U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q/A
(Amendment No. 1)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
Commission File No. 000-25386
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 by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date. The number of shares
of $0.001 par value common stock outstanding as of August 13, 2003, was
20,984,640.
FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Three Months Ended and as of June 30, 2003
TABLE OF CONTENTS
Item Page
- ------- -------
Part I. Financial Information
1 Financial Statements:
Consolidated Balance Sheets................................. 4
Consolidated Statements of Operations....................... 6
Consolidated Statements of Cash Flows....................... 8
Notes to Consolidated Financial Statements.................. 9
2 Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 15
Part II. Other Information
6 Exhibits and Reports on Form 8-K.................................. 23
-- Signatures........................................................ 24
2
Explanatory Note
This Form 10-Q/A constitutes Amendment No. 1 to the Registrant's 10-Q
for the fiscal quarter ended June 30, 2003. Further information can be found in
footnote 11 to the consolidated financial statement. The following changes are
reflected:
The Company has determined that certain adjustments are required to
restate the consolidated financial statements for the years ended December 31,
2002, 2001 and 2000. Overall, the adjustments decreased the net loss for the
year ended December 31, 2000, by $597,818, or $0.04 per share. The adjustments
also reduced the accumulated deficit at December 31, 2000, by $973,990 and
increased the cost basis of treasury stock by the same amount. These adjustments
were necessary to account for certain loans to officers in 1998 using variable
stock option accounting.
3
PART I.
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
June 30, December 31,
2003 2002
--------------------- ---------------------
ASSETS
Current assets:
Cash and cash equivalents.............................................. $ 2,963,196 $ 705,012
Accounts receivable:
Accrued oil sales.................................................... 219,044 238,236
Joint interest owners and others..................................... 56,530 36,893
Inventory.............................................................. 79,143 84,262
Other current assets................................................... 84,455 95,726
----------- ------------
Total current assets................................................. 3,402,368 1,160,129
----------- ------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved............................................................... 6,249,853 4,754,377
Unproved............................................................. 154,261 154,261
Other property and equipment......................................... 3,716,200 3,683,226
----------- ------------
Gross property and equipment....................................... 10,120,314 8,591,864
Less: accumulated depreciation, depletion and amortization........... (4,168,993) (4,685,487)
----------- ------------
Net property and equipment......................................... 5,951,321 3,906,377
----------- ------------
Other assets:
Certificates of deposit ............................................... 356,500 356,500
Other.................................................................. 2,789 18,072
----------- ------------
Total other assets................................................... 359,289 374,572
----------- ------------
Total assets............................................................. $ 9,712,978 $ 5,441,078
=========== ============
-- Continued --
The accompanying notes are an integral part of the consolidated financial statements.
4
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
-- Continued --
June 30, December 31,
2003 2002
-------------- --------------
(As Restated) (As Restated)
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable.......................................................... $ 395,309 $ 376,264
Accrued liabilities....................................................... 4,726,657 4,933,393
Current portion of note payable........................................... 3,325,000 5,000,000
-------------- --------------
Total current liabilities............................................... 8,446,966 10,309,657
Asset retirement obligation ............................................... 364,123 --
-------------- --------------
Total liabilities....................................................... 8,811,089 10,309,657
-------------- --------------
Stockholders' equity (deficit):
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 2,250,000
shares issued ($5,625,000 liquidation preference)
as of June 30, 2003, and no shares as of December 31, 2002.............. 2,250 --
Common stock, $0.001 par value, 100,000,000 shares authorized;
17,716,185 and 17,651,917 shares issued as of June 30, 2003 and
December 31, 2002, respectively......................................... 17,715 17,652
Additional paid-in capital................................................ 53,857,509 48,075,035
Accumulated deficit....................................................... (52,975,585) (52,961,266)
-------------- --------------
Total stockholders' equity (deficit) ................................... 901,889 (4,868,579)
-------------- --------------
Total liabilities and stockholders' equity (deficit) ....................... $ 9,712,978 $ 5,441,078
============= ==============
The accompanying notes are an integral part of the consolidated financial statements.
5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
For the three months For the six months
ended June 30, ended June 30,
--------------------------------- --------------------------------
2003 2002 2003 2002
---------------- ---------------- --------------- ----------------
Revenues:
Oil and gas sales................................. $ 506,575 $ 568,730 $ 1,118,518 $ 1,014,539
Oilfield services................................. 23,200 38,512 32,528 42,865
------------ ------------- -------------- -------------
Total revenues.................................. 529,775 607,242 1,151,046 1,057,404
------------ ------------- -------------- -------------
Operating costs and expenses:
Lease operating expenses.......................... 396,343 337,877 756,804 690,419
Geological and geophysical costs.................. 223,980 174,890 290,859 301,726
Oilfield services costs........................... 53,633 73,256 128,774 185,698
Depreciation, depletion and amortization.......... 155,890 151,665 255,420 316,652
Accretion expense................................. 9,286 -- 18,572 --
Amortization of deferred compensation (G&A)....... -- -- -- 54,688
General and administrative (G&A).................. 556,372 620,675 1,053,888 1,258,722
------------ ------------- -------------- -------------
Total operating costs and expenses.............. 1,395,504 1,358,363 2,504,317 2,807,905
------------ ------------- -------------- -------------
Operating loss...................................... (865,729) (751,121) (1,353,271) (1,750,501)
------------ ------------- -------------- -------------
Other income (expense):
Interest income and other income and expense, net. (294) -- 9,319 104,677
Interest expense.................................. (240,053) (119,012) (469,861) (242,262)
------------ ------------- -------------- -------------
Total other income (expense).................... (240,347) (119,012) (460,542) (137,585)
------------ ------------- -------------- -------------
Loss before cumulative effect of change in
accounting principle.............................. (1,106,076) (870,133) (1,813,813) (1,888,086)
Cumulative effect of change in accounting principle. -- -- 1,799,494 --
------------ ------------- -------------- -------------
Net loss ........................................... $ (1,106,076) $ (870,133) $ (14,319) $ (1,888,086)
============ ============= ============== =============
Pro forma net loss reflecting adoption of SFAS 143.. $ (878,499) $ (1,904,818)
============= =============
-- Continued --
The accompanying notes are an integral part of the consolidated financial statements.
