10-K 1 k123102.txt 10-K FOR YEAR ENDED DECEMBER 31, 2002 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 Commission File Number: 0-25386 FX ENERGY, INC. ---------------------------------------------------- (Exact name of registrant as specified in its charter) Nevada 87-0504461 -------------------------------- ------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 3006 Highland Drive, Suite 206, Salt Lake City, Utah 84106 ----------------------------------------------------- ----------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: Telephone (801) 486-5555 Telecopy (801) 486-5575 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- None None Securities registered pursuant to Section 12(g) of the Act: Common Stock, Par Value $0.001 Preferred Stock Purchase Rights ------------------------------- (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. As of June 30, 2002, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $36,259,913. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. As of March 20, 2003, FX Energy had outstanding 17,708,025 shares of its common stock, par value $0.001. DOCUMENTS INCORPORATED BY REFERENCE. FX Energy's definitive Proxy Statement in connection with the 2003 Annual Meeting of Stockholders is incorporated by reference in response to Items 10 through 13 of Part III of this Annual Report. -------------------------------------------------------------------------------- FX ENERGY, INC. Form 10-K for the fiscal year ended December 31, 2002 -------------------------------------------------------------------------------- Table of Contents Item Page ---- ---- Part I -- Special Note on Forward-Looking Statements........................ 1 1 and 2 Business and Properties........................................... 2 3 Legal Proceedings................................................. 17 4 Submission of Matters to a Vote of Security Holders............... 17 Part II 5 Market for Registrant's Common Equity and Related Stockholder Matters............................................. 18 6 Selected Financial Data........................................... 20 7 Management's Discussion and Analysis of Financial Condition and Results of Operation........................................ 21 7A Quantitative and Qualitative Disclosures about Market Risk........ 33 8 Financial Statements and Supplementary Data....................... 33 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................................ 34 Part III 10 Directors and Executive Officers of the Registrant................ 35 11 Executive Compensation............................................ 35 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................................. 35 13 Certain Relationships and Related Transactions.................... 35 14 Controls and Procedures........................................... 35 Part IV 15 Exhibits, Financial Statement Schedules and Reports on Form 8-K..................................................... 37 -- Signatures........................................................ 41 -- Certifications.................................................... 42 -- Report of Independent Accountants................................ F-1 i -------------------------------------------------------------------------------- SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS -------------------------------------------------------------------------------- This report contains statements about the future, sometimes referred to as "forward-looking" statements. Forward-looking statements are typically identified by the use of the words "believe," "may," "will," "should," "expect," "anticipate," "estimate," "project," "propose," "plan," "intend" and similar words and expressions. We intend that the forward-looking statements will be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements that describe our future strategic plans, goals or objectives are also forward-looking statements. Readers of this report are cautioned that any forward-looking statements, including those regarding us or our management's current beliefs, expectations, anticipations, estimations, projections, proposals, plans or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as: o our future ability to attract industry or financial partners to share the costs of exploration, exploitation, development and acquisition activities; o the cost of additional capital that we may require and possible related restrictions on our future operating or financing flexibility; o future plans and the financial and technical resources of industry or financial partners; o future events that may result in the need for additional capital; o future drilling and other exploration schedules and sequences for various wells and other activities; o the future results of drilling individual wells and other exploration and development activities; o future variations in well performance as compared to initial test data; o the prices at which we may be able to sell oil or gas; o fluctuations in prevailing prices for oil and gas; o uncertainties of certain terms to be determined in the future relating to our oil and gas interests, including exploitation fees, royalty rates and other matters; o uncertainties regarding future political, economic, regulatory, fiscal, taxation and other policies in Poland; and o other factors that are not listed above. The forward-looking information is based on present circumstances and on our predictions respecting events that have not occurred, that may not occur, or that may occur with different consequences from those now assumed or anticipated. Actual events or results may differ materially from those discussed in the forward-looking statements as a result of various factors, including the risk factors detailed in this report. The forward-looking statements included in this report are made only as of the date of this report. 1 PART I -------------------------------------------------------------------------------- ITEMS 1 AND 2. BUSINESS AND PROPERTIES -------------------------------------------------------------------------------- Introduction We are an independent oil and gas company focused on exploration, development and production opportunities in the Republic of Poland. In association with our partner, the Polish Oil and Gas Company, or POGC, we were the first western company to discover and produce gas in Poland. The cooperative working environment in Poland allows us to operate effectively with in-country operating and technical personnel, access geological and geophysical data readily, and obtain other necessary support in Poland. We also produce oil and have an oilfield services company in the United States. We are focused on Poland because of its attractive oil and gas exploration and production opportunities. In our view, these opportunities exist because the country has only recently been open to foreign oil and gas companies. As a result, its known productive areas are underexplored, underdeveloped and underexploited today. Poland's heavy dependence on oil and gas imports and its fiscal regime favorable to foreign investment reinforce the attractiveness of Poland. Strategy We seek the potential rewards of high potential exploration opportunities while endeavoring to minimize our exposure to the risks normally associated with exploration. We compensate for our small size and limited capital by leveraging our land position against the financial and technical resources of larger industry partners. Our primary strategic relationship is with POGC, a fully integrated oil and gas company owned by the Treasury of the Republic of Poland. Our strategic alliance with POGC provides us with access to important exploration data as well as technical and operational support. POGC is a partner in substantially all of our ongoing activities in Poland, including the Fences I and II project areas where POGC is the operator, Block 108 of the Pomeranian project area where we are the operator, and the Wilga project area where Apache Corporation is the operator. We believe that our relationship with POGC will continue to provide additional opportunities in Poland. We have shifted our focus away from pure exploration to concentrate on underexplored acreage in productive fairways where we have the opportunity to find significant gas reserves with lower risk. Our strategy is to: o acquire large acreage positions in underexplored areas of known production fairways, particularly where there has been little or no exploration for many years; o carry out an initial evaluation of the properties to provide value uplift at low cost; and o market these properties to industry on conventional farmout terms. We expect this strategy to allow us to more than recoup our costs, earn a carried interest in the initial drilling phase without direct financial exposure of our own, and retain the upside of a substantial interest in potential reserves. We have a successful track record of arranging industry farmouts in Poland in several different areas. Project Areas Our ongoing activities in Poland are conducted in five project areas: Pomeranian, Wilga, and Fences I, II and III. Our focus today is on the three Fences project areas, where the gas-bearing Rotliegendes sandstone reservoir rock in Poland's Permian basin is a direct analog to the Southern North Sea, or SNS, gas basin offshore England. Underpinning our focus on the three Fences areas are the lack of exploration in these areas over the past two decades and the availability of new geophysical technology that has proved successful in the SNS. Fences I is 265,000 acres (1,074 sq. km) in western Poland's Permian basin where we hold a 49% interest. Several gas fields located in the Fences I block are excluded or "fenced off" from our exploration acreage. These fields, 2 discovered by POGC between 1974 and 1982, produce from Rotliegendes sandstone reservoirs and contain total recoverable reserves of over 500 Bcf of gas. Fences II is 670,000 acres (2,715 sq. km) located north of and contiguous with the Fences I block. The 450 Bcf Radlin field forms part of the block's southern border. Under a January 2003 agreement, we have the right to earn a 49% interest from POGC. Fences III is 770,000 acres (3,122 sq. km) located approximately 25 miles south of Fences I. In March 2003, we reached agreement with the Ministry of the Environment in Poland on final principal terms, subject to formal documentation, for 100% of the exploration rights to the Fences III project area. As with the Fences I block, several gas fields located in the Fences III block are fenced off from the exploration acreage. These fields, discovered by POGC between 1967 and 1976, produced from both Rotliegendes sandstone and Zechstein carbonate reservoirs and contained total reserves of approximately 950 Bcf of gas. There has not been an exploration program on this acreage in more than 25 years. We signed a farmout agreement covering the Fences I block in January 2003, with CalEnergy Gas, the upstream gas business unit of MidAmerican Energy Holdings Company, whereby CalEnergy Gas has the right, but not the obligation, to earn a 24.5% interest by spending a total of $10.6 million, including the cost to drill two wells, plus certain cash payments to us. We are in early stage discussions with several SNS-experienced companies regarding Fences II and Fences III. The Fences I, II and III project areas (a total of 1.7 million gross acres or 6,911 sq. km) are within an area of underexplored Rotliegendes sandstone. Cumulative Rotliegendes discoveries in Poland amount to 5 Tcf compared to 42 Tcf in the SNS. An exploration program to look for Rotliegendes gas reserves has not been undertaken in Poland using the technology available today, and no sustained exploration effort has been made in the three Fences project areas for Rotliegendes gas fields in the last 20 years. In addition to the Fences project areas, we hold a 45% interest in Block 255, a 250,000 acre block where the Wilga #2 discovery well is located. The well was tested and completed, but is not currently in production. We also hold an 85% interest in a 227,000 acre block in the Pomeranian project area where the Tuchola #6 discovery was drilled in 2001, and 100% interest in the remaining approximately 2.0 million acres in the Pomeranian project area. During the balance of 2003, we anticipate that CalEnergy Gas will drill two wells in the Fences I project area. We will also be marketing the Fences II project area to industry for farmout, and may see one well drilled in this area in 2003. In addition, we will be evaluating and reprocessing seismic data, and perhaps acquiring new seismic data, in the Fences III project area to prepare for farming out. We also expect to advance our discussions with POGC concerning the possible expansion of our joint interests in Poland. Assumptions References to us in this report include FX Energy, Inc., our subsidiaries and the entities or enterprises organized under Polish law in which we have an interest and through which we conduct our activities in that country. All historical production and test data about Poland, excluding wells in which we have participated, have been derived from information furnished by either POGC or the Polish Ministry of Environmental Protection, Natural Resources and Forestry unless noted otherwise. 3 The Republic of Poland The Republic of Poland is located in central Europe, has a population of approximately 39 million people and covers an area comparable in size to New Mexico. During 1989, Poland peacefully asserted its independence and became a parliamentary democracy. Since 1989, Poland has enacted comprehensive economic reform programs and stabilization measures that have enabled it to form a free-market economy and turn its economic ties from the east to the west, with most of its current international trade with the countries of the European Union and the United States. The economy has undergone extensive restructuring in the post-communist era. Gross domestic production had been strong and steady in 1993 through 2000, but fell back in 2001 and 2002 with slowdowns in domestic investment and consumption and the persistent weakness in the European economy, according to the CIA fact book on Poland. The contribution of the private sector to gross domestic production rose from around 18% in 1989 to 39% in 1995 and 70% in 1999, even though privatization has gone relatively slowly. Private-sector nonagricultural employment rose from 14% of the labor force in 1989 to 61% in 1999. The Polish government credits foreign investment as a forceful growth factor in successfully creating a stable free-market economy. According to the Polish Foreign Investment Agency, cumulative foreign direct investment flow into Poland is estimated to have aggregated approximately $62 billion from 1989 through mid-2002. Since its transition to a market economy and a parliamentary democracy, Poland has experienced significant economic growth and political change. Poland has developed and is refining legal, tax and regulatory systems characteristic of parliamentary democracies with interpretation and procedural safeguards. The Polish government has generally taken steps to harmonize Polish legislation with that of the European Union in anticipation of Poland's entry into the European Union in 2004 and to facilitate interaction with European Union members. Since 1995, the Polish corporate income tax rate has been reduced each year, and now stands at 27% of net income. Poland has created an attractive legal framework and fiscal regime for oil and gas exploration by actively encouraging investment by foreign companies to offset its lack of capital to further explore its oil and gas resources. In July 1995, Poland's Council of Ministers approved a program to restructure and privatize the Polish petroleum sector. So far under this plan, a refinery located in Plock has been privatized as a publicly-held company with its stock trading on the London and Warsaw stock exchanges. We expect that the gas distribution segments of POGC will be privatized next, followed by the exploration, production and oilfield services segment. Increased participation by Western companies using Western capital in the oil and gas sector is consistent with the approved privatization policy. Prior to becoming a parliamentary democracy during 1989, the exploration and development of Poland's oil and gas resources were hindered by a combination of foreign influence, a centrally-controlled economy, limited financial resources, and a lack of modern exploration technology. As a result, Poland is currently a net energy importer. Oil is imported primarily from countries of the former Soviet Union and the Middle East, and gas is imported primarily from Russia. In the early 1990s, the World Bank loaned Poland $250 million to fund the purchase of new exploration and drilling equipment for Poland's oil and gas industry to help shift its domestic sources of energy consumed from coal to oil and natural gas. The following table highlights selected statistics obtained from the U.S. Department of Energy regarding the oil and gas industry in Poland:
Oil Gas ----------------------- --------------------- Proved reserves as of January 1, 2002....................... 114.9 MMBbls 5.1 Tcf Average production per day during 2001...................... 14,000 Bbls per day 0.5 Bcf per day Average imports per day during 2001......................... 420,000 Bbls per day 0.8 Bcf per day
