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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, 2002
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)
(801) 486-5555
------------------------------
(Registrant's telephone number)
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 [ ]
The number of shares of $0.001 par value common stock outstanding as of
November 13, 2002, was 17,651,917.
FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Nine Months Ended and as of September 30, 2002
TABLE OF CONTENTS
Item Page
- --------- ------
Part I. Financial Information
1. Consolidated Balance Sheets...................................... 3
1. Consolidated Statements of Operations............................ 5
1. Consolidated Statements of Cash Flows............................ 6
1. Notes to the Consolidated Financial Statements................... 7
2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................ 10
3. Quantitative and Qualitative Disclosures about Market Risk....... 18
4. Controls and Procedures.......................................... 19
Part II. Other Information
4. Submission of Matters to a Vote of Security Holders.............. 20
6. Exhibits and Reports on Form 8-K................................. 21
-- Signatures....................................................... 21
2
PART I.
ITEM 1. FINANCIAL STATEMENTS
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
September 30, December 31,
2002 2001
------------------ -----------------
ASSETS
Current assets:
Cash and cash equivalents.............................................. $ 1,132,484 $ 3,157,427
Accounts receivable:
Accrued oil and gas sales............................................ 780,761 478,857
Joint interest owners and others..................................... 130,303 49,075
Inventory.............................................................. 82,913 87,260
Other current assets................................................... 138,829 95,004
------------- -------------
Total current assets................................................. 2,265,290 3,867,623
------------- -------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved............................................................... 4,838,631 4,789,252
Unproved............................................................. 655,523 655,523
Other property and equipment......................................... 3,679,532 3,587,433
------------- -------------
Gross property and equipment....................................... 9,173,686 9,032,208
Less: accumulated depreciation, depletion and amortization........... (4,529,401) (4,090,293)
------------- -------------
Net property and equipment......................................... 4,644,285 4,941,915
------------- -------------
Other assets:
Certificates of deposit ............................................... 356,500 356,500
Other.................................................................. 2,789 2,789
------------- -------------
Total other assets................................................... 359,289 359,289
------------- -------------
Total assets............................................................. $ 7,268,864 $ 9,168,827
============= =============
-- Continued --
The accompanying notes are an integral part of the consolidated financial statements.
3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
-- Continued --
September 30, December 31,
2002 2001
------------------ -----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable....................................................... $ 529,215 $ 492,306
Accrued liabilities.................................................... 2,944,089 2,816,561
Current portion of note payable (Note 2) .............................. 5,000,000 --
-------------- --------------
Total current liabilities............................................ 8,473,304 3,308,867
Long-term debt:
Note payable (Note 2) ................................................. -- 4,906,916
-------------- --------------
Total liabilities.................................................... 8,473,304 8,215,783
-------------- --------------
Commitments (Note 2)
Stockholders' equity:
Common stock, $.001 par value, 100,000,000 shares authorized;
17,651,917 and 17,913,575 shares outstanding as of
September 30, 2002 and December 31, 2001, respectively ............... 17,652 17,914
Treasury stock, at cost, 0 and 285,340 shares at September 30,
2002 and December 31, 2001, respectively (Note 7)...................... -- (909,815)
Deferred compensation from stock option modifications.................. -- (54,688)
Additional paid-in capital............................................. 49,049,025 49,910,078
Accumulated deficit.................................................... (50,271,117) (48,010,445)
-------------- --------------
Total stockholders' equity (deficit)................................. (1,204,440) 953,044
-------------- --------------
Total liabilities and stockholders' equity............................... $ 7,268,864 $ 9,168,827
============= ==============
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
September 30, ended September 30,
--------------------------------- --------------------------------
2002 2001 2002 2001
---------------- ---------------- --------------- ----------------
Revenues:
Oil and gas sales................................. $ 618,069 $ 553,919 $ 1,632,607 $ 1,791,679
Oilfield services................................ 358,520 620,559 401,385 1,386,499
-------------- -------------- -------------- ---------------
