U. S. SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003
Commission File No. 0-25386
FX ENERGY, INC.
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Nevada 87-0504461
- -------------------------------- -------------------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206
Salt Lake City, Utah 84106
-----------------------------------------------------------
(Address of principal executive offices, including Zip Code)
(801) 486-5555
----------------------------------------------------
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date. The number of shares
of $0.001 par value common stock outstanding as of November 11, 2003, was
21,712,425.
FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Quarter Ended September 30, 2003
TABLE OF CONTENTS
Item Page
- ---------- --------
Part I. Financial Information
1 Financial Statements:
Consolidated Balance Sheets........................... 3
Consolidated Statements of Operations................. 5
Consolidated Statements of Cash Flows................. 7
Notes to Consolidated Financial Statements............ 8
2 Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 14
3 Quantitative and Qualitative Disclosures about Market Risk.. 21
4 Controls and Procedures..................................... 21
Part II. Other Information
2 Changes in Securities and Use of Proceeds................... 22
6 Exhibits and Reports on Form 8-K............................ 22
-- Signatures.................................................. 24
2
PART I.
ITEM 1. FINANCIAL STATEMENTS
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
December 31,
September 30, 2002
2003 (as restated)
--------------- ---------------
ASSETS
Current assets:
Cash and cash equivalents.............................................. $ 4,929,199 $ 705,012
Restricted cash........................................................ 3,325,000 --
Accounts receivable:
Accrued oil and gas sales............................................ 226,215 238,236
Joint interest owners and others..................................... 52,129 36,893
Inventory.............................................................. 79,656 84,262
Other current assets................................................... 208,257 95,726
--------------- ---------------
Total current assets................................................. 8,820,456 1,160,129
--------------- ---------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved............................................................... 6,286,840 4,754,377
Unproved............................................................. 154,261 154,261
Other property and equipment......................................... 3,717,741 3,683,226
--------------- ---------------
Gross property and equipment....................................... 10,158,842 8,591,864
Less: accumulated depreciation, depletion and amortization........... (4,326,198) (4,685,487)
--------------- ---------------
Net property and equipment......................................... 5,832,644 3,906,377
--------------- ---------------
Other assets:
Certificates of deposit ............................................... 356,500 356,500
Other.................................................................. 368,373 18,072
--------------- ---------------
Total other assets................................................... 724,873 374,572
--------------- ---------------
Total assets............................................................. $ 15,377,973 $ 5,441,078
=============== ===============
-- Continued --
The accompanying notes are an integral part of the consolidated financial statements.
3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
-- Continued --
December
September 31, 2002
30, 2003 (as restated)
--------------- ---------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable....................................................... $ 451,460 $ 376,264
Accrued liabilities.................................................... 2,399,769 4,933,393
Current portion of note payable ....................................... 3,325,000 5,000,000
--------------- ---------------
Total current liabilities............................................ 6,176,229 10,309,657
Asset retirement obligation ............................................ 373,410 --
--------------- ---------------
Total liabilities.................................................... 6,549,639 10,309,657
--------------- ---------------
Stockholders' equity (deficit):
Preferred stock, $0.001 par value, 5,000,000 shares authorized;
2,250,000 shares issued and outstanding ($5,625,000 liquidation
preference) as of September 30, 2003, and no shares as of
December 31, 2002.................................................... 2,250 --
Common stock, $.001 par value, 100,000,000 shares authorized;
20,986,252 and 17,651,917 shares issued and outstanding as
of September 30, 2003, and December 31, 2002, respectively........... 20,987 17,652
Additional paid-in capital............................................. 62,646,910 48,075,035
Accumulated deficit.................................................... (53,841,813) (52,961,266)
--------------- ---------------
Total stockholders' equity (deficit)................................. 8,828,334 (4,868,579)
--------------- ---------------
Total liabilities and stockholders' equity............................... $ 15,377,973 $ 5,441,078
=============== ===============
The accompanying notes are an integral part of the consolidated financial statements.
4
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
For the three months ended For the nine months ended
September 30, September 30,
------------------------------- -----------------------------
2003 2002 2003 2002
-------------- --------------- ------------- -------------
Revenues:
Oil and gas sales................................. $ 557,637 $ 618,069 $ 1,676,155 $ 1,632,607
Oilfield services................................. 43,874 358,520 76,402 401,385
-------------- --------------- ------------- -------------
Total revenues.................................. 601,511 976,589 1,752,557 2,033,992
-------------- --------------- ------------- -------------
Operating costs and expenses:
Lease operating expenses.......................... 361,008 340,887 1,117,812 1,031,306
Geological and geophysical costs.................. 115,624 87,453 406,483 389,179
Oilfield services costs........................... 97,077 257,576 225,851 443,274
Depreciation, depletion and amortization.......... 157,205 145,198 412,625 461,849
Amortization of deferred compensation (G&A)....... -- -- -- 54,688
Accretion expense................................. 9,287 -- 27,859 --
Other general and administrative costs (G&A)...... 515,538 416,503 1,569,426 1,675,225
-------------- --------------- ------------- -------------
Total operating costs and expenses.............. 1,255,739 1,247,617 3,760,056 4,055,521
-------------- --------------- ------------- -------------
Operating loss...................................... (654,228) (271,028) (2,007,499) (2,021,529)
-------------- --------------- ------------- -------------
Other income (expense):
Interest and other income......................... 9,474 17,209 18,793 121,886
Interest expense.................................. (221,474) (118,767) (691,335) (361,029)
-------------- --------------- ------------- -------------
Total other income (expense).................... (212,000) (101,558) (672,542) (239,143)
-------------- --------------- ------------- -------------
Loss before cumulative effect of change in
accounting principle.............................. (866,228) (372,586) (2,680,041) (2,260,672)
Cumulative effect of change in accounting principle. -- -- 1,799,494 --
Net loss............................................ $ (866,228) $ (372,586) $ (880,547) $ (2,260,672)
============== =============== ============= =============
Pro forma net loss reflecting adoption
of SFAS 143....................................... $ (380,952) $ (2,285,770)
=============== =============
The accompanying notes are an integral part of the consolidated financial statements.
