ITEM 3. LEGAL PROCEEDINGS - --------------------------------------------------------------------------------
We are not a party to any material legal proceedings, and no material legal proceedings have been threatened by us or, to the best of our knowledge, against us.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - --------------------------------------------------------------------------------
No matter was submitted to a vote of our security holders during the fourth quarter of the fiscal year ended December 31, 2003.
PART II
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS - --------------------------------------------------------------------------------
Price Range of Common Stock and Dividend Policy
The following table sets forth for the periods indicated the high and low closing prices for our common stock as quoted under the symbol "FXEN" on the Nasdaq SmallCap Market since April 2002 and on the Nasdaq National Market previously:
Low High 2004: First Quarter (through March 9, 2004).......... $4.55 $12.45
2003: Fourth Quarter................................. 3.20 5.52 Third Quarter.................................. 2.84 3.30 Second Quarter................................. 2.81 3.36 First Quarter.................................. 2.60 3.54
2002: Fourth Quarter................................. 2.24 3.04 Third Quarter.................................. 1.83 2.99 Second Quarter................................. 1.99 2.98 First Quarter.................................. 1.97 3.01
We have never paid cash dividends on our common stock and do not anticipate that we will pay dividends in the foreseeable future. We intend to reinvest any future earnings to further expand our business. We estimate that, as of February 27, 2004, we had approximately 4,200 stockholders.
Our common stock is currently traded on the Nasdaq SmallCap Market under the symbol FXEN.
Recent Sales of Unregistered Securities
In November 2003, we received net proceeds of approximately $1.9 million from the sale of 726,173 Units, each Unit consisting of one share of common stock and a five-year warrant to purchase one share of common stock at $3.75 per share, an aggregate of 1,452,346 additional shares. These Units were sold in a private placement of securities to five unaffiliated purchasers pursuant to antidilution provisions of our March 2003 private placement of 2003 Series Convertible Preferred Stock and to one officer.
In December 2003, we sold 2,362,051 shares of common stock in a private placement of securities to 17 unaffiliated purchasers, raising a total of $9.1 million (net of offering costs of $600,000). The offering was placed privately, primarily through CDC Securities, Inc., and included unaffiliated purchasers pursuant to antidilutive provisions of our March 2003 private placement of 2003 Series Convertible Preferred Stock.
Net proceeds from these placements will be used to pay geological and geophysical costs, general and administrative and project marketing costs, and our share of further exploration and possible production facilities.
Each of the purchasers in each transaction was an accredited investor who was provided with a private placement memorandum detailing our business and financial information, including copies of our periodic reports as filed with the Securities and Exchange Commission, and who was provided with the opportunity to ask questions directly of our executive officers.
In each of the above transactions, the securities purchased were restricted securities taken for investment. Certificates for all shares issued in the such transactions bore a restrictive legend conspicuously on their face and stop-transfer instructions were noted respecting such certificates on our stock transfer records. Each of the foregoing transactions was effected in reliance on the exemption from registration provided in Section 4(2) of the Securities Act of 1933 as transactions not involving any public offering.
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ITEM 6. SELECTED FINANCIAL DATA - --------------------------------------------------------------------------------
The following selected financial data for the five years ended December 31, 2003, are derived from our audited financial statements and notes thereto, certain of which are included in this report. The selected financial data should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations, and our Consolidated Financial Statements and the Notes thereto included elsewhere in this report:
- Continued -
(1) Includes lease operating expenses and production taxes. (2) Includes geophysical and geological costs, exploratory dry hole costs and nonproducing leasehold impairments. (3) Includes proved property write downs relating to our properties in the United States and Poland.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - --------------------------------------------------------------------------------
The following discussion of our historical financial condition and results of operations should be read in conjunction with Item 6. "Selected Consolidated Financial Data," our Consolidated Financial Statements and related Notes contained in this report.
Introduction
2003 was an important year for FX Energy. At the beginning of the year, we were in a tenuous financial situation, with negative working capital of $9.2 million and $700,000 in cash. There was doubt about our ability to continue as a going concern. During the year, we made considerable progress in improving our financial condition. Through private placements of common and preferred stock, we raised $25.4 million (net of offering costs). In addition, we converted $3.6 million of outstanding debt and accrued interest payable into common stock. We also used proceeds from our equity offerings to make payments on our outstanding obligations to POGC. At the end of the year, we had cash of approximately $17.0 million, with working capital of $16.0 million.
We were also successful in 2003 in launching our exploration program in the Fences I and II prospect areas. We entered into a farmout agreement with CalEnergy Gas, and in October 2003 with POGC and CalEnergy Gas began drilling
the Zaniemysl-3 well in the Fences I area. We announced early in 2004 that the well encountered approximately 38 net meters (125 feet) of porous gas-bearing Rotliegendes sandstone. During a drill stem test of the top 18 meters of the structure, the well flowed at a controlled rate of approximately 12.5 million cubic feet of gas per day. Together with our partners, POGC and CalEnergy Gas, we are evaluating how to best produce and exploit the Zaniemysl field. For further discussion concerning the Zaniemysl-3 well and the Fences I and II areas, see Exploration, Development and Production Activities in Poland.
In early 2003, we also announced the creation of our Technical and Advisory Panel, consisting of three individuals with extensive experience in international oil and gas exploration and investment banking, including extensive experience and success in the Southern North Sea. We believe that the addition of these individuals to our technical team greatly enhanced our exploration expertise and our ability to attract capital.
We believe that we are now well positioned to carry out our exploration plans in Poland. We believe that we have enough capital to drill at least four additional wells in the Fences I and II areas during 2004, without selling or farming out any of our working interests, in addition to funding increased levels of geological and geophysical costs and ongoing administrative expenses.
Following is a brief discussion concerning some the significant events that occurred during 2003:
Private Placements of Common and Convertible Preferred Stock
In March 2003, we sold 2,250,000 shares of 2003 Series Convertible Preferred Stock in a private placement of securities, raising a total of $5,593,871 after offering costs of $31,129. Each share of preferred stock immediately converted into one share of common stock and one warrant to purchase one share of common stock at $3.60 per share upon registration of the common shares. The warrants to purchase common stock are exercisable anytime between March 1, 2004, and March 1, 2008, and entitle the holders, for a period of 10 days following any new issuances of equity securities or securities convertible or exercisable into equity securities in other than a public offering, to preserve their approximate 16.3% ownership subsequent to this offering by purchasing such new securities issued on the same terms as issued to others. The preferred stock had a liquidation preference equal to the sales price for the shares, which was $2.50 per share. The 2,250,000 shares of 2003 Series Convertible Preferred Stock were converted to our common stock on a one-for-one basis on October 27, 2003, pursuant to a registration statement that became effective on that date.
Between the months of July and November, 2003, we sold 3,991,310 Units, consisting of one share of common stock and one warrant to purchase one share of common stock at $3.75 per share, raising a total of $10,734,672 after offering costs of $41,685. The warrants to purchase common stock are exercisable one year after closing and expire between July 22, 2008, and November 4, 2008.
In December 2003, we placed privately 2,362,051 shares of common stock, raising a total of $9,137,021 after offering costs of $571,009. Approximately $6.5 million of the net proceeds came from several European investors including banks, mutual funds, life insurance companies and pension funds located in Germany, Austria, Belgium and Spain. This is the first significant investment in the Company by investors in the European financial community, and we are hopeful that this placement will create additional interest from other European investors.
The net proceeds from the 2003 offerings were used to reduce the note payable to Rolls-Royce Power Ventures Limited, or RRPV, to reduce the accrued liability to the Polish Oil and Gas Company, and will be used to fund ongoing geological, geophysical and drilling costs in Poland, and support ongoing prospect marketing and general and administrative costs.