Total revenues.................................. 976,589 1,174,478 2,033,992 3,178,178
-------------- -------------- -------------- ---------------
Operating costs and expenses:
Lease operating expenses.......................... 340,887 313,047 1,031,306 951,531
Geological and geophysical costs.................. 87,453 493,712 389,179 2,449,459
Exploratory dry hole costs........................ -- 1,595 -- 3,197
Impairment of unproved oil and gas properties..... -- 58,500 -- 58,500
Oilfield services costs........................... 257,576 408,042 443,274 1,091,691
Depreciation, depletion and amortization.......... 145,198 161,018 461,849 500,355
Amortization of deferred compensation (G&A)....... -- 185,186 54,688 1,022,860
Apache Poland general and administrative costs.... -- 276,131 -- 388,708
Other general and administrative costs (G&A)...... 416,503 560,066 1,675,225 2,045,225
-------------- -------------- -------------- ---------------
Total operating costs and expenses.............. 1,247,617 2,457,297 4,055,521 8,511,526
-------------- -------------- -------------- ---------------
Operating loss...................................... (271,028) (1,282,819) (2,021,529) (5,333,348)
-------------- -------------- -------------- ---------------
Other income (expense):
Interest and other income......................... 17,209 207,831 121,886 398,038
Interest expense.................................. (118,767) (119,930) (361,029) (223,426)
-------------- -------------- -------------- ---------------
Total other income (expense).................... (101,558) 87,901 (239,143) 174,612
-------------- -------------- -------------- ---------------
Net loss............................................ $ (372,586) $ (1,194,918) $ (2,260,672) $ (5,158,736)
============== ============== ============== ===============
Basic and diluted net loss per common share......... $ (0.02) $ (0.07) $ (0.13) $ (0.29)
============== ============== ============== ===============
Basic and diluted weighted average number
of shares outstanding............................. 17,650,906 17,680,235 17,637,769 17,680,235
============== ============== ============== ===============
The accompanying notes are an integral part of the consolidated financial statements.
5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
For the nine months
ended September 30,
----------------------------------
2002 2001
-------------- --------------
Cash flows from operating activities:
Net loss............................................................... $ (2,260,672) $ (5,158,736)
Adjustments to reconcile net loss to net
cash used in operating activities:
Gain on sale of property interest.................................. -- (28,864)
Exploratory dry hole costs......................................... -- 3,197
Impairment of unproved oil and gas properties...................... -- 58,500
Depreciation, depletion and amortization........................... 461,849 500,355
Amortization of deferred compensation (G&A)........................ 54,688 1,022,860
Stock issued for services.......................................... 44,000 --
Increase (decrease) from changes in working capital items:
Accounts receivable.................................................. (383,132) (325,715)
Inventory............................................................ 4,347 (239)
Other current assets................................................. (43,825) (42,737)
Accounts payable and accrued liabilities............................. 257,514 1,405,929
-------------- --------------
Net cash used in operating activities.............................. (1,865,231) (2,565,450)
-------------- --------------
Cash flows from investing activities:
Additions to oil and gas properties.................................... (49,379) (665,945)
Additions to other property and equipment.............................. (114,833) (215,430)
Proceeds from sale of property interest................................ -- 44,040
Proceeds from maturing marketable debt securities...................... -- 1,281,993
-------------- --------------
Net cash provided by (used in) investing activities.................. (164,212) 444,658
-------------- --------------
Cash flows from financing activities:
Proceeds from loan and gas purchase option agreement................... -- 5,000,000
Proceeds from the exercise of options.................................. 4,500 --
-------------- --------------
Net cash provided by financing activities............................ 4,500 5,000,000
-------------- --------------
Increase (decrease) in cash and cash equivalents......................... (2,024,943) 2,879,208
Cash and cash equivalents at beginning of period......................... 3,157,427 1,079,038
-------------- --------------
Cash and cash equivalents at end of period............................... $ 1,132,484 $ 3,958,246
============== ===============
The accompanying notes are an integral part of the consolidated financial statements
6
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 quarterly report on Form 10-Q for the six
months ended June 30, 2002, the quarterly report on Form 10-Q for the three
months ended March 31, 2002, and the annual report on Form 10-K for the year
ended December 31, 2001, including the financial statements and notes thereto.
The interim financial statements include the accounts of FX Energy,
Inc., its wholly-owned subsidiaries and its undivided interests in Poland. All
significant inter-company accounts and transactions have been eliminated in
consolidation. As of September 30, 2002, FX Energy owned 100% of the voting
stock of all of its subsidiaries.