During 1998, Poland joined NATO and has been invited to join the European Union in 2004. In order to achieve member status in the European Union, Poland must raise its environmental standards. In Poland, coal is the dominant energy source, accounting for 65.4% of the country's annual energy consumption as recently as 2000. Increased consumption of natural gas, as an alternative to coal, is considered to be a key component in meeting the European Union's strict environmental guidelines for its members. The demand for gas in Poland is expected to increase in the future, primarily due to increased economic growth coupled with the conversion to gas from coal as an energy source for power plants. 4 Poland has crude oil pipelines serving the major refineries and a network of gas pipelines serving major metropolitan, commercial, industrial and gas production areas, including significant portions of our acreage. Poland has a well-developed infrastructure of hard-surfaced roads and railways over which we believe oil produced could be transported for sale. There are refineries in Gdansk and Plock in Poland and one in Germany near the western Polish border that we believe could process any crude oil we may produce in Poland. All facilities and pipelines currently used to gather and transport oil and gas in Poland are owned and operated by POGC. Exploration, Development and Production Activities in Poland Exploratory Activities in Poland Our strategy is to bring industry partners into our projects in Poland to provide the capital for early-stage exploration drilling. In January 2003, we entered into a farmout agreement with CalEnergy Gas that allows it to spend a total of $10.6 million by December 15, 2003, including the cost to drill two wells plus certain cash payments to us, to earn a 24.5% interest (half of our 49% interest) in our Fences I project area. Full performance by CalEnergy Gas would more than cover our $4.4 million obligation to POGC and complete our $16.0 million earning requirement for the Fences I project area. However, any such payment to us is pledged to RRPV until the note, with a principal balance of approximately $3.3 million, plus interest, has been satisfied in full. We are seeking an industry partner for our Fences II project area, and following our initial evaluation of the Fences III area, we plan to seek other industry partners to join us. Polish Exploration Rights As of December 31, 2002, our oil and gas exploration rights in Poland were comprised of the following gross acreage components:
Operator ----------------------------------------------- Total FX Energy Apache POGC Acreage --------------- --------------- --------------- --------------- Project Area: Fences I(1)............................... -- -- 265,000 265,000 Pomeranian(2)............................. 2,200,000 -- -- 2,200,000 Wilga(3).................................. -- 250,000 -- 250,000 --------------- --------------- --------------- --------------- Total gross acreage..................... 2,200,000 250,000 265,000 2,715,000 =============== =============== =============== ===============
-------------------- (1) In April 2000, we entered into an agreement with POGC to earn 49% of POGC's 100% interest in the Fences I project area by spending $16.0 million of exploration costs. (2) We own a 100% interest in the Pomeranian project area, except for Block 108 (approximately 250,000 acres), where we own an 85% interest and POGC owns a 15% interest. (3) We own a 45% interest, Apache owns a 45% interest and POGC owns a 10% interest in the Wilga project area. The foregoing table excludes 670,000 acres in the Fences II project area, operated by POGC, in which we have the right to acquire a 49% interest under a January 2003 agreement, and 770,000 acres in the Fences III project area, to be operated by us, in which we will have the right to acquire 100% of the exploration rights, subject to final documentation. As we continue to explore and evaluate our acreage in Poland, we expect to increasingly focus our operational and financial efforts on known productive trends and recent discoveries. As we do so, we may elect not to retain our interest in acreage that we determine carries a higher exploration risk. Fences I Project Area The Fences I project area consists of approximately 265,000 gross acres (1,074 sq. km) in western Poland's Permian basin. Several gas fields located in the Fences I block are excluded or "fenced off" from the exploration acreage. These fields, discovered by POGC between 1974 and 1982, produce from 5 Rotliegendes sandstone reservoirs with cumulative recoverable reserves of over 500 Bcf of gas. The Rotliegendes is the primary target horizon throughout most of the Fences I project area, at depths from about 2,800 to 3,200 meters, except along the extreme southwest portion where the target reservoir is carbonates of the lower Permian. In April 2000, we agreed to spend $16.0 million on exploration costs in the Fences I project area to earn a 49% interest. When expenditures exceed $16.0 million, POGC will pay its 51% share of further costs. To date, we have incurred expenditures of $10.6 million (including $4.4 million in accrued liabilities payable to POGC on or before December 31, 2003) toward the $16.0 million commitment, leaving a remaining work commitment of $5.4 million. During 2000, we drilled the Kleka 11, our first Rotliegendes target, which began producing in early 2001. During 2001, we drilled the Mieszkow 1, an exploratory dry hole. The Mieszkow well demonstrated the need to apply modern seismic processing and to assure careful handling of velocities in seismic interpretation. In 2002, we reprocessed approximately 1,200 km of 2-D seismic data that had not previously been processed with modern geophysical techniques, covering most of the Fences area. POGC has since begun reprocessing some of the 3-D data in the Fences I area. In January 2003, we entered into a Farmout Agreement with CalEnergy Gas, the upstream gas business unit of MidAmerican Energy Holdings Company, whereby CalEnergy Gas has the right, but not the obligation, to earn a 24.5% interest by spending a total of $10.6 million, including the cost to drill two wells plus certain cash payments to us, all to be completed by December 15, 2003. CalEnergy Gas also has the right to terminate participation after each of the first two wells. However, if CalEnergy Gas completes all the earning requirements, the work performed and payments will exceed our remaining obligations to POGC to complete our earning requirements in the Fences I project area. However, any such payment to us is pledged to RRPV until the note, with a principal balance of approximately $3.3 million, plus interest, has been satisfied in full. Fences II Project Area The Fences II project area is 670,000 acres (2,715 sq. km) located north of and contiguous with the Fences I block. POGC's 450 Bcf Radlin field forms part of the Fences II southern border. Under a January 2003 agreement, we have the right to earn a 49% interest from POGC, subject to satisfactory completion of our obligations in Fences I. In early 2002, Conoco, Inc., Ruhrgas and POGC drilled a dry hole in the northeast of the Fences II area. The well, although dry, did confirm the presence of reservoir quality Rotliegendes sandstone at a depth of more than 3,700 meters, which makes virtually the entire block prospective for Rotliegendes subject to accurate geophysical resolution of the trapping features. A significant amount of geological and geophysical work was completed by POGC and Conoco before Conoco's withdrawal from the project at the end of 2002. As a result, we were able immediately to begin marketing drill-ready prospects in the Fences II project area. We plan to bring an industry partner into the project as soon as possible, perhaps in time to drill in 2003. We are currently gathering the abundant seismic data for evaluation and possible reprocessing. Later this year, we may acquire new 2-D data to define additional prospects for drilling. Fences III Project Area The Fences III project area is 770,000 acres (3,122 sq. km) located approximately 25 miles south of Fences I. In March 2003, we reached agreement with the Ministry of the Environment in Poland on final principal terms, subject to formal documentation, for 100% of the exploration rights to the Fences III project area. As with the Fences I block, several gas fields located in the Fences III block are fenced off from the exploration acreage. These fields, discovered by POGC between 1967 and 1976, produced from both Rotliegendes sandstone and Zechstein carbonate reservoirs and contained total reserves of approximately 950 Bcf of gas. There has not been an exploration program on this acreage in 25 years. We are currently gathering the seismic data, quite abundant in the northern portion of the block, for evaluation, mapping and possible 6 reprocessing. We will have to carry out a geophysical exploration program to identify leads and prospects that merit drilling. Subject to the availability of funds, we will carry out this work before bringing in a partner. However, as we hold 100% interest in the area, we have greater flexibility and could bring in a partner to help with the geophysical costs if we so elected. The Fences I, II and III project areas (a total of 1.7 million gross acres or 6,911 sq. km) are all within an area of underexplored Rotliegendes sandstone. Cumulative Rotliegendes discoveries in Poland amount to 5 Tcf compared to 42 Tcf in the SNS. An exploration program focused on Rotliegendes gas reserves has not been undertaken in Poland using the technology available today, and no sustained exploration effort has been made in the three Fences project areas for Rotliegendes gas fields in the last 20 years. Pomeranian Project Area We are the operator and have a 100% interest in the Pomeranian project area, except for Block 108, where we have an 85% interest and POGC has a 15% interest. The Pomeranian project area is located in northwestern Poland and consists of exploration rights covering approximately 2.2 million gross acres lying along the underexplored northern edge of the Permian Basin in northwestern Poland. The Pomeranian project area is relatively unexplored and has had little oil and gas production. We believe portions of the Pomeranian project area may be geologically similar to the producing trends along the southern edge of Poland's Permian Basin. In the past, POGC provided us with existing seismic data and well logs and cores from the Pomeranian project area for reprocessing and analysis. During 2000 and 2001, we and our previous partners acquired approximately 600 kilometers of new 2-D seismic data in the Pomeranian project area and drilled two wells: the Tuchola 108-2 and the Chojnice 108-6. An open-hole test on the Tuchola 108-2 resulted in a flow rate of 9.5 MMcf of gas per day from the Main Dolomite Reef formation at a depth between 2,535 meters and 2,595 meters. The Tuchola 108-2 well was subsequently completed in an approximately 200 foot thick section of the Main Dolomite, but remains shut-in. The Chojnice 108-6 was drilled at an offset location approximately three kilometers northwest of the Tuchola 108-2 and was subsequently determined to be an exploratory dry hole. We intend to farm out part of our interest to an industry partner prior to conducting further exploratory activities on the Pomeranian project area. Wilga/Block 255 Project Area The Wilga project area in central southeast Poland consists of exploration rights on approximately 250,000 gross acres held by us, Apache and POGC in Block 255, where the Wilga 2 discovery well is located. We have a 45% working interest in the Wilga project area, which is operated by Apache. Initial production tests on the Wilga 2 yielded a combined gross flow rate of 16.9 MMcf of gas and 570 Bbls of condensate per day from the Carboniferous formation at a depth of approximately 2,800 meters. During 2001, we and our partners successfully completed an extended flow test on the Wilga 2, confirming that the well is capable of quite high rates of production, but the well continues to be shut-in. No further exploration is planned for the block at this time. Polish Properties Legal Framework General Usufruct and Concession Terms In 1994, Poland adopted the Geological and Mining Law, which specifies the process for obtaining domestic exploration and exploitation rights. All of our rights in Poland have been awarded pursuant to this law. Under the Geological and Mining Law, the concession authority enters into oil, gas and mining usufruct (lease) agreements that grant the holder the exclusive right to explore or exploit the designated oil and gas or minerals for a specified period under prescribed terms and conditions. The holder of the mining usufruct must also acquire an exploration concession to obtain surface access to the exploration area by applying to the concession authority and providing the opportunity for comment by local governmental authorities. The concession authority has granted us oil and gas exploration rights on the Wilga and Pomeranian project areas, is expected to do so on the Fences III project area in the near future, and has granted POGC oil and gas 7 exploration rights on the Fences I and II project areas. The agreements divide these areas into blocks, generally containing approximately 250,000 acres each. Concession licenses have been acquired for surface access to all areas that lie within existing usufructs, except Fences III. The first three-year exploration period begins after the date of the last concession signed under each respective usufruct. We believe all material concession terms have been satisfied to date. If commercially viable oil or gas is developed, the concession owner would be required to apply for an exploitation concession, as provided by the usufructs, generally with a term of 25 to 30 years or so long as commercial production continues. Upon the grant of the exploitation concession, the concession owner may become obligated to pay a fee, to be negotiated but expected to be less than 1% of the market value of the estimated recoverable reserves in place. The concession owner would also be required to pay a royalty on any production, the amount of which will be set by the Council of Ministers, within a range established by legislation for the mineral being extracted. The royalty rate for gas is currently $0.03 per Mcf. This rate could be increased or decreased by the Council of Ministers between $0.02 and $0.08 per Mcf (the current statutory minimum and maximum royalty rate). Local governments will receive 60% of any royalties paid on production. The holder of the exploitation concession license must also acquire rights to use the land from the surface owner. The usufruct owner could be subject to significant delays in obtaining the consents of local authorities or satisfying other governmental requirements prior to obtaining an exploitation concession. Fences I Project Area The Fences I project area consists of a single oil and gas exploration concession controlled by POGC. Three producing fields lie within the concession boundaries (Radlin, Kleka and Kaleje), but are excluded from the Fences I project area. The concession is for a period of six years ending in September 2007 and carries a work requirement during the first three years of one exploratory well, 70 square kilometers of 3-D seismic data, and reprocessing of 400 kilometers of 2-D seismic data. The seismic reprocessing requirement has been completed. Fences II Project Area The Fences II project area consists of four oil and gas exploration concessions controlled by POGC. The concessions have expiration dates ranging from July 2004 to August 2007, with three-year extension rights. Remaining work commitments in the aggregate include 70 kilometers of 3-D seismic, 250 kilometers of new 2-D seismic, 100 kilometers of seismic reprocessing and drilling four wells. Fences III Project Area We expect that the formal agreement, when completed, for the Fences III project area will provide for a single oil and gas exploration concession that will be held by us. Several producing fields lie within the concession boundaries, but are excluded from the Fences III project area. The concession will be for a period of six years ending in mid-2009 and will carry a work requirement during the first two years, which will not include any drilling. Wilga/Block 255 Project Area The Wilga project area consists of a single oil and gas exploration concession controlled by Apache. The concession is for a period of six years ending in August 2003, when the concession must be relinquished except for lands within exploitation concessions or for which an application for an exploitation concession has been filed. All work commitments have been completed. Pomeranian Project Area The Pomeranian project area consists of 10 oil and gas concessions controlled by us. The concessions are for a period of six years ending in December 2004, when the concession must be relinquished except for lands within exploitation concessions or for which an application for an exploitation concession has been filed. All work commitments have been completed except for the drilling of one well in 2004. 8 As of December 31, 2002, all required usufruct/concession payments had been made for each of the above project areas. Production, Transportation and Marketing Poland has crude oil pipelines traversing the country and a network of gas pipelines serving major metropolitan, commercial, industrial and gas production areas, including significant portions of our acreage. Poland has a well-developed infrastructure of hard-surfaced roads and railways over which we believe oil produced could be transported for sale. There are refineries in Gdansk and Plock in Poland and one in Germany near the western Polish border that we believe could process crude oil produced in Poland. Should we choose to export any oil or gas we produce, we will be required to obtain prior governmental approval. During early 2001, we and POGC constructed a pipeline from the Kleka 11 well approximately four kilometers to POGC's Radlin field gas processing facility and began selling gas produced to POGC at a price of $2.02 per MMBtu under a five-year contract that may be terminated by us with a 90-day written notice. The Kleka 11 is currently producing at a gross rate of approximately 1.0 MMcf of gas per day. As part of an agreement with POGC, we have agreed to assign our interest in the Kleka 11 well, including amounts representing unpaid gas sales, to POGC as partial settlement of the remaining obligation under our $16.0 million commitment to POGC. Accordingly, we will receive no net gas production from the Kleka 11 well in 2003. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation. The following table sets forth our average net daily gas production, average sales price and average production costs associated with our Polish gas production during 2002 and 2001: 2002 2001 ---- ---- Polish producing property data: Average daily net gas production (Mcf)(1)..... 494 800 Average sales price per Mcf................... $ 1.58 $ 1.58 Average production costs per Mcf(2)........... $ 0.16 $ 0.16 -------------------- (1) Consists solely of the Kleka 11 well, which began producing on February 22, 2001, and which we have now agreed to transfer to POGC. Production was curtailed in 2002 to control the production of water. (2) Production costs include lifting costs (electricity, fuel, water, disposal, repairs, maintenance, pumper, transportation and similar items). Production costs do not include such items as G&A costs, depreciation, depletion or Polish income taxes. We did not have any Polish oil or gas production during 2000. 9 United States Properties Producing Properties In the United States, we currently produce oil in Montana and Nevada. All of our producing properties, except for the Rattlers Butte field (an exploratory discovery during 1997), were purchased during 1994. A summary of our average daily production, average working interest and net revenue interest for our United States producing properties during 2002 follows:
Average Daily Production (Bbls) Average Average ---------------------------- Working Net Revenue Gross Net Interest Interest ------------- -------------- -------------- -------------------- United States producing properties: Montana: Cut Bank............................ 257 220 99.5% 85.7% Bears Den........................... 16 6 48.0 39.2 Rattlers Butte...................... 48 3 6.3 5.1 ------------- -------------- Total............................. 321 229 ------------- -------------- Nevada: Trap Spring......................... 10 2 21.6 20.0 Munson Ranch........................ 40 14 36.0 34.1 Bacon Flat.......................... 36 4 16.9 12.5 ------------- -------------- Total............................. 86 20 ------------- -------------- Total United States producing properties................... 407 249 ============= ==============
In Montana, we operate the Cut Bank and Bears Den fields and have an interest in the Rattlers Butte field, which is operated by an industry partner. Production in the Cut Bank field commenced with the discovery of oil in the 1940s at an average depth of approximately 2,900 feet. The Southwest Cut Bank Sand Unit, which is the core of our interest in the field, was originally formed by Phillips Petroleum Company in 1963. An initial pilot waterflood program was started in 1964 by Phillips and eventually encompassed the entire unit with producing wells on 40 and 80-acre spacing. In the Cut Bank field, we own an average working interest of 99.5% in 93 producing oil wells, 27 active injection wells and one active water supply well. The Bears Den field was discovered in 1929 and has been under waterflood since 1990. In the Bears Den field, we own a 48% working interest in three active water injection wells and five producing oil wells, which produce oil at a depth of approximately 2,430 feet. The Rattlers Butte field was discovered during 1997. In the Rattlers Butte field, we own a 6.3% working interest in two oil wells producing at a depth of approximately 5,800 feet and one active water injection well. In Nevada, we operate the Trap Spring and Munson Ranch fields and have an interest in the Bacon Flat field, which is operated by an industry partner. The Trap Spring field was discovered in 1976. In the Trap Spring field, we produce oil from a depth of approximately 3,700 feet from one well, with a working interest of 21.6%. The Munson Ranch field was discovered in 1988. In the Munson Ranch field, we produce oil at an average depth of 3,800 feet from five wells, with an average working interest of 36%. The Bacon Flat field was discovered in 1981. In the Bacon Flat field, we produce oil from one well at a depth of approximately 5,000 feet, with a 16.9% working interest. 10 Production, Transportation and Marketing The following table sets forth our average net daily oil production, average sales price and average production costs associated with our United States oil production during 2002, 2001 and 2000:
Years Ended December 31, ------------------------------------- 2002 2001 2000 ----------- ----------- ----------- United States producing property data: Average daily net oil production (Bbls).......................... 249 256 265 Average sales price per Bbl...................................... $21.19 $19.41 $26.14 Average production costs per Bbl(1).............................. $14.59 $14.50 $13.99
---------------------- (1) Production costs include lifting costs (electricity, fuel, water, disposal, repairs, maintenance, pumper, transportation and similar items) and production taxes. Production costs do not include such items as G&A costs, depreciation, depletion, state income taxes or federal income taxes. We sell oil at posted field prices to one of several purchasers in each of our production areas. For the first half of 2002 and for the years ended December 31, 2001 and 2000, more than 85% of our total oil sales were to CENEX, a regional refiner and marketer. In June 2002, we began selling our Montana production, which represents over 85% of our total oil sales, to Plains Marketing Canada L.P. Posted prices are generally competitive among crude oil purchasers. Our crude oil sales contracts may be terminated by either party upon 30 days' notice. Oilfield Services - Drilling Rig and Well-Servicing Equipment In Montana, we perform a variety of third-party contract oilfield services, including drilling, workovers, location work, cementing and acidizing. We currently have a drilling rig capable of drilling to a vertical depth of 6,000 feet, a workover rig, two service rigs, cementing equipment, acidizing equipment and other associated oilfield servicing equipment. We first started our oilfield servicing business in 1998 in an effort to increase our United States revenues, which had been declining due to the depressed oil prices that had occurred throughout that year. Proved Reserves Proved reserves are the estimated quantities of crude oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. Our 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, or SEC. 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, 2002, of $25.00 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 estimated present value, discounted at 10% per annum, of the discounted future net cash flows, or PV-10 Value, was determined in accordance with SFAS No. 69 "Disclosure About Oil and Gas Activities" and SEC guidelines. Our proved reserve estimates are subject to continuing revisions as additional information becomes available or assumptions change. Estimates of our proved United States oil reserves were prepared by Larry Krause Consulting, an independent engineering firm in Billings, Montana. Estimates of our proved Polish gas reserves were prepared by Troy-Ikoda Limited, an independent engineering firm in the United Kingdom. No estimates of our proved reserves have been filed with or included in any report to any other federal agency during 2002. 11 The following summary of proved reserve information as of December 31, 2002, represents estimates net to us only and should not be construed as exact:
United States Poland ---------------------------- --------------------------- Total Oil PV-10 Value Gas PV-10 Value PV-10 Value ------------ --------------- ------------ -------------- ------------------ (MBbls) (In thousands) (MMcf) (In thousands) (In thousands) Proved reserves: Developed producing........ 1,015 $ 5,190 1,374 $ 1,066 $ 6,256 Undeveloped................ 27 190 2,836 3,774 3,964 ------------ --------------- ------------ -------------- ------------------ Total.................... 1,042 $ 5,380 4,210 $ 4,840 $10,220 ============ =============== ============ ============== ==================
Drilling Activities The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2002, 2001 and 2000:
Years Ended December 31, ------------------------------------------------------------------- 2002 2001 2000 --------------------- --------------------- --------------------- Gross Net Gross Net Gross Net ---------- ---------- --------- ---------- --------- ---------- Discoveries: United States....................... -- -- -- -- -- -- Poland.............................. -- -- 1.0 0.5 1.0 0.5 ---------- ---------- --------- ---------- --------- ---------- Total............................. -- -- 1.0 0.5 1.0 0.5 ---------- ---------- --------- ---------- --------- ---------- Exploratory dry holes: United States....................... -- -- -- -- -- -- Poland.............................. -- -- 2.0 1.0 2.0 1.0 ---------- ---------- --------- ---------- --------- ---------- Total............................. -- -- 2.0 1.0 2.0 1.0 ---------- ---------- --------- ---------- --------- ---------- Total wells drilled................... -- -- 3.0 1.5 3.0 1.5 ========== ========== ========= ========== ========= ==========
We did not drill any exploratory wells in 2002, and we did not drill any development wells during 2002, 2001 or 2000. Wells and Acreage As of December 31, 2002, our producing gross and net well count consisted of the following:
Number of Wells ------------------------ Gross Net ----------- ----------- Well count: United States(1).................................................................. 118.0 107.2 Poland(2)......................................................................... 1.0 0.5 ----------- ----------- Total........................................................................... 119.0 107.7 =========== ===========
------------------------- (1) All of our United States wells are producing oil wells. We have no gas production in the United States. (2) Includes only the Kleka 11, a producing gas well which we have now agreed to transfer to POGC. 12 The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2002:
Developed Undeveloped ---------------------------- ---------------------------- Gross Net Gross Net ---------------------------- ---------------------------- United States: North Dakota................................. -- -- 7,955 5,351 Montana...................................... 10,732 10,418 1,150 1,057 Nevada....................................... 400 128 37 16 ------------- ------------- ------------- -------------- Total..................................... 11,132 10,546 9,142 6,424 ------------- ------------- ------------- -------------- Poland: (1)(2) Fences I project area(3)..................... 225 110 265,000 130,000 Wilga project area........................... 543 244 250,000 113,000 Pomeranian project area(4)................... -- -- 2,200,000 2,135,000 ------------- ------------- ------------- -------------- Total Polish acreage..................... 768 354 2,715,000 2,378,000 ------------- ------------- ------------- -------------- Total Acreage.................................. 11,900 10,900 2,724,142 2,384,424 ============= ============= ============= ==============
------------------------ (1) All gross undeveloped Polish acreage is rounded to the nearest 50,000 acres and net undeveloped Polish acreage is rounded to the nearest 1,000 acres. (2) Developed acreage in the Fences project areas is attributable only to the Kleka 11 well, which we have now agreed to transfer to POGC. The net acreage amount assumes we spend $16.0 million of exploration expenditures to earn a 49% interest. (3) Excludes acreage in which we may earn an interest under arrangements reached after December 31, 2002. (4) We own a 100% interest in the Pomeranian project area, except for Block 108 (approximately 250,000 acres), where we own an 85% interest. Government Regulation Poland Our activities in Poland are subject to political, economic and other uncertainties, including the adoption of new laws, regulations or administrative policies that may adversely affect us or the terms of our exploration or production rights; political instability and changes in government or public or administrative policies; export and transportation tariffs and local and national taxes; foreign exchange and currency restrictions and fluctuations; repatriation limitations; inflation; environmental regulations and other matters. These operations in Poland are subject to the Geological and Mining Law dated as of September 4, 1994, and the Protection and Management of the Environment Act dated as of January 31, 1980, which are the current primary statutes governing environmental protection. Agreements with the government of Poland respecting our areas create certain standards to be met regarding environmental protection. Participants in oil and gas exploration, development and production activities generally are required to (1) adhere to good international petroleum industry practices, including practices relating to the protection of the environment; and (2) prepare and submit geological work plans, with specific attention to environmental matters, to the appropriate agency of state geological administration for its approval prior to engaging in field operations such as seismic data acquisition, exploratory drilling and field-wide development. Poland's regulatory framework respecting environmental protection is not as fully developed and detailed as that which exists in the United States. We intend to conduct our operations in Poland in accordance with good international petroleum industry practices and, as they develop, Polish requirements. As Poland continues to progress towards its stated goal of becoming a member of the European Union, it is expected to pass further legislation aimed at harmonizing Polish environmental law with that of the European Union. 13 United States State and Local Regulation of Drilling and Production Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. Our oil production is affected to some degree by state regulations. States in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes and related regulations are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit. Environmental Regulations The federal government and various state and local governments have adopted laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. These laws and regulations may also increase the costs of drilling and operation of wells. We may also be held liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990, or OPA `90. In addition, we may be subject to other civil claims arising out of any such incident. As with any owner of property, we are also subject to clean-up costs and liability for hazardous materials, asbestos or any other toxic or hazardous substance that may exist on or under any of our properties. We believe that we are in compliance in all material respects with such laws, rules and regulations and that continued compliance will not have a material adverse effect on our operations or financial condition. Furthermore, we do not believe that we are affected in a significantly different manner by these laws and regulations than our competitors in the oil and gas industry. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Furthermore, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. The Resource Conservation and Recovery Act, or RCRA, and regulations promulgated thereunder govern the generation, storage, transfer and disposal of hazardous wastes. RCRA, however, excludes from the definition of hazardous wastes "drilling fluids, produced waters and other wastes associated with the exploration, development, or production of crude oil, gas or geothermal energy." 14 Because of this exclusion, many of our operations are exempt from RCRA regulation. Nevertheless, we must comply with RCRA regulations for any of our operations that do not fall within the RCRA exclusion. The OPA `90 and related regulations impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA `90 establishes strict liability for owners of facilities that are the site of a release of oil into "waters of the United States." While OPA `90 liability more typically applies to facilities near substantial bodies of water, at least one district court has held that OPA `90 liability can attach if the contamination could enter waters that may flow into navigable waters. Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future, such as proposals made in Congress and at the state level from time to time, that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes" and make the reclassified wastes subject to more stringent and costly handling, disposal and clean-up requirements. The impact of any such changes, however, would not likely be any more burdensome to us than to any other similarly situated company involved in oil and gas exploration and production. Federal and Indian Leases A substantial part of our producing properties in Montana consist of oil and gas leases issued by the Bureau of Land Management or by the Blackfeet Tribe under the supervision of the Bureau of Indian Affairs. These activities must comply with rules and orders that regulate aspects of the oil and gas industry, including drilling and operating on leased land and the calculation and payment of royalties to the federal government or the governing Indian nation. Operations on Indian lands must also comply with applicable requirements of the governing body of the tribe involved including, in some instances, the employment of tribal members. We believe we are currently in full compliance with all material provisions of such regulations. Safety and Health Regulations We must also conduct our operations in accordance with various laws and regulations concerning occupational safety and health. Currently, we do not foresee expending material amounts to comply with these occupational safety and health laws and regulations. However, since such laws and regulations are frequently changed, we are unable to predict the future effect of these laws and regulations. Title to Properties We rely on sovereign ownership of exploration rights and mineral interests by the Polish government in connection with our activities in Poland and have not conducted and do not plan to conduct any independent title examination. We regularly consult with our Polish legal counsel when doing business in Poland. Nearly all of our United States working interests are held under leases from third parties. We typically obtain a title opinion concerning such properties prior to the commencement of drilling operations. We have obtained such title opinions or other third-party review on nearly all of our producing properties, and we believe that we have satisfactory title to all such properties sufficient to meet standards generally accepted in the oil and gas industry. Our United States properties are subject to typical burdens, including customary royalty interests and liens for current taxes, but we have concluded that such burdens do not materially interfere with the use of such properties. Further, we believe the economic effects of such burdens have been appropriately reflected in our acquisition cost of such properties and reserve estimates. Title investigation before the acquisition of undeveloped