5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
-- Continued --
For the three months ended For the nine months ended
September 30, September 30,
------------------------------- -----------------------------
2003 2002 2003 2002
-------------- --------------- ------------- -------------
Basic loss per common share before cumulative
effect of change in accounting principle.......... $ (0.04) $ (0.02) $ (0.15) $ (0.13)
Cumulative effect of change in accounting principle. -- -- 0.10 --
-------------- --------------- ------------- -------------
Basic net loss per common share..................... $ (0.04) $ (0.02) $ (0.05) $ (0.13)
============== =============== ============= =============
Diluted loss per common share before cumulative
effect of change in accounting principle.......... (0.04) (0.02) (0.15) (0.13)
Cumulative effect of change in accounting principle. -- -- 0.10 --
-------------- --------------- ------------- -------------
Diluted net loss per common share................... $ (0.04) $ (0.02) $ (0.05) $ (0.13)
============== =============== ============= =============
Pro forma net loss per common share reflecting
adoption of SFAS 143
Basic............................................... $ (0.02) $ (0.13)
=============== =============
Diluted............................................. $ (0.02) $ (0.13)
=============== =============
Basic and diluted weighted average number of shares
outstanding....................................... 20,065,624 17,650,906 18,486,055 17,637,769
The accompanying notes are an integral part of the consolidated financial statements.
6
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
For the nine months ended
September 30,
----------------------------------
2003 2002
-------------- -------------
Cash flows from operating activities:
Net loss............................................................... $ (880,547) $ (2,260,672)
Adjustments to reconcile net loss to net
cash used in operating activities:
Cumulative effect of change in accounting principle................ (1,799,494) --
Accretion expense.................................................. 27,859 --
Amortization of loan fees.......................................... 69,467 --
Depreciation, depletion and amortization........................... 412,625 461,849
Amortization of deferred compensation (G&A)........................ -- 54,688
Stock issued for services.......................................... 91,181 44,000
Increase (decrease) from changes in working capital items:
Accounts receivable.................................................. (3,215) (383,132)
Inventory............................................................ 4,606 4,347
Other assets......................................................... (81,998) (43,825)
Accounts payable and accrued liabilities............................. (194,983) 257,514
-------------- -------------
Net cash used in operating activities.............................. (2,354,499) (1,865,231)
-------------- -------------
Cash flows from investing activities:
Payments for oil and gas properties.................................... (2,301,743) (49,379)
Additions to other property and equipment.............................. (37,149) (114,833)
Partner advance........................................................ (365,584) --
Increase in restricted cash............................................ (3,325,000) --
Changes in other assets................................................ 15,283 --
-------------- -------------
Net cash provided by (used in) investing activities.................. (6,014,193) (164,212)
-------------- -------------
Cash flows from financing activities:
Proceeds from preferred stock offering, net............................ 5,593,872 --
Proceeds from common stock offering, net............................... 8,774,007 --
Payment of loan fees................................................... (100,000) --
Payments on notes payable.............................................. (1,675,000) --
Proceeds from the exercise of options.................................. -- 4,500
-------------- -------------
Net cash provided by financing activities............................ 12,592,879 4,500
-------------- -------------
Increase (decrease) in cash and cash equivalents......................... 4,224,187 (2,024,943)
Cash and cash equivalents at beginning of period......................... 705,012 3,157,427
-------------- -------------
Cash and cash equivalents at end of period............................... $ 4,929,199 $ 1,132,484
============== =============
The accompanying notes are an integral part of the consolidated financial statements.
7
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
(Unaudited)
Note 1: Basis of Presentation
The interim financial statements are unaudited. In the opinion of the
management of FX Energy, Inc. and Subsidiaries ("FX Energy" or the "Company"),
the interim financial statements include all adjustments, consisting only of
normal recurring adjustments, necessary for a fair presentation of the results
for the presented interim periods. The interim financial statements should be
read in conjunction with FX Energy's amended quarterly report on Form 10-Q/A for
the three and six months ended June 30, 2003, the amended quarterly report on
Form 10-Q/A for the three months ended March 31, 2003, and the amended annual
report on Form 10-K/A for the year ended December 31, 2002, 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 intercompany accounts and transactions have been eliminated in
consolidation. At September 30, 2003, FX Energy owned 100% of the voting stock
of all of its subsidiaries.
Note 2: Private Placements of Common and Convertible Preferred Stock
During the months of July and August, 2003, the Company sold 3,265,137
Units, consisting of one share of common stock and one warrant to purchase one
share of common stock at $3.75 per share, raising a total of $8.8 million after
offering costs of $42,000. The warrants to purchase common stock are exercisable
anytime between July 22, 2004, and July 22, 2008.
In March 2003, the Company sold 2,250,000 shares of 2003 Series
Convertible Preferred Stock in a private placement of securities, raising a
total of $5.6 million after offering costs of $31,000. Each share of preferred
stock immediately converts into one share of common stock and one warrant to
purchase one share of common stock at $3.60 per share upon registration of the
common shares. The warrants to purchase common stock are exercisable anytime
between March 1, 2004, and March 1, 2008, and entitle the holders, for a period
of 10 days following any new issuances of equity securities or securities
convertible or exercisable into equity securities in other than a public
offering, to preserve their approximate 16.3% ownership as of February 2003 by
purchasing such new securities issued on the same terms as issued to others. The
preferred stock has a liquidation preference equal to the sales price for the
shares, which was $2.50 per share.
In connection with the issuance of the 2003 Series Convertible
Preferred Stock, the Company allocated approximately $2.3 million of the
proceeds to the warrants, and the remaining amount of the proceeds to a
beneficial conversion feature. As the conversion of the preferred shares and the
issuance of the warrants are contingent upon the registration of the underlying
shares, these shares will be included in the calculation of earnings per share
upon the conversion of the preferred stock to common stock.
The net proceeds from these offerings were used to reduce the note
payable to Rolls-Royce Power Ventures Limited, or RRPV, to reduce the obligation
to the Polish Oil and Gas Company, or POGC, and will be used to fund ongoing
geological and geophysical costs in Poland and support ongoing prospect
marketing and general and administrative costs.