Note 2: Financing with Rolls-Royce Power Ventures
On March 9, 2001, the Company signed a $5.0 million, 9.5% loan
agreement and gas purchase option agreement with Rolls-Royce Power Ventures
Limited ("RRPV"). As collateral for the loan, the Company granted RRPV a lien on
most of the Company's Polish property interests. The loan was interest free for
the first year. In consideration for the loan, the Company granted RRPV an
option to purchase gas from the Company's properties in Poland, subject to
availability, exercisable on or before March 9, 2002. The option was not
exercised by RRPV. In accordance with the loan agreement, the entire principal
amount plus accrued interest are due on March 9, 2003, unless RRPV elects to
convert the loan to restricted common stock at $5.00 per share, the market value
of the Company's common stock at the time the terms with RRPV were finalized.
Accordingly, the entire balance of the RRPV note is shown as a current liability
in the September 30, 2002, balance sheet.
As of December 31, 2001, the Company had received $5.0 million from
RRPV under this arrangement. For financial reporting purposes, the Company
imputed interest expense for the first year at 9.5%, or $433,790, to be
amortized ratably over the one-year interest free period and recorded an option
premium of $433,790 pertaining to granting RRPV an option to purchase gas from
the Company's properties in Poland, to be amortized ratably to other income over
the one-year option period. Effective March 10, 2002, the Company began
recording interest expense at 9.5% per annum.
Note 3: 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. Options and warrants to purchase
5,618,967 and 5,390,667 shares of common stock at prices ranging from $2.40 to
$10.25 per share with a weighted average exercise price of $4.88 and $5.08 per
share were outstanding at September 30, 2002 and 2001, respectively. No options
or warrants were included in the computation of diluted net loss per share for
the periods ended September 30, 2002 and 2001, because the effect would have
been antidilutive.
7
Note 4: Reclassifications
Certain balances in the September 30, 2001, financial statements have
been reclassified to conform to the current year presentation. These changes had
no effect on the previously reported net loss, total assets, liabilities or
stockholders' equity.
Note 5: Income Taxes
FX Energy recognized no income tax benefit from the losses generated in
the first nine months of 2002 and the first nine months of 2001.
Note 6: 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, 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.
8
Reportable business segment information for the three months ended
September 30, 2001, the nine months ended September 30, 2001 and as of September
30, 2001, follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended September 30, 2001:
Revenues (1)..................................... $ 553,919 $ 620,559 $ -- $ 1,174,478
Net profit or (loss) (2)......................... (634,902) 133,393 (693,409) (1,194,918)
Nine months ended September 30, 2001:
Revenues (3)..................................... 1,791,679 1,386,499 -- 3,178,178
Net profit or (loss) (4)......................... (2,282,248) 70,484 (2,946,972) (5,158,736)
As of September 30, 2001:
Identifiable net property and equipment (5)...... 7,027,362 1,050,113 107,387 8,184,862
- -----------------------
(1) E&P revenues include $469,667 generated in the United States and
$84,252 generated in Poland.
(2) Nonsegmented items include $560,066 of general and administrative costs
and $59,037 of other income and expense.
(3) E&P revenues include $1,496,781 generated in the United States and
$294,898 generated in Poland.
(4) Nonsegmented items include $2,045,225 of general and administrative
costs and $145,748 of other income and expense.
(5) Nonsegmented items include $107,387 of corporate office equipment,
hardware and software.
Note 7: Treasury Stock
During the third quarter of 2002, the Company retired 285,340 shares of
treasury stock, and returned them to the status of authorized but unissued
shares.
9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Introduction
As of September 30, 2002, we had approximately $1.1 million of cash and
cash equivalents, negative working capital of approximately $6.2 million and a
stockholders' deficit of approximately $1.2 million. In addition, we have a
remaining commitment of $9.3 million ($2.7 million of which is included in our
accrued liabilities at September 30, 2002) that must be spent by us in order to
complete our earning obligation in our Fences project area. Our current
financial position raises substantial doubt about our ability to continue as a
going concern. After the recent implementation of certain cost-cutting measures,
we estimate that our existing cash and cash equivalents should be sufficient to
meet our minimum requirements through approximately the first quarter of 2003,
without regard to our Fences project area commitment and our RRPV obligation.
