $ 3,254,304 $ 940,041
================= =================
Supplemental non-cash activity disclosure:
Non-cash investing activities
Additions to oil and gas properties included $121,544 and $269,047 of
additions financed with accounts payable and accrued liabilities for the periods
ended March 31, 2000 and 1999, respectively. Additions to other property and
equipment included $53,960 of additions financed with accounts payable for the
period ended March 31, 2000.
The accompanying notes are an integral part of the
consolidated financial statements.
F-5
FX ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1: Basis of Presentation
The interim financial data are unaudited; however, in the opinion of
the management of FX Energy, Inc. and Subsidiaries ("FX Energy" or the
"Company"), the interim data includes all adjustments, consisting only of normal
recurring adjustments, necessary for a fair statement of the results for the
interim periods. The interim financial statements should be read in conjunction
with FX Energy's annual report on Form 10-K as amended for the year ended
December 31, 1999, including the financial statements and notes thereto.
The consolidated financial statements include the accounts of FX Energy
and its wholly-owned subsidiaries and FX Energy's undivided interests in Poland.
All significant inter-company accounts and transactions have been eliminated in
consolidation. At March 31, 2000, FX Energy owned 100% of the voting stock of
all of its subsidiaries.
Certain balances in the 1999 financial statements have been
reclassified to conform to the current quarter presentation. These changes had
no effect on total assets, total liabilities, stockholders' equity or net loss.
Note 2: Income Taxes
FX Energy recognized no income tax benefit from the losses generated in
the first quarter of 2000 and the first quarter of 1999.
Note 3: Officer Loans
As of March 31, 2000, notes receivable and accrued interest from
officers, before an impairment allowance, totaled $2,070,411, with a due date of
on or before December 31, 2000. The notes receivable and accrued interest are
collateralized by 233,340 shares of FX Energy's common stock. In accordance with
SFAS No. 114, "Accounting by Creditors for Impairment of a Loan," FX Energy has
recorded a cumulative impairment allowance of $670,371 as of March 31, 2000,
including $4,859 for the quarter ended March 31, 2000 and $665,512 for the year
ended December 31, 1999, based on the value of the underlying collateral.
In consideration for extending the term from December 31, 1999 through
December 31, 2000, the officers agreed that if the average closing price of the
common stock for five consecutive trading days results in a value of the
collateral equal to or above the total principal and accrued interest balances,
the officers will repay the loans within 45 days thereafter either in cash or by
tendering to the Company such number of shares which at the average closing
price for the previous five consecutive trading days equals the principal and
accrued interest then due.
The impairment allowance will continue to be adjusted quarterly based
on the market value of the collateral shares.
F-6
Note 4: Business Segment Information
FX Energy operates within two segments of the oil and gas industry: the
exploration and production segment ("E&P") and the contract drilling and well
servicing segment ("contract services").
Reportable business segment information as of March 31, 2000 and for
the three months ended March 31, 2000 follows:
Non-
Contract Segmented
E&P Services Items (1) Total
-------------- -------------- ------------------------------
Revenues.................. $ 596,630 $ 73,738 $ -- $ 670,368
Net loss.................. (195,659) (52,713) (487,820) (736,192)
Identifiable net property
and equipment (2)....... 2,365,128 630,418 155,128 3,150,674
- --------------------
(1) Net loss reconciling items include $596,967 of general and administrative
expenses, $19,940 of corporate DD&A and $129,087 of other income and
expense. Identifiable net property and equipment includes $155,128 of
corporate office equipment, hardware and software.
(2) Identifiable net property and equipment are reported by business segment
for management reporting and reportable business segment disclosure
purposes. Current assets, other assets and current liabilities are not
allocated to business segments for management reporting or business segment
disclosure purposes.
Reportable business segment information as of March 31, 1999 and for
the three months ended March 31, 1999 follows:
Non-
Contract Segmented
E&P Services Items (1) Total
-------------- -------------- ------------------------------
Revenues.................. $ 233,708 $ 87,543 $ -- $ 321,251
Net loss.................. (211,004) (46,266) (465,249) (722,519)
Identifiable net property
and equipment (2)....... 1,957,953 655,963 222,374 2,836,290
- --------------------
(1) Net loss reconciling items include $536,389 of general and administrative
expenses, $31,051 of corporate DD&A and $102,191 of other income and
expense. Identifiable net property and equipment includes $222,374 of
corporate office equipment, hardware and software.
(2) Identifiable net property and equipment are reported by business segment
for management reporting and reportable business segment disclosure
purposes. Current assets, other assets and current liabilities are not
allocated to business segments for management reporting or business segment
disclosure purposes.
Note 5: Subsequent Events
Fences Project Area
On April 11, 2000, FX Energy signed an agreement with the Polish Oil
and Gas Company ("POGC") under which FX Energy will earn a 49% working interest
in approximately 300,000 gross acres in west central Poland (the "Fences"
project area) by spending $16 million for agreed exploration drilling, seismic
acquisition and related activities.
Sale of Common Stock
In June 2000, FX Energy sold 2,969,000 shares of restricted common
stock for $10,391,500, resulting in net proceeds of approximately $9,300,000.
F-7
THIS PAGE INTENTIONALLY LEFT BLANK
F-8
PricewaterhouseCoopers
Report of Independent Accountants
To the Stockholders and Board of Directors
of FX Energy, Inc., and Subsidiaries:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, cash flows, and stockholders' equity
present fairly, in all material respects, the consolidated financial position of
FX Energy, Inc., and Subsidiaries (the "Company") as of December 31, 1999 and
1998, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States. 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 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 the opinion expressed above.
PricewaterhouseCoopers LLP
Salt Lake City, Utah
February 8, 2000
F-9
FX ENERGY, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 1999 and 1998
1999 1998
------------- -----------
ASSETS
Current assets:
Cash and cash equivalents $ 1,619,237 $ 1,811,780
Investment in marketable debt securities 5,249,003 2,929,914
Receivables:
Accrued oil sales 243,183 95,064
Joint interest and other receivables 171,242 240,102
Interest receivable 86,723 86,258
Inventory 66,361 68,327
Other current assets 126,006 66,053
------------- -----------
Total current assets 7,561,755 5,297,498
------------- -----------
Property and equipment, at cost:
Oil and gas properties (successful efforts
method):
Proved 1,687,089 1,605,279
Unproved 1,382,880 1,178,408
Other property and equipment 2,652,102 2,494,688
------------- -----------
Gross property and equipment 5,722,071 5,278,375
Less accumulated depreciation, depletion
and amortization (3,173,493) (2,679,441)
------------- -----------
Net property and equipment 2,548,578 2,598,934
------------- -----------
Other assets:
Certificates of deposit 356,500 356,500
Deposits 2,789 --
------------- -----------
Total other assets 359,289 356,500
------------- -----------
Total assets $ 10,469,622 $ 8,252,932
============= ===========
-Continued-
The accompanying notes are an integral part of these consolidated financial
statements
F-10
FX ENERGY, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, Continued
As of December 31, 1999 and 1998
1999 1998
----------- -----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 623,911 $ 420,906
Accrued liabilities 1,478,862 911,950
----------- -----------
Total current liabilities 2,102,773 1,332,856
----------- -----------
Commitments (Notes 2 and 11)
Stockholders' equity:
Preferred stock, $.001 par value, 5,000,000 shares
authorized; 1999 and 1998: no shares outstanding -- --
Common stock, $.001 par value, 30,000,000 shares
authorized;
1999: 14,849,003 shares issued and outstanding;
1998: 13,054,503 shares issued and outstanding 14,849 13,055
Notes receivable from officers (1,370,873) (1,304,527)
Additional paid-in capital 38,480,556 31,112,861
Accumulated deficit (28,757,683) (22,901,313)
----------- -----------
Total stockholders' equity 8,366,849 6,920,076
----------- -----------
Total liabilities and stockholders' equity $10,469,622 $ 8,252,932
=========== ===========
The accompanying notes are an integral part of these consolidated financial
statements
F-11
FX ENERGY, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the years ended December 31, 1999, 1998 and 1997
1999 1998 1997
------------ ----------- ----------
Revenues:
Oil sales $ 1,554,474 $ 1,123,511 $2,040,233
Drilling revenue 864,689 322,769 496,158
Gain on sale of property interests -- 466,891 272,234
------------ ----------- ----------
Total revenues 2,419,163 1,913,171 2,808,625
------------ ----------- ----------
Operating costs and expenses:
Lease operating costs 899,258 966,732 1,094,043
Production taxes 63,141 79,602 145,372
Geological and geophysical costs 1,959,422 2,109,375 1,683,753
Exploratory dry hole costs 1,001,433 17,422 3,478,456
Impairments 92,605 5,885,042 152,105
Drilling costs 641,871 240,061 328,820
Depreciation, depletion and amortization 494,052 671,277 634,559
General and administrative 2,961,878 2,572,212 2,565,690
------------ ----------- ----------
Total operating costs and expenses 8,113,660 12,541,723 10,082,798
------------ ----------- ----------
Operating loss (5,694,497) (10,628,552) (7,274,173)
------------ ----------- ----------
Other income (expense):
Interest and other income 511,636 506,209 661,665
Interest expense (7,997) -- (83,273)
Impairment of notes receivable from
officers (665,512) -- --
------------ ----------- ----------
Total other income (expense) (161,873) 506,209 578,392
------------ ----------- ----------
Net loss before extraordinary gain (5,856,370) (10,122,343) (6,695,781)
Extraordinary gain (Note 2) -- -- 3,076,242
