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U. S. SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 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 [ ]
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 July 27, 2002, was
17,648,917.
FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Six Months Ended and as of June 30, 2002
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................... 6
Notes to 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
Part II. Other Information
6 Exhibits and Reports on Form 8-K.............................. 20
-- Signatures.................................................... 21
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
June 30, December 31,
2002 2001
--------------------- ---------------------
ASSETS
Current assets:
Cash and cash equivalents............................................. $ 1,320,644 $ 3,157,427
Accounts receivable:
Accrued oil sales................................................... 698,912 478,857
Joint interest owners and others.................................... 77,547 49,075
Inventory............................................................. 85,806 87,260
Other current assets.................................................. 19,294 95,004
----------- -----------
Total current assets................................................ 2,202,203 3,867,623
----------- -----------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved.............................................................. 4,818,002 4,789,252
Unproved............................................................ 655,523 655,523
Other property and equipment........................................ 3,653,799 3,587,433
----------- -----------
Gross property and equipment...................................... 9,127,324 9,032,208
Less: accumulated depreciation, depletion and amortization.......... (4,384,203) (4,090,293)
----------- -----------
Net property and equipment........................................ 4,743,121 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............................................................ $ 7,304,613 $ 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 --
June 30, December 31,
2002 2001
--------------------- ---------------------
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable...................................................... $ 312,867 $ 492,306
Accrued liabilities................................................... 2,828,100 2,816,561
Current portion of note payable (Note 2) ............................. 5,000,000 --
----------- -----------
Total current liabilities........................................... 8,140,967 3,308,867
Long-term debt:
Note payable (Note 2)................................................. -- 4,906,916
----------- -----------
Total liabilities................................................... 8,140,967 8,215,783
----------- -----------
Stockholders' equity (deficit):
Common stock, $.001 par value, 100,000,000 shares authorized;
17,934,257 and 17,913,575 shares issued as of June 30, 2002
and December 31, 2001, respectively................................. 17,935 17,914
Treasury stock, at cost, 285,340 shares............................... (909,815) (909,815)
Deferred compensation from stock option modifications................. -- (54,688)
Additional paid-in capital............................................ 49,954,057 49,910,078
Accumulated deficit................................................... (49,898,531) (48,010,445)
----------- -----------
Total stockholders' equity (deficit) ............................... (836,354) 953,044
----------- -----------
Total liabilities and stockholders' equity (deficit) ................... $ 7,304,613 $ 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 six months
June 30, ended June 30,
--------------------------------- --------------------------------
2002 2001 2002 2001
---------------- ---------------- --------------- ----------------
Revenues:
Oil and gas sales................................. $ 568,730 $ 640,693 $ 1,014,539 $ 1,237,760
Oilfield services................................ 38,512 722,402 42,865 765,940
------------- -------------- ------------- ------------
Total revenues.................................. 607,242 1,363,095 1,057,404 2,003,700
------------- -------------- ------------- ------------
Operating costs and expenses:
Lease operating expenses.......................... 337,877 332,790 690,419 638,484
Geological and geophysical costs.................. 174,890 754,267 301,726 1,955,747
Exploratory dry hole costs........................ -- -- -- 1,602
Oilfield services costs........................... 73,256 567,819 185,698 683,649
Depreciation, depletion and amortization.......... 151,665 200,704 316,652 339,338
Amortization of deferred compensation (G&A)....... -- 446,181 54,688 837,675
Apache Poland general and administrative costs.... -- 112,577 -- 112,577
General and administrative........................ 620,675 803,263 1,258,722 1,485,157
------------- -------------- ------------- ------------
Total operating costs and expenses.............. 1,358,363 3,217,601 2,807,905 6,054,229
------------- -------------- ------------- ------------
Operating loss...................................... (751,121) (1,854,506) (1,750,501) (4,050,529)