We are aggressively pursuing additional capital from both industry and
equity market sources and have implemented measures to reduce our cash
requirements to enable us to continue operations, including the following:
o We are actively negotiating the farmout of our Polish
properties. On October 28, 2002, we announced the signing of a
Memorandum of Understanding with CalEnergy Gas (Holdings)
Ltd., an affiliate of MidAmerican Energy Holdings Company, for
the joint exploration of certain of our oil and gas
exploration property interests in Poland. Details of the
Memorandum of Understanding remain confidential pending the
negotiation of definitive agreements, third-party
participation and other matters. The proposed transaction is
subject to the negotiation of a definitive agreement with
CalEnergy and other matters.
o Our current liabilities at September 30, 2002, include $5.0
million, secured by a lien on most of our Polish property
interests, due RRPV that is repayable in March 2003, unless
converted to common stock at $5.00 per share. We may seek an
extension of the due date, conversion of the obligation at the
previously agreed or a newly-negotiated price per share, a
release of the lien in order to facilitate further exploration
or financing or other modification of our agreements with
RRPV.
o We have reduced by 50% the salaries of all key employees. We
have taken steps to reduce or eliminate as much of our other
ongoing costs requiring cash expenditures as practicable.
o We are seeking funds through a farmout of our Polish
properties to help us satisfy the $2.7 million accrued
liability related to the Fences project area as well as the
remaining commitment of $6.6 million that must be spent by us
in order to complete our earning obligation in this project
area. In addition, we are seeking to alter the terms of our
agreement with Polish Oil and Gas Company, or POGC, respecting
the Fences project area.
As of the date of this report, we do not have a commitment from a third
party to provide any additional funding. There can be no assurance that we will
be able to obtain additional financing, further reduce expenses, renegotiate the
terms of existing agreements or successfully complete other steps to enable us
to continue as a going concern. If we are unable to obtain sufficient funds to
satisfy our future cash requirements, we may be forced to curtail operations
further, dispose of assets, issue securities to meet obligations or seek
extended payment terms from our creditors. Such events would materially and
adversely affect our financial position and results of operations and result in
the dilution of the interests of existing stockholders.
10
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 2002 to the Third Quarter of 2001
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
2002 and 2001 is set forth in the following table:
Quarter Ended September 30,
--------------------------------------------------------------
Oil Gas
------------------------------ -------------------------------
2002 2001 2002 2001
-------------- -------------- --------------- ---------------
Revenues............................................. $ 562,000 $ 470,000 $ 56,000 $ 84,000
Percent change versus prior year's quarter......... +20% -33%
Average price per (Bbl or Mcf)....................... $ 24.28 $ 19.82 $ 1.58(1) $ 1.58(1)
Percent change versus prior year's quarter......... +23% --%
Production volumes (Bbls or Mcf)..................... 23,170 23,694 36,328 53,377
Percent change versus prior year's quarter......... -2% -33%
- --------------------
(1) The contract price prior to adjusting for Btu content was $2.02 per
Mcf.
Oil Revenues. Oil revenues were $562,000 during the third quarter of
2002, a 20% increase compared to the same period of 2001. During the third
quarter of 2002, our average oil prices rose 23%, from $19.82 per barrel in 2001
to $24.28 per barrel in 2002, while oil production was relatively constant.
Gas Revenues. Gas revenues were $56,000 during the third quarter of
2002, down 33% from the same quarter of 2001, all attributable to the Kleka 11,
our first producing well in Poland, which began producing in early 2001. The
decline in gas production is the result of the operator choking back the well to
avoid any increase in water production. We are currently selling gas produced by
the Kleka 11 to POGC based on U.S. dollar pricing under a five-year contract
that may be terminated by us with a 90-day written notice.
11
Lease Operating Costs. Lease operating costs were $341,000 during the
third quarter of 2002, an increase of 9% compared to $313,000 during the same
period of 2001. Lease operating costs incurred during the current year include
approximately $6,000, or an estimated $0.16 per Mcf produced, associated solely
with the Kleka 11 well, while Kleka operating costs in 2001 were $10,000. During
the third quarter of 2002, oil lifting costs were $14.10 per barrel, an increase
of 12% over the average lifting cost of $12.57 recognized during the same
quarter of 2001. The year to year increase is due to higher well maintenance
costs in 2002.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$87,000 during the third quarter of 2002, a decrease of $302,000, or 78%,
compared to $389,000 during the same period of 2001. During the third quarter of
2002, we incurred only seismic reprocessing and other related costs. Limited
available capital in 2002 has caused us to sharply curtail our exploration
activities in Poland. Subject to our ability to raise additional equity or
obtain further financing from industry partners, we expect that our exploration
activities in Poland will continue to be minimal in the near term.
DD&A Expense - E&P. DD&A expense for producing properties was $25,000
during the third quarter of 2002, a decrease of $50,000 compared to $75,000
during the same period of 2001. DD&A expense declined primarily as a result of
lower production volumes from the Kleka 11 well in the current quarter.