------------ ----------- ----------
Net loss (5,856,370) (10,122,343) (3,619,539)
============ =========== ==========
Basic and diluted net loss per share:
Net loss before extraordinary gain $ (0.41) $ (0.78) $ (0.53)
Extraordinary gain -- -- 0.24
Net Loss $ (0.41) $ (0.78) $ (0.29)
Basic and diluted weighted average number of ------------ ----------- ----------
shares outstanding 14,198,724 12,978,900 12,596,977
============ =========== ==========
The accompanying notes are an integral part of these consolidated financial
statements
F-12
FX ENERGY, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31, 1999, 1998 and 1997
1999 1998 1997
------------ ------------ ------------
Cash flows from operating activities:
Net loss $ (5,856,370) $(10,122,343) $ (3,619,539)
Adjustments to reconcile net loss to net cash
used in operating activities:
Extraordinary gain -- -- (3,076,242)
Depreciation, depletion and amortization 494,052 671,277 634,559
Impairments 92,605 5,885,042 28,515
Gain on sale of property interests -- (466,891) (272,234)
Exploratory dry hole costs 240,132 -- 210,205
Common stock and options issued for services 302,687 119,375 70,625
Accrued interest income from officer loans (134,295) (64,170) --
Impairment of notes receivable from officers 665,512 -- --
Increase (decrease) from changes in:
Receivables (100,044) 260,024 (147,678)
Inventory 1,966 (945) (47,166)
Other current assets (59,953) 20,960 (19,530)
Accounts payable and accrued liabilities 608,285 588,908 357,752
------------ ------------ ------------
Net cash used in operating activities (3,745,423) (3,108,763) (5,880,733)
------------ ------------ ------------
Cash flows from investing activities:
Additions to oil and gas properties (463,387) (179,765) (1,136,935)
Additions to other property and equipment (137,094) (260,877) (394,291)
Net change in other assets (2,789) -- 25,000
Proceeds from sale of property interests 6,000 506,000 340,152
Proceeds from sale of equipment -- 6,928 13,051
Employee advances -- -- (15,000)
Purchase of marketable debt securities (6,617,089) (6,578,332) (3,940,582)
Proceeds from maturities of marketable debt
securities 4,298,000 7,589,000 5,476,574
------------ ------------ ------------
Net cash provided by (used) in investing
activities (2,916,359) 1,082,954 367,969
------------ ------------ ------------
Cash flows from financing activities:
Proceeds from long-term debt -- -- 1,575,992
Notes receivable from officers (597,563) (840,357) (150,000)
Proceeds from issuance of common stock,
options and warrants, net of offering
costs 7,066,802 166,027 252,777
------------ ------------ ------------
Net cash provided by (used in) financing
activities 6,469,239 (674,330) 1,678,769
------------ ------------ ------------
Increase (decrease) in cash (192,543) (2,700,139) (3,833,995)
Cash and cash equivalents at beginning of
year 1,811,780 4,511,919 8,345,914
------------ ------------ ------------
Cash and cash equivalents at end of year $ 1,619,237 $ 1,811,780 $ 4,511,919
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements
F-13
FX ENERGY, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
for the years ended December 31, 1999, 1998 and 1997
Common Stock
------------------- Officers'
Par Paid-in Notes Accumulated
Shares Value Capital Receivable Deficit Total
---------- ------- ----------- ------------ ------------ ------------
Balance at January 1, 1997 12,492,547 $12,492 $30,054,620 $ -- $(9,159,431) $ 20,907,681
Exercise of warrants and options 159,334 160 252,617 -- -- 252,777
Common stock issued for services 10,000 10 70,615 -- -- 70,625
Net loss -- -- -- -- (3,619,539) (3,619,539)
---------- ------- ----------- ------------ ------------ ------------
Balance at December 31, 1997 12,661,881 12,662 30,377,852 -- 12,778,970) 17,611,544
Exercise of warrants and options 382,622 383 615,644 -- -- 616,027
Common stock issued for services 10,000 10 119,365 -- -- 119,375
Officers' notes - principal -- -- -- (1,240,357) -- (1,240,357)
Officers' notes - interest -- -- -- (64,170) -- (64,170)
Net loss -- -- -- -- (10,122,343) (10,122,343)
---------- ------- ----------- ------------ ------------ ------------
Balance at December 31, 1998 13,054,503 13,055 31,112,861 (1,304,527) (22,901,313) 6,920,076
Exercise of warrants and options 2,000 2 13,248 -- -- 13,250
Sale of common stock 1,792,500 1,792 7,168,208 -- -- 7,170,000
Common stock placement costs -- -- (116,448) -- -- (116,448)
Officers' notes - principal -- -- -- (597,563) -- (597,563)
Officers' notes - interest -- -- -- (134,295) -- (134,295)
Officers' notes - impairment -- -- -- 665,512 -- 665,512
Options issued for services -- -- 302,687 -- -- 302,687
Net loss -- -- -- -- (5,856,370) (5,856,370)
---------- ------- ----------- ------------ ------------ ------------
Balance at December 31, 1999 14,849,003 $14,849 $38,480,556 $(1,370,873) $(28,757,683) $ 8,366,849
========== ======= =========== ============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements
F-14
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies:
Organization
FX Energy, Inc., a Nevada corporation and its subsidiaries (collectively
hereinafter referred to as the "Company") operate in the oil and gas
industry in Poland and the United States. In Poland, the Company is
engaged in oil and gas exploration, appraisal, development and property
acquisition activities. In the United States, the Company is engaged in
producing, exploring and developing oil and gas properties and operates a
drilling and well servicing company.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries and the Company's undivided interests in
Poland. All significant inter-company accounts and transactions have been
eliminated in consolidation. At December 31, 1999, the Company owned 100%
of the voting common stock or other equity securities of its subsidiaries.
Inventory
Inventory consists primarily of tubular supplies and other well equipment
and is valued at the lower of average cost or market.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil
and gas operations. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are
capitalized when incurred, pending determination of whether an individual
well has found proved reserves. If it is determined that an exploratory
well has not found proved reserves, the costs of drilling the well are
expensed. The costs of development wells are capitalized whether productive
or nonproductive.
Geological and geophysical costs on exploratory prospects and the costs of
carrying and retaining unproved properties are expensed as incurred. An
impairment allowance is provided to the extent that capitalized costs of
unproved properties, on a field-by-field 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 field-
by-field basis using the units-of-production method. The computation of
DD&A takes into consideration restoration, dismantlement and abandonment
costs and the anticipated proceeds from equipment salvage. The estimated
restoration, dismantlement and abandonment costs are expected to be offset
by the estimated residual value of lease and well equipment.
An impairment loss is recorded if the net capitalized costs of proved oil
and gas properties exceed the aggregate undiscounted future net revenues
determined on a field-by-field basis. The impairment loss recognized
equals the excess of net capitalized costs over the related fair value
determined on a property by property basis. (Note 14)
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.
F-15
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Other Property and Equipment
Other property and equipment, including drilling and well servicing
equipment, are stated at cost. Depreciation of other property and
equipment is calculated using the straight-line method over the estimated
useful lives (ranging from 3 to 40 years) of the respective assets. The
cost of normal maintenance and repairs is charged to operating costs and
expensed as incurred. Material expenditures that increase the life of an
asset are capitalized and depreciated over the estimated remaining useful
life of the asset. The cost of other property and equipment sold, or
otherwise disposed of, and the related accumulated depreciation are removed
from the accounts and any gain or loss is reflected in current operations.
Other property and equipment (gross) is summarized as follows:
December 31, Estimated
------------------------- Useful Life
1999 1998 (in years)
----------- ----------- -----------
Other Property and Equipment: (In thousands)
Drilling and well servicing
equipment $ 1,906 $ 1,771 6
Trucks 190 188 5
Building 80 80 40
Office Equipment 476 456 3 to 6
----------- -----------
Total $ 2,652 $ 2,495
=========== ===========
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 (Note 12) 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.
Cash Equivalents and Statement of Cash Flows
The Company considers all highly-liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents. Non-cash
transactions not reflected in the consolidated statements of cash flows
include the following:
Years Ended December 31,
---------------------------------
1999 1998 1997
---------- --------- ---------
Non-cash transactions: (In thousands)
Bonus applied to stock option exercise $ -- $ 200 $ --
by officers
Recourse notes receivable from officers
due to stock option exercise -- 250 --
Reclassification of notes receivable -- 150 --
from officers
Additions to oil and gas properties
financed with accrued 63 -- --
iabilities
Supplemental disclosure of cash flow
information:
Cash paid during the year for:
Interest $ 8 $ -- $ 534
Taxes -- -- --
F-16
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
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 will 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 1998 and 1997 financial statements have been
reclassified to conform to the current year presentation. These changes
had no effect on total assets, total liabilities, stockholders' equity or
net loss.
Foreign Operations
The Company's investments and operations in Poland are comprised of U.S.
Dollar expenditures.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
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, 1999, 1998 and 1997 were as
follows:
Options and
December 31, Warrants Price Range
------------ ----------- --------------
1999 4,167,073 $1.50 - $10.25
1998 3,684,239 $1.50 - $10.25
1997 3,707,694 $1.10 - $10.25
The Company had a net loss in 1999, 1998 and 1997. The above options or
warrants were not included in the computation of diluted earnings per share
for the years ended December 31, 1999, 1998 or 1997 because the effect
would have been antidilutive.