6
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
-- Continued --
For the three months For the six months
ended June 30, ended June 30,
--------------------------------- --------------------------------
2003 2002 2003 2002
---------------- ---------------- --------------- ----------------
Basic loss per common share before
cumulative effect of change in accounting principle. $ (0.06) $ (0.05) $ (0.10) $ (0.11)
Cumulative effect of change in accounting principle. -- -- 0.10 --
------------ ------------- -------------- -------------
Basic net loss per common share..................... $ (0.06) $ (0.05) $ -- $ (0.11)
============ ============= ============== =============
Diluted loss per common share before cumulative
effect of change in accounting principle........... (0.06) (0.05) (0.10) (0.11)
Cumulative effect of change in accounting principle. -- -- 0.10 --
------------ ------------- -------------- -------------
Diluted net loss per common share................... $ (0.06) $ (0.05) $ -- $ (0.11)
============ ============= ============== =============
Pro forma net loss per common share reflecting
adoption of SFAS 143
Basic............................................... $ (0.05) $ (0.11)
============= =============
Diluted............................................. $ (0.05) $ (0.11)
============= =============
Basic and diluted weighted average number of
shares outstanding................................ 17,714,099 17,633,917 17,683,180 17,631,092
The accompanying notes are an integral part of the consolidated financial statements
7
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
For the six months
ended June 30,
-------------------------------------
2003 2002
------------------ -----------------
Cash flows from operating activities:
Net loss.......................................................... $ (14,319) $ (1,888,086)
Adjustments to reconcile net loss to net
cash used in operating activities:
Cumulative effect of change in accounting principle........... (1,799,494) --
Accretion expense............................................. 18,572 --
Depreciation, depletion and amortization...................... 255,420 316,652
Amortization of loan fees..................................... 38,255 --
Amortization of deferred compensation (G&A)................... -- 54,688
Common stock issued for services.............................. 72,515 44,000
------------- ------------
Increase (decrease) from changes in working capital items:
Accounts receivable............................................. (445) (248,527)
Inventory....................................................... 5,119 1,454
Other current assets............................................ 73,016 75,710
Accounts payable and accrued liabilities........................ (69,291) (74,816)
------------- ------------
Net cash used in operating activities......................... (1,420,652) (1,718,925)
------------- ------------
Cash flows from investing activities:
Additions to oil and gas properties............................... (119,711) (28,750)
Additions to other property and equipment......................... (35,608) (89,108)
Decreases in other assets......................................... 15,283 --
------------- ------------
Net cash used in investing activities........................... (140,036) (117,858)
------------- ------------
Cash flows from financing activities:
Proceeds from preferred stock offering, net....................... 5,593,872 --
Payment of loan fees.............................................. (100,000) --
Payments on notes payable......................................... (1,675,000) --
------------- ------------
Net cash provided by financing activities....................... 3,818,872 --
------------- ------------
(Decrease) increase in cash and cash equivalents.................... 2,258,184 (1,836,783)
Cash and cash equivalents at beginning of period.................... 705,012 3,157,427
------------- ------------
Cash and cash equivalents at end of period.......................... $ 2,963,196 $ 1,320,644
============= ============
The accompanying notes are an integral part of the consolidated financial statements
8
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
(Unaudited)
Note 1: Basis of Presentation
The interim financial data are unaudited; however, in the opinion of
the management of FX Energy, Inc. and subsidiaries ("FX Energy" or the
"Company"), the interim data includes all adjustments, consisting only of normal
recurring adjustments, necessary for a fair presentation of the results for the
interim periods. The interim financial statements should be read in conjunction
with FX Energy's annual report on Form 10-K for the year ended December 31,
2002, and the Form 10-Q for the quarter ended March 31, 2003, including the
financial statements and notes thereto.
The consolidated financial statements include the accounts of FX Energy
and its wholly-owned subsidiaries and FX Energy's undivided interests in Poland.
All significant intercompany accounts and transactions have been eliminated in
consolidation. At June 30, 2003, FX Energy owned 100% of the voting stock of all
of its subsidiaries.
Note 2: Private Placement of Convertible Preferred Stock
On March 13, 2003, the Company sold 2,250,000 shares of 2003 Series
Convertible Preferred Stock in a private placement of securities, raising a
total of $5.6 million after offering costs of $31,000. Each share of preferred
stock immediately converts into one share of common stock and one warrant to
purchase one share of common stock at $3.60 per share upon registration of the
common shares. The warrants to purchase common stock are exercisable anytime
between March 1, 2004, and March 1, 2008. The preferred stock has a liquidation
preference equal to the sales price for the shares, which was $2.50 per share.