Apache Poland G&A Costs. Apache Poland G&A costs consisted of our share
of direct overhead costs incurred by Apache in Poland in accordance with the
terms of the Apache Exploration Program. Apache Poland G&A costs were $276,000
during the third quarter of 2001. As this program terminated in 2001, there are
no Apache Poland G&A costs during 2002.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $359,000
during the third quarter of 2002, a decrease of 42% from $621,000 recorded
during the same period of 2001. During the third quarter of 2002, the contract
drilling industry was significantly curtailed in the area where we operate.
Conversely, the third quarter of 2001 was an unusually active quarter in terms
of contract drilling. 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. As revenues from oilfield services dropped,
our oilfield services costs did likewise, dropping from $408,000 during the
third quarter of 2001 to $258,000 during the same period of 2002, a decrease of
37%. In general, oilfield services costs are directly associated with oilfield
services revenues. The bulk of the costs in 2002 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 $82,000 during the third quarter of 2002, an increase of 4% compared to
$79,000 during the same period of 2001, primarily due to capital additions
incurred after the third quarter of 2001 being depreciated during the third
quarter of 2002.
12
Nonsegmented Information
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was zero during the third quarter of 2002, compared to $185,000
during the same period of 2001. 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. All of the deferred compensation associated with these
transactions has now been amortized.
G&A Costs. G&A costs were $417,000 during the third quarter of 2002, a
26% decrease from the $560,000 recorded for the same period of 2001, due
primarily to reduced employee compensation costs.
Interest and Other Income. We recorded $17,000 of interest and other
income during the third quarter of 2002, compared to $208,000 during the third
quarter of 2001. The bulk of other income in 2001 was related to the
amortization of an option premium that resulted from granting RRPV an option to
purchase gas from our properties in Poland. In addition, our cash balances in
2001 were significantly higher than in 2002, which provided us with a small
amount of interest income in that period.
Interest Expense. Interest expense of $119,000 during the third quarter
of 2002 was unchanged from the same period of 2001. All of the interest expense
in both periods is related to our arrangement with RRPV. Interest expense from
March 9, 2001, through March 8, 2002, consisted of interest imputed at 9.5%.
Beginning on March 9, 2002, we began accruing interest payable on the RRPV note
at 9.5% per annum.
Comparison of the First Nine Months of 2002 to the First Nine Months of 2001
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 2002 and 2001 is set forth in the following table:
Nine Months Ended September 30,
-----------------------------------------------------------------
Oil Gas
------------------------------- --------------------------------
2002 2001 2002 2001
----------------- ------------- --------------- ---------------
Revenues.......................................... $ 1,414,000 $1,497,000 $ 218,000 $295,000
Percent change versus prior year's quarter...... -6% -26%
Average price per (Bbl or Mcf).................... $ 20.52 $ 21.29 $ 1.58(1) $ 1.58(1)
Percent change versus prior year's quarter...... -4% --%
Production volumes (Bbls or Mcf).................. 68,942 70,308 138,342 186,825
Percent change versus prior year's quarter...... -2% -26%
- --------------------
(1) The contract price prior to adjusting for Btu content was $2.02 per
Mcf.
13
Oil Revenues. Oil revenues were $1,414,000 during the first nine months
of 2002, a 6% decrease compared to the same period of 2001. During the first
nine months of 2002, our average oil prices were 4% lower than in the same
period of the prior year, while oil production was relatively constant.
Gas Revenues. Gas revenues were $218,000 during the first nine months
of 2002, down 26% from the same period of 2001. The decline in gas production is
the result of the operator choking back the well to avoid any increase in water
production. We are currently selling gas produced by the Kleka 11 to POGC based
on U.S. dollar pricing under a five-year contract that may be terminated by us
with a 90-day written notice.
Lease Operating Costs. Lease operating costs were $1,031,000 during the
first nine months of 2002, an increase of 8% compared to $952,000 during the
same period of 2001. The increase was due primarily to one-time workover
expenses and higher third-party maintenance activities incurred during the first
quarter of this year. Lease operating costs incurred during the first nine
months of 2002 include approximately $24,000, or an estimated $0.16 per Mcf
produced, associated solely with the Kleka 11 well, while Kleka operating costs
during the same period of 2001 were $32,000. During the first nine months of
2002, oil lifting costs were $14.26 per barrel, an increase of 12% over the
average lifting cost of $12.79 recognized during the same period of 2001. The
year to year increase is due to higher well maintenance costs in 2002.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$389,000 during the first nine months of 2002, a decrease of 85% compared to
$2,511,000 during the same period of 2001. During the first nine months of 2002,
we incurred only minimal seismic reprocessing and other related costs. Limited
available capital in 2002 has caused us to sharply curtail our exploration
activities in Poland. Subject to our ability to raise additional equity or
obtain further financing from industry partners, we expect that our exploration
activities in Poland will continue to be minimal in the near term.