2. Investment in Poland:
Apache Exploration Program
Effective January 1, 1999, the Company and Apache Corporation ("Apache")
entered into an agreement which further defined the relationship between
the Company and Apache in Poland by establishing an Area of Mutual Interest
Agreement ("AMI Agreement") covering the entire country of Poland, except
for the 0.9 million acre Baltic Project Area, for oil and gas exploration,
production, development and acquisition activities for a period of two
years. The AMI Agreement effectively consolidated the terms of various
agreements signed between the Company and Apache during 1997, 1998 and 1999
into one basic agreement, referred to collectively as the Apache
Exploration Program.
F-17
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Under terms of the Apache Exploration Program, Apache has either agreed to
or completed the following primary terms:
o Apache paid the Company $950,000 in up-front cash, including $450,000
during 1997 for the Lublin Basin and $500,000 during 1998 for the
Carpathian area;
o Apache must cover the Company's pro-rata share of cost to drill ten
exploratory wells, including paying for drilling and completion costs
for seven wells in the Lublin Basin and drilling costs (excluding
completion costs) for three wells in the Carpathian area;
o Apache must cover the Company's pro-rata share of cost to shoot 2,000
kilometers of 2D seismic; including 1,650 kilometers of 2D seismic in
the Lublin Basin completed during 1998 and 350 kilometers in the
Carpathian area that has yet to be completed;
o Apache must cover all of the Company's pro-rata share of all
concession and usufruct fees during the first three years in the
Lublin Basin (approximately $695,000) and the Carpathian area
(approximately $160,000);
o Apache must cover all of the Company's pro-rata share of annual
training costs during the first three years in the Lublin Basin
($80,000 per year) and the Carpathian area ($15,000 per year); and
o Apache may not charge the Company for any of its pro-rata share of
Polish G&A costs through June 30, 2000. Thereafter, Apache may charge
the Company for 25% of its Polish G&A costs, increased by 5% upon the
drilling of each of the five remaining exploratory wells; up to a
maximum of 50%.
The AMI Agreement modified and further defined the Apache Exploration
Program by adding the following additional terms:
o The Company and Apache must offer each other a fifty-percent interest
in any new exploration, appraisal, development, property acquisition
or other activities conducted by either party within the AMI during
all of 1999 and 2000.
o The ten exploratory wells under the Apache Exploration Program may, at
the consent of both parties, be drilled anywhere within the AMI.
o The Company and Apache have equal 50% working interests in the
Pomeranian and Warsaw West areas.
o Apache is the operator of all areas controlled by the Company and
Apache within the AMI.
Option Agreements between the Company, Apache and POGC
As a result of various agreements included within the Apache Exploration
Program between the Company, Apache and POGC, the Company and Apache's
working interest in the Lublin Basin, Carpathian and Pomeranian areas is
subject to being reduced by POGC's option to participate for up to a one-
third working interest on a block by block basis in each respective area.
In turn, the Company and Apache each have an independent reciprocal right
to participate in the exploration of the POGC controlled areas in each of
the respective project areas with up to a one-third working interest each.
Should POGC elect to participate in any of the Company's concessions, the
Company's and Apache's interest will be reduced in equal proportions. The
Company does not have any option agreements with POGC covering Warsaw West
or the Baltic Project Area.
Exploration Activities
The first four exploratory wells drilled under terms of the Apache
Exploration Program were all determined to be exploratory dry holes during
1999. In accordance with terms of the Apache Exploration Program, Apache
covered all of the Company's working interest share of costs for all four
wells, including 33.3% for
F-18
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
the Czernic 277-2, 47.5% for the Poniatowa 317- 1, 45.0% for the Witkow 1
and 33.3% for the Siedliska 2. The fifth well, the Wilga 2, was announced
to be an exploratory success on January 25, 2000 after initial production
test results indicated a combined flow rate of 16.9 Mmcf of gas and 570
Bbls of condensate per day from three intervals in a Carboniferous horizon.
Under terms of the Apache Exploration Program, Apache will cover all of the
Company's 45.0% drilling and completion costs for the Wilga 2. (Note 16)
During June 1999, the Company elected to participate with a 5.0% working
interest in drilling the Andrychow 6, an exploratory well operated by POGC
on POGC option acreage in southern Poland. The well cost approximately
$99,000 net to the Company and was determined to be an exploratory dry hole
during December 1999.
Appraisal and Development Activities
On February 26, 1999, The Company, Apache and POGC entered into an
agreement to jointly develop the Lachowice Farm-in, a shut-in POGC gas
discovery with three wells in the Carpathian area, with Apache as operator.
Under terms of the agreement, The Company and Apache agreed to pay all of
the following costs in order to earn a one-third interest each in the
project: (1) test and recomplete up to three shut-in gas wells; (2) if
warranted, drill three additional wells; and, (3) if warranted, construct
gathering and processing facilities. All costs and net revenues
thereafter, including additional development drilling and lease operating
costs, would be shared one-third each by the Company, Apache and POGC.
During June 1999, the Company and Apache commenced testing and recompletion
procedures on the Stryszawa 2K. The Stryszawa 2K was subsequently plugged
and abandoned after it failed to maintain a commercial production rate.
During September 1999, the Company and Apache tested the Lachowice 7 to
determine its commercial potential. The test results of the Lachowice 7
did not warrant constructing gathering and processing facilities. The
Company and Apache plan to turn the Lachowice 7 back to POGC and terminate
the Lachowice Farm-in.
Baltic Project Area
On May 3, 1996, the Company entered into a agreement with RWE-DEA, formerly
Deutsche Texaco, to jointly explore the Baltic Project Area. Under terms
of the Agreement, RWE-DEA had the right to earn a fifty-percent interest in
the Baltic Project Area by paying the Company $250,000 in cash, paying the
first $1,100,000 for a 2D seismic survey, the first $1,000,000 of cost
relating to the initial exploratory well to be drilled at a location to be
designated by RWE-DEA and fifty-percent of the cost relating to the second
exploratory well at a location designated by the Company. Polish
government approval was required to approve RWE-DEA's participation in the
Baltic Project Area by purchasing fifty-percent of Warmia Petroleum
Company, Sp z o.o. ("Warmia"), a wholly owned subsidiary of the Company
which holds the Baltic Project Area. The Company obtained a $2.5 million
Irrevocable Standby Letter of Credit whereby the Company agreed to refund
RWE-DEA all advanced funds should the Polish government disapprove RWE-
DEA's purchase of fifty-percent of Warmia. The Irrevocable Standby Letter
of Credit expired on January 31, 1997 and the Polish government approved
RWE-DEA's purchase of fifty-percent of Warmia in June 1997. RWE-DEA had
advanced Warmia $3,076,000 through June 30, 1997 to fund exploration
activity on the Baltic Project Area, which the Company had recorded as a
long-term note payable.
Prior to drilling the second well on the Baltic Project Area, RWE-DEA had
advanced the Company all funds required to date under the Agreement,
including funding the first $1,000,000 of costs relating to the Orneta #1,
the initial exploratory well drilled on the Baltic Project Area which was
plugged and abandoned as a dry hole in April 1997 at a gross cost of
$1,834,000. On June 30, 1997, RWE-DEA elected to not fund its fifty-
percent share of the Gladysze #1-A, the second exploratory well drilled on
the Baltic Project Area, which resulted in the termination of RWE-DEA's
right to earn a fifty-percent interest in the Baltic Project Area. The
Gladysze #1-A was drilled without RWE-DEA as a participant and was
subsequently plugged and abandoned as a dry hole in September 1997 at a
gross cost of $1,262,000. Upon termination of RWE-DEA's right to earn a
fifty-percent interest in the Baltic Project
F-19
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Area, the Company eliminated its long-term notes payable relating to
RWE-DEA and recognized an extraordinary gain of $3,076,000.
During March 1999, the Company relinquished approximately 1.2 million acres
within the Baltic Project Area, leaving a total of approximately 0.9
million undeveloped acres in the Baltic Project Area. The Polish
government also consented to apply the Gladysze 1-A, the second well
drilled on the Baltic Project Area during 1997, to the work commitment for
the second three-year exploration phase. As such, the Company has
satisfied all work commitments applicable to the Baltic Project Area's six-
year exploration phase. The Company's Baltic Project Area is the only
acreage holding in Poland in which the Company has an interest that
contains mandatory acreage relinquishment provisions.
At December 31, 1999, the Company had $494,000 of capitalized leasehold
costs related to the Baltic Project Area. The Company is currently seeking
a strategic partner to participate in further exploration of the Baltic
Project Area.
Gold Exploration - Sudety Project Area
On July 26, 1999, Homestake terminated its agreement with the Company to
jointly explore for gold on the Company's Sudety Project Area in
southwestern Poland. During 1997, Homestake initially paid the Company
$212,000 and agreed to spend a minimum of $1,100,000 over two years
exploring the Sudety Project Area. Homestake completed its minimum
exploration commitments during the first six months of 1999. The Company
has discontinued further gold exploration in the Sudety Project Area.
3. Performance Bond Deposits:
As of December 31, 1999, the Company had a replacement bond to a federal
agency in the amount of $463,000, which was collateralized by certificate
of deposits totaling $231,500. In addition, there are certificates of
deposits totaling $125,000 covering performance bonds in other states.
4. Investment in Marketable Debt Securities:
The Company follows the provisions of SFAS No. 115, "Accounting for Certain
Investments in Debt and Equity Securities." In accordance with SFAS No.
115, the Company has classified all of its marketable debt securities as
held-to-maturity because the Company has both the intent and ability to
hold these investments until they mature. At December 31, 1999, the
Company's held-to-maturity securities consisted of corporate bonds with
remaining contractual maturities of less than twelve months and the
carrying amount of these investments approximated market value.