8
Note 3: Financing with Rolls-Royce Power Ventures
In early 2003, the Company reached an agreement with RRPV to amend its
9.5% Convertible Secured Note in the amount of $5,000,000. Following its private
placement of convertible preferred stock described in Note 2, the Company paid
$2,250,000 to RRPV, $1,675,000 of which was applied to the outstanding principal
balance, $475,000 of which was applied to accrued interest, and the remaining
$100,000 was a loan extension payment that is being amortized over the remaining
term of the loan. In return, RRPV extended the maturity date of the note from
March 9, 2003, to December 31, 2003. The Company also agreed to pay 40% of the
gross proceeds of any subsequent equity or debt offering concluded prior to the
amended maturity date to RRPV, and agreed to assign its rights to payments under
the CalEnergy Gas (Holdings), Ltd. agreement to RRPV, except for those amounts
related to drilling the two wells. All such payments will be used to offset the
remaining principal and interest. In exchange for these payments, RRPV agreed to
release its lien on interests earned by CalEnergy Gas under its agreement with
the Company.
The loan amendment contained other terms and conditions, including an
increase in the interest rate on the note from 9.5% to 12% per annum effective
March 9, 2003. The time period during which RRPV can convert the principal
amount of the note into shares of common stock was extended to December 31,
2003, with the conversion price reduced from $5.00 per share to $3.42 per share,
the market price of the Company's stock when RRPV agreed to extend the payment
date. In accordance with APB 14 "Accounting for Convertible Debt and Debt Issued
with Stock Purchase Warrants," no charge to income will be recorded as a result
of the reduction in conversion price as the new conversion price does not result
in any intrinsic value.
In September 2003, the Company deposited the remaining principal
amount, $3,325,000 into an escrow account in favor of RRPV, using proceeds from
the private placements described in Note 2. RRPV is entitled to receive the
funds at the maturity date if it has not exercised its right to convert the
principal amount into shares of common stock. This amount is shown as restricted
cash in the consolidated balance sheets at September 30, 2003. In connection
with this event, the interest rate on the loan was reduced from 12% to 9% per
annum.
Note 4: Net Income (Loss) Per Share
Basic earnings per share is computed by dividing net income (loss) by
the weighted average number of common shares outstanding. Diluted earnings per
share is computed by dividing net income (loss) by the sum of the weighted
average number of common shares and the effect of dilutive unexercised stock
options and warrants and convertible debt and preferred stock. Options to
purchase 4,421,017 and 5,618,967 shares of common stock at prices ranging from
$1.50 to $10.25 per share, with a weighted average price of $4.68 and $4.88 per
share, were outstanding at September 30, 2003 and 2002, respectively. In
addition, the preferred stock (see Note 2) is convertible into 2,250,000 shares
of common stock upon registration, at which time an additional 2,250,000
warrants to purchase common stock at $3.60 per share will be issued. No
preferred stock, convertible debt, options or warrants were included in the
computation of diluted net loss per share for the periods ended September 30,
2003 and 2002, because the effect would have been antidilutive.
9
Note 5: Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board, or FASB,
issued Statement No. 143 (SFAS 143), "Accounting for Asset Retirement
Obligations." The Company adopted SFAS 143 beginning January 1, 2003. The most
significant impact of this standard on the Company was a change in the method of
accruing for site restoration costs. Under SFAS 143, the fair value of asset
retirement obligations is recorded as a liability when incurred, which is
typically at the time the assets are placed in service. Amounts recorded for the
related assets are increased by the amount of these obligations. Over time, the
liabilities are accreted for the change in their present value and the initial
capitalized costs are depreciated over the useful lives of the related assets.
The Company used an expected cash flow approach to estimate its asset
retirement obligations under SFAS 143. Upon adoption, the Company recorded a
retirement obligation of $345,000, an increase in property and equipment cost of
$1,535,000, a decrease in accumulated depreciation, depletion and amortization
of $609,000, and a cumulative effect of change in accounting principle, net of
$0 tax, of $1,799,000. As a result of adoption of SFAS 143, the Company
estimates that accretion expense will be approximately $37,000 in 2003. For the
three- and nine-month periods ended September 30, 2003, the effect of adopting
SFAS 143 increased expenses $9,287 and $27,859, or $0.00 and $0.00 per basic
share, respectively.
At January 1 and September 30, 2003, there are no assets legally
restricted for purposes of settling asset retirement obligations. There was no
impact on the Company's cash flows as a result of adopting SFAS 143 because the
cumulative effect of change in accounting principle is a noncash transaction.
The Company's estimated asset retirement obligation liability at
January 1, 2003, was approximately $322,000.
Following is a reconciliation of the asset retirement obligation from
December 31, 2002, to September 30, 2003:
Asset retirement obligation as of December 31, 2002..... $ --
Obligation arising from adoption of SFAS 143............ 345,551
Liabilities settled..................................... --
Accretion expense....................................... 27,859
----------
Asset retirement obligation as of September 30, 2003.... $ 373,410
==========
Note 6: Income Taxes
FX Energy recognized no income tax benefit from the net loss generated
in the first nine months of 2003 and 2002.
10
Note 7: Business Segments
FX Energy operates within two segments of the oil and gas industry: the
exploration and production segment ("E&P") and the oilfield services segment.
Identifiable net property and equipment are reported by business segment for
management reporting and reportable business segment disclosure purposes.
Current assets, other assets, current liabilities, and long-term debt are not
allocated to business segments for management reporting or business segment
disclosure purposes. Reportable business segment information for the three
months ended September 30, 2003, the nine months ended September 30, 2003, and
as of September 30, 2003, excluding the cumulative effect of change in
accounting principle, follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended September 30, 2003:
Revenues(1)...................................... $ 557,637 $ 43,874 $ -- $ 601,511
Net loss(2)...................................... (8,363) (127,641) (730,224) (866,228)
Nine months ended September 30, 2003:
Revenues(3)...................................... 1,676,155 76,402 -- 1,752,557
Net loss(4)...................................... (58,440) (371,565) (2,250,036) (2,680,041)
As of September 30, 2003:
Identifiable net property and equipment(5)....... 5,161,730 581,531 89,382 5,832,643
- ----------------------
(1) All E&P revenues were generated in the United States.
(2) Nonsegmented items include $515,537 of general and administrative costs,
$212,000 of other income and expense, and $2,687 of corporate depreciation,
depletion and amortization.
(3) All E&P revenues were generated in the United States.
(4) Nonsegmented items include $1,569,425 of general and administrative costs,
$672,542 of other income and expense, and $8,069 of corporate depreciation,
depletion and amortization.
(5) Nonsegmented items include $89,382 of corporate office equipment, hardware
and software.