DD&A Expense - E&P. DD&A expense for producing properties was $178,000
during the first nine months of 2002, a decrease of $73,000 compared to $251,000
during the same period of 2001. DD&A expense declined primarily as a result of
lower production volumes from the Kleka 11 well in 2002.
Apache Poland G&A Costs. Apache Poland G&A costs consisted of our share
of direct overhead costs incurred by Apache Corporation in Poland in accordance
with the terms of the Apache Exploration Program. Apache Poland G&A costs were
$389,000 during the first nine months of 2001. As this program terminated in
2001, there are no Apache Poland G&A costs during 2002.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $401,000
during the first nine months of 2002, a decrease of 71% from $1,386,000 recorded
during the same period of 2001. During the first nine months of 2002, the
contract drilling industry was significantly curtailed in the area where we
operate. Conversely, the first nine months of 2001 was an unusually active
period in terms of contract drilling. 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. As revenues from oilfield services dropped,
our oilfield services costs did likewise, dropping from $1,092,000 during the
first nine months of 2001 to $443,000 during the same period of 2002, a decrease
of 59%. In general, oilfield services costs are directly associated with
oilfield services revenues. The bulk of the costs in 2002 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.
14
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $253,000 during the first nine months of 2002, an increase of $29,000
compared to $224,000 during the same period of 2001, primarily due to capital
additions incurred after the first nine months of 2001 being depreciated during
the first nine months of 2002.
Nonsegmented Information
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $55,000 during the first nine months of 2002, compared to
$1,023,000 during the same period of 2001. 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. All of the deferred compensation associated
with these transactions has now been amortized.
G&A Costs. G&A costs were $1,675,000 during the first nine months of
2002, an 18% decrease from the $2,045,000 recorded for the same period of 2001,
due primarily to reduced employee compensation costs.
Interest and Other Income. We recorded $122,000 in interest and other
income during the first nine months of 2002, compared to $398,000 during the
first nine months of 2001. The bulk of other income in 2002 and approximately
50% of other income in 2001 was related to the amortization of an option premium
that resulted from granting RRPV an option to purchase gas from our properties
in Poland. In addition, our cash balances in 2001 were significantly higher than
in 2002, which provided us with approximately $156,000 of interest income in
that period, compared to no interest income this year.
Interest Expense. Interest expense was $361,000 during the first nine
months of 2002, compared to $223,000 during the same period of 2001. All of the
interest expense in both periods relates to our arrangement with RRPV. Interest
expense from March 9, 2001, through March 8, 2002, consisted of interest imputed
at 9.5%. Beginning on March 9, 2002, we began accruing interest payable on the
RRPV note at 9.5% per annum.
Financial Condition
Liquidity and Cash Flows
Liquidity and Capital Resources
General. As of September 30, 2002, we had approximately $1.1 million of
cash and cash equivalents and negative working capital of approximately $6.2
million, coupled with a history of operating losses. These matters raise
substantial doubt about our ability to continue as a going concern. In addition,
we have a remaining commitment of $9.3 million ($2.7 million of which is
included in our accrued liabilities at September 30, 2002) that must be spent by
us in order to complete our earning obligation in our Fences project area.
15
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities and agreements with industry
partners that funded our share of costs in certain exploratory activities in
order to earn an interest in our properties. As of the date of this report, we
do not have a commitment from a third party to provide any additional funding
for our ongoing operations. The continuation of our exploratory efforts in
Poland is dependent on our ability to raise additional capital or to farm out
our properties. The availability of such capital or farmout will affect the
timing, pace, scope and amount of our future capital expenditures. There can be
no assurance that we will be able to obtain a farmout or additional financing,
further reduce expenses or successfully complete other steps to continue as a
going concern. If we are unable to obtain sufficient funds to satisfy our future
cash requirements, we may be forced to curtail operations, dispose of assets or
seek extended payment terms from our creditors. Such events would materially and
adversely affect our financial position and results of operations. See Item 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operations: Introduction.