5. Accrued Liabilities:
The Company's accrued liabilities as of December 31, 1999 and 1998 are
composed of the following:
As of December 31,
-------------------------
1999 1998
---------- ----------
Accrued Liabilities: (In thousands)
Compensation costs $ 1,185 $ 699
Unproved property additions 63 --
Exploratory dry hole costs 99 --
Seismic costs 28 131
Other costs 104 82
---------- ----------
Total $ 1,479 $ 912
========== ==========
F-20
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
6. Long-term Debt:
During 1998, the Company had a bank credit facility with a borrowing base
of $2,850,000 as of January 1, 1998. The borrowing base was subject to a
monthly basis reduction of $25,000. The Company did not utilize the credit
facility and subsequently terminated the credit facility during the year
ended December 31, 1998.
7. Income Taxes:
The Company recognized no income tax benefit from the losses generated
during the years ended December 31, 1999, 1998 and 1997.
The components of the net deferred tax asset as of December 31, 1999 and
1998 are as follows:
December 31,
-------------------------
1999 1998
----------- ----------
(In thousands)
Deferred tax liability:
Property and equipment basis
differences $ (104) $ (962)
Deferred tax asset:
Net operating loss carryforwards 11,180 9,437
Impairment of oil and gas properties 1,218 2,196
Impairment of notes receivable from
officers 248 --
Options issued for services 113 --
Other 193 14
Valuation allowance (12,848) (10,685)
----------- ----------
Net deferred tax asset $ -- $ --
=========== ==========
The change in the valuation allowance during the years ended December 31,
1999, 1998 and 1997 is as follows:
December 31,
-----------------------------------
1999 1998 1997
---------- ---------- ---------
(In thousands)
Balance, beginning of year $ (10,685) $ (6,131) $ (3,868)
Increase due to property and
equipment basis differences 4 22 24
Decrease (increase) due to
impairment of oil and gas properties -- (2,196) --
Decrease due to investment in Warmia -- -- 661
Increase due to net operating loss (1,989) (2,444) (2,876)
Other (178) 64 (72)
---------- ---------- ---------
Balance, end of year . $ (12,848) $ (10,685) $ (6,131)
========== ========== =========
SFAS No. 109 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, 1999 and 1998.
F-21
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
At December 31, 1999, the Company had net operating loss ("NOL")
carryforwards, including foreign losses, of approximately $30,000,000
available to offset future taxable income, of which approximately
$18,749,000 expires from 2008 through 2012 and $11,251,000 expires
subsequent to 2017. The utilization of these carryforwards against future
taxable income may become subject to an annual limitation if there is a
change in ownership. $6,168,000 of the NOL carryforward relates to tax
deductions resulting from the exercise of stock options during 1999, 1998
and 1997. The tax benefit from adjusting the valuation allowance related
to this portion of the NOL carryforward will be credited to additional
paid-in capital.
8. Related Party Transactions:
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 bonus credit 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 notes receivable and accrued interest totaled $2,036,385 with a due
date of on or before December 31, 2000 (as extended). The Company has no
further commitment to advance additional funds to the officers.
In consideration for extending the term from December 31, 1999 through
December 31, 2000, the officers agreed that if the average closing price of
the common stock for five consecutive trading days results in a value of
the collateral equal to or above the total principal and accrued interest
balances, the officers will repay the loans within 45 days thereafter
either in cash or by tendering to the Company such number of shares which
at the average closing price for the previous five consecutive trading days
equals the principal and accrued interest then due.
The notes receivable and accrued interest are collateralized by 233,340
shares of the Company's common stock. In accordance with SFAS No. 114,
"Accounting by Creditors for Impairment of a Loan," the Company recorded an
impairment allowance of $666,000 as of December 31, 1999, based on the
value of the underlying collateral. The impairment allowance will be
adjusted quarterly based on the market value of the collateral shares.
9. Stock Options and Warrants:
Stock Options
As of December 31, 1999, the Company's 1998 Stock Option Plan had issued
options to purchase 438,501 shares out of a maximum total of 500,000
authorized shares allowed within the 1998 Stock Option Plan. As of
December 31, 1999, all other prior year stock option plans had issued the
maximum allowed options under each respective stock option plan. The
Company has submitted the 1999 Stock Option Plan, which includes a maximum
of 500,000 options, for shareholder approval at the 2000 annual
shareholders' meeting.
All stock option plans are each administered by a committee (the
"Committee") consisting of the board of directors or a committee thereof.
At its discretion, the Committee may grant stock options to any employee,
including officers, in the form of incentive stock options ("ISOs"), as
defined in the Internal Revenue Code, or options which do not qualify as
ISOs or stock awards. In addition to the options granted under the stock
option plans, the Company also issues non-qualified options outside the
stock option plans. Options granted under these stock option plans have
terms ranging from five to seven years and vest over periods ranging from
the date of grant to three years.
F-22
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
As of December 31, 1999, the Company had options outstanding under the
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 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:
Years Ended December 31,
-----------------------------------
1999 1998 1997
----------- ---------- --------
(In thousands, except per share
amounts)
Net Loss:
As Reported $ (5,856) $ (10,122) $ (3,620)
Pro Forma (7,930) (11,680) (5,991)
Basic and Diluted
Net Loss Per Share:
As Reported $ (0.41) $(0.78) $ (0.29)
Pro Forma (0.56) (0.90) (0.48)
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 during 1999, 1998 and 1997 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 80.5%, 76.2% and 80.4%
for 1999, 1998 and 1997, respectively; (2) expected lives ranging from four
to seven years; (3) risk-free interest rates at the date of grant ranging
from 4.44% to 6.43%; and, (4) dividend yield of zero for each year.
The following table summarizes fixed option activity for the years ended
December 31, 1999, 1998 and 1997:
December 31,
----------------------------------------------------------------------
1999 1998 1997
------------------------ ---------------------- --------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
--------- ----------- --------- ---------- --------- ---------
Fixed Options
Outstanding:
Beginning of year 3,413,667 $ 6.590 3,357,500 $ 4.473 2,732,834 $ 3.710
Granted 521,000 5.866 480,000 8.875 725,500 7.203
Exercised (2,000) 6.625 (303,000) 1.500 (78,334) 1.698
Canceled (36,166) 7.920 (120,833) 8.400 (22,500) 9.486
--------- ----------- --------- ---------- --------- ---------
End of year 3,896,501 $ 6.481 3,413,667 $ 6.590 3,357,500 $ 4.473
========= =========== ========= ========== ========= =========
Exercisable at
year-end 2,872,681 $ 4.656 2,329,012 $ 6.970 2,242,000 $ 3.878
========= =========== ========= ========== ========= =========
Weighted-average
fair value of
options granted
during the year $ 3.61 $ 3.930 $ 4.458
F-23
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following table summarizes information about fixed stock options
outstanding at December 31, 1999:
Options Outstanding Options Exercisable
-------------------------------------- ---------------------
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices at 12/31/99 Life Price at 12/31/99 Price
(in years)
------------- ----------- ----------- ---------- ----------- --------
$1.500 178,000 .668 $ 1.500 178,000 $ 1.500
3.000 1,700,000 3.082 3.000 1,700,000 3.000
5.750 - 7.250 1,011,500 5.795 6.279 351,673 6.752
7.375 - 8.875 1,001,001 4.320 8.660 639,008 8.753
10.250 6,000 5.129 10.250 4,000 10.250
----------- ----------- ---------- ----------- --------
Total 3,896,501 3.993 $ 5.641 2,872,681 $ 4.656
=========== =========== ========== =========== ========
Warrants
The following table summarizes changes in outstanding warrants during
the years ended December 31, 1999, 1998 and 1997:
Shares Price Range
------------------ ---------------
Warrants:
Outstanding at December 31, 1996 431,194 $ 1.10 - 6.90
Exercisable at December 31, 1996 281,194 1.10 - 3.00
=======
Warrants exercised during 1997 (81,000) 1.10 - 2.60
-------
Outstanding at December 31, 1997 350,194 1.10 - 6.90
Exercisable at December 31, 1997 350,194 1.10 - 6.90
=======
Warrants exercised during 1998 (79,622) 1.10 - 2.60
Outstanding at December 31, 1998 270,572 1.65 - 6.90
=======
Exercisable at December 31, 1998 270,572 1.65 - 6.90
Outstanding at December 31, 1999 270,572 ======= 1.65 - 6.90
=======
Exercisable at December 31, 1999 270,572 $ 1.65 - 6.90
=======
10. Private Placement of Common Stock:
On April 8, 1999, the Company initiated a private placement that resulted
in the sale of 1,792,500 shares of common stock for net proceeds of
$7,054,000. No placement fees were paid by the Company in connection with
the sale of the aforementioned shares.
11. Commitments:
Employment Agreements
Effective January 1, 1995, the Company entered into three-year employment
agreements with David N. Pierce and Andrew W. Pierce, each of whom is an
officer and director. The agreements provide for initial annual
compensation of $120,000 and $96,000, respectively, with annual increases
of at least 7.5%, as determined by the board of directors or the
compensation committee. Each employment agreement, as amended, provides
that on the initiation of the first test well in the Baltic Project Area,
which commenced in late January 1997, the executive employee was entitled
to receive a $100,000 bonus that may, at the election of the officer, be
applied against the exercise of options to purchase common stock or paid in
cash upon termination of employment with the Company. The Company accrued
$200,000 at December 31, 1997 to reflect this obligation. On February 17,
1998, each officer exercised options to purchase common
F-24
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
stock and applied their respective bonuses awarded to him in 1997 towards
the exercise price (Note 8). The terms of such employment agreements are
automatically extended for an additional year on the anniversary date of
each such agreement. In the event of termination of employment resulting
from a change in control of the Company not approved by the Board of
Directors, each of the two officers would be entitled to a termination
payment equal to 150% of his annual salary at the time of termination and
the value of previously granted employee benefits, including stock options
and stock awards.