Reportable business segment information for the three months ended
September 30, 2002, the nine months ended September 30, 2002, and as of
September 30, 2002, follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended September 30, 2002:
Revenues (1)..................................... $ 618,069 $ 358,520 $ -- $ 976,589
Net profit or (loss) (2)......................... 164,883 18,588 (556,057) (372,586)
Nine months ended September 30, 2002:
Revenues (3)..................................... 1,632,607 401,385 -- 2,033,992
Net profit or (loss) (4)......................... 34,305 (295,206) (1,999,771) (2,260,672)
As of September 30, 2002:
Identifiable net property and equipment (5)...... 3,728,178 844,313 71,794 4,644,285
- ----------------------
(1) E&P revenues include $562,504 generated in the United States and $55,565
generated in Poland.
(2) Nonsegmented items include $416,503 of general and administrative costs and
$101,558 of other expense.
(3) E&P revenues include $1,414,478 generated in the United States and $218,129
generated in Poland.
(4) Nonsegmented items include $1,675,225 of general and administrative costs
and $239,143 of other expense.
(5) Nonsegmented items include $71,794 of corporate office equipment, hardware
and software.
11
Note 8: Stock-Based Compensation
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board ("APB") Opinion
No. 25 and related interpretations. Nonemployee stock-based compensation is
accounted for using the fair value method in accordance with SFAS No. 123,
"Accounting for Stock-based Compensation" ("SFAS 123").
On December 31, 2002, the FASB issued Statement No. 148, "Accounting
for Stock Based Compensation Transition and Disclosure" ("SFAS 148"), which
amends SFAS No. 123. SFAS 148 requires more prominent and frequent disclosures
about the effects of stock-based compensation. The Company adopted SFAS 148 for
the year ended December 31, 2002. The Company will continue to account for its
stock-based compensation according to the provisions of APB Opinion No. 25.
Had compensation cost for the Company's stock options been recognized
based on the estimated fair value on the grant date under the fair value
methodology prescribed by SFAS 123, the Company's net earnings and earnings per
share for the periods ended September 30, 2003 and 2002, would have been as
follows:
(in thousands, except for per share data) For the three months For the nine months
ended September 30, ended September 30,
------------------------- -------------------------
2003 2002 2003 2002
----------- --------- ----------- ---------
Net loss:
Net loss, as reported................................... $ (866) $ (373) $ (881) $ (2,261)
Less: Total stock-based employee compensation
expense determined under the fair value based method
for all awards........................................ (207) (283) (620) (849)
----------- --------- ----------- ---------
Pro forma net loss................................. $ (1,073) $ (656) $ (1,501) $ (3,110)
=========== ========= =========== =========
Basic and diluted net loss per share:
As reported........................................ $ (0.04) $ (0.02) $ (0.05) $ (0.13)
Pro forma.......................................... $ (0.05) $ (0.04) $ (0.08) $ (0.18)
Note 9: Intangible Leaseholds Costs
Statement of Financial Accounting Standards No. 141, Business
Combinations ("SFAS 141"), and Statement of Financial Accounting Standards No.
142, Goodwill and Intangible Assets ("SFAS 142"), were issued by the FASB in
June 2001 and became effective for the Company on July 1, 2001, and January 1,
2002, respectively. SFAS 141 requires all business combinations initiated after
June 30, 2001, to be accounted for using the purchase method. Additionally, SFAS
141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS 142 establishes new guidelines for accounting
for goodwill and other intangible assets. Under SFAS 142, goodwill and certain
other intangible assets are not amortized, but rather are reviewed annually for
impairment.
One interpretation being considered relative to these standards is that
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds should be classified separately from oil and gas
properties, as intangible assets on the Company's balance sheets. In addition,
the disclosures required by SFAS 141 and 142 relative to intangibles would be
included in the notes to financial statements. Historically, FX Energy, like
many other oil and gas companies, has included these oil and gas mineral rights
held under lease and other contractual arrangements representing the right to
extract such reserves as part of the oil and gas properties, even after SFAS 141
and 142 became effective.
12
This interpretation of SFAS 141 and 142 described above would only
affect the Company's balance sheet classification of oil and gas leaseholds. The
Company's results of operations and cash flows would not be affected, since
these oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves would continue to
be amortized in accordance with accounting rules for oil and gas companies
provided in Statement of Financial Accounting Standards No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies.
At December 31, 2002, and September 30, 2003, the Company had
undeveloped leaseholds of approximately $147,000 that would be classified under
that interpretation on its consolidated balance sheets as "intangible
undeveloped leaseholds" and developed leaseholds of approximately $7,000 that
would be classified under that interpretation as "intangible developed
leaseholds" if the Company applied the interpretation currently being
considered.
The Company will continue to classify its oil and gas mineral rights
held under lease and other contractual rights representing the right to extract
such reserves as tangible oil and gas properties until further interpretative
guidance is provided.
Note 10: Subsequent Event
Subsequent to September 30, 2003, the Company received net proceeds of
approximately $1.9 million from the sale of 726,173 Units, consisting of one
share of common stock and a five-year warrant to purchase one share of common
stock at $3.75 per share, an aggregate of 1,452,346 additional shares. These
shares were sold pursuant to antidilution provisions of the Company's private
placement of 2003 Series Convertible Preferred Stock as described in Note 2. Net
proceeds from this placement will be used to pay obligations due POGC,
geological and geophysical costs, general and administrative and project
marketing costs, and the Company's share of further exploration and possible
production facilities.
The Company's 2,250,000 shares of 2003 Series Convertible Preferred
Stock described in Note 2 were converted to common stock on a one-for-one basis
on October 27, 2003, pursuant to a registration statement that became effective
on that date.