Working Capital (current assets less current liabilities). Our working
capital deficit was $(6,208,000) as of September 30, 2002, a decrease of
$6,767,000 from December 31, 2001. In accordance with the terms of our RRPV loan
agreement, the entire principal amount of $5,000,000, plus accrued interest, is
due on March 9, 2003, unless RRPV elects to convert the loan to restricted
common stock at $5.00 per share, the market value of the Company's common stock
at the time the terms with RRPV were finalized, before March 9, 2003.
Accordingly, the entire balance of the RRPV note, along with interest accrued
through September 30, 2002, is shown as a current liability on the balance
sheet.
In 2000, we agreed to spend $16.0 million of exploration costs on the
Fences project area, which is owned and operated by POGC, in order to earn a
49.0% interest. After we complete our $16.0 million commitment, POGC will begin
bearing its 51.0% share of further costs. As of September 30, 2002, we have made
cash payments of approximately $6.7 million pertaining to the required $16.0
million, and we have accrued $2.7 million of additional costs incurred during
2001 on the Fences project area. Our objective is to assign to an outside
partner a portion of the project interests in consideration of the partner's
assumption of all, or a major portion of, our remaining obligation to earn an
interest in the Fences project area, including payment of the $2.7 million of
accrued costs.
Operating Activities. Net cash used in operating activities before
working capital changes was $1,700,000 during the first nine months of 2002, a
decrease of $1,903,000 compared to $3,603,000 during the same period of 2001.
This reduction in cash used is a direct reflection of our curtailed exploration
activities and lower geological and geophysical costs in Poland. During the
first nine months of 2002, $165,000 were used to fund changes in working capital
items, while during the first nine months of 2001, funds provided by changes in
working capital items were $1,037,000. We also issued 20,682 shares of stock to
consultants for services during the second quarter of 2002.
Investing Activities. We spent $164,000 in investing activities during
the first nine months of 2002, including $113,000 on upgrading our oilfield
servicing equipment, and $49,000 on our proved properties in the United States.
During the first nine months 2001, our investing activities provided net cash of
$445,000. During that period, we incurred $419,000 of costs relating to our
Polish properties, spent $241,000 on upgrading our producing properties in the
United States, $215,000 on our oilfield servicing equipment, and received
$1,282,000 from maturing marketable debt securities.
Financing Activities. We received $4,500 in cash from the exercise of
stock options during the first nine months of 2002. Cash provided by financing
activities was $5.0 million during the first nine months of 2001. During March
2001, we signed a $5.0 million loan agreement with RRPV. As of September 30,
2001, we had received the entire $5.0 million under the arrangement with RRPV.
16
Critical Accounting Policies
A summary of our significant accounting policies is included in Note 1
of our Consolidated Financial Statements contained in the annual report on Form
10-K for the year ended December 31, 2001. 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.
The preparation of financial statements in accordance with generally
accepted accounting principles 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 and the estimates of oil and gas reserves.
Risk Factors
We face a number of risks in our business, including, but not limited
to, the risk factors discussed in our annual report on Form 10-K for the year
ended December 31, 2001, and other Securities and Exchange Commission filings.
Other Items
On January 1, 2002, we adopted Statement of Financial Accounting
Standards ("SFAS") No. 141 "Business Combinations," SFAS No. 142 "Goodwill and
Other Intangible Assets," and SFAS No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets." The adoption of these new standards did not have
a significant impact on our financial statements.
In August 2001, the Financial Accounting Standards Board issued SFAS
No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 is effective
for us beginning January 1, 2003. The most significant impact of this standard
to us will be a change in the method of accruing for site restoration costs.
Under SFAS No. 143, the fair value of asset retirement obligations will be
recorded as liabilities when they are incurred, which are typically at the time
the assets are installed. Amounts recorded for the related assets will be
increased by the amount of these obligations. Over time, the liabilities will be
accreted for the change in their present value and the capitalized costs will be
depreciated over the useful lives of the related assets. We are currently
evaluating the impact of adopting SFAS No. 143.
We have reviewed all other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on our results
of operations or financial position. Based on that review, we believe that none
of these pronouncements will have a significant effect on current or future
earnings or operations.
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," "will," "should," "expect,"
"anticipate," "estimate," "project," "propose," "plan," "intend" and similar
words and expressions. We intend that the forward-looking statements will be
covered by the safe harbor provisions for forward-looking statements contained
in Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Statements that describe our future strategic plans, goals
or objectives are also forward-looking statements.