Rolls-Royce Power Ventures
In March 2003, following the private placement of convertible preferred stock, we paid $2.3 million to RRPV, which included $1.7 million in principal, $500,000 in accrued interest, and a $100,000 loan extension fee. In return, RRPV amended the loan agreement to extend the maturity date of the note to December 31, 2003. We agreed to pay 40% of the gross proceeds of any subsequent equity or debt offering concluded prior to the amended maturity date, up to the amount still owing under the loan agreement to RRPV, and also agreed to assign our
rights to payments under the CalEnergy Gas agreement to RRPV, except for those amounts relating to two wells required to be drilled under the agreement. All such payments would be used to offset the remaining principal and interest.
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, an extension of the conversion period until December 31, 2003, with the conversion price being changed from $5.00 per share to $3.42 per share, the market price of our stock when RRPV agreed to extend the payment date, and an extension fee payment of $100,000.
In September 2003, we placed the then outstanding $3.3 million principal balance of the note into an escrow account in favor of RRPV. In turn, the interest rate on the loan was reduced to 9% per annum. In December 2003, RRPV exercised its right to convert the outstanding principal balance and accrued interest into 972,222 shares of common stock. RRPV released to us the escrowed funds and subsequently released all outstanding liens and other collateral secured by the note to us. Consequently, we have fully satisfied and discharged all of our obligations to RRPV.
CalEnergy Gas Agreement
In January 2003, we signed a farmout agreement with CalEnergy Gas (Holdings) Ltd., an affiliate of MidAmerican Energy Holdings Company, for the joint exploration of our Fences I project in Poland. Under the terms of the agreement, CalEnergy Gas had the right, but not the obligation, to pay 100% of the costs to drill an initial well, and by so doing, earn a 24.5% interest (50% of our 49% interest) in that drilling prospect. Following the completion of the initial well, CalEnergy Gas could elect to terminate the agreement or to drill a second well. If CalEnergy Gas elected to drill a second well, it would be obligated to pay us $1 million prior to drilling. CalEnergy Gas would also have been obligated to pay 100% of the costs of drilling a second well to earn 24.5% interest in that prospect. Following the second well, CalEnergy Gas had the option to acquire 24.5% (50% of our 49% interest) of the entire Fences project area by paying to us the sum of $10.4 million, less the costs of drilling the first two wells and less the cost of any additional geological and geophysical costs it incurred on the Fences area.
Following completion of the Zaniemysl-3 well in early 2004, CalEnergy Gas requested more than a six-month extension in which to undertake an additional technical evaluation before committing to an additional exploration well. We and POGC elected instead to proceed without delay to select a specific drillsite in the Rusocin prospect in Fences I and to proceed with drilling as soon as possible.
By virtue of the Zaniemysl-3 well, CalEnergy Gas retains a 24.5% working interest in the approximately 2,200 gross acre Zaniemysl field, but CalEnergy Gas will have no right to participate in other prospects in the Fences I area. We will continue to work with CalEnergy Gas and POGC on development of the Zaniemysl-3 discovery and surrounding opportunities that can be developed as part of a single economic unit.
All of the qualifying costs related to our 49% interest in the Fences I project area that are paid for by CalEnergy Gas will be credited against the remaining obligation under our $16.0 million earn-in agreement with POGC (see below). We believe that our outstanding obligation will be reduced by approximately $2.5 million related to the costs of the Zanymiesl-3 well. CalEnergy Gas has received consent from POGC to the transfer of one-half of our working interest according to the agreement terms.
Fences I Settlement Agreement
On April 11, 2000, we agreed to spend $16.0 million of exploration costs on the Fences I project area to earn a 49% interest. When expenditures exceed $16.0 million, POGC will be obligated to pay its 51% share of further costs. Through the end of 2001, we had paid $6.7 million towards the $16.0 million and had accrued approximately $2.7 million of additional costs pertaining to the Fences I project area.
In late 2002, as part of our discussions with POGC concerning the CalEnergy Gas agreement and the opportunity to participate with POGC in other exploration projects, we reaffirmed our intent to fulfill the $16.0 million commitment with POGC and entered into an agreement to restructure our payments to them. In connection with this agreement, and in order to clarify
uncertainties about the nature and timing of our obligation regarding the balance of our $16.0 million commitment, we agreed to recognize in 2002, and pay to POGC at a future date, an additional $2.3 million of costs related to prior exploration activities in the Fences project areas, $1.6 million of which will be credited towards the $16.0 million commitment. The 2002 amount includes $704,000 in interest costs related to our prior liabilities to POGC, $433,000 in drilling costs, $418,000 in pipeline costs, $502,000 in seismic costs, and $250,000 related to foreign exchange adjustments.
As part of our agreement, we agreed that the remaining balance under our $16.0 million commitment was $5.4 million as of January 2003. Since that time, we have incurred additional qualifying costs of approximately $100,000, reducing our outstanding commitment to approximately $5.3 million as of December 31, 2003. We expect that our outstanding commitment will be further reduced by approximately $2.5 million in costs paid by CalEnergy Gas associated with the Zaniemysl-3 well. Following the drilling of the initial test well on the Rusocin prospect, and the acquisition and reprocessing of additional seismic in the Fences I area scheduled for this year, we believe that we will have satisfied the entire $16.0 million commitment by the end of 2004.
As part of our future payments towards the $16.0 million commitment, we agreed to assign to POGC all of our rights to the Kleka 11 well, including the amounts recorded as accounts receivable for Kleka gas sales. Accordingly, at December 31, 2002, our receivable from POGC in the amount of $607,000 was offset against the POGC liability. The liability is to be further offset by the value of the remaining gas reserves associated with the Kleka well, as determined by an independent engineer. We also agreed to begin accruing interest on the past due amount to POGC. The interest rate in effect at December 31, 2002, was 12.8% per annum; the interest rate was reduced in March 2003 to 10.4%, and again to 9.8% in September 2003.
During 2003, we paid a total of $2.9 million in cash to POGC and recorded a $190,000 value added tax liability related to the Kleka gas sales in partial settlement of the outstanding liability. When we complete the assignment of the Kleka 11 well, we believe we will have satisfied this obligation in full. As of December 31, 2003, our share of the Kleka 11 well had estimated proved developed producing gas reserves with an estimated net present value, discounted at 10%, of approximately $1.1 million, as determined by an independent engineer, an amount equal to our outstanding liability to POGC. Should POGC not concur with the independent engineer's assessment of reserves, we may be required to pay additional cash to settle our remaining $1.1 million liability to POGC.
Critical Accounting Policies
Oil and Gas Activities
We follow the successful efforts method of accounting for our oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, these costs plus the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net cash flows determined on a property-by-property basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value, determined on a property-by-property basis. As a result of the foregoing, our results of operations for any particular period may not be indicative of the results that could be expected over longer periods.
Intangible Leasehold Costs
Statement of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS 141") and Statement of Financial Accounting Standards No. 142, "Goodwill and Intangible Assets" ("SFAS 142") were issued by the FASB in June 2001 and became effective for us on July 1, 2001, and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, we have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after SFAS 141 and 142 became effective.
This interpretation of SFAS 141 and 142 described above would only affect our balance sheet classification of oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies."
At both December 31, 2003 and 2002, we had undeveloped leaseholds of approximately $166,000 and $147,000, respectively, that would be classified under that interpretation on our consolidated balance sheets as "intangible undeveloped leaseholds" and developed leaseholds of approximately $7,000 in both years that would be classified under that interpretation as "intangible developed leaseholds" if we applied the interpretation currently being considered.
We will continue to classify our 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.
Oil and Gas Reserves
Engineering estimates of our oil and gas reserves are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. There are authoritative guidelines regarding the engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved." Proved reserve estimates are updated at least annually and take into account recent production and technical information about each field. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. This change is considered a change in estimate for accounting purposes and is reflected on a prospective basis in related depreciation rates.