On July 1, 1996, the Company entered into a three-year employment agreement
with Jerzy B. Maciolek, who is an officer of the Company, providing for an
initial annual salary of $96,000 with an annual increase to be determined
by the Company's board of directors or the compensation committee. The
employment agreement also provides for annual incentive bonuses of up to
$100,000, payable in cash, stock or options and a $100,000 bonus to be
issued annually on May 12, 1998, 1999 and 2000 to be applied against
future stock option exercises. In the event such bonuses are earned, but
not used by Mr. Maciolek and his employment with the Company is terminated,
the Company must pay the bonus to Mr. Maciolek in cash. In the event the
employment contract is terminated by the Company, other than for cause, or
by Mr. Maciolek for cause or because of a change in control of the Company,
Mr. Maciolek is entitled to a termination payment equal to any accrued but
unpaid salary and unreimbursed expenses and benefits plus his salary for
the remaining term of the employment agreement. Additionally, all options
held by Mr. Maciolek shall immediately vest and not be forfeited. The
agreement will automatically be extended for an additional one year upon
each anniversary date of the effective date unless otherwise terminated
pursuant to the terms thereof.
Consulting Agreement
Effective August 3, 1995, the Company entered into a consulting agreement
with Lovejoy and Associates, a consulting company owned by Tom Lovejoy, a
director of the Company, under which Lovejoy and Associates would advise
the Company respecting future financing alternatives, possible sources of
debt and equity financing, with particular emphasis on funding for the
Company's Polish activities and the Company's relationship with the
investment community at a fee of $10,000 per month commencing October 15,
1995 and continuing through December 31, 1997. The agreement was extended
through December 31, 1999 at a rate of $15,000 per month for January and
February 1998 and a subsequent rate of $17,000 per month thereafter. The
consulting agreement was terminated effective May 1, 1999 when Mr. Lovejoy
became the Company's Chief Financial Officer.
Polish Exploration Agreements
The Company is committed to the following obligations in Poland, presented
on a gross basis, to retain its exploratory concession acreage:
Exploratory Wells
-----------------
Beginning First Second Concession
of Three Three Annual and
Exploration Whole Year Year 2D Seismic Training Usufruct
Period Blocks Phase Phase Acquisition Fees (5) Fees (6)
------------------ ----- ----------- ----------- --------- ---------
Lublin (1), (2) Various (7) 24 6 1 per block 1,650 km $ 80,000 $ 675,000
Carpathian (2) 12/31/98 12 1 2 350 km 15,000 160,000
Pomeranian (3) 12/31/98 10 1 2 600 km 25,000 250,000
Warsaw West (3) 11/13/98 13 1 2 1,500 km 25,000 390,000
Baltic (4) 03/07/96 10 1 1 None 25,000 200,000
(1) The Company must drill an exploratory well in each undrilled block
during the second three year phase or relinquish the undrilled block
at the end of the exploration term. The Lublin Basin includes the
Block 298 usufruct, which includes only one exploration block, which
has a requirement to drill two exploratory wells during the second
three year phase. All other Lublin Basin usufructs require the
drilling of one well per block during the second three year phase. As
of December 31, 1999, the Company had drilled two exploratory wells to
be applied against the first three year exploration phase exploratory
well requirement, covered all concession and usufruct fees and
acquired 1,650 kilometers of 2D seismic.
F-25
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
(2) Apache has agreed to cover all of the Company's drilling, seismic,
annual training fees, concession, and usufruct fees during the first
three year phase to earn a fifty percent interest in the Lublin Basin
and Carpathian areas.
(3) The Company and Apache are equal partners in the Pomeranian and Warsaw
West areas. As of December 31, 1999, the Company had covered all
concession and usufruct fees.
(4) The Company has a one-hundred percent interest in the Baltic Project
Area. As of December 31, 1999, the Company had satisfied the minimum
exploratory well requirement for the entire exploration term by
drilling two exploratory wells.
(5) Annual training costs are for each year during the entire six year
exploration term.
(6) Concession and usufruct fees are payable on various terms over the
first three year exploration term, except the Baltic Project Area,
which is payable in equal installments of $33,333 per year over six
years.
(7) The Lublin Basin consists of four usufructs, the Vistula, Lublin
Middle, Block 298, and Komarow which have exploration periods
beginning August 8, 1997, June 30, 1998, June 30, 1998 and March 4,
1998, respectively.
Capital Requirements
As of December 31, 1999, the Company had $6.9 million of cash, cash
equivalents and marketable debt securities with no long-term debt. In view
of the Apache Exploration Program, this amount is expected to be sufficient
to fund the Company's present minimum exploration and operating commitments
during 2000 and part of 2001. The Company intends to seek additional
capital to fund any activities outside the scope of its present minimum
exploration and operating activities, including further exploration,
appraisal and development costs for the Wilga discovery and any other
additional exploration, appraisal, development or property acquisition
activities.
12. Business Segments:
The Company operates within two segments of the oil and gas industry:
exploration and production ("E&P") and drilling and well servicing
("Drilling") and within the exploration segment of the mining industry.
For segment and management reporting purposes the Company's mining segment
is not material and is excluded from the discussion herein.
The Company's revenues associated with its E&P activities are comprised of
oil sales from its producing properties in Montana and Nevada and gains on
the sale of partial property interests of the Company's exploratory
properties in Poland. For the years ended December 31, 1999, 1998 and
1997, over 85% of the Company's total oil sales were to one purchaser
located in Montana. The Company believes this purchaser could be replaced,
if necessary, without a loss in revenue. E&P operating costs are comprised
of: (1) exploration costs, including geological and geophysical costs,
exploratory dry holes and non-producing leasehold impairments; and, (2)
production costs which include lease operating expenses and production
taxes. Substantially all exploration costs are applied to the Company's
operations in Poland and all lease operating costs are applied to the
Company's domestic production. The Company's revenues associated with its
drilling activities are comprised of contract drilling and well servicing
fees generated by the Company's drilling rig and other well servicing
equipment in Montana. Drilling operating costs are comprised of direct
costs associated with its drilling and well servicing operations. DD&A
directly associated with a respective segment is disclosed within that
segment. The Company does not allocate current assets, corporate DD&A,
general and administrative expenses, income taxes, interest expense,
interest income, other income, other expense or officer loan impairments to
its operating segments for management and segment reporting purposes. All
material inter-company transactions between the Company's business segments
are eliminated for management and segment reporting purposes.
F-26
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Information on the Company's operations by business segment for the years
ended December 31, 1999, 1998 and 1997 is summarized as follows:
Year Ended December 31, 1999
-----------------------------------
E&P Drilling Total
--------- --------- ---------
Operations Summary: (In thousands)
Revenues $ 1,554 $ 865 $ 2,419
Cash operating costs (1) 3,844 642 4,486
Non-cash operating costs (2) 140 -- 140
--------- --------- ---------
Operating income or (loss) before
DD&A (2,430) 223 (2,207)
Depreciation, depletion, &
amortization 51 334 385
--------- --------- ---------
Operating loss $ (2,481) $ (111) $ (2,592)
========= ========= =========
Identifiable net property and
equipment:
Non-producing leaseholds - Poland $ 691 $ -- $ 691
Non-producing leaseholds - United
States 692 -- 692
Producing properties 494 -- 494
Equipment and other -- 581 581
--------- ---------- --------
Total $ 1,877 $ 581 $ 2,458
========= ========== ========
Property and equipment capital
expenditures $ 526 $ 138 $ 664
========= ========== ========
(1) Excludes $31,000 of exploratory costs relating to the Company's gold
concessions.
(2) Includes stock options valued at $119,000 issued to a Polish citizen
for consulting services and $21,000 non-producing leasehold impairment
comprised of costs incurred prior to 1999.
Year Ended December 31, 1998
---------------------------------
E&P Drilling Total
-------- ---------- --------
Operations Summary: (In thousands)
Revenues (1) $ 1,590 $ 323 $ 1,913
Cash operating costs (2) 3,025 240 3,265
Non-cash operating costs (3) 119 -- 119
-------- ---------- --------
Operating income or (loss) before
DD&A (1,554) 83 (1,471)
Depreciation, depletion, &
amortization 231 322 553
-------- ---------- --------
Operating loss $(1,785) $ (239) $(2,024)
======== ========== ========
Identifiable net property and
equipment:
Non-producing leaseholds - Poland $ 461 $ -- $ 461
Non-producing leaseholds - United
States 717 -- 717
Producing properties 463 -- 463
Equipment and other -- 780 780
------- ---------- --------
Total 1,641 $ 780 $ 2,421
Property and equipment capital ======= ========== ========
expenditures $ 180 $ 156 $ 336
======= ========== ========
(1) E&P revenues include $1,123,000 generated in the United States and
$467,000 generated in Poland.
(2) Excludes $29,000 of exploratory costs relating to the Company's gold
concessions.
(3) Includes Company common stock issued for services of $119,000 and
excludes non-cash impairment charge of $5,885,000 for domestic proved
properties.