properties is less thorough than that conducted prior to drilling, as is standard practice in the industry. Employees and Consultants As of December 31, 2002, we had 28 employees, consisting of six in Salt Lake City, Utah; 19 in Oilmont, Montana; one in Greenwich, Connecticut; and two in Houston, Texas. Our employees are not represented by a collective bargaining 15 organization. We consider our relationship with our employees to be satisfactory. We also regularly engage technical consultants to provide specific geological, geophysical and other professional services. Offices and Facilities Our corporate offices, located at 3006 Highland Drive, Salt Lake City, Utah, contain approximately 3,010 square feet and are rented at $2,960 per month under a month-to-month agreement. In Montana, we own a 16,160 square foot building located at the corner of Central and Main in Oilmont, where we utilize 4,800 square feet for our field office and rent the remaining space to unrelated third parties for $875 per month. In Poland, we rent a small office suite for $1,400 per month in Warsaw, at Al. Jana Pawla II 29, as an office of record in Poland. Oil and Gas Terms The following terms have the indicated meaning when used in this Report: "Bcf" means billion cubic feet of natural gas. "Bbl" means barrel of oil. "Btu" means British thermal units. "Carried" or "Carry" refers to an agreement under which one party (carrying party) agrees to pay for all or a specified portion of costs of another party (carried party) on a property in which both parties own a portion of the working interest. "Condensate" means a light hydrocarbon liquid, generally natural gasoline (C5 to C10), that condenses to a liquid (i.e., falls out of wet gas) as the wet gas is sent through a mechanical separator near the well. "Development well" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "Exploratory well" means a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. "Field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic conditions. "Gross" acres and "gross" wells means the total number of acres or wells, as the case may be, in which an interest is owned, either directly or though a subsidiary or other Polish enterprise in which we have an interest. "Horizon" means an underground geological formation that is the portion of the larger formation that has sufficient porosity and permeability to constitute a reservoir. "MBbls" means thousand barrels of oil. "Mcf" means one cubic foot of natural gas. "MMBbls" means million barrels of oil. "MMBtu" means million British thermal units, a unit of heat energy used to measure the amount of heat that can be generated by burning gas or oil. 16 "MMcf" means million cubic feet of natural gas. "Net" means, when referring to wells or acres, the fractional ownership working interests held by us, either directly or through a subsidiary or other Polish enterprise in which we have an interest, multiplied by the gross wells or acres. "Proved reserves" means the estimated quantities of crude oil, gas and gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. "Proved reserves" may be developed or undeveloped. "PV-10 Value" means the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10.0%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non property-related expenses, such G&A costs, debt service, future income tax expense or depreciation, depletion and amortization. "Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and that is distinct and separate from other reservoirs. "Tcf" means trillion cubic feet of natural gas. -------------------------------------------------------------------------------- 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. -------------------------------------------------------------------------------- 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, 2002. 17 PART II -------------------------------------------------------------------------------- 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: Low High --- ---- 2003: First Quarter (through March 20, 2003)........... $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 2001: Fourth Quarter................................... 1.81 3.00 Third Quarter.................................... 2.55 3.20 Second Quarter................................... 2.91 6.20 First Quarter.................................... 3.50 5.94 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 March 20, 2003, we had approximately 4,100 stockholders. Our common stock is currently traded on the Nasdaq SmallCap Market under the symbol FXEN. Recent Sales of Unregistered Securities In August 2002, we granted to certain directors, executive officers and key employees options to purchase an aggregate of 551,000 shares of common stock at $2.40 per share at any time on or before seven years after the date of grant. In June 2002, we issued to two persons an aggregate of 20,682 shares of common stock as payment for services rendered. On the date of this transaction, the market price for our common stock was approximately $2.15. On March 13, 2003, we sold 2,250,000 shares of 2003 Series Convertible Preferred Stock in a private placement of securities, raising a total of approximately $5.6 million after offering costs. Each share of preferred stock is convertible into one share of common stock and one warrant to purchase one share of common stock at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The preferred stock has a liquidation preference equal to the sales price for the shares, which was $2.50 per share. The net proceeds from the offering, plus our available cash, will be used to reduce our obligation to RRPV by approximately $2.2 million (see 18 discussion of RRPV note amendment below), partially reduce our obligation to POGC, fund ongoing geological and geophysical costs in Poland, and support ongoing prospect marketing and general and administrative costs. The foregoing transactions were the result of arm's-length negotiations with accredited investors who were provided with our business and financial information, including copies of our periodic reports as filed with the Securities and Exchange Commission, and who were provided with the opportunity to ask questions directly of our executive officers. Transactions involving the issuances of stock to persons who, at the time of such transactions, were either executive officers, directors, principal stockholders or other affiliates are noted. In each case of the issuance of stock to affiliates, unless otherwise noted, such affiliates purchased stock on the same terms at which stock was sold to unrelated parties in contemporaneous transactions, and such transactions were approved unanimously by the disinterested directors. In each instance, 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. 19 -------------------------------------------------------------------------------- ITEM 6. SELECTED FINANCIAL DATA -------------------------------------------------------------------------------- The following selected consolidated financial data for the five years ended December 31, 2002, are derived from our audited financial statements and notes thereto, certain of which are included in this report. The selected consolidated financial data should be read in conjunction with our Consolidated Financial Statements and the Notes thereto included elsewhere in this report:
Years Ended December 31, --------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ------------ ------------ ------------ ------------ (In thousands, except per share amounts) Statement of Operations Data: Revenues: Oil and gas sales....................... $ 2,209 $ 2,229 $ 2,521 $ 1,554 $ 1,124 Oilfield services....................... 533 1,584 1,290 865 323 Gain on sale of property interests...... -- -- -- -- 467 ----------- ------------ ------------ ------------ ------------ Total revenues........................ 2,742 3,813 3,811 2,419 1,914 ----------- ------------ ------------ ------------ ------------ Operating costs and expenses: Lease operating costs (1)............... 1,365 1,358 1,349 962 1,046 Exploration costs (2)................... 1,541 6,544 7,389 3,053 2,127 Proved property impairment (3).......... 1,038 -- -- -- 5,885 Oilfield services costs................. 540 1,301 1,084 642 240 Depreciation, depletion and amortization.......................... 618 662 386 494 672 Amortization of deferred compensation (G&A).................... 55 1,078 652 -- -- Apache Poland general and administrative costs.................. -- 575 957 -- -- General and administrative.............. 2,440 883 2,654 2,962 2,572 ----------- ------------ ------------ ------------ ------------ Total operating costs and expenses.. 7,597 12,401 14,471 8,113 12,542 ----------- ------------ ------------ ------------ ------------ Operating loss............................ (4,855) (8,588) (10,660) (5,694) (10,628) ----------- ------------ ------------ ------------ ------------ Other income (expense): Interest and other income............... 119 543 557 511 506 Interest expense........................ (1,189) (331) (2) (7) -- Impairment of notes receivable.......... -- (34) (738) (666) -- ----------- ------------ ------------ ------------ ------------ Total other income (expense)........ (1,070) 178 (183) (162) 506 ----------- ------------ ------------ ------------ ------------ Net loss.................................. $ (5,925) $ (8,410) $ (10,843) $ (5,856) $ (10,122) =========== ============ ============ ============ ============ Basic and diluted net loss per share: Net loss.............................. $ (0.34) $ (0.48) $ (0.66) $ (0.41) $ (0.78) =========== ============ ============ ============ ============ Basic and diluted weighted average shares outstanding...................... 17,641 17,673 16,435 14,199 12,979
- Continued - 20
Years Ended December 31, ----------------------------------------------------------- 2002 2001 2000 1999 1998 ------------ ----------- ---------- ---------- ----------- (In thousands) Cash Flow Statement Data: Net cash used in operating activities............... $ (2,162) $ (3,248) $ (6,082) $ (2,984) $ (3,091) Net cash provided by (used in) investing activities. (295) 326 (3,834) (3,678) 1,066 Net cash provided by (used in) financing activities. 5 5,000 9,375 6,469 (674) Balance Sheet Data: Working capital..................................... $ (9,150) $ 558 $ 616 $ 5,459 $ 3,965 Total assets........................................ 5,441 9,168 10,570 10,470 8,253 Long-term debt...................................... -- 4,907 -- -- -- Stockholders' equity................................ (4,869) 953 8,231 8,367 6,920 -----------------------------
(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. -------------------------------------------------------------------------------- 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 As of December 31, 2002, we had approximately $700,000 of cash and cash equivalents, a working capital deficit of approximately $9.2 million, and a stockholders' deficit of approximately $4.9 million. In addition, we have a remaining commitment of $5.6 million that must be spent by us (in addition to payment of the $4.4 million to POGC, which is included in our accrued liabilities at December 31, 2002), in order to complete our earning obligation in our Fences project areas. These factors cause uncertainty about our ability to continue as a going concern. Since December 31, 2002, we have substantially improved our overall financial position and prospects for achieving a sound financial condition by obtaining $5.6 million in equity funding, reaching new terms respecting our Fences 1 obligations, extending our RRPV obligation with revised terms and entering into a farmout agreement with CalEnergy Gas under which it may provide cash and drilling funds of up to $10.6 million. Our primary obligations through the end of 2003 include $3.3 million principal amount plus interest due RRPV at year end, $4.4 million plus interest due POGC at year end, $5.6 million of Fences I work commitment, and approximately $1.8 million for general, administrative and marketing expenses, for a total of approximately $16.0 million, plus any geological and geophysical costs we may wish to expend. Offsetting these amounts, we have $3.8 million in available cash and may look forward to other sources of funds including $10.6 million of work and cash that may be realized under the CalEnergy Farmout Agreement, $0.6 million in accrued Kleka 11 production revenue, and an amount to be determined (PV-10 value $1.1 million) for the future value of Kleka 11 production, for an approximate total of approximately $16.0 million. In addition, we have the right to earn a 49% interest in the Fences II project area and anticipate completing documentation soon for a 100% interest in the Fences III project area. We believe we can 21 arrange with industry partners to trade a portion of our interest in these properties for drilling funds and cash payments that will exceed our related acquisition or earning and any related geological and geophysical costs. Despite our financial condition, we believe these events have substantially improved our ability to continue as a going concern. Private Placement of Convertible Preferred Stock On March 13, 2003, we sold 2,250,000 shares of 2003 Series Convertible Preferred Stock in a private placement of securities, raising a total of $5.6 million after offering costs. Each share of preferred stock is convertible into one share of common stock and one warrant to purchase one share of common stock at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The preferred stock has a liquidation preference equal to the sales price for the shares, which was $2.50 per share. The net proceeds from the offering, plus our available cash, were used to reduce our obligation to RRPV (see discussion of RRPV note amendment below), fund ongoing geological and geophysical costs in Poland, and support ongoing prospect marketing and general and administrative costs. 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 has the right, but not the obligation, to pay 100% of the costs to drill an initial well, and by so doing, will earn a 24.5% interest (50% of our interest) in that drilling prospect. Following the completion of the initial well, CalEnergy Gas may elect to terminate the agreement or to drill a second well. If CalEnergy Gas elects to drill a second well, it will pay us $1 million prior to drilling. CalEnergy Gas will pay 100% of the costs to drill a second well to earn 24.5% interest in that prospect. Following the second well, CalEnergy Gas has the option to acquire 24.5% (50% of our interest) of the entire Fences project area by paying to us the sum of $10.6 million, less the costs of drilling the first two wells and less the cost of any additional geological and geophysical costs it has incurred on the Fences area. Any such payment to us is pledged to RRPV, until its note, with a principal balance of approximately $3.3 million, plus interest, has been satisfied in full. We expect the net proceeds to us to be approximately $5.6 million before the end of 2003, from which we will be obligated to pay RRPV. All of the costs related to our 49% interest in the project area that are paid for by CalEnergy Gas will be credited against the remaining $5.6 million obligation under our $16.0 million work obligation to POGC (see below). CalEnergy Gas has received consent from POGC concerning the transfer of our working interest according to the agreement terms, and RRPV has committed to permit the transfer, free of any lien or encumbrance, of 50% of our interest to CalEnergy Gas. We expect drilling to commence in the second quarter of 2003. Fences I Settlement Agreement On April 11, 2000, we agreed to spend $16.0 million of exploration costs on the Fences project areas to earn a 49% interest. When expenditures exceed $16.0 million, POGC will pay its 51% share of further costs. Through the end of 2001, we had paid $6.7 million towards the $16.0 million commitment. As of December 31, 2001, we had accrued $2,678,477 of additional costs pertaining to the Fences project areas. 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. In connection with this agreement, we agreed to recognize in 2002, and pay at a future date, an additional $2.3 million of costs related to prior exploration activities in the Fences project areas to POGC, $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. 22 In addition, as part of our future payments towards the remaining commitment, we have agreed to assign in 2003, as soon as is practicable, 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 $606,986 was offset against the POGC liability. The liability will be further offset in 2003 by the value of the remaining gas reserves associated with the Kleka well, as determined by an independent engineer. Lastly, we 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 as of March 21, 2003, was 10.4%. Rolls-Royce Power Ventures In early 2003, we reached an agreement with RRPV to amend its 9.5% Convertible Secured Note in the amount of $5.0 million (see Footnote 6 in the financial statements). Our current liabilities at December 31, 2002, include the $5.0 million principal balance, plus accrued interest of $392,000. The note is secured by a lien on our Fences I and Wilga property interests and was repayable in March 2003, unless converted to common stock at $5.00 per share or otherwise amended. In March 2003, following our successful private placement of convertible preferred stock, we paid $2.2 million to RRPV. In return, RRPV extended the maturity date of the note to December 31, 2003. We have also agreed to pay 40% of the gross proceeds of any subsequent equity or debt offering concluded prior to the amended maturity date to RRPV. We also agreed to assign our rights to payments under the CalEnergy Gas agreement to RRPV, except for those amounts related to drilling the two wells. All such payments will be used to offset the remaining principal and interest. In exchange for these payments, RRPV agreed to release its lien on interests earned by CalEnergy Gas under its agreement with us. The loan amendment contains 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, and an extension fee payment of $100,000. Cost Reduction Measures In mid-2002, we recognized that it would likely require an extended period to consummate a farmout transaction with our Fences I project and our ability to raise additional equity/debt would be restricted until such an arrangement was in place. We further recognized the importance of reducing our overhead expenses to conserve cash while in discussions with potential partners. Effective July 1, 2002, we undertook several measures to reduce our ongoing expenses. We cut the salaries of all key employees by 50% and did not replace employees who left the Company. We also reduced the level of benefits available to all employees. We cut other areas of overhead expenses where possible. In addition to our overhead reductions, we significantly reduced the amount of money designated for ongoing seismic and other exploration costs. Summary Despite our financial condition, because of the events described above, we believe that we are well-positioned to obtain additional funding and continue as a going concern. There can be no assurance that we will be able to obtain additional financing or successfully complete the necessary steps to enable us to continue as a going concern. If we are unable to obtain sufficient funds to satisfy our future cash requirements, we may be forced to curtail operations further, dispose of assets, issue securities to meet obligations, or seek extended payment terms from our creditors. Such events would materially and adversely affect our financial position and results of operations and result in the dilution of the interests of existing stockholders. 23 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. 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. 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, 2002, 2001 and 2000, respectively, follows. Further information concerning our business segments can be found in Note 13, Business Segments, in the financial statements. 24 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, 2002, 2001 and 2000, is set forth in the following table:
For the year ended December 31, ---------------------------------------------------------------------------- 2002 2001 2000 -------------------------------------------------- ------------------------- Oil Gas Oil Gas Oil Gas -------------------------------------- ----------- ------------ ------------ Revenues.............................. $1,924,000 $ 285,000 $ 1,835,000 $ 394,000 $ 2,521,000 $ -- Percent change versus prior year.... +4.9% -27.7% -28.0% +100% +62.2% Average price (Bbls or Mcf)(1)........ $ 21.19 $ 1.58 $ 19.41 $1.58 $ 26.14 $ -- Percent change versus prior year.... +9.2% -- -25.8% +100% +70.3% Production volumes (Bbls or Mcf)...... 90,817 180,407 94,522 249,661 96,416 -- Percent change versus prior year.... -3.9% -27.7% -1.9% +100% -4.8% Lifting costs per Bbls or Mcf(2)...... $ 14.28 $ 0.16 $ 13.62 $ .16 $ 12.13 $ -- Percent change versus prior year.... +4.8% -- +12.3% -- +36.6% -----------------------
(1) The contract price for gas during 2002 and 2001, prior to adjusting for actual physical content of Btu, was $2.02 per MMBtu. (2) Lifting costs per barrel are computed by dividing the related lease operating expenses by the total barrels of oil produced after royalties. 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 $1.9 million, $1.8 million and $2.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. Essentially 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, the degree of maintenance performed, and the declining production rates attributable to the natural production declines of our producing properties. 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 2000. The Kleka 11, our first producing well in Poland, began producing during February 2001. During 2002 and 2001, gas produced by the Kleka 11 was sold to POGC based on U.S. dollar pricing 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 $1.4 million for each of the years ended December 31, 2002, 2001 and 2000. Operating costs rose slightly from 2001 to 2002, as higher oil lifting costs offset lower oil and gas production. Operating costs rose from 2000 levels in 2001 due to the commencement of production from the Kleka well in Poland, as well as higher per unit oil lifting costs. 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 $2.6 million, $6.5 million and $7.4 million for the years ended December 31, 2002, 2001 and 2000, respectively. Limited available capital in 2002 caused us to sharply curtail our exploration activities in Poland. Subject to the commencement of drilling activities under the CalEnergy Gas agreement and our ability secure additional equity/debt financing, exploration costs will continue to be curtailed in the near term. G&G costs were $1.0 million, $2.9 million and $4.7 million for the years ended December 31, 2002, 2001 and 2000, respectively. During 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, $552,000 acquiring and analyzing 2-D seismic data on the Pomeranian project area, and granted stock options valued at $36,000 to a Polish consultant. During 2000, we spent approximately $2.1 million on acquiring 3-D seismic data in the Fences project areas, approximately $477,000 on acquiring and analyzing 2-D seismic data on the 25 Lublin Basin, Pomeranian and Warsaw West project areas, and granted stock options valued at approximately $81,000 to a Polish consultant. Under terms of the Poland 2001 Agreement Credit, Apache covered our share of additional G&G costs totaling $53,000 and $19,000 during 2001 and 2000, respectively. Exploratory dry-hole costs were $0, $3.1 million and $2.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. Due to our capital limitations, we did not participate in any exploratory drilling in 2002. During 2001, we incurred costs of $3.1 million pertaining to the Mieszkow 1 well on the Fences project areas. In accordance with FASB No. 19, we have classified the Mieszkow 1 as an exploratory dry hole for financial reporting purposes, because further operations have been suspended since drilling, pending the reprocessing and interpretation of 3-D seismic data in order to evaluate the economic feasibility of additional drilling operations at the well site. During 2000, we drilled the Wilga 3 and Wilga 4 wells near our Wilga 2 discovery on the Wilga project area, both of which were subsequently determined to be exploratory dry holes. The two wells cost a net amount of $1.1 million and $900,000, respectively, after Apache covered one-half of our 45% share of drilling costs under terms of the Apache Exploration Program. Impairments of oil and gas properties were $1.5 million, $584,000 and $674,000 for the years ended December 31, 2002, 2001 and 2000, respectively. During 2002, we incurred an impairment of $509,000 in costs associated with the Tuchola 108-2 well. A preliminary open-hole test in early January 2001 on the well resulted in a flow rate of 9.5 MMcf of gas per day from the Main Dolomite Reef formation at a depth between 2,535 meters and 2,595 meters. The flow rate was limited by the capacity of the surface equipment. The well was subsequently completed in an approximately 200 foot thick section of the Main Dolomite, 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, and FASB No. 19 requires well costs to be impaired if more than one year elapses from drilling to production. We also recognized an impairment of $1.0 million in costs 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. During 2000, we incurred impairments of $674,000 for the Williston Basin in North Dakota, where we also no longer have exploration plans. Impairments will vary from period to period based on our determination that capitalized costs of unproved properties, on a property-by-property basis, are not realizable. 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, $575,000 and $957,000 for the years ended December 31, 2002, 2001 and 2000. During mid-2001, we began to narrow the focus of our ongoing exploratory efforts relating to the Apache Exploration Program by including only the Pomeranian and Wilga project areas and discontinued our exploratory activities on the Lublin Basin, Warsaw West and Carpathian project areas. Prior to July 1, 2000, Apache covered all of our pro rata share of Apache Poland G&A costs. Effective July 1, 2000, we began paying approximately 35% of Apache Poland G&A costs, to be adjusted as each of Apache's remaining drilling requirements were completed. Apache has since completed its remaining drilling requirements, and we are now responsible only for our 45% share of Apache Poland G&A costs relating to ongoing, jointly conducted activities in the Wilga project area in Poland for which Apache is the operator, subject to a preapproved annual budget. In addition to the above amounts, Apache covered our share of additional Apache Poland G&A costs totaling $464,000 and $33,000 during 2001 and 2000, respectively, under terms of the Poland 2001 Agreement Credit. 26 Poland 2001 Agreement Credit. Under an amendment to the Apache Exploration Program effective January 1, 2001, referred to as the Poland 2001 Agreement, Apache agreed to issue to us a credit that included Apache covering $932,000 of our share of joint costs in Poland (other than carried costs) in return for the release of Apache's commitment to cover our share of costs to shoot 339 kilometers of 2-D seismic data in the Carpathian project area. During 2001 and 2000, we used the entire Poland 2001 Agreement Credit, as shown below:
Poland 2001 Agreement Credit ----------------------------------------------- 2001 2000 Total --------------- --------------- --------------- Cost category: Geological and geophysical costs......................... $ 53,000 $ 19,000 $ 72,000 Exploratory dry hole costs............................... 25,000 (3,000) 22,000 Apache Poland general and administrative costs........... 464,000 33,000 497,000 Leasehold costs.......................................... -- 65,000 65,000 Tuchola 108-2 completion costs........................... 276,000 -- 276,000 --------------- --------------- --------------- Total.................................................. $ 818,000 $ 114,000 $ 932,000 =============== =============== ===============
DD&A Expense - Producing Operations. DD&A expense for producing properties was $281,000, $322,000 and $73,000 for the years ended December 31, 2002, 2001 and 2000, respectively. DD&A expense incurred during 2002 and 2001 includes approximately $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 2000. The DD&A rate per barrel for oil produced in the United States was $0.89, $0.69 and $0.76 during 2002, 2001 and 2000, respectively. The differences between the DD&A rates per barrel from year to year are primarily the result of changes in oil reserve estimates computed as of December 31 of each year. Oilfield Services Segment Oilfield Services Revenues. Oilfield services revenues were $0.5 million, $1.6 million and $1.3 million for the years ended December 31, 2002, 2001 and 2000, respectively. Oilfield services revenues increased from 2000 to 2001 due to improved market conditions and an increased emphasis on using our oilfield servicing equipment for contract third-party services rather than servicing company-owned properties. Conversely, the contract drilling industry was significantly curtailed in the area where we operate in 2002, and our revenues declined sharply 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 Servicing Costs. Oilfield services costs were $0.5 million, $1.3 million and $1.1 million for the years ended December 31, 2002, 2001 and 2000, respectively, or 100%, 82% and 84% of oilfield servicing revenues, respectively. Oilfield services costs as a percentage of oilfield services revenues were relatively flat during 2001, as compared to 2000. During 2002, oilfield servicing costs were a higher percentage of oilfield services revenues, as compared to 2001, due to increased 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 $310,000, $308,000 and $247,000 for the years ended December 31, 2002, 2001 and 2000, respectively. We spent $116,000, $248,000 and $779,000 on upgrading our oilfield servicing equipment during 2002, 2001 and 2000, respectively. Nonsegmented Items Amortization of Deferred Compensation (G&A). Amortization of deferred compensation was $55,000, $1.1 million and $652,000 during the years ended December 31, 2002, 2001 and 2000, respectively. On April 5, 2001, we extended 27 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 have all been amortized as of December 31, 2002. G&A Costs - Corporate. G&A costs were $2.4 million, $883,000, and $2.7 million for the years ended December 31, 2002, 2001 and 2000, respectively. During 2001, G&A costs were $1.8 million lower than 2000 G&A costs, primarily due to the Company writing off $1.7 million of compensation that was accrued as of December 31, 2000. Without the write-offs, G&A costs during 2001 would have been approximately $3.5 million. During 2002, in recognition of our limited resources, we aggressively pursued the cost reduction measures described earlier, resulting in costs lower than 2001, excluding the $1.7 million write-off during that year, and actual 2000 costs. Interest and Other Income - Corporate. Interest and other income was $119,000, $514,000 and $557,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Our cash, cash equivalent and marketable debt securities balances were $0.7 million, $3.2 million and $2.4 million as of December 31, 2002, 2001 and 2000, respectively. Lower cash balances and interest rates in 2002 and 2001 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 amortizing an option premium resulting from granting RRPV an option to purchase gas from our properties in Poland. Interest Expense. Interest expense was $1.2 million, $331,000 and $2,000 for the years ended December 31, 2002, 2001 and 2000, respectively. During, 2002 and 2001, we recorded $93,000 and $341,000, respectively, of imputed interest expense relating to our financing arrangement with RRPV. On March 9, 2002, we began to accrue interest on the $5.0 million RRPV obligation at an annual rate of 9.5%. Impairment of Notes Receivable. Impairment of notes receivable was $0, $34,000, and $738,000 for the years ended December 31, 2002, 2001 and 2000, respectively. In accordance with SFAS No. 114 "Accounting by Creditors for Impairment of a Loan," the notes receivable carrying value must be adjusted at the end of each reporting period to reflect the market value of the underlying collateral. On November 8, 2000, a former employee exercised an option to purchase 52,000 shares of our 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 us 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 our common stock in return for cancellation of the note receivable. We recorded a loss of $34,060 on the transaction and the acquisition of 52,000 shares of common stock at a price of $2.63 per share, the closing price of our stock on November 8, 2001. Also during 2000, two of our officers surrendered collateral shares to us in return for the cancellation of the notes receivable from those officers that were outstanding on December 28, 2000. The officers' notes included principal and interest of $2.2 million reduced by a cumulative impairment allowance of $1.4 million based on the market value of 233,340 shares of the our common stock held as collateral. As a result of the transaction, we recorded the acquisition of 233,340 shares of treasury stock at a cost of $773,000. There were no notes receivable or related impairments thereof in 2002. Income Taxes. We incurred net losses of $5.9 million, $8.4 million and $10.8 million for the years ended December 31, 2002, 2001 and 2000, 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. 28 Liquidity and Capital Resources As of December 31, 2002, we had approximately $700,000 of cash and cash equivalents, a working capital deficit of approximately $9.2 million, and a stockholders' deficit of approximately $4.9 million. In addition, we have a remaining work commitment of $5.6 million that must be spent by us (in addition to payment of the $4.4 million to POGC, which is included in our accrued liabilities at December 31, 2002) in order to complete our earning obligation in our Fences project areas. Our financial position as of December 31, 2002, raises uncertainty about our ability to continue as a going concern. We have made significant progress in several areas toward improving our liquidity and capital resources discussed in detail at the beginning of this MD&A section. We raised $5.6 million from the recent sale of equity securities, we extended the due dates on the RRPV note and the accrued liability to POGC, we arranged to reduce our liability to POGC by the value of our interest in the Kleka 11 well, and we signed a farmout agreement with CalEnergy Gas that, if CalEnergy Gas fully earns half our interest in Fences I, will result in $10.6 million of work commitments performed and cash paid to us. In addition, we recently obtained the right to earn a 49% interest in the Fences II project area and anticipate completing documentation soon for a 100% interest in the Fences III project area. We believe we can arrange with industry partners to trade a portion of our interest in these properties for drilling funds and cash payments that will exceed our related costs. Although, notwithstanding these measures, there remains uncertainty about our ability to continue as a going concern, we believe the prospect of eliminating that uncertainty during the current year has been substantially improved. To date, we have financed our operations principally through the sale of equity securities, issuance of debt securities, and agreements with industry partners that funded our share of costs in certain exploratory activities in order to earn an interest in our properties. The continuation of our exploratory efforts in Poland is dependent on our ability to raise additional capital or to farm out our properties. The availability of such capital or farmouts will affect the timing, pace, scope and amount of our future capital expenditures. If we are unable to arrange farmouts for the Fences II and Fences II project areas, or having done so, if the results of operations there are disappointing, or if CalEnergy Gas's drilling program is unsuccessful, or if CalEnergy Gas elects not to pursue that drilling program, or if other disappointing events should occur, there can be no assurance that we will be able to secure additional partners or obtain additional equity or debt financing. We may also not be able to further reduce expenses or successfully complete other steps to continue as a going concern. If we are unable to obtain sufficient funds to satisfy our future cash requirements, we may be forced to curtail operations, dispose of assets, or seek extended payment terms from our vendors. 