Despite the inherent imprecision in these engineering estimates, these estimates are used in determining depreciation expense and impairment expense and in disclosing the supplemental standardized measure of discounted future net cash flows relating to proved oil and gas properties. Depreciation rates are determined based on estimated proved reserve quantities (the denominator) and capitalized costs of producing properties (the numerator). Producing properties' capitalized costs are amortized based on the units of oil or gas produced. Therefore, assuming all other variables are held constant, an increase in estimated proved reserves decreases our depreciation, depletion and amortization expense. Also, estimated reserves are often used to calculate future cash flows from our oil and gas operations, which serve as an indicator of fair value in determining whether a property is impaired or not. The larger the estimated reserves, the less likely the property is impaired.
Stock Based Compensation
We have chosen to account for stock options granted to employees and directors under the recognition and measurement principles of APB Opinion No. 25 instead of the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-based Compensation," as amended by SFAS No. 148, "Accounting for Stock-based Compensation Transition and Disclosure."
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the exploration and production segment, or E&P, and the oilfield services segment. Direct revenues and costs, including depreciation, depletion and amortization costs, or DD&A, general and administrative costs, or G&A, and other income
directly associated with their respective segments are detailed within the following discussion. DD&A, G&A, amortization of deferred compensation (G&A), interest income, other income, interest expense, impairment of notes receivable from officers 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 years ended December 31, 2003, 2002 and 2001, respectively, follows. Further information concerning our business segments can be found in Note 13, Business Segments, in the financial statements.
Exploration and Production Segment
A summary of the amount and percentage change, as compared to their respective prior year period, for oil and gas revenues, average oil and gas prices, oil and gas production volumes, and lifting costs per barrel and Mcf for the years ended December 31, 2003, 2002 and 2001, is set forth in the following table:
(1) The contract price for gas during 2002 and 2001 was $2.02 per MMBtu; the produced gas averaged 0.8 MMBtu per Mcf. (2) Lifting costs per barrel are computed by dividing the related lease operating expenses by the total barrels of oil produced. Lifting costs per Mcf of gas are computed by dividing the related lease operating expenses by the total Mcf of gas produced before royalties. Lifting costs do not include production taxes.
Oil Revenues. Oil revenues were $2.2 million, $1.9 million and $1.8 million for the years ended December 31, 2003, 2002 and 2001, respectively. All oil revenues during the three years were derived from our producing properties in the United States. During these three years, oil revenues fluctuated primarily due to volatile oil prices and the declining production rates attributable to the natural production declines of our producing properties. Oil revenues in 2003 increased from 2002 levels by approximately $433,000 due to higher oil prices, offset by approximately $127,000 related to production declines. Oil revenues in 2002 increased from 2001 levels by approximately $161,000 due to higher oil prices, offset by approximately $72,000 related to production declines.
Gas Revenues. Our gas revenues are derived solely from our Polish producing operations. Gas revenues were $285,000 and $394,000 for the years ended December 31, 2002 and 2001, respectively. There were no gas revenues during 2003. As part of our Fences I settlement with POGC in early 2003, we agreed to assign our interest in the Kleka 11 well effective December 2002, along with the related accounts receivable, to POGC as soon as possible in order to conserve cash while reducing the balance of our liability due to POGC. Accordingly, we recorded no gas sales in 2003. Gas volumes in 2002 reflected a full year of production from the Kleka 11, our first producing well in Poland, which began producing in late February 2001. During 2002 and 2001, gas produced by the Kleka 11 was sold to POGC based on U.S. dollar pricing at a fixed price under a five-year contract, which may be terminated by giving POGC a 90-day written notice. The decline in gas production from 2001 to 2002 is the result of the operator choking back the well to avoid any increase in water production.
Lease Operating Costs. Lease operating costs were $1.5 million in 2003 and $1.4 million for each of 2002 and 2001. Operating costs rose slightly from 2002 to 2003, and from 2001 to 2002, as higher oil lifting costs offset lower oil and gas production. Operating costs in 2003 increased approximately $250,000 due to higher lifting costs, offset by approximately $86,000 related to lower oil and gas production. Operating costs in 2002 increased approximately $68,000 due to higher lifting costs, offset by approximately $61,000 related to lower oil and gas production.
Exploration Costs. Our exploration efforts are focused in Poland, and the expenses consist of geological and geophysical costs, or G&G costs, exploratory dry holes and oil and gas leasehold impairments. Exploration costs were $684,000, $2.6 million and $6.5 million for the years ended December 31, 2003, 2002 and 2001, respectively. Limited available capital caused us to sharply curtail our exploration activities in Poland in 2003 and 2002. We expect to increase our level of exploration costs in 2004 as we increase our pace of prospect development, selection, and drilling.
G&G costs were $523,000, $1.0 million and $2.9 million for the years ended December 31, 2003, 2002 and 2001, respectively. During 2003 and 2002, most of our G&G costs were spent on reprocessing and further analyzing the seismic data on the Fences I area. During 2001, we spent approximately $1.8 million on acquiring 3-D seismic data in the Fences project areas, and the remainder acquiring and analyzing 2-D seismic data on the Pomeranian project area.
Exploratory dry-hole costs were $0, $0 and $3.1 million for the years ended December 31, 2003, 2002 and 2001, respectively. Due to our capital limitations, we did not participate in any exploratory drilling in 2003 and 2002. During 2001, we incurred dry hole costs of $3.1 million pertaining to the Mieszkow 1 well on the Fences I project area.
Impairments of oil and gas properties were $161,000, $1.5 million and $584,000 for the years ended December 31, 2003, 2002 and 2001, respectively. During 2003, the entire impairment related to the Kleka 11 well, which was written down to the value established by an independent reservoir engineer, and included both capital costs and related pipeline costs. We have agreed to transfer the Kleka 11 well to POGC to satisfy outstanding obligations. During 2002, we incurred an impairment of $509,000 in costs associated with the Tuchola 108-2 well. The well was completed in 2001, but has since been shut-in pending a pipeline connection. Constrained capital has prevented us from drilling the additional appraisal and development wells and building the necessary infrastructure. We also recognized an impairment of $1.0 million associated with the Kleka 11 well, where lower production profiles caused a downward revision in recoverable future reserves. During 2001, we incurred impairments of $525,000 for the Baltic project area and $59,000 for the Warsaw West project area, both of which are located in Poland in areas where we no longer have exploration plans.
Apache Poland G&A Costs. Apache Poland G&A costs consist 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 $0, $0 and $575,000 for the years ended December 31, 2003, 2002 and 2001. During mid-2001, we began to narrow the focus of our ongoing exploratory efforts with Apache by continuing to work only on the Pomeranian and Wilga project areas and discontinued our exploratory activities on the Lublin Basin, Warsaw West and Carpathian project areas. There were no jointly conducted activities in the Wilga project area in 2003 and 2002.