In connection with the issuance of the 2003 Series Convertible
Preferred Stock, the Company allocated approximately $2.3 million of the
proceeds to the warrants, and the remaining amount of the proceeds to a
beneficial conversion feature. As the conversion of the preferred shares and the
issuance of the warrants are contingent upon the registration of the underlying
shares, these amounts will be recognized in the calculation of earnings per
share upon the conversion of the preferred stock to common stock. A registration
statement on Form S-3 has been filed with the SEC to effect this registration.
The net proceeds from the offering were used to reduce the note payable
to Rolls-Royce Power Ventures Limited, or RRPV, and will be used to fund ongoing
geological and geophysical costs in Poland and support ongoing prospect
marketing and general and administrative costs.
Note 3: Financing with Rolls-Royce Power Ventures
In early 2003, the Company reached an agreement with RRPV to amend its
9.5% Convertible Secured Note in the amount of $5,000,000. Following its private
placement of convertible preferred stock described in Note 2, the Company paid
$2,250,000 to RRPV, $1,675,000 of which was applied to the outstanding balance,
$475,000 of which was applied to accrued interest, and the remaining $100,000
was a loan extension payment and is being amortized over the remaining term of
the loan. In return, RRPV extended the maturity date of the note from March 9,
2003, to December 31, 2003. The Company also agreed to pay 40% of the gross
proceeds of any subsequent equity or debt offering concluded prior to the
amended maturity date to RRPV, and agreed to assign its rights to payments under
the CalEnergy Gas (Holdings), Ltd. agreement to RRPV, except for those amounts
related to drilling the two wells. All such payments will be used to offset the
remaining principal and interest. In exchange for these payments, RRPV agreed to
release its lien on interests earned by CalEnergy Gas under its agreement with
the Company.
9
The loan amendment contained other terms and conditions, including an
increase in the interest rate on the note from 9.5% to 12% per annum effective
March 9, 2003. The time period during which RRPV can convert the principal
amount of the note into shares of common stock was extended to December 31,
2003, with the conversion price being changed from $5.00 per share to $3.42 per
share, the market price of the Company's stock when RRPV agreed to extend the
payment date. In accordance with APB 14 "Accounting for Convertible Debt and
Debt Issued with Stock Purchase Warrants," no charge to income will be recorded
as a result of the reduction in conversion price as the new conversion price
does not result in any intrinsic value.
Note 4: Net Income (Loss) Per Share
Basic earnings per share is computed by dividing the net income (loss)
by the weighted average number of common shares outstanding. Diluted earnings
per share is computed by dividing the net income (loss) by the sum of the
weighted average number of common shares and the effect of dilutive unexercised
stock options and warrants and convertible preferred stock. Options to purchase
4,431,017 and 5,885,167 shares of common stock at prices ranging from $1.50 to
$10.25 per share with a weighted average price of $5.52 per share and at $4.87
per share were outstanding at June 30, 2003 and 2002, respectively. In addition,
the preferred stock (see Note 2) is convertible into 2,250,000 shares of common
stock upon registration, at which time an additional 2,250,000 warrants to
purchase common stock at $3.60 per share will be issued. No preferred stock,
options or warrants were included in the computation of diluted net loss per
share for the periods ended June 30, 2003 and 2002, because the effect would
have been antidilutive.
Note 5: Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board, or FASB,
issued Statement No. 143 (SFAS 143), "Accounting for Asset Retirement
Obligations." The Company adopted SFAS 143 beginning January 1, 2003. The most
significant impact of this standard on the Company was a change in the method of
accruing for site restoration costs. Under SFAS 143, the fair value of asset
retirement obligations is recorded as a liability when incurred, which is
typically at the time the assets are placed in service. Amounts recorded for the
related assets are increased by the amount of these obligations. Over time, the
liabilities are accreted for the change in their present value and the initial
capitalized costs are depreciated over the useful lives of the related assets.
The Company used an expected cash flow approach to estimate its asset
retirement obligations under SFAS 143. Upon adoption, the Company recorded a
retirement obligation of $345,000, an increase in property and equipment cost of
$1,535,000, a decrease in accumulated depreciation, depletion and amortization
of $609,000 and a cumulative effect of change in accounting principle, net of $0
tax, of $1,799,000. As a result of adoption of SFAS 143, the Company estimates
that accretion expense will be approximately $37,000 in 2003. For the three- and
six-month periods ended June 30, 2003, the effect of adopting SFAS 143 increased
expenses $9,286 and $18,572 or $0.00 and $0.00 per basic share, respectively.
At January 1, 2003, there are no assets legally restricted for purposes
of settling asset retirement obligations. There was no impact on the Company's
cash flows as a result of adopting SFAS 143 because the cumulative effect of
change in accounting principle is a noncash transaction.
10
The Company's estimated asset retirement obligation liability at
January 1, 2002, was approximately $322,000.
Following is a reconciliation of the asset retirement obligation from
December 31, 2002, to June 30, 2003.
Asset retirement obligation as of December 31, 2002....... $ --
Obligation arising from cumulative effect of change
in accounting principle................................. 345,551
Liabilities settled....................................... --
Accretion expense......................................... 18,572
----------
Asset retirement obligation as of June 30, 2003........... $ 364,123
==========
Note 6: Income Taxes
FX Energy recognized no income tax benefit from the net loss generated
in the first half of 2003 and the first half of 2002.