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 partners, 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 that we cannot predict. 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 $(9.2) million as of December 31, 2002, a decrease of $9.7 million from December 31, 2001. In accordance with the terms of our RRPV loan agreement, the entire principal amount of $5.0 million, plus accrued interest, was due on March 9, 2003, unless RRPV earlier converted the loan to restricted common stock at $5.00 per share, the market value of our common stock at the time the terms with RRPV were finalized. Accordingly, the entire balance of the RRPV note, along with interest accrued through December 31, 2002, is shown as a current liability on the balance sheet. As discussed above, we reached an agreement with RRPV to extend the maturity date of the loan until December 31, 2003. 29 Our current liabilities also include $4.4 million of costs related to our Fences project in Poland. In 2000, we agreed to spend $16.0 million of exploration costs on this project area, which is owned and operated by POGC, in order to earn a 49% interest. As of December 31, 2002, we have made cash payments of approximately $6.7 million pertaining to the required $16.0 million, in addition to the amount accrued at year-end. Operating Activities. We used net cash of $2.1 million, $3.1 million and $6.1 million in our operating activities during 2002, 2001 and 2000, respectively, primarily as a result of the net losses incurred in those years. The declining use of cash in operations is also a reflection of a systematic reduction in exploration costs, as our resources have become limited over time. Investing Activities. We used net cash of $295,000 in investing activities during 2002, received net cash of $326,000 from our investing activities during 2001, and used net cash of $3.9 million in investing activities during 2000. 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. During 2000, we spent $7.7 million on various additions to both proved and unproved properties, and spent $779,000 on additions to oilfield servicing equipment. We also received a net of $4.0 million net from transactions in marketable debt securities. Financing Activities. We received net cash of $4,500, $5.0 million and $9.4 million from our financing activities during 2002, 2001 and 2000, respectively. During 2001, we received $5.0 million pertaining to our RRPV loan and gas purchase option agreement. Also, during 2001, we acquired 52,000 shares of common stock at a cost of $137,000 in a noncash transaction. During 2000, we received net proceeds of $9.3 million ($10.4 million gross) from the private placement of 2,969,000 shares of our common stock, and received $103,000 in cash and $156,000 in the form of a full recourse promissory note secured by 52,000 shares of our common stock from the exercise of options and warrants to purchase 95,572 shares of our common stock. Also, during 2000, we acquired 233,340 shares of treasury stock at a cost of $773,000 in a noncash transaction Contractual Obligations and Contingent Liabilities and Commitments The following is a summary of our significant contractual obligations and commitments as of December 31, 2002 (in thousands): Contractual Obligations and Commitments Due by December 31, 2003 --------------------------------------- ------------------------ (In thousands) Note Payable (RRPV).......................... $ 5,000 plus interest(1) Fences I work commitment(2).................. 5,600 Cash payment to POGC(2)...................... 4,400 plus interest ------------------------ Total.................................. $ 15,000 plus interest(1) ========================= -------------------- (1) In March 2003, we paid RRPV $2.2 million, which reduced the balance due to approximately $3.3 million, plus interest. (2) The Fences I work commitment and the cash payment to POGC are required in order for us to meet our commitment to earn a 49% interest in the Fences I project area. 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 partners 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. 30 Risk Factors Our business is subject a number of material risks, including the following: o Our success depends on our discovery of commercial quantities of oil or gas in Poland. To date in Poland, our exploration efforts have resulted in one producing well (the Kleka 11, which we have recently agreed to transfer to POGC), two discoveries (the Wilga 2 and Tuchola 108-2, both shut-in), and 12 exploratory dry holes. Our success will depend on our ability to generate drilling prospects that result in the discovery of commercial quantities of oil or gas and the establishment of reserves. We cannot predict whether any prospect we identify may contain reserves, whether we can assemble the financial and other resources to complete drilling or other exploration, or whether any gas or oil we discover can be produced and marketed commercially. o We will continue to require additional capital. We will rely principally on proceeds from the sale of securities and farmout or other industry-sharing arrangements for planned exploration, appraisal, development and property acquisition programs in Poland. Obtaining additional financing may dilute the interest of our existing stockholders or our interest in the specific project being financed. We cannot assure that additional funds could be obtained or, if obtained, would be on terms favorable to us. o Funding activities may limit our activities. Our capital expenditure budget for 2003 for the payment of POGC, completion of earning requirements in Fences I, repayment of RRPV, geophysical and geological work, and prospect marketing and other operating costs exceeds our current resources. Therefore, we will be able to complete our planned activities only if we are able to obtain additional financing. If we cannot obtain required additional financing, we may be forced to curtail our activities sharply in order to continue. o Our loan agreement with RRPV restricts our flexibility. We have encumbered certain of our property interests in Poland to secure repayment of the remaining $3.3 million balance, plus interest, due RRPV by December 31, 2003. Unless converted to common stock at $3.42 per share, we may have to raise additional capital to repay the loan. The loan will have to be repaid notwithstanding our other cash requirements or the potentially greater financial return from other expenditures. In addition, our agreements with RRPV contain financial and operating covenants that are customary for transactions of this nature, including limitations on additional indebtedness. Our agreement with RRPV also specifies usual and customary events of default. o We face a number of other risks, including: - Continuing world political instability and the threat or existence of armed hostilities involving the United States and major oil and gas producers may adversely affect our ability to obtain required financing, enter into farmout or other exploration arrangements with industry partners, or complete planned exploration. - The exploration models, tools and concepts we are applying in Poland have not been fully tested in that geological setting, which increases exploration risk and cost. - We cannot accurately predict the oil or gas potential of any prospect, test or discovery. - We will continue to be dependent on the technical expertise and financial resources of our exploration partners in Poland, particularly CalEnergy Gas and POGC, who act as the operators of specific projects. - Our activities in Poland are subject to uncertainties related to its governmental policies and Poland's continuing economic growth and the implementation of its long-term privatization strategy. 31 New Accounting Pronouncements In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 is effective for us beginning January 1, 2003. The most significant impact of this standard to us will be a change in the method of accruing for site restoration costs. Under SFAS No. 143, the fair value of asset retirement obligations will be recorded as liabilities when they are incurred, which are typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the capitalized costs will be depreciated over the useful lives of the related assets. We are currently evaluating the impact of adopting SFAS No. 143. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liabilities Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). This statement requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS No. 146 will be effective for exit or disposal activities that are initiated after December 31, 2002. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation Transition and Disclosure." This statement amends FASB Statement No. 123, or SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure provisions of SFAS No. 123 to require prominent disclosure in both annual and interim financial statements about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. As we will continue to account for stock-based compensation according to APB 25, adoption of SFAS No. 148 will require us to provide prominent disclosures about the effects of SFAS No. 123 on reported income and will require disclosure of these affects in the interim financial statements as well. SFAS No. 148 is effective for the financial statements for fiscal years ending after December 15, 2002, and subsequent interim periods. We believe that the adoption of this standard will have no material impact on our operating results and financial position. In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, which expands on the accounting guidance of Statements Nos. 5, 57, and 107 and incorporates without change the provisions of FASB Interpretation No. 34, which is being superseded. This interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. In addition, guarantors are required to make significant new disclosures, even if the likelihood of the guarantor making payments under the guarantee is remote. The interpretation's disclosure requirements are effective for the Company as of December 31, 2002. The recognition requirements of FIN 45 are to be applied prospectively to guarantees issued or modified after December 31, 2002. The Company has no significant guarantees and the adoption of this interpretation did not have a material impact on the Company's financial statements. In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"), Consolidation of Variable Interest Entities. The objective of this interpretation is to provide guidance on how to identify a variable interest entity and determine when the assets, liabilities, noncontrolling interests and results of operations of a variable interest entity need to be included in a company's consolidated financial statements. A company that holds variable interests in an entity will need to consolidate the entity if the company's interest in the variable interest entity is such that the company will absorb a majority of the variable interest entity's expected losses and/or receive a majority of the entity's expected residual returns, if they occur. The provisions of this interpretation became effective upon issuance. As of December 31, 2002, the Company did not have any variable interest entities that will be subject to FIN 46. 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. 32 -------------------------------------------------------------------------------- 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. Our gas production in Poland is currently being sold to POGC based on U.S. dollar pricing under a five-year contract that may be terminated by us with a 90-day written notice. The limited volume and single source of our gas production means we cannot assure uninterruptible production or production in amounts that would be meaningful to industrial users, which may depress the price we may be able to obtain. There is currently no competitive market for the sale of gas in Poland. Accordingly, we expect that the prices we receive for the gas we produce will be lower than would be the case in a competitive setting and may be lower than prevailing western European prices, at least until a fully competitive market develops in Poland. We currently do not engage in any hedging activities or have any derivative financial instruments to protect ourselves against market risks associated with oil and gas price fluctuations, although we may elect to do so if we achieve a significant amount of production in Poland. 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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -------------------------------------------------------------------------------- Our financial statements, including the accountant's report, are included beginning at page F-1 immediately following the signature page of this report. 33 -------------------------------------------------------------------------------- ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE -------------------------------------------------------------------------------- We have not disagreed on any items of accounting treatment or financial disclosure with our auditors. 34 PART III -------------------------------------------------------------------------------- ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT -------------------------------------------------------------------------------- The information from the definitive proxy statement for the 2003 annual meeting of stockholders under the caption "Election of Directors: Executive Officers, Directors and Nominees" and "Compliance with Section 16(a) of the Exchange Act" is incorporated herein by reference. -------------------------------------------------------------------------------- ITEM 11. EXECUTIVE COMPENSATION -------------------------------------------------------------------------------- The information from the definitive proxy statement for the 2003 annual meeting of stockholders under the caption "Election of Directors: Executive Compensation" is incorporated herein by reference. -------------------------------------------------------------------------------- ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS -------------------------------------------------------------------------------- The information from the definitive proxy statement for the 2003 annual meeting of stockholders under the caption "Election of Directors: Security Ownership of Certain Beneficial Owners and Management" is incorporated herein by reference. -------------------------------------------------------------------------------- ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS -------------------------------------------------------------------------------- The information from the definitive proxy statement for the 2003 annual meeting of stockholders under the caption "Election of Directors: Certain Relationships and Related Transactions" is incorporated herein by reference. -------------------------------------------------------------------------------- ITEM 14. CONTROLS AND PROCEDURES -------------------------------------------------------------------------------- Disclosure controls are procedures that are designed with an objective of ensuring that information required to be disclosed in our periodic reports filed with the SEC, such as this Annual Report on Form 10-K, is recorded, processed, summarized and reported within the time periods specified by the SEC. Disclosure controls are also designed with an objective of ensuring that such 35 information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, in order to allow timely consideration regarding required disclosures. The evaluation of our disclosure controls by the Chief Executive Officer and Chief Financial Officer included a review of the controls' objectives and design, the operation of the controls, and the effect of the controls on the information presented in this Annual Report. Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that disclosure controls can or will prevent or detect all errors and all fraud, if any. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Also, projections of any evaluation of the disclosure controls and procedures to future periods are subject to the risk that the disclosure controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on their review and evaluation as of a date within 90 days of the filing of this Form 10-K, and subject to the inherent limitations all as described above, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934) are effective. They are not aware of any significant changes in our disclosure controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. 36 PART IV -------------------------------------------------------------------------------- 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 F-1: Page ----- Report of Independent Accountants........................... F-1 Consolidated Balance Sheets as of December 31, 2002 and 2001.................................................. F-2 Consolidated Statements of Operations for each of the Three Years Ended December 31, 2002, 2001 and 2000, respectively.............................................. F-3 Consolidated Statements of Cash Flows for each of the Three Years Ended December 31, 2002, 2001 and 2000, respectively.............................................. F-5 Consolidated Statements of Stockholders' Equity (Deficit) for each of the Three Years Ended December 31, 2002, 2001 and 2000, respectively.................................... F-6 Notes to the Consolidated Financial Statements.............. F-7 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:
SEC Exhibit Reference Number* Number Title of Document Location ---------- ----------- ------------------------------------------------------------------------- ----------------- Item 3. Articles of Incorporation and Bylaws ------------------------------------------------------------------------------------------------- 3.01 3 Restated and Amended Articles of Incorporation Incorporated by Reference(1) 3.02 3 Bylaws Incorporated by Reference(2) Item 4. Instruments Defining the Rights of Security Holders ------------------------------------------------------------------------------------------------- 4.01 4 Specimen Stock Certificate Incorporated by Reference(2) 4.02 4 Form of Designation of Rights, Privileges, and Preferences of Series A Incorporated by Preferred Stock Reference(3) 4.03 4 Form of Rights Agreement dated as of April 4, 1997, between FX Energy, Incorporated by Inc. and Fidelity Transfer Corp. Reference(3) 4.04 4 Form of Designation of Rights, Privileges, and Preferences of 2003 This filing Series Convertible Preferred Stock 4.05 4 Specimen Stock Certificate for 2003 Series Convertible Preferred Stock This filing 37 SEC Exhibit Reference Number* Number Title of Document Location ---------- ----------- ------------------------------------------------------------------------- ----------------- Item 10. Material Contracts ------------------------------------------------------------------------------------------------- 10.05 10 Mining Usufruct Agreement between the State Treasury of the Republic of Incorporated by Poland and Lubex Petroleum Company Sp. z o.o. dated December 20, Reference(4) 1996, relating to concession blocks 255 and others (Wilga) 10.10 10 Mining Usufruct Agreement between the State Treasury of the Republic of Incorporated by Poland and FX Energy Poland Sp. z o.o. and Partners, commercial Reference(5) partnership, dated October 30, 1997, related to concession blocks 85, 86, 87, 88, 89, 105,108, 109, 129 and 149 in northwestern Poland (Pomeranian) 10.26 10 Frontier Oil Exploration Company 1995 Stock Option and Award Plan** Incorporated by Reference(6) 10.27 10 Form of FX Energy, Inc. 1996 Stock Option and Award Plan** Incorporated by Reference(4) 10.28 10 Form of FX Energy, Inc. 1997 Stock Option and Award Plan** Incorporated by Reference(7) 10.29 10 Form of FX Energy, Inc. 1998 Stock Option and Award Plan** Incorporated by Reference(7) 10.30 10 Employment Agreements between FX Energy, Inc. and each of David Pierce Incorporated by and Andrew Pierce, effective January 1, 1995** Reference(2) 10.31 10 Amendments to Employment Agreements between FX Energy, Inc. and each of Incorporated by David Pierce and Andrew Pierce, effective May 30, 1996** Reference(8) 10.32 10 Form of Stock Option with related schedule (D. Pierce and A. Pierce)** Incorporated by Reference(2) 10.33 10 Form of Stock Option granted to D. Pierce and A. Pierce** Incorporated by Reference(2) 10.34 10 Form of Non-Qualified Stock Option with related schedule** Incorporated by Reference(6) 10.39 10 Employment Agreement between FX Energy, Inc. and Jerzy B. Maciolek** Incorporated by Reference(8) 10.40 10 Addendum to Employment Agreement between FX Energy, Inc. and Jerzy B. Incorporated by Maciolek** Reference(9) 10.41 10 Second Addendum to Employment Agreement between FX Energy, Inc. and Incorporated by Jerzy B. Maciolek** Reference(9) 10.42 10 Employment Agreement between FX Energy, Inc. and Scott J. Duncan** Incorporated by Reference(9) 10.43 10 Form of Indemnification Agreement between FX Energy, Inc. and certain Incorporated by directors, with related schedule** Reference(4) 10.44 10 Form of Option granted to executive officers and directors, with Incorporated by related schedule** Reference(4) 10.52 10 Form of Indemnification Agreement between FX Energy, Inc. and certain Incorporated by directors, with related schedule** Reference(7) 38 SEC Exhibit Reference Number* Number Title of Document Location ---------- ----------- ------------------------------------------------------------------------- ----------------- 10.53 10 Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Incorporated by Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Reference(10) Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to Fences project area 10.55 10 Option extensions with related schedules** Incorporated by Reference(11) 10.57 10 US$5,000,000 9.5% Convertible Secured Note dated as of March 9, 2001 Incorporated by Reference(12) 10.58 10 Form of Pledge Agreement FX Energy Poland Sp. z o.o. and Rolls Royce Incorporated by Power Ventures Limited dated March 9, 2001, and related schedules Reference(12) 10.59 10 Sales / Purchase Agreement Special Provisions between Plains Marketing This filing Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002 10.60 10 Form of Non-Qualified Stock Option awarded August 14, 2002, with This filing related schedule** 10.61 10 Description of compensation arrangement with Thomas B. Lovejoy and This filing outside directors** 10.62 10 Agreement Regarding Cooperation within the Poznan Area (Fences II) This filing entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o. 10.63 10 Settlement Agreement Regarding the Fences Area entered into January 8, This filing 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o. 10.64 10 Farmout Agreement Entered into by and between FX Energy Poland This filing Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. Covering the "Fences Area" in the Foresudetic Monocline made as of January 9, 2003 10.65 10 Letter Agreement between Rolls-Royce Power Ventures Limited and FX This filing Energy, Inc. dated February 6, 2003 10.66 10 Amendment Agreement No. 1 to 9.5% Convertible Secured Note between FX This filing Energy, Inc. and Rolls-Royce Power Ventures Limited dated March 10, 2003 Item 21 Subsidiaries of the Registrant ------------------------------------------------------------------------------------------------- 21.01 21 Schedule of Subsidiaries Incorporated by Reference(9) Item 23 Consents of Experts and Counsel ------------------------------------------------------------------------------------------------- 23.01 23 Consent of PricewaterhouseCoopers LLP, independent accountants This filing 23.02 23 Consent of Larry D. Krause, Petroleum Engineer This filing 23.03 23 Consent of Troy-Ikoda Limited, Petroleum Engineers This filing 39 SEC Exhibit Reference Number* Number Title of Document Location ---------- ----------- ------------------------------------------------------------------------- ----------------- Item 99 Miscellaneous ---------- ----------- ------------------------------------------------------------------------- 99.01 99 Certification of Principal Executive Officer This filing 99.02 99 Certification of Principal Financial Officer This filing --------------------------------
* 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. (1) Incorporated by reference from the proxy statement respecting the 1997 annual meeting of stockholders. (2) Incorporated by reference from the registration statement on Form SB-2, SEC File No. 33-88354-D. (3) Incorporated by reference from the report on Form 8-K dated April 4, 1997. (4) Incorporated by reference from the annual report on Form 10-KSB for the year ended December 31, 1996. (5) Incorporated by reference from the quarterly report on Form 10-QSB for the quarter ended September 30, 1997. (6) Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended September 30, 1995. (7) Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 1999. (8) Incorporated by reference from the registration statement on Form S-1, SEC File No.333-05583. (9) Incorporated by reference from the annual report on Form 10-KSB for the year ended December 31, 1997. (10) Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended March 31, 2000. (11) Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended September 30, 2000. (12) Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2000. (b) Reports on Form 8-K. During the quarter ended December 31, 2002, we filed the following item on Form 8-K: Date of Event Reported Item(s) Reported --------------------------- ------------------------------------------ October 28, 2002 Item 5. Other Events 40 -------------------------------------------------------------------------------- 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. Dated: March 26, 2003 FX ENERGY, INC. (Registrant) /s/ David N. Pierce ------------------------------ David N. Pierce, President and Chief Executive Officer Dated: March 26, 2003 /s/ Thomas B. Lovejoy ------------------------------ Thomas B. Lovejoy Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Dated: March 26, 2003 /s/ David N. Pierce ---------------------------- David N. Pierce, Director /s/ Andrew W. Pierce ---------------------------- Andrew W. Pierce, Director ---------------------------- Jerzy B. Maciolek, Director /s/ Thomas B. Lovejoy ---------------------------- Thomas B. Lovejoy, Director /s/ Scott J. Duncan ---------------------------- Scott J. Duncan, Director /s/ Peter L. Raven ---------------------------- Peter L. Raven, Director /s/ Clay Newton ---------------------------- Clay Newton, Director 41 CERTIFICATIONS I, David N. Pierce, certify that: 1. I have reviewed this annual report on Form 10-K of FX Energy, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 26, 2003 /s/ David N. Pierce ----------------------------- David N. Pierce Principal Executive Officer 42 CERTIFICATIONS I, Thomas B. Lovejoy, certify that: 1. I have reviewed this annual report on Form 10-K of FX Energy, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 26, 2003 /s/ Thomas B. Lovejoy ---------------------------- Thomas B. Lovejoy Principal Financial Officer 43 REPORT OF INDEPENDENT ACCOUNTANTS 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, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. /s/ PricewaterhouseCoopers LLP Salt Lake City, Utah March 13, 2003 F-1
FX ENERGY, INC. AND SUBSIDIARIES Consolidated Balance Sheets As of December 31, 2002 and 2001 2002 2001 ----------------- ---------------- ASSETS Current assets: Cash and cash equivalents............................................................ $ 705,012 $ 3,157,427 Receivables: Accrued oil sales................................................................ 238,236 478,857 Joint interest and other receivables............................................. 36,893 49,075 Inventory............................................................................ 84,262 87,260 Other current assets................................................................. 95,726 95,004 ----------------- ---------------- Total current assets......................................................... 1,160,129 3,867,623 ----------------- ---------------- Property and equipment, at cost: Oil and gas properties (successful efforts method): Proved........................................................................... 4,754,377 4,789,252 Unproved......................................................................... 154,261 655,523 Other property and equipment......................................................... 3,683,226 3,587,433 ----------------- ---------------- Gross property and equipment..................................................... 8,591,864 9,032,208 Less accumulated depreciation, depletion and amortization............................ (4,685,487) (4,090,293) ----------------- ---------------- Net property and equipment................................................... 3,906,377 4,941,915 ----------------- ---------------- Other assets: Certificates of deposit.............................................................. 356,500 356,500 Deposits............................................................................. 18,072 2,789 ----------------- ---------------- Total other assets........................................................... 374,572 359,289 ----------------- ---------------- Total assets............................................................................. $ 5,441,078 $ 9,168,827 ================= ================ -Continued- The accompanying notes are an integral part of these consolidated financial statements F-2
FX ENERGY, INC. AND SUBSIDIARIES Consolidated Balance Sheets As of December 31, 2002 and 2001 -Continued- 2002 2001 ----------------- ---------------- LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable..................................................................... $ 376,264 $ 492,306 Accrued liabilities.................................................................. 4,933,393 2,816,561 Note payable......................................................................... 5,000,000 -- ----------------- ---------------- Total current liabilities.................................................... 10,309,657 3,308,867 Long-term debt: Note payable......................................................................... -- 4,906,916 ----------------- ---------------- Total liabilities............................................................ 10,309,657 8,215,783 ----------------- ---------------- Commitments (Note 7) Stockholders' equity (deficit): Preferred stock, $.001 par value, 5,000,000 shares authorized as of December 31, 2002 and 2001; no shares outstanding................................ -- -- Common stock, $.001 par value, 100,000,000 shares authorized as of December 31, 2002 and 2001; 17,651,917 and 17,913,575 shares issued as of December 31, 2002 and 2001, respectively......................................... 17,652 17,914 Treasury stock, at cost, 0 and 233,340 shares as of December 31, 2002 and 2001, respectively............................................................... -- (909,815) Deferred compensation from stock option modifications................................ -- (54,688) Additional paid in capital........................................................... 49,049,025 49,910,078 Accumulated deficit.................................................................. (53,935,256) (48,010,445) ----------------- ---------------- Total stockholders' equity (deficit) ........................................ (4,868,579) 953,044 ----------------- ---------------- Total liabilities and stockholders' equity (deficit) .................................... $ 5,441,078 $ 9,168,827 ================= ================ The accompanying notes are an integral part of these consolidated financial statements F-3
FX ENERGY, INC. AND SUBSIDIARIES Consolidated Statements of Operations For the years ended December 31, 2002, 2001 and 2000 2002 2001 2000 ---------------- ----------------- ---------------- Revenues: Oil and gas sales.................................................. $ 2,208,916 $ 2,229,064 $ 2,520,779 Oilfield services.................................................. 533,438 1,583,811 1,290,055 ---------------- ----------------- ---------------- Total revenues................................................. 2,742,354 3,812,875 3,810,834 ---------------- ----------------- ---------------- Operating costs and expenses: Lease operating expenses........................................... 1,365,454 1,358,304 1,348,399 Geological and geophysical costs................................... 1,030,660 2,909,270 4,679,391 Exploratory dry hole costs......................................... -- 3,051,334 2,034,206 Impairment of oil and gas properties............................... 1,547,860 583,855 674,158 Oilfield services costs............................................ 539,783 1,300,713 1,084,129 Depreciation, depletion and amortization........................... 617,937 661,644 385,807 Amortization of deferred compensation (G&A)........................ 54,688 1,077,547 652,489 Apache Poland general and administrative costs..................... -- 575,303 956,936 Other general and administrative costs (G&A)....................... 2,440,528 882,985 2,654,430 ---------------- ----------------- ---------------- Total operating costs and expenses............................. 7,596,910 12,400,955 14,469,945 ---------------- ----------------- ---------------- Operating loss......................................................... (4,854,556) (8,588,080) (10,659,111) ---------------- ----------------- ---------------- Other income (expense): Interest and other income.......................................... 118,961 542,824 557,080 Interest expense................................................... (1,189,216) (330,816) (2,422) Impairment of notes receivable..................................... -- (34,060) (738,177) ---------------- ----------------- ---------------- Total other income (expense)................................... (1,070,255) 177,948 (183,519) ---------------- ----------------- ---------------- Net loss.............................................................. $ (5,924,811) $ (8,410,132) $ (10,842,630) ================ ================= ================ Basic and diluted net loss per share................................... $ (0.34) $ (.48) $ (.66) ================ ================= ================ Basic and diluted weighted average number of shares Outstanding........................................................ 17,641,335 17,672,684 16,435,436 ================ ================= ================ The accompanying notes are an integral part of these consolidated financial statements F-4
FX ENERGY, INC. AND SUBSIDIARIES Consolidated Statements of Cash Flows For the years ended December 31, 2002, 2001 and 2000 2002 2001 2000 ---------------- ----------------- ---------------- Cash flows from operating activities: Net loss........................................................... $ (5,924,811) $ (8,410,132) $ (10,842,630) Adjustments to reconcile net loss to net cash used in Operating activities: Depreciation, depletion and amortization................... 617,937 661,644 385,807 Impairment of oil and gas properties....................... 1,547,860 583,855 674,158 Impairment of notes receivable............................. -- 34,060 738,177 Accrued interest income from notes receivable.............. -- (14,820) (140,359) Gain (loss) on property dispositions....................... -- (28,864) -- Exploratory dry hole costs................................. -- 3,051,334 2,034,206 Common stock and stock options issued for services......... 44,000 35,653 80,813 Amortization of deferred compensation (G&A)................ 54,688 1,077,547 652,489 Increase (decrease) from changes in working capital items: Receivables.................................................... 252,803 (101,280) 74,496 Inventory...................................................... 2,998 660 (21,559) Other current assets........................................... (722) (14,691) 45,693 Accounts payable and accrued liabilities....................... 1,243,345 (122,696) 236,757 ---------------- ----------------- ---------------- Net cash used in operating activities...................... (2,161,902) (3,247,730) (6,081,952) ---------------- ----------------- ---------------- Cash flows from investing activities: Additions to oil and gas properties................................ (161,195) (754,500) (6,988,314) Additions to other property and equipment.......................... (118,535) (245,414) (812,340) Net change in other assets......................................... (15,283) -- -- Proceeds from sale of property interests........................... -- 44,040 -- Purchase of marketable debt securities............................. -- -- (6,314,990) Proceeds from marketable debt securities........................... -- 1,281,993 10,282,000 ---------------- ----------------- ---------------- Net cash provided by (used) in investing activities............ (295,013) 326,119 (3,833,644) ---------------- ----------------- ---------------- Cash flows from financing activities: Proceeds from loan and gas purchase option agreement............... -- 5,000,000 -- Proceeds from issuance of common stock, net of offering costs...... -- -- 9,272,453 Proceeds from exercise of stock options and warrants............... 4,500 -- 102,944 ---------------- ----------------- ---------------- Net cash provided by financing activities...................... 4,500 5,000,000 9,375,397 ---------------- ----------------- ---------------- Net increase or (decrease) in cash and cash equivalents................ (2,452,415) 2,078,389 (540,199) Cash and cash equivalents at beginning of year......................... 3,157,427 1,079,038 1,619,237 ---------------- ----------------- ---------------- Cash and cash equivalents at end of year............................... $ 705,012 $ 3,157,427 $ 1,079,038 ================ ================= ================ The accompanying notes are an integral part of these consolidated financial statements F-5