------------- -------------- ------------- ------------
Other income (expense):
Interest income and other income and expense, net. -- 137,823 104,677 190,207
Interest expense.................................. (119,012) (90,236) (242,262) (103,496)
------------- -------------- ------------- ------------
Total other income (expense).................... (119,012) 47,587 (137,585) 86,711
------------- -------------- ------------- ------------
Net loss............................................ $ (870,133) $ (1,806,919) $ (1,888,086) $ (3,963,818)
============= ============== ============= ============
Basic and diluted net loss per common share......... $ (0.05) $ (0.10) $ (0.11) $ (0.22)
============= ============== ============= ============
Basic and diluted weighted average number
of shares outstanding............................. 17,633,917 17,680,235 17,631,092 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 six months
ended June 30,
-------------------------------------
2002 2001
------------------ -----------------
Cash flows from operating activities:
Net loss............................................................... $ (1,888,086) $ (3,963,818)
Adjustments to reconcile net loss to net
cash used in operating activities:
Exploratory dry hole costs......................................... -- 1,602
Depreciation, depletion and amortization........................... 316,652 339,338
Amortization of deferred compensation (G&A)........................ 54,688 837,675
Stock issued for services.......................................... 44,000 --
------------ ------------
Net cash used before changes in working capital items.......... (1,472,746) (2,785,203)
------------ ------------
Increase (decrease) from changes in working capital items:
Accounts receivable.................................................. (248,527) (451,648)
Inventory............................................................ 1,454 1,206
Other current assets................................................. 75,710 36,893
Accounts payable and accrued liabilities............................. (74,816) 1,661,376
------------ ------------
Net cash used in operating activities.............................. (1,718,925) (1,537,376)
------------ ------------
Cash flows from investing activities:
Additions to oil and gas properties.................................... (28,750) (196,112)
Additions to other property and equipment.............................. (89,108) (167,043)
Proceeds from maturing marketable debt securities...................... -- 1,281,993
------------ ------------
Net cash provided by (used in) investing activities.................. (117,858) 918,838
------------ ------------
Cash flows from financing activities:
Proceeds from loan and gas purchase option agreement................... -- 5,000,000
------------ ------------
Net cash provided by financing activities............................ -- 5,000,000
------------ ------------
(Decrease) increase in cash and cash equivalents......................... (1,836,783) 4,381,462
Cash and cash equivalents at beginning of period......................... 3,157,427 1,079,038
------------ ------------
Cash and cash equivalents at end of period............................... $ 1,320,644 $ 5,460,500
============ ============
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
These 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 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.
These 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 June 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
("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 June 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
5,885,585 and 5,547,917 shares of common stock at prices ranging from $1.50 to
$10.25 per share with a weighted average exercise price of $4.87 and $5.13 per
share were outstanding at June 30, 2002 and 2001, respectively. No options or
warrants were included in the computation of diluted net loss per share for the
periods ended June 30, 2002 and 2001, because the effect would have been
antidilutive.
7
Note 4: Reclassifications
Certain balances in the June 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 six months of 2002 and the first six 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 June 30, 2002, the six months ended June 30, 2002, and as of June
30, 2002, follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended June 30, 2002:
Revenues(1).................................. $ 568,730 $ 38,512 $ -- $ 607,242
Net loss(2).................................. (13,297) (129,988) (726,848) (870,133)
Six months ended June 30, 2002:
Revenues(3).................................. 1,014,539 42,865 -- 1,057,404
Net loss(4).................................. (130,578) (313,794) (1,443,714) (1,888,086)
As of June 30, 2002:
Identifiable net property and equipment(5)... 3,732,395 901,771 108,955 4,743,121
- ----------------------
(1) E&P revenues include $498,193 generated in the United States and $70,537
generated in Poland.
(2) Nonsegmented items include $620,675 of general and administrative costs and
$106,173 of other income and expense.
(3) E&P revenues include $851,975 generated in the United States and $162,564
generated in Poland.