Note 11: Restatement
In October 2003, the Company determined that it needed to correct the
accounting treatment for certain loans made to officers in 1998. These loans
were made to facilitate the exercise of stock options by these officers and were
collateralized by 233,340 shares of Company stock owned by the officers. The
Company previously accounted for these loans in accordance with SFAS No. 114,
"Accounting by Creditors for Impairment of a Loan" and recognized impairment
charges in 1999 and 2000 based on the market value of the collateral shares. The
Company also recognized interest income on the loans. In December 2000, the
officers transferred the collateral shares to the Company and the adjusted loan
balance was recorded as treasury stock. The Company has determined that the
officer loans should have been accounted for as a deemed purchase of treasury
stock and the granting of a variable stock option in accordance with EITF 95-16,
"Accounting for Stock Compensation Arrangements with Employer Loan Features
under APB Opinion No. 25." Under variable stock option accounting, the Company
would have recognized increases or decreases in compensation expense based on
the market value of the Company's stock. In addition, the Company would not have
recorded interest income on the loans or the impairment charges related to the
loans. Because a portion of the shares deemed to have been purchased were
acquired through the exercise of stock options and had not been owned for at
least six months, the Company also would have recorded a compensation charge of
$90,000 related to those shares, reflecting the difference between the purchase
price and the original option exercise price for those shares.
13
The following sets forth the effects of the restatement to the
Company's consolidated balance sheet at December 31, 2002. No income statement
amounts subsequent to December 31, 2000, were affected by the restatement:
December 31, 2002
Stockholders' deficit
As Reported As Restated
----------- -----------
Common stock $ 17,652 $ 17,652
Additional paid in capital 49,049,025 48,075,035
Accumulated deficit (53,935,256) (52,961,266)
------------ ------------
Total stockholders' deficit $ (4,868,579) $ (4,868,579)
============ ============
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, general and administrative costs, or G&A, associated with their
respective segments are detailed within the following discussion. DD&A, G&A,
amortization of deferred compensation (G&A), interest income, other income,
interest expense, and other costs, which are not allocated to individual
operating segments for management or segment reporting purposes, are discussed
in their entirety following the segment discussion. A comparison of the results
of operations by business segment and the information regarding nonsegmented
items follows:
Comparison of the Third Quarter of 2003 to the Third Quarter of 2002
Exploration and Production
Our oil and gas revenues are comprised of oil production in the United
States and gas production in Poland. A summary of the percentage change in oil
and gas revenues, average price, and production volumes for the third quarter of
2003 and 2002 is set forth in the following table:
Quarter Ended September 30,
--------------------------------------------------------------
Oil Gas
------------------------------ -------------------------------
2003 2002 2003 2002
-------------- -------------- --------------- ---------------
Revenues............................................. $ 558,000 $ 562,000 $ -- $ 56,000
Percent change versus prior year's quarter......... -1% -100%
Average price per barrel of oil or $ 25.58 $ 24.28 -- $ 1.58(1)
thousand cubic feet of natural gas...............
Percent change versus prior year's quarter......... +5% --%
Production volumes (barrels of oil
or thousand cubic feet of natural gas)........... 21,800 23,170 -- 36,328
Percent change versus prior year's quarter......... -6% -100%
- -------------------
(1) The contract price prior to adjusting for British thermal unit content was
$2.02 per thousand cubic feet of natural gas.
14
Oil Revenues. Oil revenues were $558,000 during the third quarter of
2003, a 1% decrease compared to the same period of 2002. During the third
quarter of 2003, our average oil prices rose 5%, from $24.28 per barrel in 2002
to $25.58 per barrel in 2003, while oil production quantities declined by 6%.
Oil revenues in 2003 increased from 2002 levels by approximately $29,000 due to
higher oil prices, offset by approximately $33,000 related to normal production
declines.
Gas Revenues. Gas revenues were $0 during the third quarter of 2003,
compared to $56,000 in gas revenues during the same period of 2002. As part of
our Fences I settlement with the Polish Oil and Gas Company, or POGC, in early
2003, we agreed to assign our interest in the Kleka 11 well, along with the
related accounts receivable, to POGC as soon as possible in order to conserve
cash while reducing the balance of our liability due to POGC. Accordingly, we
stopped recording gas sales in 2003. Gas volumes in the third quarter of 2002
reflected a full quarter of production from the Kleka 11, our first producing
well in Poland, which began producing in late February 2001.
Lease Operating Costs. Lease operating costs were $361,000 during the
third quarter of 2003, an increase of $20,000, or 6%, compared to the same
period of 2002. The increase was due primarily to workover expenses and higher
third-party maintenance activities incurred during the third quarter of 2003.
Lease operating costs incurred during the third quarter of 2003 include no costs
associated with the Kleka 11 well, while lease operating costs at the Kleka 11
well averaged approximately $0.16 per thousand cubic feet of gas in the prior
year. Our third quarter 2003 operating costs increased approximately $50,000 due
to higher lifting costs, offset by approximately $30,000 related to lower oil
and gas production.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$116,000 during the third quarter of 2003, compared to $87,000 during the same
period of 2002, an increase of 33%.
DD&A Expense - E&P. DD&A expense for producing properties was $80,000
during the third quarter of 2003, an increase of $55,000 compared to $25,000
during the same period of 2002. Because of our agreement to convey to POGC our
interest in the Kleka 11 well, we incurred no DD&A expense associated with the
Kleka 11 well during the third quarter of 2003, while we incurred $50,000 in
Kleka 11 well-related DD&A expense during the same quarter of 2002. The increase
from year to year, however, is due primarily to the net book value of domestic
assets being increased as a result of the adoption of SFAS 143 effective January
1, 2003.
Accretion Expense. Accretion expense reflects the third quarter
increase in our asset retirement obligation under SFAS 143.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $44,000
during the third quarter of 2003, a decrease of 88% from $359,000 recorded
during the same period of 2002. During the third quarter of this year, the
contract drilling industry was at a virtual standstill in the area where we
operate. Oilfield services revenues will continue to fluctuate from period to
period based on market demand, weather, the number of wells drilled, downtime
for equipment repairs, the degree of emphasis on utilizing our oilfield
servicing equipment on our Company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $97,000 during
the third quarter of 2003, down from the $258,000 incurred in the same period of
2002. The bulk of the costs in both periods related to downtime maintenance
costs associated primarily with our drilling rig. Oilfield services costs will
also continue to fluctuate year to year based on revenues generated, market
demand, weather, the number of wells drilled, downtime for equipment repairs,
the degree of emphasis on utilizing our oilfield servicing equipment on our
Company-owned properties, and other factors.
15
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $74,000 during the third quarter of 2003, a decrease of $8,000 compared to
$82,000 during the same period of 2002, primarily due to some older assets
becoming fully depreciated before the end of the third quarter of 2003.