F-27
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Year Ended December 31, 1997
----------------------------------------
E&P Drilling Total
---------- ----------- ---------
Operations Summary: (In thousands)
Revenues (1) $ 2,242 $ 496 $ 2,738
Cash operating costs 6,455 329 6,784
Non-cash operating costs (2) 99 -- 99
---------- ----------- ---------
Operating income or (loss) before DD&A (4,312) 167 (4,145)
Depreciation, depletion, & amortization 261 289 550
---------- ----------- ---------
Operating loss $ (4,573) $ (122) $ (4,695)
========== =========== =========
Identifiable net property and equipment:
Non-producing leaseholds - Poland $ 461 $ -- $ 461
Non-producing leaseholds - United States 709 -- 709
Producing properties 6,447 -- 6,447
Equipment and other -- 935 935
--------- ----------- ---------
Total net assets $ 7,617 $ 935 $ 8,552
========= =========== =========
Property and equipment capital expenditures $ 860 $ 210 $ 1,070
========= =========== =========
(1) E&P revenues include $2,040,000 generated in the United States and
$202,000 generated in Poland. Excludes $71,000 gain from sale of
property interest relating to the Company's gold concessions in
Poland.
(2) Includes Company common stock issued for services of $70,000
and a non-cash impairment charge of $29,000 for a lease in
Wyoming acquired prior to 1997.
A reconciliation of the segment information to the consolidated
totals for the years ended December 31, 1999, 1998 and 1997 follows:
Year Ended December 31,
------------------------------------------
1999 1998 1997
---------- ----------- ------------
Revenues: (In thousands)
Reportable segments $ 2,419 $ 1,913 $ 2,738
Non-reportable segments -- -- 71
---------- ----------- ------------
Total consolidated revenues $ 2,419 $ 1,913 $ 2,809
========== =========== ============
Operating Loss:
Reportable segments $ (2,592) $ (2,024) $ (4,695)
Expense or (revenue) adjustments:
Non-reportable segments 31 29 (71)
Impairment of domestic proved property -- 5,885 --
General and administrative expenses 2,962 2,572 2,566
Corporate DD&A 109 118 85
Other -- 1 (1)
---------- ----------- ------------
Consolidated net operating loss $ (5,694) $ (10,629) $ (7,274)
========== =========== ============
Net Property and Equipment:
Reportable segments $ 2,458 $ 2,421 $ 8,552
Corporate assets 91 178 209
---------- ----------- ------------
Net property and equipment $ 2,549 $ 2,599 $ 8,761
========== =========== ============
Property and Equipment Capital Expenditures:
Reportable segments $ 581 $ 336 $ 1,070
Corporate assets 19 105 461
---------- ----------- ------------
Net property and equipment capital
expenditures $ 600 $ 441 $ 1,531
========== =========== ============
F-28
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
13. Quarterly Financial Data (Unaudited):
During the year ended ended December 31, 1999, the Company recorded
exploratory dry hole costs of $580,000 and $389,000 during the third and
fourth quarters, respectively, and an officer loan impairment of
$666,000 during the fourth quarter. During the year ended December
31, 1998, the Company incurred a domestic proved property impairment
of $5,885,000, of which $5,640,000 and $245,000 were recorded during
the third and fourth quarters, respectively.
Summary quarterly information for the years ended December 31, 1999 and
1998 is as follows:
For the Quarter Ended
---------------------------------------------------
December 31 September 30 June 30 March 31
------------ ------------ ---------- -----------
(In thousands, except per share amounts)
1999 Quarterly
Information:
Revenues $ 785 $ 862 $ 451 $ 321
Net operating loss (2,746) (1,228) (895) (825)
Net loss $ (3,272) $ (1,072) $ (789) (723)
Basic and diluted net
loss per common
share $ (.21) $ (.08) $ (.06) $ (.06)
1998 Quarterly
Information:
Revenues $ 416 $ 426 $ 272 $ 799
Operating income or
(loss) (1,949) (6,511) (1,465) (704)
Net income or $ (6,392) $ (1,353) $ (519)
(loss) $ (1,858)
Basic and diluted net
loss per Common
share $ (.15) $ (.49) $ (.10) $ (.04)
14. Disclosure about Oil and Gas Properties and Producing Activities:
Impairment of Unproved Oil and Gas Properties
In accordance with generally accepted accounting principles, the Company
must record an impairment expense to the extent that capitalized costs of
unproved properties, on a property by property basis, are considered not
realizable. During the year ended December 31, 1999, the Company recorded
an impairment expense of $21,000 relating to a prospect located in Nevada
and $72,000 relating to the Lachowice Farm-in in Poland. During the year
ended December 31, 1997, the Company recorded an impairment expense of
$152,000 relating to several prospects in Montana, Nevada and Wyoming.
Impairment of Proved Oil and Gas Properties
In accordance with generally accepted accounting principles, the Company
must record an impairment expense if the Company determines the net book
value of its proved oil and gas properties, on a property by property
basis, exceeds the aggregate future net revenues from such properties. As
of December 31, 1998, the Company's future undiscounted net revenues from
its domestic proved developed properties was $1,015,000 and its discounted
future net revenues (PV-10) of it domestic proved developed properties was
$472,000. The future net revenues at December 31, 1998 were computed
using a price of $8.11 per barrel, the average price at December 31, 1998.
Accordingly, the Company recorded an impairment expense of $5,885,000 for
the year ended December 31, 1998, which reduced the carrying value of its
domestic proved properties to $463,000, an amount which approximated the
fair value of its domestic proved developed reserves determined on a
property by property basis.
F-29
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
In view of the Company's increased focus on its Polish exploration and
development opportunities and the probability of continued depressed oil
prices, management has determined it is unlikely the Company will incur any
domestic development costs in the foreseeable future. Accordingly, the
Company's proved reserves as of December 31, 1999 and 1998 include only
those reserves attributable to developed properties.
Capitalized Costs
Capitalized costs relating to oil and gas producing activities as of
December 31, 1999 and 1998 are summarized as follows:
United States Poland Total
-------------- --------- ---------
(In thousands)
December 31, 1999:
Proved properties $ 1,687 $ -- $ 1,687
Unproved properties 692 691 1,383
-------------- --------- ---------
Total gross properties 2,379 691 3,070
Less accumulated, depreciation, --
depletion and amortization (1,193) (1,193)
-------------- --------- ---------
Total $ 1,186 $ 691 $ 1,877
============== ========== ==========
December 31, 1998:
Proved properties $ 1,605 $ -- $ 1,605
Unproved properties 718 461 1,179
------------- --------- ---------
Total gross properties 2,323 461 2,784
Less accumulated depreciation, --
depletion and amortization (1,142) (1,142)
------------- --------- ---------
Total $ 1,181 $ 461 $ 1,642
============= ========= =========
Acquisition, Exploration and Development Activities
Costs incurred in oil property acquisition, exploration and development
activities during the years ended December 31, 1999, 1998 and 1997, whether
capitalized or expensed, are summarized as follows:
United
States Poland Total
--------- --------- ---------
(In thousands)
December 31, 1999:
Acquisition of properties:
Proved $ -- $ -- $ --
Unproved 1 230 231
Exploration costs 38 3,016 3,054
Development costs 82 -- 82
-------- -------- ---------
Total $ 121 $ 3,246 $ 3,367
======== ======== =========
December 31, 1998:
Acquisition of properties:
Proved $ -- $ -- $ --
Unproved 15 33 48
Exploration costs 34 2,092 2,126
Development costs 132 -- 132
-------- -------- ---------
Total $ 181 $ 2,125 $ 2,306
======== ======== =========
F-30
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
December 31, 1997:
Acquisition of properties:
Proved $ -- $ -- $ --
Unproved 733 66 799
Exploration costs 1,419 3,895 5,314
Development costs 187 -- 187
-------- -------- ---------
Total $ 2,339 $ 3,961 $ 6,300
======== ======== =========
15. Summary Oil and Gas Reserve Data (Unaudited):
The following quantity and value information is based on prices as of the
end of each respective reporting period. No price escalations were
assumed. Operating costs and production taxes 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 amounts were deducted for general overhead,
depreciation, depletion and amortization, interest expense and income
taxes.
The determination of oil and gas reserves is based on estimates and is
highly complex and interpretive. The estimates are subject to continuing
revisions as additional information becomes available or assumptions
change. All of the Company's oil reserves are in the United States.
Estimated Quantities of Proved Oil Reserves
Following is a reconciliation of the Company's interest in net quantities
of proved oil reserves. All proved oil reserves are located in the United
States. 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.
Changes in estimated oil reserves of the Company for the years ended
December 31, 1999, 1998 and 1997 are as follows:
For the years ended December 31,
---------------------------------
1999 1998 1997
---------- --------- --------
(In thousands bbls of oil)
Total proved reserves:
Beginning of year 1,535 4,760 5,443
Purchase of minerals in-place -- -- --
Extensions and discoveries -- -- 18
Revisions of previous estimates (354) (3,110) (575)
Production (101) (115) (126)
---------- --------- --------
End of year 1,080 1,535 4,760
---------- --------- --------
Proved developed reserves:
Beginning of year 1,535 2,282 2,829
---------- --------- --------
End of year 1,080 1,535 2,282
---------- --------- --------
The decrease in 1999 reserves as compared to 1998 reserves was principally
due to higher operating costs and a higher production decline rate utilized
in the 1999 report as compared to the 1998 report. The decrease in 1998
reserves as compared to 1997 was principally due to the elimination of
2,478,000 bbls of proved undeveloped reserves which were included as of as
of December 31, 1997 and a $5.70 per bbl decrease in oil prices at year-end
1998 as compared to year-end 1997.