DD&A Expense - Producing Operations. DD&A expense for producing properties was $347,000, $281,000 and $322,000 for the years ended December 31, 2003, 2002 and 2001, respectively. DD&A expense during 2003, 2002 and 2001 includes approximately $0, $205,000 and $258,000, respectively, or $1.03 per Mcf of gas produced, associated solely with the Kleka 11 well that began producing in Poland during February 2001. DD&A expense declined from 2001 to 2002 due to reduced production from the well. There was no DD&A expense associated with Poland during 2003, as we agreed to transfer our interest in the Kleka 11 well to POGC. The increase from 2002 to 2003 is due primarily to the net book value of domestic assets being increased as a result of the adoption of SFAS 143 effective January 1, 2003.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $98,000, $523,000 and $1.6 million for the years ended December 31, 2003, 2002 and 2001, respectively. During 2003, the contract drilling industry was at a virtual standstill in the area where we operate, and the outlook for 2004 remains unfavorable. The industry was also significantly curtailed in the area where we operate in 2002, and our revenues declined sharply from 2001 as a result. 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 using our oilfield services equipment on our company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $190,000, $540,000 and $1.3 million for the years ended December 31, 2003, 2002 and 2001, respectively, or 194%, 101% and 82% of oilfield servicing revenues, respectively. During 2003 and 2002, oilfield servicing costs were a higher percentage of oilfield services revenues, as compared to 2001, due to increased downtime, maintenance and repair costs associated with our oilfield servicing equipment. In general, oilfield servicing costs are directly associated with oilfield services revenues. As such, oilfield services costs will continue to fluctuate period to period based on the number of wells drilled, revenues generated, weather, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our company-owned properties, and other factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services was $304,000, $310,000 and $308,000 for the years ended December 31, 2003, 2002 and 2001, respectively. We spent $116,000, $248,000 and $779,000 on upgrading our oilfield servicing equipment during 2002, 2001 and 2000, respectively.
Nonsegmented Items
G&A Costs - Corporate. G&A costs were $3.2 million, $2.4 million and $883,000 for the years ended December 31, 2003, 2002 and 2001, respectively. During 2002, in recognition of our limited resources, we aggressively pursued certain cost reduction measures to help conserve capital. As part of those reductions, most of our employees and directors and some of our consultants reduced their salaries and fees by 50%. During 2003, after we successfully raised more than $25 million through the sale of equity, we reinstated those salaries and fees. In addition, we incurred higher accounting and legal fees as a result of an SEC review of our 2002 and 2003 filings and the submission of several SEC registration statements resulting from our stock sales. Accordingly, our 2003 G&A costs were significantly higher than those incurred during 2002. In addition, we were able to resume many of our activities in Poland, which resulted in higher travel costs for the year. During 2001, G&A costs were unusually low, primarily due to the Company writing off $1.7 million of compensation that was accrued as of December 31, 2000. None of this waived compensation has or will be paid.
Interest and Other Income - Corporate. Interest and other income was $36,000, $119,000 and $514,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Lower cash balances and interest rates in 2003 and 2002 reduced our interest income in both years. During the years ended December 31, 2002 and 2001, we recorded other income of $93,000 and $341,000, respectively, pertaining to the amortization of an option premium resulting from granting RRPV an option to purchase gas from our properties in Poland.
Interest Expense. Interest expense was $788,000, $1.2 million and $331,000 for the years ended December 31, 2003, 2002 and 2001, respectively. In March 2002, we began to accrue interest on the $5.0 million RRPV obligation at an annual rate of 9.5%. From May to September, 2003, the RRPV interest rate increased to 12%. It was reduced to 9.5% from October to November, 2003, at which time RRPV converted its note payable and accrued interest into common stock. We began accruing interest our on obligation to POGC during 2002, which accounted for interest expense of $371,000 and $614,000 in 2003 and 2002, respectively. As part of our further restructured agreement with POGC, we stopped accruing interest on the obligation at December 31, 2003. During 2002 and 2001, we recorded $93,000 and $341,000, respectively, of imputed interest expense relating to our financing arrangement with RRPV.
Amortization of Deferred Compensation (G&A). Amortization of deferred compensation was $0, $55,000, and $1.1 million during the years ended December 31, 2003, 2002 and 2001, respectively. On April 5, 2001, we extended the term of options to purchase 125,000 shares of our 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 noncash deferred compensation costs of $1.8 million, including $219,000 for the April 5, 2001, option extension and $1.6 million for the August 4, 2000, option extension, to be amortized over their respective one-year vesting periods from the date of extension. The deferred costs were all amortized as of December 31, 2002.
Income Taxes. We incurred net losses of $2.9 million, $5.9 million and $8.4 million for the years ended December 31, 2003, 2002 and 2001, respectively. SFAS No. 109 "Accounting for Income Taxes" requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our consolidated statement of operations for these years.
Liquidity and Capital Resources
We have made significant progress in improving our liquidity and capital resources during the past year. At the beginning of the year, we were in a tenuous financial situation, with negative working capital of $9.2 million and $700,000 in cash. Through private placements of common and preferred stock, we raised $25.4 million (net of offering costs) during 2003. In addition, $3.6 million of outstanding debt and accrued interest were converted into common stock. We used proceeds from our equity sales to reduce our outstanding obligations to POGC. At the end of the year, we had cash of approximately $17 million, with working capital of $15.8 million. We believe we are now well positioned to carry out our exploration activities in Poland.
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 return for an interest in our properties. The continuation of our exploratory efforts in Poland may be dependent on our ability to raise additional capital or to farm out our properties. The availability of such capital or farmouts may affect the timing, pace, scope and amount of our future capital expenditures. We cannot assure that we will be able to secure additional participants or obtain additional equity or debt financing or complete farmout or other industry cost- and risk-sharing arrangements, particularly, if we fail to make additional discoveries. Such events would materially and adversely affect our financial position and results of operations.
We may seek to obtain additional funds for future capital investments from strategic alliances with other energy or financial participants, the sale of additional securities, project financing, sale of partial property interests, or other arrangements, all of which may dilute the interest of our existing stockholders or our interest in the specific project financed. We may change the allocation of capital among the categories of anticipated expenditures depending upon future events. For example, we may change the allocation of our expenditures based on the actual results and costs of future exploration, appraisal, development, production, property acquisition and other activities. In addition, we may have to change our anticipated expenditures if costs of placing any particular discovery into production are higher, if the field is smaller, or if the commencement of production takes longer than expected.
Working Capital (current assets less current liabilities). Our working capital was $16.0 million as of December 31, 2003, an increase of $25.0 million from December 31, 2002. The improvement is due primarily to the sale of equity securities discussed earlier. In addition, $3.6 million of outstanding debt and accrued interest were converted into common stock, which paid in full our note payable to RRPV.
Our current liabilities include $1.1 million of costs related to our Fences I project in Poland. This amount is equal to the value of the remaining gas reserves at the Kleka 11, which we have agreed to assign to POGC effective December 2002. We may be required to pay additional cash to settle this liability.
Operating Activities. We used net cash of $5.6 million, $2.1 million and $3.1 million in our operating activities during 2003, 2002 and 2001, respectively, primarily as a result of the net losses incurred in those years. We made significant progress in reducing our outstanding liabilities during 2003.
Investing Activities. We used net cash of $1.4 million in investing activities in 2003, used $295,000 in investing activities during 2002, and received net cash of $326,000 from our investing activities during 2001. During 2003, we used $700,000 to pay liabilities associated with oil and gas property additions from prior years. Also included in this amount is a deposit with CalEnergy Gas in the amount of $366,000 to cover drilling expenses for the Zaniemysl-3 well, in the event costs exceed an agreed upon target amount. We spent $194,000 in 2003 related to our proved properties and oilfield equipment
in the United States. During 2002, the bulk of cash used was for upgrading our producing oil and gas properties and our well-servicing equipment. During 2001, our capital expenditures for producing properties and well-servicing equipment were offset by $1.3 million in maturing marketable debt securities.
Financing Activities. We received net cash of $23.7 million, $4,500 and $5.0 million from our financing activities during 2003, 2002 and 2001, respectively. During 2003, we received a total of $25.4 million in net proceeds from the sale of securities. These proceeds were offset by $1.8 million paid to RRPV, $1.7 million of which was a principal payment on its note payable, and $100,000 of which was a loan extension fee paid in March 2003. During 2001, we received $5.0 million pertaining to our RRPV loan and gas purchase option agreement.