Note 7: Business Segments
FX Energy operates within two segments of the oil and gas industry: the
exploration and production segment ("E&P") and the oilfield services segment.
Identifiable net property and equipment are reported by business segment for
management reporting and reportable business segment disclosure purposes.
Current assets, other assets, current liabilities and long-term debt are not
allocated to business segments for management reporting or business segment
disclosure purposes. Reportable business segment information for the three
months ended June 30, 2003, the six months ended June 30, 2003, and as of June
30, 2003, excluding the cumulative effect of change in accounting principle,
follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended June 30, 2003:
Revenues(1)...................................... $ 506,575 $ 23,200 $ -- $ 529,775
Net loss(2)...................................... (202,242) (105,729) (798,105) (1,106,076)
Six months ended June 30, 2003:
Revenues(3)...................................... 1,118,518 32,528 -- 1,151,046
Net loss(4)...................................... (50,079) (243,924) (1,519,818) (1,813,821)
As of June 30, 2003:
Identifiable net property and equipment(5)....... 5,204,824 655,969 90,528 5,951,321
- ------------------
(1) All E&P revenues were generated in the United States.
(2) Nonsegmented items include $556,372 of general and administrative costs,
$240,347 of other income and expense, and $1,386 of corporate DD&A.
(3) All E&P revenues were generated in the United States.
(4) Nonsegmented items include $1,053,888 of general and administrative costs,
$460,542 of other income and expense, and $5,388 of corporate DD&A.
(5) Nonsegmented items include $90,528 of corporate office equipment, hardware
and software.
11
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.
Note 8: Stock-Based Compensation
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board ("APB") Opinion
No. 25 and related interpretations. Nonemployee stock-based compensation is
accounted for using the fair value method in accordance with SFAS No. 123,
"Accounting for Stock-based Compensation."
On December 31, 2002, the FASB issued Statement No. 148, "Accounting
for Stock Based Compensation Transition and Disclosure" (SFAS 148), which amends
SFAS No. 123. SFAS 148 requires more prominent and frequent disclosures about
the effects of stock-based compensation. The Company adopted SFAS 148 for the
year ended December 31, 2002. The Company will continue to account for its
stock-based compensation according to the provisions of APB Opinion No. 25.
12
Had compensation cost for the Company's stock options been recognized
based on the estimated fair value on the grant date under the fair value
methodology prescribed by SFAS No. 123, the Company's net earnings and earnings
per share for the periods ended June 30, 2003 and 2002, would have been as
follows:
(in thousands, except for per share data) For the three months ended For the six months ended
June 30, June 30,
---------------------------- ----------------------------
2003 2002 2003 2002
------------- ------------- ------------- -------------
Net income (loss):
Net income (loss), as reported........................ $ (1,106) $ (870) $ (14) $ (1,888)
Less: Total stock-based employee compensation
expense determined under the fair value based
method for all awards................................ (207) (283) (413) (566)
---------- ---------- ---------- --------
Pro forma net income (loss)...................... $ (1,313) $ (1,153) $ (427) $ (2,454)
========== ========== ========== ========
Basic and diluted net income (loss) per share:
As reported...................................... $ (0.06) $ (0.05) $ 0.00 $ (0.11)
Pro forma........................................ (0.07) $ (0.07) $ (0.02) (0.14)
Note 9: Intangible Leaseholds Costs
Statement of Financial Accounting Standards No. 141, Business
Combinations (FAS 141) and Statement of Financial Accounting Standards, No. 142,
Goodwill and Intangible Assets (FAS 142) were issued by the Financial Accounting
Standards Board (FASB) in June 2001 and became effective for the Company on July
1, 2001, and January 1, 2002, respectively. FAS 141 requires all business
combinations initiated after June 30, 2001, to be accounted for using the
purchase method. Additionally, FAS 141 requires companies to disaggregate and
report separately from goodwill certain intangible assets. FAS 142 establishes
new guidelines for accounting for goodwill and other intangible assets. Under
FAS 142, goodwill and certain other intangible assets are not amortized, but
rather are reviewed annually for impairment.
One interpretation being considered relative to these standards is that
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds should be classified separately from oil and gas
properties, as intangible assets on the Company's balance sheets. In addition,
the disclosures required by FAS 141 and 142 relative to intangibles would be
included in the notes to financial statements. Historically, FX Energy, like
many other oil and gas companies, has included these oil and gas mineral rights
held under lease and other contractual arrangements representing the right to
extract such reserves as part of the oil and gas properties, even after FAS 141
and 142 became effective.
This interpretation of FAS 141 and 142 described above would only
affect the Company's balance sheet classification of oil and gas leaseholds. The
Company's results of operations and cash flows would not be affected, since
these oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves would continue to
be amortized in accordance with accounting rules for oil and gas companies
provided in Statement of Financial Accounting Standards No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies (FAS 19).
13
At December 31, 2002, the Company had undeveloped leaseholds of
approximately $147,000 that would be classified under that interpretation on its
balance sheet as "intangible undeveloped leasehold" and developed leaseholds of
an estimated $7,000 that would be classified under that interpretation as
"intangible developed leaseholds" if the Company applied the interpretation
currently being considered.