(4) Nonsegmented items include $1,258,722 of general and administrative costs
and $184,992 of other income and expense.
(5) Nonsegmented items include $108,955 of corporate office equipment, hardware
and software.
8
Reportable business segment information for the three months ended June
30, 2001, the six months ended June 30, 2001, and as of June 30, 2001, follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended June 30, 2001:
Revenues(1)...................................... $ 640,693 $ 722,402 $ -- $ 1,363,095
Net profit (loss)(2)............................. (677,244) 79,415 (1,209,090) (1,806,919)
Six months ended June 30, 2001:
Revenues(3)...................................... 1,237,760 765,940 -- 2,003,700
Net loss(4)...................................... (1,647,346) (62,909) (2,253,563) (3,963,818)
As of June 30, 2001:
Identifiable net property and equipment(5)....... 7,114,559 1,096,332 112,241 8,323,132
- --------------------
(1) E&P revenues include $492,514 generated in the United States and $148,179
generated in Poland.
(2) Nonsegmented items include $803,263 of general and administrative costs and
$405,827 of other income and expense.
(3) E&P revenues include $1,027,114 generated in the United States and $210,646
generated in Poland.
(4) Nonsegmented items include $1,485,157 of general and administrative costs
and $768,406 of other income and expense.
(5) Nonsegmented items include $112,241 of corporate office equipment, hardware
and software.
9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Introduction
As of June 30, 2002, we had approximately $1.3 million of cash and cash
equivalents, negative working capital of approximately $5.9 million and a
stockholders' deficit of approximately $836,000. In addition, we have a
remaining commitment of $9.3 million ($2.7 million of which is included in our
accrued liabilities at June 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.
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, and based on the progress of these negotiations to
date, management is optimistic that an arrangement can be
reached before year-end.
o Our current liabilities at June 30, 2002, included $5.0
million, secured by a lien on most of our Polish property
interests, due Rolls-Royce Power Ventures 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 deferred the payment of 50% of the salaries of all key
employees and may pay the deferred amount in stock. 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 respecting 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, and general and administrative costs, or G&A, directly
associated with their respective segments are detailed within the following
discussion. G&A, amortization of deferred compensation (G&A), interest income,
other income, interest expense, officer loan impairment 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 Second Quarter of 2002 to the Second 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 second quarter of
2002 and 2001 is set forth in the following table:
Quarter Ended June 30,
-------------------------------------------------------------
Oil Gas
----------------------------- -------------------------------
2002 2001 2002 2001
-------------- -------------- ---------------- --------------
Revenues............................................. $ 498,000 $ 493,000 $ 71,000 $ 148,000
Percent change versus prior year's quarter......... +1% -52%
Average price per (Bbl or Mcf)....................... $ 21.56 $ 21.21 $ 1.58(1) $ 1.58(1)
Percent change versus prior year's quarter......... +2% --%
Production volumes (Bbls or Mcf)..................... 23,110 23,219 44,652 93,878
Percent change versus prior year's quarter......... --% -52%
- -------------------
(1) The contract price prior to adjusting for Btu content was $2.02 per Mcf.
(2) Lifting costs are computed by dividing lease operating expenses by the
related volumes produced.
Oil Revenues. Oil revenues were $498,000 during the second quarter of
2002, a 1% increase compared to the same period of 2001. During the second
quarter of 2002, our average oil prices rose slightly, from $21.21 per barrel in
2001 to $21.56 per barrel in 2002, while oil production was relatively constant.
Gas Revenues. Gas revenues were $71,000 during the second quarter of
2002, down 52% 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.
Lease Operating Costs. Lease operating costs were $338,000 during the
second quarter of 2002, an increase of 2% compared to $333,000 during the same
period of 2001. Lease operating costs incurred during the current year include
approximately $8,000, or an estimated $0.16 per Mcf produced, associated solely
with the Kleka 11 well, while Kleka operating costs in 2001 were $15,000. During
the second quarter of 2002, oil lifting costs were $13.74 per barrel, an
increase of 4% over the average lifting cost of $13.24 recognized during the
same quarter of 2001.