Nonsegmented Information
G&A Costs. G&A costs were $516,000 during the third quarter of 2003, a
24% increase from the $417,000 recorded for the same period of 2002. This
increase was due partially to higher consulting and legal fees associated with
the Company's ongoing efforts to obtain industry participants in its Fences
projects.
Interest and Other Income. Interest and other income was negligible
during both the third quarter of 2003 and 2002.
Interest Expense. Interest expense was $221,000 during the third
quarter of 2003, compared to $119,000 during the same period of 2002. We began
accruing interest on our POGC obligation in the fourth quarter of 2002. In
addition, the interest rate on our RRPV obligation was increased from 9.5% to
12% as of March 9, 2003. The rate was subsequently reduced to 9% as of September
3, 2003.
Comparison of the First Nine Months of 2003 to the First Nine Months
of 2002
Exploration and Production
Our oil and gas revenues are comprised of oil production in the United
States and gas production in Poland. A summary of the percentage change in oil
and gas revenues, average price, and production volumes for the first nine
months of 2003 and 2002 is set forth in the following table:
Nine Months Ended September 30,
-----------------------------------------------------------------
Oil Gas
------------------------------- --------------------------------
2003 2002 2003 2002
----------------- ------------- --------------- ---------------
Revenues........................................... $ 1,676,000 $1,414,000 $ -- $ 218,000
Percent change versus prior year's quarter....... +19% -100%
Average price per barrel of oil or
thousand cubic feet of natural gas............. $ 26.20 $ 20.52 -- $ 1.58(1)
Percent change versus prior year's quarter....... +28% --%
Production volumes (barrels of oil or
thousand cubic feet of natural gas)............ 63,986 68,942 -- 138,342
Percent change versus prior year's quarter....... -7% -100%
- -----------------
(1) The contract price prior to adjusting for British thermal unit content was
$2.02 per thousand cubic feet of natural gas.
Oil Revenues. Oil revenues were $1,676,000 during the first nine months
of 2003, a 19% increase compared to the same period of 2002. During the first
nine months of 2003, our average oil prices were 28% higher than in the same
period of the prior year, while oil production quantities declined by 7%. Oil
revenues in 2003 increased from 2002 levels by approximately $392,000 due to
higher oil prices, offset by approximately $130,000 related to normal production
declines.
Gas Revenues. Gas revenues were $0 during the first nine months of
2003, down 100% from the same period of 2002. As part of our Fences I settlement
with POGC, in early 2003, we agreed to assign our interest in the Kleka 11 well,
along with the related accounts receivable, to POGC as soon as possible in order
to conserve cash while reducing the balance of our liability to POGC.
Accordingly, we stopped recording gas sales in 2003.
16
Lease Operating Costs. Lease operating costs were $1,118,000 during the
first nine months of 2003, an increase of 8% compared to $1,031,000 during the
same period of 2002. The increase was due primarily to workover expenses and
higher third-party maintenance activities incurred during the first nine months
of this year. Lease operating costs incurred during the first nine months of
2002 include approximately $24,000, or an estimated $0.16 per thousand cubic
feet of natural gas produced, associated solely with the Kleka 11 well, while
Kleka operating costs during the same period of 2003 were $0. Operating costs
for the first nine months of 2003 increased approximately $194,000 due to higher
lifting costs, offset by approximately $107,000 related to lower oil production
and gas production.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$406,000 during the first nine months of 2003, an increase of 4% compared to
$389,000 during the same period of 2002.
DD&A Expense - E&P. DD&A expense for producing properties was $182,000
during the first nine months of 2003, an increase of $4,000 compared to $178,000
during the same period of 2002. DD&A expense incurred during the first nine
months of 2002 includes approximately $157,000 associated with the Kleka 11
well, while Kleka-related DD&A expense during the same period of 2003 was $0.
The Kleka decrease was partially offset by higher DD&A charges at our domestic
properties, due to the net book value of those assets being increased as a
result of the adoption of SFAS 143.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $76,000
during the first nine months of 2003, a decrease of 81% from $401,000 recorded
during the same period of 2002. During the first nine months of this year, the
contract drilling industry was at a virtual standstill in the area where we
operate. Oilfield services revenues will continue to fluctuate from period to
period based on market demand, weather, the number of wells drilled, downtime
for equipment repairs, the degree of emphasis on utilizing our oilfield
servicing equipment on our Company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $226,000 during
the first nine months of 2003, down from the $443,000 incurred in the same
period of 2002. In general, oilfield services costs are directly associated with
oilfield services revenues. The bulk of the costs in 2003 relates to downtime
maintenance costs associated primarily with our drilling rig. Oilfield services
costs will also continue to fluctuate year to year based on revenues generated,
market demand, weather, the number of wells drilled, downtime for equipment
repairs, the degree of emphasis on utilizing our oilfield servicing equipment on
our Company-owned properties, and other factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $222,000 during the first nine months of 2003, a decrease of $31,000
compared to $253,000 during the same period of 2002.
17
Nonsegmented Information
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $54,688 during the first nine months of 2002, compared to $0
during the same period of 2003. On April 5, 2001, we extended the term of
options to purchase 125,000 shares of the Company's common stock that were to
expire during 2001 for a period of two years, with a one-year vesting period. On
August 4, 2000, we extended the term of options and warrants to purchase 678,000
shares of our common stock that were to expire during 2000 for a period of two
years, with a one-year vesting period. In accordance with FIN 44 "Accounting for
Certain Transactions Involving Stock Compensation," we incurred total noncash
deferred compensation costs of $1.8 million associated with the option
extensions, to be amortized over their respective one-year vesting periods from
the date of extension. The deferred compensation associated with these
transactions was fully amortized as of September 30, 2002.
G&A Costs. G&A costs were $1,569,000 during the first nine months of
2003, a 6% decrease from the $1,675,000 recorded for the same period of 2002.
Interest and Other Income. We recorded $19,000 in interest and other
income during the first nine months of 2003, compared to $122,000 during the
first nine months of 2002. The bulk of other income in 2002 was related to the
amortization of an option premium that resulted from granting RRPV an option to
purchase gas from our properties in Poland.
Interest Expense. Interest expense was $691,000 during the first nine
months of 2003, compared to $361,000 during the same period of 2002. We began
accruing interest on our POGC obligation in the fourth quarter of 2002. In
addition, the interest rate on our RRPV obligation was increased from 9.5% to
12% as of March 9, 2003. The rate was subsequently reduced to 9% as of September
3, 2003.