The Company will continue to classify its oil and gas mineral rights
held under lease and other contractual rights representing the right to extract
such reserves as tangible oil and gas properties until further interpretative
guidance is provided.
Note 10: Subsequent Event
Subsequent to June 30, 2003, the Company received net proceeds of
approximately $8.8 million from the sale of 3,265,137 shares of common stock and
five-year warrants to purchase at $3.75 per share an aggregate of 3,265,137
additional shares. Net proceeds from this placement are allocated toward paying
obligations due Polish Oil and Gas Company and RRPV on December 31, 2003,
geological and geophysical costs, general and administrative and project
marketing costs, and the Company's share of further exploration and possible
production facilities.
Note 11: Restatement
In October 2003, the Company determined that it needed to correct the
accounting treatment for certain loans made to officers in 1998. These loans
were made to facilitate the exercise of stock options by these officers and were
collateralized by 233,340 shares of Company stock owned by the officers. The
Company previously accounted for these loans in accordance with SFAS No. 114,
"Accounting by Creditors for Impairment of a Loan" and recognized impairment
charges in 1999 and 2000 based on the market value of the collateral shares. The
Company also recognized interest income on the loans. In December 2000, the
officers transferred the collateral shares to the Company and the adjusted loan
balance was recorded as treasury stock. The Company has determined that the
officer loans should have been accounted for as a deemed purchase of treasury
stock and the granting of a variable stock option in accordance with EITF 95-16,
"Accounting for Stock Compensation Arrangements with Employer Loan Features
under APB Opinion No. 25." Under variable stock option accounting, the Company
would have recognized increases or decreases in compensation expense based on
the market value of the Company's stock. In addition, the Company would not have
recorded interest income on the loans or the impairment charges related to the
loans. Because a portion of the shares deemed to have been purchased were
acquired through the exercise of stock options and had not been owned for at
least six months, the Company also would have recored a compensation charge of
$90,000 related to those shares, reflecting the difference between the purchase
price and the original option exercise price for those shares.
The following sets forth the effects of the restatement to the
Company's consolidated balance sheets at December 31, 2002, and June 30, 2003.
No income statement amounts subsequent to December 31, 2000, were affected by
the restatement:
December 31, 2002
Stockholders' deficit
As Reported As Restated
------------ -------------
Common stock $ 17,652 $ 17,652
Additional paid in capital 49,049,025 48,075,035
Accumulated deficit (53,935,256) (52,961,266)
------------ -------------
Total stockholders' deficit $ (4,868,579) $ (4,868,579)
============ =============
June 30, 2003
Stockholders' equity
As Reported As Restated
------------ -------------
Common stock $ 17,715 $ 17,715
Preferred stock 2,250 2,250
Additional paid in capital 54,831,499 53,857,509
Accumulated deficit (53,949,575) (52,975,585)
------------ -------------
Total stockholders' equity $ 901,889 $ 901,889
============ =============
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, 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, and other costs, which are not allocated to
individual operating segments for management or segment reporting purposes, are
discussed in their entirety following the segment discussion. A comparison of
the results of operations by business segment and the information regarding
nonsegmented items for the three months ended June 30, 2003 and 2002, follows.
Comparison of the Second Quarter of 2003 to the Second Quarter of 2002
Exploration and Production
Our oil and gas revenues are comprised of oil production in the United
States in 2003 and 2002 and gas production in Poland only in 2002. A summary of
the percentage change in oil and gas revenues, average price and production
volumes for the second quarter of 2003 and 2002 is set forth in the following
table:
Quarter Ended June 30,
--------------------------------------------------------------
Oil Gas
------------------------------ -------------------------------
2003 2002 2003 2002
-------------- -------------- --------------- ---------------
Revenues............................................. $ 507,000 $ 498,000 $ -- $ 71,000
Percent change versus prior year's quarter....... +2% -100%
Average price (per barrel of oil or
thousand cubic feet of natural gas)................ $ 23.81 $ 21.56 $ -- $ 1.58(1)
Percent change versus prior year's quarter....... +10% -100%
Production volumes (barrels of oil or
thousand cubic feet of natural gas)................ 21,286 23,110 -- 44,652
Percent change versus prior year's quarter....... -8% -100%
- -------------------
(1) The contract price prior to adjusting for British thermal unit content was
$2.02 per thousand cubic feet of natural gas.
Oil Revenues. Oil revenues were $507,000 during the second quarter of
2003, a 2% increase compared to the same period of 2002. During the second
quarter of 2003, our average oil prices rose 10%, from $21.56 per barrel in 2002
to $23.81 per barrel in 2003, while oil production quantities declined by 8%.
Oil revenues in 2003 increased from 2002 levels by approximately $48,000 due to
higher oil prices, offset by approximately $39,000 related to production
declines.
Gas Revenues. Gas revenues were $0 during the second quarter of 2003,
compared to $71,000 in gas revenues during the same period of 2002. As part of
our Fences I settlement with the Polish Oil and Gas Company, or POGC, in early
2003, we agreed to assign our interest in the Kleka well, along with the related
accounts receivable amount, to POGC as soon as possible in 2003 in order to
conserve cash while reducing the balance of our liability due to POGC.
Accordingly, we have stopped recording gas sales in 2003. Gas volumes in the
second quarter of 2002 reflected a full quarter of production during 2002 from
the Kleka 11, our first producing well in Poland, which began producing in late
February 2001.