We believe that our capital resources from existing cash balances are adequate to meet the requirements of our business through 2004, and that we have adequate liquidity to maintain our operations as they currently exist.
Contractual Obligations and Contingent Liabilities and Commitments
The following is a summary of our significant contractual obligations and commitments as of December 31, 2003:
Contractual Obligations and Commitments Due by December 31, 2004 --------------------------------------- ------------------------ (In thousands)
Fences I work commitment(1)................... $5,265 ------ Total................................... $5,265 ====== - -------------------------- (1) The Fences I work commitment is required in order for us to earn a 49% interest in the Fences I project area. We expect that the balance of our earning requirement will be met by the approximately $2.5 million in costs paid by CalEnergy Gas associated with the Zaniemysl-3 well, the costs of drilling the initial test well on the Rusocin prospect, and the acquisition and reprocessing of additional seismic in the Fences I area scheduled for 2004.
Our oil and gas drilling and production operations are subject to hazards incidental to the industry that can cause severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations, personal injury, and loss of life. To lessen the effects of these hazards, we maintain insurance of various types to cover our United States operations and rely on the insurance or financial capabilities of our exploration participants in Poland. These measures do not cover risks related to violations of environmental laws or all other risks involved in oil and gas exploration, drilling and production. We would be adversely affected by a significant adverse event that is not fully covered by insurance or by our inability to maintain adequate insurance in the future at rates we consider reasonable.
New Accounting Pronouncements
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.
- -------------------------------------------------------------------------------- ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS - --------------------------------------------------------------------------------
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.
We currently have no gas production in Poland. Previously, our gas in Poland was sold to POGC based on U.S. dollar pricing under a five-year contract. The limited volume and sources 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.
Foreign Currency Risk
We have entered into various agreements in Poland, primarily in U.S. dollars or the U.S. dollar equivalent of the Polish zloty. We conduct our day-to-day business on this basis as well. The Polish zloty is subject to exchange rate fluctuations that are beyond our control. We do not currently engage in hedging transactions to protect ourselves against foreign currency risks, nor do we intend to do so in the foreseeable future.
- -------------------------------------------------------------------------------- ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - --------------------------------------------------------------------------------
Our financial statements, including the auditor's report, are included beginning at page immediately following the signature page of this report.
- -------------------------------------------------------------------------------- ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - --------------------------------------------------------------------------------
We have not disagreed with our auditors on any items of accounting treatment or financial disclosure.
- -------------------------------------------------------------------------------- ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES - --------------------------------------------------------------------------------
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission's rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2003, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2003, our disclosure controls and procedures were effective.
There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART III
- -------------------------------------------------------------------------------- ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual meeting of stockholders under the captions "Corporate Governance," "Proposal 1. Election of Directors," and "Section 16(a) Beneficial Ownership Reporting Compliance" is incorporated herein by reference.
- -------------------------------------------------------------------------------- ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION - --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual meeting of stockholders under the caption "Executive Compensation" is incorporated herein by reference.
- -------------------------------------------------------------------------------- ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS - --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual meeting of stockholders under the caption "Principal Stockholders" is incorporated herein by reference.
- -------------------------------------------------------------------------------- ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual meeting of stockholders under the caption "Certain Relationships and Related Transactions" is incorporated herein by reference.
- -------------------------------------------------------------------------------- ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES - --------------------------------------------------------------------------------
The information from the definitive proxy statement for the 2004 annual meeting of stockholders under the caption "Relationship with Independent Auditors" is incorporated herein by reference.
PART IV
- -------------------------------------------------------------------------------- ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K - --------------------------------------------------------------------------------
(a) The following documents are filed as part of this report or incorporated herein by reference.
1. Financial Statements. See the following beginning at page:
Page -------
Report of Independent Auditors............................... Consolidated Balance Sheets as of December 31, 2003 and 2002................................................... Consolidated Statements of Operations for each of the Three Years Ended December 31, 2003, 2002 and 2001........ Consolidated Statements of Cash Flows for each of the Three Years Ended December 31, 2003, 2002 and 2001........ Consolidated Statements of Stockholders' Equity (Deficit) for each of the Three Years Ended December 31, 2003, 2002 and 2001............................................. Notes to the Consolidated Financial Statements..............
2. Supplemental Schedules. The Financial Statement schedules have been omitted because they are not applicable or the required information is otherwise included in the accompanying Financial Statements and the notes thereto.
3. Exhibits. The following exhibits are included as part of this report:
* All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601 and the number following the decimal indicating the sequence of the particular document. Omitted numbers in the sequence refer to documents previously filed as an exhibit, but no longer required. ** Identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit, as required by Item 15(a)(3) of Form 10-K.
(b) Reports on Form 8-K.
During the quarter ended December 31, 2003, we filed or furnished the following items on Form 8-K:
Date of Event Reported Item(s) Reported -------------------------- ------------------------------------------- December 4, 2003 Items 7 and 9 November 19, 2003 Items 7 and 9 November 17, 2003 Items 7 and 9 November 5, 2003 Items 7 and 9 October 29, 2003 Item 5 October 28, 2003 Item 5 October 16, 2003 Items 7 and 9
During the quarter ended December 31, 2003, we filed the following item on Form 8-K/A:
Date of Event Reported Item(s) Reported ------------------------- ---------------------------------------- December 4, 2003 Items 5 and 7
- -------------------------------------------------------------------------------- SIGNATURES - --------------------------------------------------------------------------------
Pursuant to the requirements of Section 13 or 15(d) 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)
Dated: March 10, 2004 By: /s/ David N. Pierce -------------------------------------- David N. Pierce President and Chief Executive Officer
Dated: March 10, 2004 By: /s/ Thomas B. Lovejoy -------------------------------------- Thomas B. Lovejoy Chief Financial Officer
Dated: March 10, 2004 By: /s/ Clay Newton -------------------------------------- Clay Newton Chief Accounting Officer
Pursuant to the requirements of Section 13 or 15(d) 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.
/s/ Thomas B. Lovejoy ------------------------------------- Dated: March 10, 2004 Thomas B. Lovejoy, Director
/s/ David N. Pierce ------------------------------------- Dated: March 10, 2004 David N. Pierce, Director
/s/ Scott J. Duncan ------------------------------------- Dated: March 10, 2004 Scott J. Duncan, Director
/s/ Dennis B. Goldstein ------------------------------------- Dated: March 10, 2004 Dennis B. Goldstein, Director
/s/ David L. Worrell ------------------------------------- Dated: March 10, 2004 David L. Worrell, Director
/s/ Arnold S. Grundvig, Jr. ------------------------------------- Dated: March 10, 2004 Arnold S. Grundvig, Jr., Director
/s/ Jerzy B. Maciolek ------------------------------------- Dated: March 10, 2004 Jerzy B. Maciolek, Director
/s/ Richard Hardman ------------------------------------- Dated: March 10, 2004 Richard Hardman, Director
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of FX Energy, Inc. and its subsidiaries:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows and of stockholders' equity present fairly, in all material respects, the financial position of FX Energy, Inc., and its subsidiaries (the "Company") at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the Financial Statements, the Company changed its method of accounting for asset retirement costs, effective January 1, 2003.
/s/ PricewaterhouseCoopers LLP
Salt Lake City, Utah February 20, 2004
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
Organization
FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively referred to hereinafter as the "Company") is an independent energy company with activities concentrated within the upstream oil and gas industry. In Poland, the Company has projects involving the exploration and exploitation of oil and gas prospects with the Polish Oil and Gas Company ("POGC") and other industry partners. In the United States, the Company produces oil from fields in Montana and Nevada and has an oilfield services company in northern Montana that performs contract drilling and well servicing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and the Company's undivided interests in Poland. All significant inter-company accounts and transactions have been eliminated in consolidation. At December 31, 2003, the Company owned 100% of the voting common stock or other equity securities of its subsidiaries.