F-31
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO 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. 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.
Future net cash flows were computed by applying the year-end oil prices of
$22.37, $8.11 and $13.81 for the years ended December 31, 1999, 1998 and
1997, respectively and production costs per bbl of $14.11, $7.43 and $6.86
for 1999, 1998 and 1997, respectively, to the period-end quantities of the
Company's proved reserves. The variance in price from year to year was due
to price volatility associated with world-wide oil price fluctuations. The
increase in production costs of $6.68 per barrel for 1999, as compared to
1998, is primarily due the economic lives of marginal wells being extended
due to an oil price $14.26 per bbl higher in the 1999 report, as compared
to the 1998 report.
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% per year was used to
reflect the timing of the future net cash flows.
The components of SMOG are detailed below:
As of December 31,
---------------------------------------
1999 1998 1997
------------ ---------- ----------
SMOG Components: (In thousands)
Future cash flows $ 24,229 $ 12,518 $
65,740
Future production costs (15,240) (11,408) (32,658)
Future development costs (105) (95) (6,273)
------------ ---------- ----------
Future net cash flows 8,884 1,015 26,809
Future income tax expense -- -- (125)
------------ ---------- ----------
Future net cash flows 8,884 1,015 26,684
10% annual discount for
estimated timing of cash
flows (3,424) (543) (13,109)
------------ ---------- ----------
Total $ 5,460 $ 472 $ 13,575
============ ========== ==========
F-32
FX ENERGY, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following are principal sources of changes in SMOG:
Years Ended December 31,
----------------------------------------
1999 1998 1997
----------- ----------- -----------
SMOG Sources: (In thousands)
Balance, beginning of year $ 472 $ 13,575 $ 26,284
Sales of oil produced, net
of production costs (592) (77) (801)
Net changes in prices and
production costs 5,032 (4,482) (16,707)
Purchases of minerals in
place -- -- --
Extensions and discoveries,
net of future costs -- -- 108
Changes in estimated future
development costs (6) 2,875 (79)
Development costs incurred
during the year 82 132 394
Revisions in previous
quantity estimates (1,650) (9,076) (1,969)
Accretion of discount 47 1,357 2,628
Net change in income taxes -- (952) 9,071
Changes in rates of
production and other 2,075 (2,880) (5,354)
----------- ----------- -----------
Balance, end of year $ 5,460 $ 472 $ 13,575
=========== =========== ===========
16. Subsequent Events:
On January 25, 2000, the Company announced that the Wilga 2, the fifth
exploratory well drilled under terms of the Apache Exploration Program, was
an exploratory success after initial test results indicated a combined flow
rate of 16.9 Mmcf of gas and 570 Bbls of condensate per day from three
intervals in a Carboniferous Horizon at a depth between 7,732 feet and
8,550 feet. The Wilga 2 is located approximately 25 miles southeast of
Warsaw and approximately 12 miles from an existing pipeline. In accordance
with terms of the Apache Exploration Program, Apache will cover the
Company's 45.0% share of drilling and completion costs pertaining to the
Wilga 2. The Company will pay for its 45.0% share of costs thereafter. The
Company and its partners plan an appraisal well immediately, followed by
additional development drilling and facilities construction later in the
year, with initial production expected to commence during early 2001. In
addition, the Company will promptly begin seismic acquisition in the Wilga
area to identify a target near the Wilga discovery to be drilled later this
year to test the possibility of additional reserves outside the Wilga
structure.
F-33
PART II
Information Not Required in Prospectus
Item 16. Exhibits and Financial Statement Schedules
(a) Exhibits
SEC
Exhibit Reference
Number Number Title of Document Location
- ------------ -------------- ---------------------------------------------------------------- -------------------
Item 3. Articles of Incorporation and Bylaws
- --------------------------------------------------------------------------------------------
3.1 3 Restated and Amended Articles of Incorporation Incorporated by
Reference(11)
3.2 3 Bylaws Incorporated by
Reference(1)
Item 4. Instruments Defining the Rights of Security Holders
- --------------------------------------------------------------------------------------------
4.1 4 Specimen Stock Certificate Incorporated by
Reference(1)
4.2 4 Form of Designation of Rights, Privileges, and Preferences of Incorporated by
Series A Preferred Stock Reference(14)
4.3 4 Form of Rights Agreement dated as of April 4, 1997, between FX Incorporated by
Energy and Fidelity Transfer Corp. Reference(14)
Item 5. Opinion re: Legality
- --------------------------------------------------------------------------------------------
5.1 5 Opinion of Kruse, Landa & Maycock, LLC Initial Filing
Item 10. Material Contracts
- --------------------------------------------------------------------------------------------
10.1 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and Frontier Poland Exploration and Reference(3)
Producing Company, Sp. z o.o. dated August 22, 1995,
relating to Blocks 51, 52, 71, 72, 91, 92, 93, 111, 112,
and 113 (Baltic)
10.2 10 Amendment No. 1 to Mining Usufruct Agreement dated August 15, Incorporated by
1996 (Baltic) Reference(4)
10.3 10 Amendment No. 2 to Mining Usufruct Agreement dated August 22, Incorporated by
1996 (Baltic) Reference (15)
10.4 10 Form of concession dated December 20, 1995, relating to Baltic Incorporated by
Concessions granted pursuant to the Mining Usufruct Reference(5)
Agreement dated August 15, 1996, with related schedule
10.5 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and Lubex Petroleum Company Sp. z o.o. Reference(10)
dated December 20, 1996, relating to concession blocks
255, 275, 295, 316, 336, 337, and 338 (Lublin)
10.6 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and Apache Poland Sp. z o.o. and FX Reference(12)
Energy Poland Sp. z o.o. (East), commercial partnership
dated October 14, 1997, related to concession blocks 257,
258, 277, 278, 297, 317, and 318 (Lublin)
10.7 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and Apache Poland Sp. z o.o. and FX Reference(12)
Energy Poland Sp. z o.o. (East), commercial partnership
dated October 14, 1997, related to concession block 298
(Lublin)
II-i
SEC
Exhibit Reference
Number Number Title of Document Location
- ------------ -------------- ---------------------------------------------------------------- -------------------
10.8 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and Apache Poland Sp. z o.o. and FX Reference(12)
Energy Poland Sp. z o.o. (East), commercial partnership
dated October 14, 1997, related to concession blocks 319,
320, 339, 340, 340A, 359, 360, 360A, 379, 380, and 380A
(Lublin)
10.9 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and Gasex Production Company Sp. z o.o. Reference(12)
and Company, commercial partnership dated October 14,
1997, related to concession blocks 410, 411, 412, 413,
414, 415, 430, 431, 432, 433, 452 and 453 (Western
Carpathian)
10.10 10 Mining Usufruct Agreement between the State Treasury of the Incorporated by
Republic of Poland and FX Energy Poland Sp. z o.o. and Reference(12)
Partners, commercial partnership dated October 30, 1997,
related to concession blocks 85, 86, 87, 88, 89, 105,108,
109, 129, and 149, in northwestern Poland (Pomeranian)
10.11 10 Option Agreement dated July 18, 1997, between Polish Oil and Incorporated by
Gas Company, FX Energy, and Apache Overseas, Inc. Reference(12)
10.12 10 Participation Agreement dated effective as of April 16, 1997, Incorporated by
between Apache Overseas, Inc., and FX Energy, pertaining Reference(13)
to the Lublin Concessions
10.13 10 Letter Agreement dated February 27, 1998, between FX Energy Incorporated by
and Apache Overseas, Inc., regarding modification to all Reference (15)
agreements for acreage in Poland under established area of
mutual interest.
10.14 10 Participation Agreement dated effective February 27, 1998, Incorporated by
between FX Energy and Apache Overseas, Inc., pertaining to Reference (15)
the Western Carpathian Concession
10.15 10 Participation Option Agreement dated effective February 27, Incorporated by
1998, between FX Energy and Apache Overseas, Inc., Reference (15)
pertaining to the Pomeranian Concession
10.16 10 Prospect Agreement between Apache Poland Sp. z o.o., and FX Incorporated by
Energy Poland Sp. z o.o., dated April 17, 1998. Reference (18)
10.17 10 Option Agreement dated effective as of February 2, 1998, Incorporated by
between POGC, FX Energy, Inc., and Apache Overseas, Inc., Reference (15)
pertaining to the Western Carpathian Concessions
10.18 10 Option Agreement dated March 5, 1998, effective as of April Incorporated by
16, 1997, between FX Energy, Inc., Apache Overseas, Inc., Reference (17)
and POGC, relating to FX Energy's Carpathian Concessions.
10.19 10 Option Agreement between FX Energy Poland Sp. z o.o., and POGC Incorporated by
dated effective May 20, 1998, relating to Pomeranian Reference (19)
Concessions
10.20 10 Agreement dated October 21, 1996, between Sudety Mining Incorporated by
Company Sp. z o.o. and the State Treasury of the Republic Reference (9)
of Poland, for the establishment of the mining usufruct
for the purpose of gold exploration in the Sudety
Concessions
II-ii
SEC
Exhibit Reference
Number Number Title of Document Location
- ------------ -------------- ---------------------------------------------------------------- -------------------
10.21 10 Earn-In and Exploration Letter of Intent dated June 13, 1997, Incorporated by
between FX Energy and Homestake Mining Company of Reference (12)
California
10.22 10 Form of Mining Usufruct Agreement between the State Treasury Incorporated by
of the Republic of Poland and FX Energy Poland Sp. z o.o. Reference (15)
Commercial Partnership, dated October 16, 1997, relating
to Sudety Concession blocks 43, 63, 64, 65, with related
schedule.