17
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 partners to share the costs of exploration, exploitation, development
and acquisition activities; and future plans and the financial and technical
resources of strategic partners.
The forward-looking information is based on present circumstances and
on our predictions respecting events that have not occurred, that may not occur
or that may occur with different consequences from those now assumed or
anticipated. Actual events or results may differ materially from those discussed
in the forward-looking statements as a result of various factors, including the
risk factors detailed in this report. The forward-looking statements included in
this report are made only as of the date of this report. We disclaim any
obligation to update any forward-looking statements whether as a result of new
information, future events or otherwise.
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.
Our gas production in Poland is currently being sold to POGC based on
U.S. dollar pricing under a five-year contract that may be terminated by us with
a 90-day written notice. The limited volume and single source of our gas
production means we cannot assure uninterruptible production or production in
amounts that would be meaningful to industrial users, which may depress the
price we may be able to obtain. There is currently no competitive market for the
sale of gas in Poland. Accordingly, we expect that the prices we receive for the
gas we produce will be lower than would be the case in a competitive setting and
may be lower than prevailing western European prices, at least until a fully
competitive market develops in Poland.
We currently do not engage in any hedging activities or have any
derivative financial instruments to protect ourselves against market risks
associated with oil and gas price fluctuations, although we may elect to do so
if we achieve a significant amount of production in Poland.
18
Foreign Currency Risk
We have entered into various agreements in Poland, primarily in U.S.
dollars or the U.S. dollar equivalent of the Polish zloty. We conduct our
day-to-day business on this basis as well. The Polish zloty is subject to
exchange rate fluctuations that are beyond our control. We do not currently
engage in hedging transactions to protect ourselves against foreign currency
risks, nor do we intend to do so in the foreseeable future.
ITEM 4. CONTROLS AND PROCEDURES
We maintain a system of internal controls and procedures designed to
provide reasonable assurance as to the reliability of our consolidated financial
statements and other disclosures included in this report. Our Board of
Directors, operating through its audit committee, provides oversight to our
financial reporting process.
Within the 90-day period prior to the date of this report, we evaluated
the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934. Based
upon that evaluation, our Chief Executive Officer and our Chief Financial
Officer concluded that our disclosure controls and procedures are effective in
alerting them in a timely manner to material information relating to FX Energy,
Inc. required to be included in this quarterly report on Form 10-Q.
There have been no significant changes in our internal controls or in
other factors that could significantly affect internal controls subsequent to
the date that we carried out our evaluation and there have been no corrective
actions regarding significant deficiencies or material weaknesses.
19
PART II.
OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On September 10, 2002, at the annual meeting of the Company's
stockholders, the stockholders approved the following matters submitted to them
for consideration:
(a) elected David N. Pierce and Peter L. Raven as directors of the
Company by a plurality as shown below:
Director For Against Abstain
------------------- ---------------- ------------- -----------
David N. Pierce 16,293,076 3,675 173,789
Peter L. Raven 16,293,076 1,000 176,464
(b) approved the 2001 Stock Option and Award Plan as shown below:
For Against Abstain
------------------ ---------------- ----------------
14,263,377 1,883,741 323,422
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 99 Additional Exhibits
- ---------- ------------ ------------------------------------------- ------------
99.01 99 Certification of Chief Executive Officer This filing
99.02 99 Certification of Chief Financial Officer This filing
(b) Reports on Form 8-K: We did not file any reports on Form 8-K during
the quarter ended September 30, 2002.
20
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
FX ENERGY, INC.
(Registrant)
Date: November 13, 2002 By /s/ David N. Pierce
-------------------------------------
President and Chief Executive Officer
Date: November 13, 2002 By /s/ Thomas B. Lovejoy
-------------------------------------
Chief Financial Officer
21
CERTIFICATION
I, David N. Pierce, certify that:
1. I have reviewed this quarterly report on Form 10-Q of FX Energy,
Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 13, 2002
/s/ David N. Pierce
- ------------------------------
David N. Pierce
Principal Executive Officer
22
CERTIFICATION
I, Thomas B. Lovejoy, certify that:
1. I have reviewed this quarterly report on Form 10-Q of FX Energy,
Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 13, 2002
/s/ Thomas B. Lovejoy
- -------------------------------
Thomas B. Lovejoy
Principal Financial Officer
23