11
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$175,000 during the second quarter of 2002, a decrease of $579,000, or 77%,
compared to $754,000 during the same period of 2001. During the second 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 $69,000
during the second quarter of 2002, a decrease of $50,000 compared to $119,000
during the same period of 2001. DD&A expense incurred during the second quarter
of 2002 includes approximately $50,000 associated with the Kleka 11, while Kleka
related DD&A expense during the same quarter of 2001 was $104,000. The decline
from year to year is due to lower production volumes 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 $113,000
during the second 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 $39,000
during the second quarter of 2002, a decrease of 95% from $722,000 recorded
during the same period of 2001. During the second quarter of 2002, the contract
drilling industry was at a virtual standstill in the area where we operate.
Conversely, the second 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 $568,000 during the
second quarter of 2001 to $73,000 during the same period of 2002, a decrease of
87%. 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 $95,000 during the second quarter of 2002, an increase of $20,000 compared
to $75,000 during the same period of 2001, primarily due to capital additions
incurred after the second quarter of 2001 being depreciated during the second
quarter of 2002.
Nonsegmented Information
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was zero during the second quarter of 2002, compared to $446,000
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
12
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 $621,000 during the second quarter of 2002, a
23% decrease from the $803,000 recorded for the same period of 2001. During the
second quarter of 2001, we incurred legal, travel and other costs related to the
RRPV loan agreement that were not repeated during the same quarter of 2002. G&A
costs in 2002 were also lower due to reduced employee compensation costs.
Interest and Other Income. We recorded no interest and other income
during the second quarter of 2002, compared to $138,000 during the second
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 was $119,000 during the second
quarter of 2002, compared to $90,000 during 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 Half of 2002 to the First Half 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 half of
2002 and 2001 is set forth in the following table:
Six Months Ended June 30,
--------------------------------------------------------------
Oil Gas
---------------------------- --------------------------------
2002 2001 2002 2001
-------------- ------------- --------------- ---------------
Revenues................................................ $ 852,000 $1,027,000 $ 163,000 $211,000
Percent change versus prior year's quarter............ -17% -23%
Average price per (Bbl or Mcf).......................... $ 18.61 $ 22.03 $ 1.58(1) $ 1.58(1)
Percent change versus prior year's quarter............ -16% --%
Production volumes (Bbls or Mcf)........................ 45,772 46,614 102,902 133,448
Percent change versus prior year's quarter............ -2% -23%
- -----------------
(1) The contract price prior to adjusting for Btu content was $2.02 per Mcf.
(2) Lifting costs are computed by dividing lease operating expenses by the
related volumes produced.
Oil Revenues. Oil revenues were $852,000 during the first half of 2002,
a 17% decrease compared to the same period of 2001. During the first half of
2002, our average oil prices were 16% lower than in the same period of the prior
year, while oil production was relatively constant.
13
Gas Revenues. Gas revenues were $163,000 during the first half of 2002,
down 23% 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 $690,000 during the
first half of 2002, an increase of 8% compared to $638,000 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 six months of 2002
include approximately $17,000, 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 $21,000. During the first half of 2002, oil lifting
costs were $14.46 per barrel, an increase of 12% over the average lifting cost
of $12.90 recognized during the same period of 2001.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$302,000 during the first half of 2002, a decrease of 85% compared to $1,957,000
during the same period of 2001. During the first half 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 $160,000
during the first half of 2002, a decrease of $17,000 compared to $177,000 during
the same period of 2001. DD&A expense incurred during the first half of 2002
includes approximately $116,000 associated with the Kleka 11, while Kleka
related DD&A expense during the same period of 2001 was $147,000. The decline
from year to year is due to lower production volumes in the current period.