15
Lease Operating Costs. Lease operating costs were $396,000 during the
second quarter of 2003, an increase of $58,000, or 17%, compared to the same
period of 2002. The increase was due primarily to workover expenses and higher
third-party maintenance activities incurred during the second quarter of this
year. Lease operating costs incurred during the second quarter of 2003 include
no costs associated with the Kleka 11, while lease operating costs at the Kleka
11 well averaged approximately $0.16 per thousand cubic feet of gas in the prior
year. Our 2003 operating costs increased approximately $93,000 due to higher
lifting costs and $4,000 due to higher production taxes, offset by approximately
$39,000 related to lower oil production.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$224,000 during the second quarter of 2003, compared to $175,000 during the same
period of 2002, an increase of 28%. Limited available capital in 2002 caused us
to sharply curtail our exploration activities in Poland that year.
DD&A Expense - E&P. DD&A expense for producing properties was $79,000
during the second quarter of 2003, an increase of $10,000 compared to $69,000
during the same period of 2002. Because of our agreement to convey to POGC our
interest in the Kleka 11 well, we incurred no DD&A expense associated with the
Kleka 11 during the second quarter of 2003, while we incurred $50,000 in Kleka
11 related DD&A expense during the same quarter of 2002. The increase from year
to year is due primarily to the net book value of domestic assets being
increased as a result of the adoption of SFAS 143.
Accretion Expense. Accretion expense reflects the second quarter
increase in our asset retirement obligation under SFAS 143 that we adopted on
January 1, 2003.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $23,000
during the second quarter of 2003, a decrease of 41% from $39,000 recorded
during the same period of 2002. During the second quarter of both years, the
contract drilling industry was at a virtual standstill in the area where we
operate. Oilfield services revenues will continue to fluctuate from period to
period based on market demand, weather, the number of wells drilled, downtime
for equipment repairs, the degree of emphasis on utilizing our oilfield
servicing equipment on our Company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $54,000 during
the second quarter of 2003, down from the $73,000 incurred in the same period of
2002. The bulk of the costs in both periods related to downtime maintenance
costs associated primarily with our drilling rig. Oilfield services costs will
also continue to fluctuate year to year based on revenues generated, market
demand, weather, the number of wells drilled, downtime for equipment repairs,
the degree of emphasis on utilizing our oilfield servicing equipment on our
Company-owned properties, and other factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $75,000 during the second quarter of 2003, a decrease of $20,000 compared to
$95,000 during the same period of 2002, primarily due to some older assets
becoming fully depreciated before the end of the second quarter of 2003.
16
Nonsegmented Information
G&A Costs. G&A costs were $556,000 during the second quarter of 2003, a
10% decrease from the $621,000 recorded for the same period of 2002, primarily
due to a 50% reduction in executive salaries that was instituted on July 1,
2002. This approximately $98,000 reduction was partially offset by $22,000 in
higher consulting and legal fees associated with the Company's ongoing efforts
to obtain industry participants in its Fences projects.
Interest and Other Income. Interest and other income was negligible
during both the second quarter of 2003 and 2002.
Interest Expense. Interest expense was $240,000 during the second
quarter of 2003, compared to $119,000 during the same period of 2002. We began
accruing interest on our POGC obligation in the fourth quarter of 2002. In
addition, the interest rate on our RRPV obligation was increased from 9.5% to
12% as of March 9, 2003.
Comparison of the First Half of 2003 to the First Half of 2002
Exploration and Production
Our oil and gas revenues are comprised of oil production in the United
States during 2003 and 2002 and gas production in Poland only in 2002. A summary
of the percentage change in oil and gas revenues, average price and production
volumes for the first half of 2003 and 2002 is set forth in the following table:
Six Months Ended June 30,
---------------------------------------------------------------
Oil Gas
----------------------------- --------------------------------
2003 2002 2003 2002
--------------- ------------- --------------- ---------------
Revenues............................................ $1,119,000 $ 852,000 $ -- $ 163,000
Percent change versus prior year's quarter...... 31% -100%
Average price (per barrel of oil or
thousand cubic feet of natural gas)............... $ 26.51 $ 18.61 $ -- $ 1.58(1)
Percent change versus prior year's quarter...... 42% -100%
Production volumes (barrels of oil or
thousand cubic feet of natural gas)............... 42,186 45,772 -- 102,902
Percent change versus prior year's quarter...... -8% -100%
- ----------------------
(1) The contract price prior to adjusting for British thermal unit content was
$2.02 per thousand cubic feet of natural gas.
Oil Revenues. Oil revenues were $1,119,000 during the first half of
2003, a 31% increase compared to the same period of 2002. During the first half
of 2003, our average oil prices were 42% higher than in the same period of the
prior year, while oil production quantities declined by 8%. Oil revenues in 2003
increased from 2002 levels by approximately $333,000 due to higher oil prices,
offset by approximately $66,000 related to production declines.
Gas Revenues. Gas revenues were $0 during the first half of 2003, down
100% from the same period of 2002. As part of our Fences I settlement with POGC,
in early 2003, we agreed to assign our interest in the Kleka 11 well, along with
the related accounts receivable amount, to POGC as soon as possible in 2003 in
order to conserve cash while reducing the balance of our liability to POGC.
Accordingly, we have stopped recording gas sales in 2003.