Cash Equivalents
The Company considers all highly-liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
Concentration of Credit Risk
The majority of the Company's receivables are within the oil and gas industry, primarily from the purchasers of its oil and gas, fees generated from oilfield services and its industry partners. The receivables are not collateralized. To date, the Company has experienced minimal bad debts, and has no allowance for doubtful accounts at December 31, 2003 and 2002. The majority of the Company's cash and cash equivalents is held by three financial institutions in Utah, Montana and New York.
Inventory
Inventory consists primarily of tubular goods and production related equipment and is valued at the lower of average cost or market.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether an individual well has found proved reserves. If it is determined that an exploratory well has not found proved reserves, or if the determination that proved reserves have been found cannot be made within one year, the costs of the well are expensed. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are not considered to be realizable. Depletion, depreciation and amortization ("DD&A") of capitalized costs of proved oil and gas properties is provided on a property-by-property basis using the unit-of-production method. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net revenues determined on a property-by-property basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value determined on a property-by-property basis. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as a recovery of costs and any resulting gain or loss is recorded as other income.
Other Property and Equipment
Other property and equipment, including oilfield servicing equipment, is stated at cost. Depreciation of other property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 40 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of other property and equipment sold, or otherwise disposed of, and the related accumulated depreciation are removed from the accounts and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation, is summarized as follows:
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Supplemental Disclosure of Cash Flow Information
Non-cash investing and financing transactions not reflected in the consolidated statements of cash flows include the following:
Revenue Recognition
Revenues associated with oil and gas sales are recorded when the title passes and are net of royalties. Oilfield service revenues are recognized when the related service is performed.
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."
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
As of December 31, 2003, the Company had 4,784,517 options outstanding under stock option and award plans as well as from other individual grants. The Company applies APB Opinion No. 25 and related interpretations in accounting for options granted under the stock option and award plans and for other option agreements. Had compensation cost for the Company's options been determined based on the fair value at the grant dates consistent with SFAS No. 123, the Company's net loss and loss per share would have been increased to the pro forma amounts indicated in the following table:
The effects of applying SFAS No. 123 are not necessarily representative of the effects on the reported net income or loss for future years.
The fair value of each option granted to employees and consultants during 2003, 2002 and 2001 is estimated on the date of grant using the Black-Scholes option pricing model. The following weighted-average assumptions were utilized for the Black-Scholes valuation: (1) expected volatility of 70% for 2003, 90% for 2002 and 78% to 83% for 2001; (2) expected lives ranging from three to seven years; (3) risk-free interest rates at the date of grant ranging from 3.00% to 4.24%; and, (4) dividend yield of zero for each year.
Income Taxes
Deferred income taxes are provided for the differences between the tax bases of assets or liabilities and their reported amounts in the financial statements. Such differences may result in taxable or deductible amounts in future years when the asset or liability is recovered or settled, respectively.
Foreign Operations
The Company's investments and operations in Poland are comprised of U.S. Dollar expenditures.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to the consolidated financial statements include the estimates of proved oil and gas reserve quantities and the related future net cash flows.
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
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
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 or debt.
Outstanding options and warrants as of December 31, 2003, 2002 and 2001 were as follows:
Options and Warrants Price Range ------------- ---------------- Balance sheet date: December 31, 2003............. 11,025,827 $2.40 - $10.25 December 31, 2002............. 5,544,017 $1.50 - $10.25 December 31, 2001............. 5,785,585 $1.50 - $10.25
The Company had a net loss in 2003, 2002 and 2001. The above options and warrants, as well as 1,000,000 shares of common stock that could have been issued under the RRPV note, were not included in the computation of diluted earnings per share for 2003, 2002 or 2001 because the effect would have been antidilutive.
Note 2: Asset Retirement Obligation
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 the adoption of SFAS 143, the Company recorded accretion expense of $37,000 in 2003.
At January 1 and December 31, 2003, there are no assets legally restricted for purposes of settling asset retirement obligations. There was no impact on the Company's cash flows as a result of adopting SFAS 143 because the cumulative effect of change in accounting principle is a noncash transaction.
The Company's estimated asset retirement obligation liability at January 1, 2002 and 2001 was approximately $322,000 and $285,000, respectively.
Following is a reconciliation of the changes in the asset retirement obligation from December 31, 2002, to December 31, 2003:
Asset retirement obligation as of December 31, 2002....... $ -- Obligation arising from adoption of SFAS 143.............. 345,551 Liabilities settled....................................... -- Accretion expense......................................... 37,145 ---------- Asset retirement obligation as of December 31, 2003....... $ 382,696 ==========
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Note 3: Other Assets
As of December 31, 2003 and 2002, the Company had a replacement bond with a federal agency in the amount of $463,000, which was collateralized by certificates of deposit totaling $231,500. In addition, there are certificates of deposit totaling $125,000 covering performance bonds in other states. As of December 31, 2003, the Company had advanced $377,000 to one of its partners to cover drilling expenses for an exploratory well in Poland in the event costs exceed an agreed upon target amount.
Note 4: Accrued Liabilities
The Company's accrued liabilities as of December 31, 2003 and 2002 were comprised of the following:
December 31, ---------------------------- 2003 2002 ------------- ------------- (In thousands) Accrued liabilities: Exploratory dry hole costs.......... $ 880 $ 880 Drilling costs...................... 172 433 Seismic costs....................... -- 1,859 Pipeline costs...................... -- 502 Interest payable, POGC.............. -- 704 Interest payable, RRPV.............. -- 392 Other costs......................... 254 163 ------------ ------------ Total........................... $ 1,306 $ 4,933 ============ ============
Note 5: Notes Payable
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"). The proceeds from the loan were used for exploration and development of additional gas reserves in Poland. The loan was interest free for the first year. In consideration for the loan and not charging interest for the first year, the Company granted RRPV an option to purchase up to 17 Mmcf of gas per day from the Company's properties in Poland, subject to availability, exercisable on or before March 9, 2002. The option to purchase gas from the Company's Polish properties was not exercised by RRPV. In accordance with the loan agreement, the entire principal amount plus accrued interest was due on or before March 9, 2003, unless RRPV elected 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, on or before March 9, 2003. As collateral for the loan, the Company granted RRPV a lien on most of the Company's Polish property interests.
For financial reporting purposes, the Company imputed interest expense for the first year at 9.5%, or $433,790, which was amortized ratably over the one-year interest free period beginning March 9, 2001 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.
In March, 2003, following a private placement of convertible preferred stock, the Company paid $2.3 million to RRPV, which included $1.7 million in principal, $0.5 million in accrued interest, and a $100,000 loan extension fee. In return, RRPV extended the maturity date of the note to December 31, 2003. The Company 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 also agreed to assign its rights to payments under the CalEnergy Gas agreement to RRPV, except for those amounts relating to two wells required to be drilled under the agreement. All such payments would 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.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
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, and an extension of the conversion period until 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 EITF 98-5, "Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios," no charge to income was recorded as a result of the reduction in conversion price as the new conversion price did not result in any intrinsic value.
In September, 2003, the Company placed the then outstanding principal balance of the note, $3.3 million, into an escrow account in favor of RRPV. In turn, the interest rate on the loan was reduced to 9% per annum. In December, 2003, RRPV exercised its right to convert the outstanding principal balance and accrued interest into 972,222 shares of common stock. Accordingly, RRPV released the escrowed funds to the Company, and subsequently released all outstanding liens and other collateral secured by the note to the Company.
Note 6: Commitments
Fences I Project Area
On April 11, 2000, the Company signed an agreement with POGC under which the Company will earn a 49.0% working interest in approximately 265,000 gross acres in west central Poland (the "Fences I" project area) by spending $16.0 million for agreed drilling, seismic acquisition and other related activities.