Liquidity and Capital Resources
With insufficient revenues to cover our operating expenses and to fund
further exploration, our greatest uncertainty is our shortage of capital and our
dependence on obtaining substantial amounts of external funding through the sale
of securities or an interest in our exploration projects in Poland. Our ability
to obtain such required funding is, to a substantial extent, dependent on the
interest of the securities markets and oil and gas industry generally in
international oil and gas exploration. Although we believe that there appears to
be growing securities markets and industry interest in financing international
oil and gas exploration, there is no assurance that this will enable us to
obtain the financing we require on acceptable terms or that such perceived
trend, if we accurately perceive it, may not become less favorable.
General. As of September 30, 2003, we had approximately $4.9 million of
cash and cash equivalents and working capital of approximately $2.6 million In
addition to our stated liabilities at September 30, 2003, we have a remaining
work commitment of $5.4 million that must be satisfied in order to earn a 49.0%
interest in our Fences I project area.
Subsequent to September 30, 2003, we received proceeds of approximately
$1.9 million, net of placement costs, from the sale of 726,173 shares of common
stock and five-year warrants to purchase at $3.75 per share an aggregate of
726,173 additional shares (see Note 10 of the Notes to the Consolidated
Financial Statements). If, as we anticipate, CalEnergy Gas earns a 24.5%
interest in the Fences I project area, thereby reducing our retained interest to
24.5%, CalEnergy Gas's $10.4 million earn-in will satisfy the balance of our
$5.4 million work commitment to POGC in the Fences I project area and provide
cash for our other commitments, which will further improve our financial
outlook.
18
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities, and agreements with industry
participants that funded our share of costs in certain exploratory activities in
order to earn an interest in our properties. We recently received approximately
$1.9 million in net proceeds from the sale of securities (see Note 10 of the
Notes to the Consolidated Financial Statements). However, the continuation of
our exploratory efforts in Poland is dependent on raising additional capital or
on arranging industry funding for such exploration, and our efforts have and
continue to be concentrated on both of these objectives. The availability of
such capital will affect the timing, pace, scope and amount of our future
capital expenditures. We cannot assure that we will be able to obtain additional
financing, reduce expenses, or successfully complete other steps to continue as
a going concern. If we are unable to obtain sufficient funds to satisfy our
future cash requirements, we may be forced to curtail operations, dispose of
assets, or seek extended payment terms from our vendors. Such events would
materially and adversely affect our financial position and results of
operations.
Working Capital (current assets less current liabilities). Our working
capital was $2,644,000 as of September 30, 2003, an improvement of $11,794,000
from our working capital deficit at December 31, 2002, of $9,150,000. This
improvement is principally a result of the private placements of common and
preferred stock discussed earlier, but does not give effect to the receipt of
net proceeds from the sale of securities subsequent to September 30, 2003. Our
current liabilities include $2.2 million of costs related to our Fences I
project in Poland and a $3.3 million note payable to RRPV, which have current
maturity dates of December 31, 2003.
Operating Activities. Net cash used in operating activities was
$2,354,000 during the first nine months of 2003, an increase of $489,000
compared to $1,865,000 in net cash used during the same period of 2002. This
increase in cash used is a direct reflection of the reduction of our outstanding
accounts payable and accrued liabilities.
Investing Activities. We spent $6,014,000 in investing activities
during the first nine months of 2003. During this period, we deposited the
remaining principal balance of our note to RRPV into an escrow account in its
favor. In addition, we used $2.1 million to pay liabilities associated with oil
and gas property additions from prior years. Also included in this amount is a
deposit with CalEnergy in the amount of $366,000 to cover drilling expenses for
the Zaniemysl well, in the event costs exceed an agreed upon target amount. We
also spent $194,000 related to our proved properties and oilfield equipment in
the United States. In the first nine months of 2002, we spent $164,000 in
investing activities , also related to our proved properties and oilfield
equipment in the United States.
Financing Activities. During the first nine months of 2003, we
completed private placements of common and convertible preferred stock resulting
in proceeds after offering costs of approximately $14,638,000. We used
$1,675,000 of the proceeds to pay down our RRPV note and incurred loan fees
relating to our new agreement with RRPV of $100,000. We received no cash from
financing activities during the first half of 2002.
Other Items
The Company has reviewed all other recently issued, but not yet
adopted, accounting standards in order to determine their effects, if any, on
the results of operations or financial position of the Company. Based on that
review, the Company believes that none of these pronouncements will have a
significant effect on current or future financial position or results of
operations.
Critical Accounting Policies
A summary of our significant accounting policies is included in Note 1
of our Consolidated Financial Statements contained in the amended annual report
on Form 10-K/A for the year ended December 31, 2002. We believe the application
of these accounting policies on a consistent basis enables us to provide
financial statement users with useful, reliable and timely information about our
earnings results, financial condition and cash flows.
19
The preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America requires our
management to make judgments, estimates and assumptions regarding uncertainties
that affect the reported amounts presented and disclosed in the financial
statements. Our management reviews these estimates and assumptions based on
historical experience, changes in business conditions, and other relevant
factors that it believes to be reasonable under the circumstances. In any given
reporting period, actual results could differ from the estimates and assumptions
used in preparing our financial statements.
Critical accounting policies are those that may have a material impact
on our financial statements and also require management to exercise significant
judgment due to a high degree of uncertainty at the time the estimate is made.
Our senior management has discussed the development and selection of our
accounting policies, related accounting estimates, and the disclosures set forth
below with the Audit Committee of our Board of Directors. We believe our
critical accounting policies include those addressing the recoverability and
useful lives of assets, the retirement obligations associated with those assets,
and the estimates of oil and gas reserves.
Forward Looking Statements
This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "could," "should,"
"expect," "anticipate," "estimate," "project," "propose," "plan," "intend" and
similar words and expressions. We intend that the forward-looking statements
will be covered by the safe harbor provisions for forward-looking statements
contained in Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Statements that describe our future strategic
plans, goals or objectives are also forward-looking statements.