17
Lease Operating Costs. Lease operating costs were $757,000 during the
first half of 2003, an increase of 10% compared to $690,000 during the same
period of 2002. The increase was due primarily to workover expenses and higher
third-party maintenance activities incurred during the first 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 thousand cubic feet of natural
gas produced, associated solely with the Kleka 11 well, while Kleka operating
costs during the same period of 2003 were $0. Our 2003 operating costs increased
approximately $133,000 due to higher lifting costs and $3,000 due to higher
production taxes, offset by approximately $69,000 related to lower oil
production and gas production.
Exploration Costs. Our exploration costs consist of geological and
geophysical costs and the costs of exploratory dry holes. Exploration costs were
$291,000 during the first half of 2003, a decrease of 4% compared to $302,000
during the same period of 2002.
DD&A Expense - E&P. DD&A expense for producing properties was $102,000
during the first half of 2003, a decrease of $58,000 compared to $160,000 during
the same period of 2002. 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 2003 was $0. The Kleka decrease
was partially offset by higher DD&A charges at our domestic properties, due to
the net book value of those assets being increased as a result of the adoption
of SFAS 143.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $33,000
during the first half of 2003, a decrease of 23% from $43,000 recorded during
the same period of 2002. During the first half of both years, the contract
drilling industry was at a virtual standstill in the area where we operate.
Oilfield services revenues will continue to fluctuate from period to period
based on market demand, weather, the number of wells drilled, downtime for
equipment repairs, the degree of emphasis on utilizing our oilfield servicing
equipment on our Company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $129,000 during
the first half of 2003, down from the $186,000 incurred in the same period of
2002. In general, oilfield services costs are directly associated with oilfield
services revenues. The bulk of the costs in 2003 relates to downtime maintenance
costs associated primarily with our drilling rig. Oilfield services costs will
also continue to fluctuate year to year based on revenues generated, market
demand, weather, the number of wells drilled, downtime for equipment repairs,
the degree of emphasis on utilizing our oilfield servicing equipment on our
Company-owned properties, and other factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $148,000 during the first half of 2003, an increase of $3,000 compared to
$145,000 during the same period 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 $0 during
the same period of 2003. On April 5, 2001, we extended the term of options to
purchase 125,000 shares of the Company's common stock that were to expire during
2001 for a period of two years, with a one-year vesting period. On August 4,
2000, we extended the term of options and warrants to purchase 678,000 shares of
our common stock that were to expire during 2000 for a period of two years, with
a one-year vesting period. In accordance with FIN 44 "Accounting for Certain
Transactions Involving Stock Compensation," we incurred total noncash deferred
compensation costs of $1.8 million associated with the option extensions, to be
amortized over their respective one-year vesting periods from the date of
extension. The deferred compensation associated with these transactions was
fully amortized as of June 30, 2002.
18
G&A Costs. G&A costs were $1,054,000 during the first half of 2003, a
16% decrease from the $1,259,000 recorded for the same period of 2002, primarily
due to a 50% reduction in executive salaries that was instituted on July 1,
2002. This approximately $199,000 reduction in executive salaries was partially
offset by $89,000 in higher consulting and legal fees associated with the
Company's ongoing efforts to obtain industry participants in its Fences
projects.
Interest and Other Income. We recorded $9,000 in interest and other
income during the first half of 2003, compared to $105,000 during the first half
of 2002. The bulk of other income in 2002 was related to the amortization of an
option premium that resulted from granting RRPV an option to purchase gas from
our properties in Poland.
Interest Expense. Interest expense was $470,000 during the first half
of 2003, compared to $242,000 during the same period of 2002. We began accruing
interest on our POGC obligation in the fourth quarter of 2002. In addition, the
interest rate on our RRPV obligation was increased from 9.5% to 12% as of March
9, 2003.
Liquidity and Capital Resources
With insufficient revenues to cover our operating expenses and to fund
further exploration, our greatest uncertainty is our shortage of capital and our
dependence on obtaining substantial amounts of external funding through the sale
of securities or an interest in our exploration projects in Poland. Our ability
to obtain such required funding is, to a substantial extent, dependent on the
interest of the securities markets and oil and gas industry generally in
international oil and gas exploration. Although we believe that there appears to
be growing securities markets and industry interest in financing international
oil and gas exploration, there is no assurance that this will enable us to
obtain the financing we require on acceptable terms or that such perceived
trend, if we accurately perceive it, may not become less favorable.
General. As of June 30, 2003, we had approximately $3.0 million of cash
and cash equivalents and negative working capital of approximately $5.0 million,
coupled with a history of operating losses. These matters raise doubt about our
ability to continue as a going concern. The negative working capital results
from an accrued liability to POGC, including accrued interest, of approximately
$4.6 million at June 30, 2003, and the current portion of our note payable to
RRPV of approximately $3.3 million. In addition, at June 30, 2003 we have a
remaining work commitment of $5.4 million that must be satisfied in order to
earn a 49.0% interest in our Fences I project area.
Subsequent to June 30, 2003, we received proceeds of approximately $8.8
million, net of placement costs, from the sale of 3,265,137 shares of common
stock and five-year warrants to purchase at $3.75 per share an aggregate of
3,265,137 additional shares. If, as we anticipate, CalEnergy Gas earns a 24.5%
interest in the Fences I project area, thereby reducing our retained interest to
24.5%, CalEnergy Gas's $10.6 million earn-in will satisfy the balance of our
$5.4 million work commitment to POGC in the Fences I project area and provide
cash for our other commitments, which will further improve our financial
outlook.