During 2000, the Company paid $6,689,432 to POGC under the agreement leaving a remaining commitment of $9,310,568. During 2002 and 2001, the Company did not make any additional cash payments to POGC relating to this agreement. As of December 31, 2001, the Company had accrued $2,678,477 of additional costs pertaining to the Fences project area $16.0 million commitment, including $880,121 for drilling activities and $1,798,356 for 3-D seismic activities.
During 2002, the Company reaffirmed its intent to fulfill its $16 million commitment with POGC. In connection with this agreement, the Company agreed to recognize and pay at a future date an additional $2,306,627 of costs related to prior exploration activities in the Fences I area to POGC, $1,602,902 of which will be credited towards the $16 million commitment. The $2,306,627 was recorded as an accrued liability, net of accounts receivable from POGC, at December 31, 2002. The 2002 amount includes $703,725 in interest costs related to the Company's prior liabilities to POGC, $432,875 in drilling costs, $417,653 in seismic costs, $502,244 in pipeline costs, and $250,130 related to foreign exchange adjustments. As part of its future payment, the Company agreed to assign in 2003 all of its right to the Kleka well, including the amounts recorded as accounts receivable for Kleka gas sales. Accordingly, at December 31, 2002, the Company's account receivable from POGC in the amount of $606,986 was offset against the POGC liability. The liability is to be offset by the value of the remaining gas reserves associated with the Kleka well, as determined by an independent engineer jointly appointed by the Company and POGC. The Company further agreed to begin accruing interest on the past due amount to POGC. The interest rate in effect at December 31, 2002 was 12.8%. The interest rate changed on January 1, 2003, to 10.4%.
During 2003, the Company paid a total of $2,916,003 in cash to POGC and recorded a $190,000 VAT liability related to the Kleka gas sales in full settlement of the outstanding liability, with the exception of the Kleka 11 assignment. As of December 31, 2003, the Kleka 11 well had estimated proved, developed, producing gas reserves with an estimated net present value, discounted at 10%, of approximately $1.1 million, as determined by an independent engineer. The parties continue to discuss the assignment of the Kleka well to POGC. Should the parties not be able to reach a consensus concerning the independent engineer's assessment of reserves, the Company may be required to pay additional cash to settle the remaining liability to POGC.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Apache Exploration Program
The Apache Exploration Program ("AEP") consists of various agreements signed between the Company and Apache Corporation ("Apache") from 1997 through 2001. Apache Poland general and administrative ("G&A") costs consist of the Company's share of direct overhead costs incurred by Apache in Poland in accordance with the terms of the AEP. Apache Poland G&A costs were $0, $0, and $575,000 during 2003, 2002 and 2001, respectively. The initial primary terms of the Apache Exploration Program included a commitment by Apache to cover the Company's share of costs to drill ten exploratory wells, to acquire 2,000 kilometers of 2-D seismic and cover the Company's share of other specified costs to earn a fifty-percent interest in the Company's Lublin Basin and Carpathian project areas. There are no ongoing obligations under the AEP as of December 31, 2001.
Note 7: Income Taxes
The Company recognized no income tax benefit from the losses generated during 2003, 2002 and 2001. The components of the net deferred tax asset as of December 31, 2003 and 2002 are as follows:
SFAS No. 109 "Accounting for Income Taxes" requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. The Company's ability to realize the benefit of its deferred tax asset will depend on the generation of future taxable income through profitable operations and expansion of the Company's oil and gas producing activities. The risks associated with that growth requirement are considerable, resulting in the Company's conclusion that a full valuation allowance be provided at December 31, 2003 and 2002.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
United States NOL
At December 31, 2003, the Company had net operating loss ("NOL") carryforwards in the United States of approximately $35,321,000 available to offset future taxable income, of which approximately $18,749,000 expires from 2008 through 2012 and 16,572,000 expires subsequent to 2018. The utilization of the NOL carryforwards against future taxable income in the United States may become subject to an annual limitation if there is a change in ownership. The NOL carryforwards in the United States include $6,326,000 relating to tax deductions resulting from the exercise of stock options. The tax benefit from adjusting the valuation allowance related to this portion of the NOL carryforward will be credited to additional paid-in capital.
Polish NOL
As of December 31, 2003, the Company had NOL carryforwards in Poland totaling approximately $11,670,000, including $345,516, $882,262 and $1,925,220 generated in 2003, 2002 and 2001, respectively. The NOL carryforwards may be carried forward five years in Poland. However, no more than fifty-percent of the NOL carryforwards for any given year may be applied against Polish income in succeeding years.
The domestic and foreign components of the Company's net loss are as follows:
Year Ended December 31, ------------------------------------------ 2003 2002 2001 ------------ ------------ ----------- (In thousands) Domestic.................. $ (1,820) $ (3,570) $ (1,585) Foreign................... (1,113) (2,355) (6,825) ------------ ------------ ----------- Total................. $ (2,933) $ (5,925) $ (8,410) ============ ============ ============
Note 8: Private Placements of Common and Convertible Preferred Stock
In March 2003, the Company sold 2,250,000 shares of 2003 Series Convertible Preferred Stock in a private placement of securities, raising a total of $5,593,871 after offering costs of $31,129. Each share of preferred stock immediately converts into one share of common stock and one warrant to purchase one share of common stock at $3.60 per share upon registration of the common shares. The warrants to purchase common stock are exercisable anytime between March 1, 2004, and March 1, 2008, and entitle the holders, for a period of 10 days following any new issuances of equity securities or securities convertible or exercisable into equity securities in other than a public offering, to preserve their approximate 16.3% ownership subsequent to this offering by purchasing such new securities issued on the same terms as issued to others. The preferred stock had 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 were contingent upon the registration of the underlying shares, these shares became included in the calculation of earnings per share upon the conversion of the preferred stock to common stock.
The Company's 2,250,000 shares of 2003 Series Convertible Preferred Stock were converted to common stock on a one-for-one basis on October 27, 2003, pursuant to a registration statement that became effective on that date.
Between the months of July and November, 2003, the Company sold 3,991,310 Units, consisting of one share of common stock and one warrant to purchase one share of common stock at $3.75 per share, raising a total of $10,734,672 after offering costs of $41,865. The warrants to purchase common stock are exercisable one year after closing, and expire between July 22, 2008 and November 4, 2008.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
In December, 2003, the Company sold 2,362,051 shares of common stock, raising a total of $9,137,021 after offering costs of $571,009.
The net proceeds from the 2003 offerings were used to reduce the note payable to Rolls-Royce Power Ventures Limited, to reduce the obligation to the Polish Oil and Gas Company, and will be used to fund ongoing geological and geophysical costs in Poland and support ongoing prospect marketing and general and administrative costs.
Note 9: Stock Options and Warrants
Equity Compensation Plans
The Company's equity compensation consists of annual stock option and award plans that are each subject to approval by the Board of Directors and are subsequently presented for approval by the stockholders at the Company's annual meetings.
The following table summarizes information regarding the Company's stock option and award plans as of December 31, 2003:
The above table excludes 1,120,000 options that have been granted outside of shareholder approved option plans.
All stock option and award plans are administered by a committee (the "Committee") consisting of members of the board of directors or a committee thereof. At its discretion, the Committee may grant stock, incentive stock options ("ISOs") or non-qualified options to any employee, including officers. In addition to the options granted under the stock option plans, the Company also issues non-qualified options outside the stock option plans. The granted options have terms ranging from five to seven years and vest over periods ranging from the date of grant to three years. Under terms of the stock option award plans, the Company may also issue restricted stock.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
The following table summarizes fixed option activity for 2003, 2002 and 2001:
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Option and Warrant Extensions
On August 5, 2001, the Company extended the term of options and warrants 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. In accordance with FIN 44 "Accounting for Certain Transactions Involving Stock Compensation," the Company incurred deferred compensation costs of $218,750 applicable to an officer and a non-officer, to be amortized to expense over the one-year vesting period.