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
$113,000 during the first half 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 $43,000
during the first half of 2002, a decrease of 94% from $766,000 recorded during
the same period of 2001. During the first half of 2002, the contract drilling
industry was at a virtual standstill in the area where we operate. Conversely,
the first half 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 $684,000 during the
first half of 2001 to $186,000 during the same period of 2002, a decrease of
73%. 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 $171,000 during the first half of 2002, an increase of $26,000 compared to
$145,000 during the same period of 2001, primarily due to capital additions
incurred after the first half of 2001 being depreciated during the first half of
2002.
Nonsegmented Information
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $54,688 during the first half of 2002, compared to $837,675
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 $1,259,000 during the first half of 2002, a
15% decrease from the $1,485,000 recorded for the same period of 2001. During
the first half of 2001, we incurred legal, travel and other costs related to the
RRPV loan agreement that were not repeated during the same period of 2002. G&A
costs in 2002 were also lower due to reduced employee compensation costs.
Interest and Other Income. We recorded $105,000 in interest and other
income during the first half of 2002, compared to $190,000 during the first half
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 $100,000 of interest income in that period,
compared to no interest income this year.
Interest Expense. Interest expense was $242,000 during the first half
of 2002, compared to $103,000 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 Capital Resources
General. As of June 30, 2002, we had approximately $1.3 million of cash
and cash equivalents and negative working capital of approximately $5.9 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 June 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,
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. See
"Introduction" above.
Working Capital (current assets less current liabilities). Our working
capital was $(5,939,000) as of June 30, 2002, a decrease of $6,498,000 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 June 30, 2002, is shown as
a current liability on the balance sheet.
Our current liabilities also include $2.7 million of costs related to
our Fences project in Poland. In 2000, we agreed to spend $16.0 million of
exploration costs on this project area, which is owned and operated by POGC, in
order to earn a 49.0% interest. After we complete our $16.0 million commitment,
POGC will begin bearing its 51.0% share of further costs.
As of June 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. We
anticipate assigning 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 at December 31, 2001.
Operating Activities. Net cash used in operating activities before
working capital changes was $1,473,000 during the first six months of 2002, a
decrease of $1,312,000 compared to $2,785,000 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 half of 2002, $246,000 were used to fund changes in working capital items,
while during the first half of 2001, funds provided by changes in working
capital items were $1,248,000. We also issued 20,682 shares of stock to
consultants for services during the second quarter of 2002.
Investing Activities. We spent $118,000 in investing activities during
the first half of 2002, including $89,000 on upgrading our oilfield servicing
equipment, and $29,000 on our proved properties in the United States. During the
first half 2001, our investing activities provided net cash of $919,000. During
that period, we incurred $33,000 of costs relating to our Polish properties,
spent $163,000 on upgrading our producing properties in the United States,
$164,000 on our oilfield servicing equipment, $3,000 on office equipment, and
received $1,282,000 from maturing marketable debt securities.
Financing Activities. We received no cash from financing activities
during the first half of 2002. Cash provided by financing activities was $5.0
million during the first half of 2001. During March 2001, we signed a $5.0
million loan agreement with RRPV. As of June 30, 2001, we had received the
entire $5.0 million under the arrangement with RRPV.
16
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.
17
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.
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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk
Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.
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.
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PART II. OTHER INFORMATION
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 Pursuant to 18 U.S.C.ss. This filing
1350, as adopted Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (Chief
Executive Officer)
99.02 99 Certification Pursuant to 18 U.S.C.ss. This filing
1350, as adopted Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (Chief
Financial Officer)
(b) Reports on Form 8-K: During the quarter ended June 30, 2002,
we did not file any reports on Form 8-K.
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: August 7, 2002 By /s/ David N. Pierce
----------------------------
David N. Pierce, President,
Chief Executive Officer
Date: August 7, 2002 By /s/ Thomas B. Lovejoy
-----------------------------
Thomas B. Lovejoy,
Chief Financial Officer
21