To date, we have financed our operations principally through the sale
of equity securities, issuance of debt securities and agreements with industry
participants that funded our share of costs in certain exploratory activities in
order to earn an interest in our properties. We recently received approximately
$8.8 million in net proceeds from the sale of securities (see Note 10). However,
the continuation of our exploratory efforts in Poland is dependent on raising
additional capital or on arranging industry funding for such exploration, and
19
our efforts have and continue to be concentrated on both of these aspects. The
availability of such capital will affect the timing, pace, scope and amount of
our future capital expenditures. We cannot assure that we will be able to obtain
additional financing, reduce expenses or successfully complete other steps to
continue as a going concern. If we are unable to obtain sufficient funds to
satisfy our future cash requirements, we may be forced to curtail operations,
dispose of assets or seek extended payment terms from our vendors. Such events
would materially and adversely affect our financial position and results of
operations.
Working Capital (current assets less current liabilities). Our working
capital deficit was $5,045,000 as of June 30, 2003, a decrease of $4,105,000
from our working capital deficit at December 31, 2002, of $9,150,000,
principally as a result of the private placement of preferred stock discussed
earlier, but without giving effect to the receipt of net proceeds from the sale
of securities subsequent to June 30, 2003. Our current liabilities include $4.6
million of costs related to our Fences I project in Poland and $3.3 million note
payable to RRPV, which has a current maturity date of December 31, 2003.
Operating Activities. Net cash used in operating activities was
$1,421,000 during the first half of 2003, a decrease of $298,000 compared to
$1,719,000 in net cash used during the same period of 2002. This reduction in
cash used is a direct reflection of our curtailed exploration activities and
lower geological and geophysical costs in Poland, as well as lower employee
costs.
Investing Activities. We spent $140,000 in investing activities during
the first half of 2003, primarily related to our proved properties and oilfield
equipment in the United States. In 2002, we spent $118,000 in investing
activities during the first half of 2002, also related to our proved properties
and oilfield equipment in the United States.
Financing Activities. During the first half of 2003, we completed a
private placement of convertible preferred stock resulting in proceeds after
offering costs of approximately $5,594,000. We used $1,675,000 of the proceeds
to pay down our RRPV note and incurred loan fees relating to our new agreement
with RRPV of $100,000. We received no cash from financing activities during the
first half of 2002.
Other Items
The Company has reviewed all other recently issued, but not yet
adopted, accounting standards in order to determine their effects, if any, on
the results of operations or financial position of the Company. Based on that
review, the Company believes that none of these pronouncements will have a
significant effect on current or future financial position or results of
operations.
20
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, 2002. We believe the application of these
accounting policies on a consistent basis enables us to provide financial
statement users with useful, reliable and timely information about our earnings
results, financial condition and cash flows.
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, the retirement obligations associated with those assets,
and the estimates of oil and gas reserves.
Forward Looking Statements
This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "could," "should,"
"expect," "anticipate," "estimate," "project," "propose," "plan," "intend" and
similar words and expressions. We intend that the forward-looking statements
will be covered by the safe harbor provisions for forward-looking statements
contained in Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Statements that describe our future strategic
plans, goals or objectives are also forward-looking statements.
Readers of this report are cautioned that any forward-looking
statements, including those regarding us or our management's current beliefs,
expectations, anticipations, estimations, projections, proposals, plans or
intentions, are not guarantees of future performance or results of events and
involve risks and uncertainties, such as the future results of drilling
individual wells and other exploration and development activities; future
variations in well performance as compared to initial test data; future events
that may result in the need for additional capital; the prices at which we may
be able to sell oil or gas; fluctuations in prevailing prices for oil and gas;
uncertainties of certain terms to be determined in the future relating to our
oil and gas interests, including exploitation fees, royalty rates and other
matters; future drilling and other exploration schedules and sequences for
various wells and other activities; uncertainties regarding future political,
economic, regulatory, fiscal, taxation and other policies in Poland; the cost of
additional capital that we may require and possible related restrictions on our
future operating or financing flexibility; our future ability to attract
strategic participants to share the costs of exploration, exploitation,
development and acquisition activities; and future plans and the financial and
technical resources of strategic participants.
21
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.
22
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 31 Rule 13a-14(a)/15d14(a) Certifications
- --------------------------------------------------------------------------------------------------------------------
31.01 31 Certification of Chief Executive Officer Pursuant to Rule 13a-14 Attached
31.02 31 Certification of Chief Financial Officer Pursuant to Rule 13a-14 Attached
Item 32 Section 1350 Certifications
- --------------------------------------------------------------------------------------------------------------------
32.01 32 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Attached
Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
32.02 32 Certification of Chief Financial Officer Pursuant to 18 U.S.C. Attached
Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(b) Reports on Form 8-K
During the quarter ended June 30, 2003, FX Energy filed the following
report on Form 8-K:
Date of Event Reported Item(s) Reported
---------------------- ----------------
April 22, 2003 Item 5. Other Events
23
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this amended report to be signed on its behalf by the
undersigned, thereunto duly authorized.
FX ENERGY, INC.
(Registrant)
Date: October 8, 2003 By /s/ David N. Pierce
---------------------------
David N. Pierce, President,
Chief Executive Officer
Date: October 8, 2003 By /s/ Thomas B. Lovejoy
---------------------------
Chief Financial Officer
24