Note Receivable from Stock Option Exercises
On November 8, 2000, a former employee exercised an option to purchase 52,000 shares of the Company's common stock at a price of $3.00 per share. The former employee elected to pay for the cost of the exercise by signing a full recourse promissory note with the Company for $156,000. Terms of the note receivable included a three-year term with annual principal payments of $52,000 plus interest accrued at 9.5%. On November 8, 2001, the former employee surrendered 52,000 shares of the Company's common stock in return for cancellation of the note receivable. The Company recorded a loss of $34,060 on the transaction and the acquisition of 52,000 shares of common stock as treasury stock at a price of $2.63 per share, the closing price of the Company's stock on November 8, 2001.
Note 10: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2003 and 2002 is as follows:
The net operating loss for the fourth quarter of 2003 includes $160,886 in property impairment costs. The net operating loss for the fourth quarter of 2002 includes $1,547,860 in property impairment costs, and $703,725 and $502,244 in interest and seismic costs, respectively, incurred in connection with a revision of the Company's agreement with POGC relative to the Fences I project area.
Note 11: Business Segments
The Company operates within two business segments of the oil and gas industry: exploration and production ("E&P") and oilfield services. The Company's revenues associated with its E&P activities are comprised of oil sales from its producing properties in the United States and oil and gas sales from its producing properties in Poland. Over 85% of the Company's oil sales in the United States were to Cenex during 2001 and the first half of 2002. From July 2002 to June 2003, over 85% of the Company's oil sales were to Plains Marketing Canada, LP. Commencing in July 2003, over 85% of the Company's oil sales were to Cenex. During 2002 and 2001, all of the Company's oil and gas sales in Poland were to POGC. There were no oil and gas sales in Poland during 2003. The Company
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
believes the purchasers of its oil and gas production could be replaced, if necessary, without a loss in revenue. E&P operating costs are comprised of: (1) exploration costs (geological and geophysical costs, exploratory dry holes, and non-producing leasehold impairments) and, (2) lease operating costs (lease operating expenses and production taxes). Substantially all exploration costs are related to the Company's operations in Poland. Substantially all lease operating costs are related to the Company's domestic production.
The Company's revenues associated with its oilfield services segment are comprised of contract drilling and well servicing fees generated by the Company's oilfield servicing equipment in Montana. Oilfield servicing costs are comprised of direct costs associated with its oilfield services.
DD&A directly associated with a respective business segment is disclosed within that business segment. The Company does not allocate current assets, corporate DD&A, general and administrative costs, amortization of deferred compensation, interest income, interest expense, other income or other expense to its operating business segments for management and business segment reporting purposes. All material inter-company transactions between the Company's business segments are eliminated for management and business segment reporting purposes.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Information on the Company's operations by business segment for 2003, 2002 and 2001 is summarized as follows:
--------------------- (3) E&P revenues include $1,924,000 generated in the United States and $285,000 generated in Poland. (4) E&P operating costs include $129,000 in geological and geophysical costs, $41,000 in lease operating costs, and $171,000 in general and administrative costs incurred in Poland. (5) E&P includes $418,000 of pipeline costs and $586,000 of proved property additions incurred in Poland and $8,000 of unproved property additions in the United States.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
--------------------- (1) E&P revenues include $1,815,000 generated in the United States and $414,000 generated in Poland. (2) E&P operating costs include $2,541,000 in geological and geophysical costs, $3,051,000 in exploratory dry hole costs, $59,000 in property impairments, $42,000 in lease operating costs, and $733,000 in general and administrative costs incurred in Poland. (3) E&P DD&A includes $258,000 in DD&A costs incurred in Poland. (4) E&P includes a $894,000 of exploratory dry hole costs, $320,000 of proved property additions and $531,000 of unproved property additions.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
A reconciliation of the segment information to the consolidated totals for 2003, 2002 and 2001 follows:
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Results of Operations
Results of operations are reflected in Note 13, Business Segments. There is no tax provision as the Company is not likely to pay any federal or local income taxes due to its operating losses. Total production costs for 2003, 2002 and 2001 were $1,545,913, $1,365,454 and $1,358,304, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities during 2003, 2002 and 2001, whether capitalized or expensed, are summarized as follows:
Exploratory dry hole costs
During 2001, for financial reporting purposes, the Company classified the Mieszkow 1 as an exploratory dry hole, and recorded exploratory dry hole costs of $3,051,334, including cash expenditures of $2,171,750 and accrued costs of $879,584. There were no dry hole costs in 2003 and 2002.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Note 13: Summary Oil and Gas Reserve Data (Unaudited)
Estimated Quantities of Proved Reserves
Proved reserves are the estimated quantities of crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. The Company's proved oil and gas reserve quantities and values are based on estimates prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission. Operating costs, production taxes and development costs were deducted in determining the quantity and value information. Such costs were estimated based on current costs and were not adjusted to anticipate increases due to inflation or other factors. No price escalations were assumed and no amounts were deducted for general overhead, depreciation, depletion and amortization, interest expense and income taxes. The proved reserve quantity and value information is based on the weighted average price on December 31, 2003 of $27.53 per bbl for oil in the United States and $2.60 per MCF of gas in Poland. The determination of oil and gas reserves is based on estimates and is highly complex and interpretive, as there are numerous uncertainties inherent in estimated quantities and values of proved reserves, projecting future rates of production and timing of development expenditures. The estimates are subject to continuing revisions as additional information becomes available or assumptions change.
Estimates of the Company's proved domestic reserves were prepared by Larry Krause Consulting, an independent engineering firm in Billings, Montana. Estimates of the Company's proved Polish reserves were prepared by Troy-Ikoda Limited, an independent engineering firm in the United Kingdom. The following unaudited summary of proved developed reserve quantity information represents estimates only and should not be construed as exact:
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
Standardized Measure of Discounted Future Net Cash Flows ("SMOG") and Changes Therein Relating to Proved Oil Reserves
Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities." Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute the proved reserve valuation do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rates also could result directly or indirectly from factors outside the Company's control, such as unintentional delays in development, environmental concerns and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating expenditures to be incurred in developing and producing the proved oil reserves at the end of the period, based on period-end costs and assuming continuation of existing economic conditions. A discount rate of 10.0% per year was used to reflect the timing of the future net cash flows. The discounted future net cash flows for the Company's Polish reserves are based on a gas and condensate sales contracts the Company has with POGC.
The components of SMOG are detailed below:
------------------------- (1) Includes $1,052 related to the Kleka 11 well, which the Company has agreed to transfer to POGC.
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
The principal sources of changes in SMOG are detailed below:
Note 14: New Accounting Pronouncements
The Company has reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on its results of operations or financial position. Based on that review, the Company believes that none of these pronouncements will have a significant effect on current or future earnings or operations.
Note 15: Interests Held Under Oil and Gas Leases
Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill and Intangible Assets" (SFAS 142) were issued by the Financial Accounting Standards Board (FASB) in June 2001 and became effective for the Company on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Company's balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, the Company has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after SFAS 141 and 142 became effective.
This interpretation of SFAS 141 and 142 described above would only affect our 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.".
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued -
At December 31, 2003 and 2002, the Company had undeveloped leaseholds of approximately $166,000 and $147,000, respectively, that would be classified under that interpretation on the balance sheet as "intangible undeveloped leasehold" and developed leaseholds of an estimated $7,000 in both years 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 interpretive guidance is provided.