10.23 10 Earn-in, Exploration, and Joint Venture Agreement between Incorporated by
Homestake Mining Company of California and FX Energy Reference (15)
effective December 31, 1997, regarding exploration for
precious metals in the Republic of Poland (Sudety)
10.24 10 Agreement between Apache Overseas, Inc., and FX Energy dated Incorporated by
effective January 1, 1999, pertaining to oil and gas Reference (20)
operations in Poland
10.25 10 Agreement on Cooperation in the Lachowice Area between POGC, Incorporated by
Apache Overseas, Inc., Apache Poland, Sp. Z o.o., FX Reference (20)
Energy, Inc., and FX Energy Poland Sp. Z o.o., dated
February 26, 1999
10.26 10 Frontier Oil Exploration Company 1995 Stock Option and Award Incorporated by
Plan* Reference(4)
10.27 10 Form of FX Energy, Inc., 1996 Stock Option and Award Plan* Incorporated by
Reference(10)
10.28 10 Form of FX Energy, Inc., 1997 Stock Option and Award Plan* Incorporated by
Reference (20)
10.29 10 Form of FX Energy, Inc., 1998 Stock Option and Award Plan* Incorporated by
Reference (20)
10.30 10 Employment Agreements between FX Energy and each of David Incorporated by
Pierce and Andrew Pierce, effective January 1, 1995* Reference(1)
10.31 10 Amendments to Employment Agreements between FX Energy and each Incorporated by
of 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. Incorporated by
Pierce) * Reference(1)
10.33 10 Form of Stock Option granted to D. Pierce and A. Pierce* Incorporated by
Reference(1)
10.34 10 Form of Non-Qualified Stock Option with related schedule* Incorporated by
Reference(4)
10.35 10 Letter Agreement dated effective August 3 , 1995, between Incorporated by
Lovejoy Associates, Inc., and FX Energy re: Financial Reference(4)
Consulting Engagement*
10.36 10 Letter Agreement dated effective August 3, 1995, between Incorporated by
Lovejoy Associates, Inc., and FX Energy re: Reference(4)
Indemnification
10.37 10 Non-Qualified Stock Option granted to Thomas B. Lovejoy* Incorporated by
Reference(4)
II-iii
SEC
Exhibit Reference
Number Number Title of Document Location
- ------------ -------------- ---------------------------------------------------------------- -------------------
10.38 10 Letter Agreement dated effective December 31, 1997, between FX Incorporated by
Energy and Lovejoy Associates, Inc., re: Extension of Reference (15)
Consulting Engagement*
10.39 10 Employment Agreement between FX Energy and Jerzy B. Maciolek* Incorporated by
Reference(8)
10.40 10 Addendum to Employment Agreement between FX Energy and Jerzy Incorporated by
B. Maciolek* Reference (15)
10.41 10 Second Addendum to Employment Agreement between FX Energy and Incorporated by
Jerzy B. Maciolek* Reference (15)
10.42 10 Employment Agreement between FX Energy and Scott J. Duncan* Incorporated by
Reference (15)
10.43 10 Form of Indemnification Agreement between FX Energy and Incorporated by
certain directors, with related schedule* Reference(10)
10.44 10 Form of Option granted to executive officers and directors, Incorporated by
with related schedule* Reference(10)
10.45 10 Memorandum of Understanding regarding officer loans (reformed Incorporated by
June 19, 1998) Reference (16)
10.46 10 Limited Recourse Promissory Note of David N. Pierce in the Incorporated by
amount of $950,954 (reformed June 19, 1998) Reference (16)
10.47 10 Pledge and Security Agreement between FX Energy, Inc. and Incorporated by
David N. Pierce (reformed June 19, 1998) Reference (16)
10.48 10 Agreement to Hold Collateral between FX Energy, Inc. and David Incorporated by
N. Pierce and Kruse, Landa & Maycock as agent to hold Reference (16)
collateral (reformed June 19, 1998)
10.49 10 Limited Recourse Promissory Note of Andrew W. Pierce in the Incorporated by
amount of $769,924 (reformed June 19, 1998) Reference (16)
10.50 10 Pledge and Security Agreement between FX Energy, Inc. and Incorporated by
Andrew W. Pierce (reformed June 19, 1998) Reference (16)
10.51 10 Agreement to Hold Collateral between FX Energy, Inc. and Incorporated by
Andrew W. Pierce and Kruse, Landa & Maycock as agent to Reference (16)
hold collateral (reformed June 19, 1998)
10.52 10 Form of Indemnification Agreement between FX Energy and Incorporated by
certain directors, with related schedule Reference (21)
10.53 10 Agreement on Cooperation in Exploration of Hydrocarbons on Incorporated by
Foresudetic Monocline dated April 11, 2000, between Reference (22)
Polskie Gornictwo Naftowe i Gaxownictwo S.A. ("POGC") and
FX Energy Poland Ps. Z o.o. relating to the Fences project
10.54 10 Agreement effective as of January 1, 2000, between FX Energy, Incorporated by
Inc., and Apache Overseas, Inc. Reference (23)
Item 21 Subsidiaries of the Registrant
- -----------------------------------------------------------------------------------------------------------------
21.1 Schedule of Subsidiaries Incorporated by
Reference (15)
II-iv
SEC
Exhibit Reference
Number Number Title of Document Location
- ------------ -------------- ---------------------------------------------------------------- -------------------
Item 23 Consents of Experts and Counsel
- --------------------------------------------------------------------------------------------
23.1 23 Consent of PricewaterhouseCoopers LLP, independent accountants Initial Filing
23.2 23 Consent of Larry D. Krause, Petroleum Engineer Initial Filing
23.3 23 Consent of Kruse, Landa & Maycock, LLC Initial Filing
Item 27 Financial Data Schedule
- --------------------------------------------------------------------------------------------
27.1 27 Financial Data Schedule This Filing
- ------------------------
* Identifies each management contract or compensatory plan or arrangement
required to be filed as an exhibit.
(1) Incorporated by reference from the registration statement on Form SB-2, SEC
File No. 33-88354-D.
(2) Incorporated by reference from the report on Form 8-K dated August 16,
1995.
(3) Incorporated by reference from the report on Form 8-K dated August 22,
1995.
(4) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended September 30, 1995.
(5) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 1995.
(6) Incorporated by reference from the reports on Form 8-K dated May 3, 1996.
(7) Incorporated by reference from the report on Form 8-K dated May 21, 1996.
(8) Incorporated by reference from the registration statement on Form S-1, SEC
File No.333-05583.
(9) Incorporated by reference from the report on Form 8-K dated October 1,
1996.
(10) Incorporated by reference from the annual report on Form 10-KSB for the
year ended December 31, 1996.
(11) Incorporated by reference from the proxy statement respecting the 1997
annual meeting of stockholders.
(12) Incorporated by reference from the quarterly report on Form 10-QSB for the
quarter ended September 30, 1997.
(13) Incorporated by reference from the report on Form 8-K dated August 6, 1997.
(14) Incorporated by reference from the report on Form 8-K dated April 4, 1997.
(15) Incorporated by reference from the annual report on Form 10-KSB for the
year ended December 31, 1997.
(16) Incorporated by reference from the annual report on Form 10-Q for the
quarter ended March 31, 1998, as amended on Form 10-Q/A filed July 15,
1998.
(17) Incorporated by reference from the report on Form 8-K dated March 23, 1998.
(18) Incorporated by reference from the report on Form 8-K dated April 20, 1998.
(19) Incorporated by reference from the report on Form 8-K dated June 2, 1998.
(20) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 1998.
(21) Incorporated by reference from the annual report on Form 10-K for the year
ended December 31, 1999.
(22) Incorporated by reference from the report on Form 8-K dated April 18, 2000.
(23) Incorporated by reference from the quarterly report on Form 10-Q for the
quarter ended March 31, 2000.
(b) Consolidated Financial Statement Schedules.
All schedules have been omitted because they are not required or because the
required information is given in the Consolidated Financial Statements or Notes
to those statements.
II-v
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
Registrant has duly caused this amendment to the Registration Statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in Salt Lake
City, Utah, on July 28, 2000.
FX Energy, Inc.
By: /s/ Scott J. Duncan
--------------------------
Scott J. Duncan
Vice-President
Pursuant to the requirements of the Securities Act of 1933, this
amendment to the Registration Statement has been signed below by the following
persons in the capacities indicated and on the 28th day of July, 2000:
- ------------------------------------------
/s/ David N. Pierce
Director, President, and Chief
Executive Officer
(Principal Executive and
Financial Officer)
- ------------------------------------------
/s/ Andrew W. Pierce
Vice-President, Chief Operations
Officer and Director
(Principal Operations Officer)
- ------------------------------------------ By: /s/ Scott J. Duncan
/s/ Thomas B. Lovejoy ---------------------
Director, Chief Financial Scott J. Duncan
Officer and Vice Chairman Attorney-in-Fact
- ------------------------------------------
/s/ Scott J. Duncan
Director, Vice-President Investor
Relations and Secretary
- ------------------------------------------
/s/ Dennis L. Tatum
Director, Vice-President and
Treasurer (Principal Accounting
Officer)
- ------------------------------------------
/s/ Peter L. Raven
Director
- ------------------------------------------
/s/ Jay W. Decker
Director
66