Readers of this report are cautioned that any forward-looking
statements, including those regarding us or our management's current beliefs,
expectations, anticipations, estimations, projections, proposals, plans or
intentions, are not guarantees of future performance or results of events and
involve risks and uncertainties, such as the future results of drilling
individual wells and other exploration and development activities; future
variations in well performance as compared to initial test data; future events
that may result in the need for additional capital; the prices at which we may
be able to sell oil or gas; fluctuations in prevailing prices for oil and gas;
uncertainties of certain terms to be determined in the future relating to our
oil and gas interests, including exploitation fees, royalty rates and other
matters; future drilling and other exploration schedules and sequences for
various wells and other activities; uncertainties regarding future political,
economic, regulatory, fiscal, taxation and other policies in Poland; the cost of
additional capital that we may require and possible related restrictions on our
future operating or financing flexibility; our future ability to attract
strategic participants to share the costs of exploration, exploitation,
development and acquisition activities; and future plans and the financial and
technical resources of strategic participants.
The forward-looking information is based on present circumstances and
on our predictions respecting events that have not occurred, that may not occur,
or that may occur with different consequences from those now assumed or
anticipated. Actual events or results may differ materially from those discussed
in the forward-looking statements as a result of various factors. The
forward-looking statements included in this report are made only as of the date
of this report. We disclaim any obligation to update any forward-looking
statements whether as a result of new information, future events or otherwise.
20
ITEM 3. QUANITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk
Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.
There is currently no competitive market for the sale of gas in Poland.
Accordingly, we expect that the prices we receive for the gas we discover and
produce will be lower than would be the case in a competitive setting and may be
lower than prevailing western European prices, at least until a fully
competitive market develops in Poland.
We currently do not engage in any hedging activities or have any
derivative financial instruments to protect ourselves against market risks
associated with oil and gas price fluctuations, although we may elect to do so
if we achieve a significant amount of production in Poland.
Foreign Currency Risk
We have entered into various agreements in Poland, primarily in U.S.
dollars or the U.S. dollar equivalent of the Polish zloty. We conduct our
day-to-day business on this basis as well. Our cash payment, with a balance due
of approximately $2.1 million as of September 30, 2003, to POGC on or before
December 31, 2003, is expressed in Polish zlotys. The Polish zloty is subject to
exchange rate fluctuations that are beyond our control. We do not currently
engage in hedging transactions to protect ourselves against foreign currency
risks, nor do we intend to do so in the foreseeable future.
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed by us in the reports that we
file or submit to the Securities and Exchange Commission under the Securities
Exchange Act of 1934, as amended, is recorded, processed, summarized and
reported within the time periods specified by the Securities and Exchange
Commission's rules and forms, and that information is accumulated and
communicated to our management, including our principal executive and principal
financial officers (whom we refer to in this periodic report as our Certifying
Officers), as appropriate to allow timely decisions regarding required
disclosure. Our management evaluated, with the participation of our Certifying
Officers, the effectiveness of our disclosure controls and procedures as of
September 30, 2003, pursuant to Rule 13a-15(b) under the Securities Exchange
Act. Based upon that evaluation, our Certifying Officers concluded that, as of
September 30, 2003, our disclosure controls and procedures were effective.
There were no changes in our internal control over financial reporting
that occurred during our most recently completed fiscal quarter that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
21
PART II--OTHER INFORMATION
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
On July 22, 2003, and August 11, 2003, we sold 2,476,637 and 788,500
Units, respectively, with each Unit consisting of one share of common stock and
a warrant to purchase one share of common stock at $3.75 per share, in a private
placement of securities to nine purchasers, raising a total of $8.8 million
after offering costs. Each of the purchasers was an accredited investor who was
provided with a private placement memorandum detailing our business and
financial information, including copies of our periodic reports as filed with
the Securities and Exchange Commission, and who was provided with the
opportunity to ask questions directly of our executive officers. The warrants
are exercisable anytime between July 22, 2004, and July 22, 2008.
The net proceeds from the offering, plus our available cash, were used
to reduce our obligation to RRPV by approximately $3.3 million, our obligation
to POGC by approximately $2.5 million, and have been allocated to fund ongoing
geological and geophysical costs in Poland, and support ongoing prospect
marketing and general and administrative costs.
On September 12, 2003, we issued 4,930 shares of common stock to a
consultant that provided financial consulting and advisory services to us. That
consultant completed its own evaluation of us and was provided with our business
and financial information, including copies of our periodic reports as filed
with the Securities and Exchange Commission, and was provided with the
opportunity to ask questions directly of our executive officers.
No underwriter participated in any of the foregoing sales and
offerings.
In each of the above transactions, the securities purchased were
restricted securities taken for investment. Certificates for all shares issued
in such transactions bore a restrictive legend conspicuously on their face and
stop-transfer instructions were noted respecting such certificates on our stock
transfer records. Each of the foregoing transactions was effected in reliance on
the exemption from registration provided in Section 4(2) of the Securities Act
of 1933 as transactions not involving any public offering.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
The following exhibits are filed as a part of this report:
SEC
Exhibit Reference
Number Number Title of Document Location
- -------------- ------------ ------------------------------------------------------------------- -------------------
Item 31 Rule 13a-14(a)/15d-14(a) Certifications
- -----------------------------------------------------------------------------------------------
31.01 31 Certification of Chief Executive Officer Pursuant to Rule 13a-14 Attached
31.02 31 Certification of Chief Financial Officer Pursuant to Rule 13a-14 Attached
22
SEC
Exhibit Reference
Number Number Title of Document Location
- -------------- ------------ ------------------------------------------------------------------- -------------------
Item 32 Section 1350 Certifications
- -----------------------------------------------------------------------------------------------
32.01 32 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Attached
Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
32.02 32 Certification of Chief Financial Officer Pursuant to 18 U.S.C. Attached
Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(b) Reports on Form 8-K
During the quarter ended September 30, 2003, FX Energy filed the
following reports on Form 8-K:
Date of Event Reported Item(s) Reported
--------------------------- -------------------------------
September 5, 2003 Item 5. Other Events
September 24, 2003 Item 5. Other Events
23
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this amended report to be signed on its behalf by the
undersigned, thereunto duly authorized.
FX ENERGY, INC.
(Registrant)
Date: November 12, 2003 By /s/ David N. Pierce
-----------------------------
David N. Pierce, President,
Chief Executive Officer
Date: November 12, 2003 By /s/ Thomas B. Lovejoy
-----------------------------
Thomas B. Lovejoy,
Chief Financial Officer
24