FX ENERGY, INC. AND SUBSIDIARIES Consolidated Statement of Stockholders' Equity (Deficit) For the years ended December 31, 2002, 2001 and 2000 Common Stock Notes and Notes Deferred ------------------- Interest Receivable Compensation Total Par Value Receivable From Stock from Additional Stockholders' Shares $.001 Per Treasury from Option Stock Option Paid in Accumulated Equity Issued Share Stock Officers Exercise Modifications Capital Deficit (Deficit) ----------- ------- --------- ----------- --------- ----------- ----------- ------------ ----------- Balance as of December 31, 1999 14,849,003 $14,849 -- $(1,370,873) -- -- $38,480,556 $(28,757,683) $ 8,366,849 Sale of common stock, net of offering costs 2,969,000 2,969 -- -- -- -- 9,269,484 -- 9,272,453 Exercise of stock options and warrants 95,572 96 -- -- -- -- 258,848 -- 258,944 Interest on notes receivable -- -- -- (140,359) -- -- -- -- (140,359) Impairment of notes receivable from officers -- -- -- 738,177 -- -- -- -- 738,177 233,340 shares tendered for payment of notes receivable and accrued interest -- -- $(773,055) 773,055 -- -- -- -- -- Recourse note from stock option exercise -- -- -- -- $(156,000) -- -- -- (156,000) Deferred compensation from stock option modifications -- -- -- -- -- $(1,565,974) 1,565,974 -- -- Amortization of deferred compensation -- -- -- -- -- 652,489 -- -- 652,489 Options issued for services -- -- -- -- -- -- 80,813 -- 80,813 Net loss for year -- -- -- -- -- -- -- (10,842,630) (10,842,630) ----------- ------- --------- ----------- --------- ----------- ----------- ------------ ----------- Balance as of December 31, 2000 17,913,575 17,914 (773,055) -- (156,000) (913,485) 49,655,675 (39,600,313) 8,230,736 Interest on notes receivable -- -- -- -- (14,820) -- -- -- (14,820) Impairment of notes receivable -- -- -- -- 34,060 -- -- -- 34,060 52,000 shares tendered for payment of notes receivable and accrued interest -- -- (136,760) -- 136,760 -- -- -- -- Deferred compensation from stock option modifications -- -- -- -- -- (218,750) 218,750 -- -- Amortization of deferred compensation -- -- -- -- -- 1,077,547 -- -- 1,077,547 Options issued for services -- -- -- -- -- -- 35,653 -- 35,653 Net loss for year -- -- -- -- -- -- -- (8,410,132) (8,410,132) ----------- ------- --------- ----------- --------- ----------- ----------- ------------ ----------- Balance as of December 31, 2001 17,913,575 17,914 (909,815) -- -- (54,688) 49,910,078 (48,010,445) 953,044 ----------- ------- --------- ----------- --------- ----------- ----------- ------------ ----------- Retirement of treasury stock (285,340) (285) 909,815 -- -- -- (909,530) -- -- Amortization of deferred compensation -- -- -- -- -- 54,688 -- -- 54,688 Common stock issued for services 20,682 20 -- -- -- -- 43,980 -- 44,000 Exercise of stock options 3,000 3 -- -- -- -- 4,497 -- 4,500 Net loss for year -- -- -- -- -- -- -- (5,924,811) (5,924,811) ----------- ------- --------- ----------- --------- ----------- ----------- ------------ ----------- Balance as of December 31, 2002 17,651,917 $17,652 $ -- $ -- $ -- $ -- $49,049,025 $(53,935,256) $(4,868,579) =========== ======= ======== =========== ========= ========== =========== ============ =========== The accompanying notes are an integral part of these consolidated financial statements F-6
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, 2002, 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. 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. 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, 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 dismantlement, restoration and abandonment costs and the anticipated proceeds from equipment salvage. The estimated dismantlement, restoration and abandonment costs are expected to be substantially offset by the estimated residual value of lease and well equipment. Effective January 1, 2003 under SFAS 143, the carrying amount of assets will be increased by their respective retirement obligations. An F-7 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - 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:
December 31, Estimated ---------------------------- Useful Life 2002 2001 (in years) ------------- ------------- ------------- (In thousands) Other property and equipment: Oilfield servicing equipment................................... $ 2,824 $ 2,730 6 Trucks......................................................... 262 262 5 Building....................................................... 96 96 40 Office equipment and furniture................................. 501 499 3 to 6 ------------- ------------- Total cost 3,863 3,587 ============= ============= Accumulated depreciation (2,819) (2,502) ============= ============= Net property and equipment................................. $ 864 $ 1,085 ============= =============
Supplemental Disclosure of Cash Flow Information Non-cash investing and financing transactions not reflected in the consolidated statements of cash flows include the following:
Year Ended December 31, ----------------------------------- 2002 2001 2000 ---------- ----------- ----------- (In thousands) Non-cash investing transactions: Additions to properties included in current liabilities................ $ 851 $ 999 $ -- Non-cash consideration received from the sale of equipment............. -- -- 23 ---------- ----------- ----------- Total.............................................................. $ 851 $ 999 $ 23 ========== =========== =========== Non-cash financing transactions: Shares tendered for payment of notes receivable and accrued interest... $ -- $ 137 $ 773 Recourse note receivable from stock option exercise.................... -- -- 156 ---------- ----------- ----------- Total.............................................................. $ -- $ 137 $ 929 ========== =========== =========== Supplemental disclosure of cash paid for interest and income taxes: Year Ended December 31, ----------------------------------- 2002 2001 2000 ---------- ----------- ----------- (In thousands) Supplemental disclosure: Cash paid during the year for interest................................ $ 1 $ 2 $ 2 Cash paid during the year for income taxes............................ -- -- --
F-8 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - 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." As of December 31, 2002, the Company had 5,544,017 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:
2002 2001 2000 ------------- ------------- ------------- (In thousands, except per share amounts) Net loss: Net loss, as reported.............................................. $ (5,925) $ (8,410) $ (10,843) Add: stock-based employee compensation expense included in reported net loss, net of related tax effects.................... 55 1,078 652 Less: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects....................................... (1,125) (1,515) (1,890) ------------- ------------- ------------- Pro forma net loss............................................ $ (6,995) $ (8,847) $ (12,081) ============= ============= ============= Basic and diluted net loss per share: As reported................................................... $ (0.34) $ (0.48) $ (0.66) Pro forma..................................................... (0.40) (0.50) (0.74)
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 2002, 2001 and 2000 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 90% for 2002, 78% to 83% for 2001 and 80% to 87% for 2000; (2) expected lives ranging from four to seven years; (3) risk-free interest rates at the date of grant ranging from 3.26% to 4.24%; and, (4) dividend yield of zero for each year. Income Taxes Deferred income taxes are provided for the difference between the tax basis of an asset or liability and its reported amount in the financial statements. Such difference may result in taxable or deductible amounts in future years when the reported amount of the asset or liability is recovered or settled, respectively. Reclassifications Certain balances in the 2001 and 2000 financial statements have been reclassified to conform to the current year presentation. These changes had no effect on total assets, total liabilities, stockholders' equity or net loss. F-9 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - 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 unaudited 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 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. Outstanding options and warrants as of December 31, 2002, 2001 and 2000 were as follows: Options and Warrants Price Range ------------ --------------- Balance sheet date: December 31, 2002.................... 5,544,017 $1.50 - $10.25 December 31, 2001.................... 5,785,585 $1.50 - $10.25 December 31, 2000.................... 4,572,917 $1.50 - $10.25 The Company had a net loss in 2002, 2001 and 2000. The above options and warrants were not included in the computation of diluted earnings per share for 2002, 2001 or 2000 because the effect would have been antidilutive. Note 2: Liquidity and Capital Resources The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern and do not include any adjustments to reflect the possible future effects on the recoverability of assets and liquidation of liabilities that may result from this uncertainty. The Company has incurred substantial operating losses and negative cash flows from operations since inception and had an accumulated deficit of approximately $54 million at December 31, 2002. These matters raise substantial doubt about the Company's ability to continue as a going concern. To date, the Company has financed its operations principally through the sale of equity securities, issuance of debt securities and through agreements with industry partners that funded the Company's share of costs in certain exploratory activities in order to earn an interest in the Company's properties. As of December 31, 2002, the Company had $705,012 of cash and cash equivalents, negative working capital of $(9,149,528) including debt due to Rolls Royce Power Ventures ("RRPV") with a principal amount of $5.0 million due on or before March 9, 2003. In addition, the Company has agreed to spend $16.0 million of exploration costs on the Fences I project area to earn a 49.0% interest. Through the end of 2002, the Company had paid $6.7 million towards the $16.0 million commitment, leaving a remaining cash commitment to POGC of $9.3 million. Subsequent to December 31, 2002, the Company has amended its loan agreement with RRPV (see Note 6) and raised approximately $5.6 million through the sale of its convertible preferred stock (see Note 17). In addition, the Company entered into a Farmout Agreement with CalEnergy Gas whereby CalEnergy Gas has the right, but not the obligation, to earn a 24.5% interest (50% of the Company's interest) in the Fences I project area by spending a total of $10.6 million, including the cost to drill two wells plus certain cash payments to the Company, all to be F-10 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - completed by December 15, 2003. CalEnergy Gas also has the right to terminate participation after each of the first two wells. However, if CalEnergy Gas completes all the earning requirements, the work performed and payments will exceed the Company's remaining obligations to POGC to complete its earning requirements in the Fences I project area. The Company's long-term success or failure is largely dependent on the outcome of its exploration, production and acquisition activities in Poland. The Company's ability to continue its ongoing oil and gas activities in Poland is dependent on accessing additional capital directly or through further farmouts. The availability of such capital will effect the timing, pace, scope and amount of the Company's future capital expenditures. There can be no assurance the Company will be able to obtain additional financing, reduce expenses or successfully complete other steps to continue as a going concern. If the Company is unable to obtain sufficient funds to satisfy its cash requirements, it may be forced to curtail operations, dispose of assets or seek extended payment terms from its vendors. Such events would materially and adversely affect the Company's financial position and results of operations. Note 3: Investment in Marketable Debt Securities The Company follows the provisions of SFAS No. 115 "Accounting for Certain Investments in Debt and Equity Securities." The Company's marketable debt securities with remaining contractual maturities of less than twelve months are classified as available for sale. The Company had no investment in debt and equity securities at December 31, 2002. Note 4: Performance Bond Deposits As of December 31, 2002 and 2001, the Company had a replacement bond to 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. Note 5: Accrued Liabilities The Company's accrued liabilities as of December 31, 2002 and 2001 were comprised of the following:
December 31, ---------------------------- 2002 2001 ------------- ------------- (In thousands) Accrued liabilities: Exploratory dry hole costs................................................... $ 880 $ 880 Drilling costs............................................................... 433 -- Seismic costs................................................................ 1,859 1,798 Pipeline costs .............................................................. 502 -- Interest payable, POGC ...................................................... 704 -- Interest payable, RRPV ...................................................... 392 -- Other costs.................................................................. 163 139 ------------- ------------- Total.................................................................... $ 4,933 $ 2,817 ============= =============
Note 6: Notes Payable On March 9, 2001, the Company signed a $5.0 million, 9.5% loan agreement and gas purchase option agreement with 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, 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 is due on or before March 9, 2003, unless RRPV elects to convert the loan to restricted common stock at $5.00 per share, the market value of the Company's common stock at the time the terms with RRPV were finalized, 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. F-11 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - For financial reporting purposes, the Company imputed interest expense for the first year at 9.5%, or $433,790, to be amortized ratably over the one-year interest free period 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 $2.2 million to RRPV. In return, RRPV extended the maturity date of the note to December 31, 2003. The Company has also agreed to pay 40% of the gross proceeds of any subsequent equity or debt offering concluded prior to the amended maturity date to RRPV. The Company also agreed to assign its rights to payments under the CalEnergy Gas agreement to RRPV, except for those amounts relating to the two wells required to be drilled under the agreement. All such payments will be used to offset the remaining principal and interest . In exchange for these payments, RRPV agreed to release its lien on interests earned by CalEnergy Gas under its agreement with the Company. The loan amendment contains 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, and an extension fee payment of $100,000. Note 7: 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, including $4,586,063 for drilling activities and $2,103,369 for 3-D seismic activities, 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 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 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%. Apache Exploration Program The Apache Exploration Program consists of various agreements signed between the Company and Apache Corporation ("Apache") during 1997 through 2001. 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. As of December 31, 2000, Apache had completed all of its requirements under the terms of the Apache Exploration Program. F-12 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - Note 8: Income Taxes The Company recognized no income tax benefit from the losses generated during 2002, 2001 and 2000. The components of the net deferred tax asset as of December 31, 2002 and 2001 are as follows:
December 31, ---------------------------- 2002 2001 ------------- ------------- (In thousands) Deferred tax liability: Property and equipment basis differences...................................... $ (370) $ (349) Deferred tax asset: Net operating loss carryforwards: United States............................................................. 12,475 12,174 Poland.................................................................... 4,224 3,893 Oil and gas properties........................................................ 1,795 1,218 Options issued for services................................................... 610 143 Other......................................................................... 10 10 Valuation allowance........................................................... (18,744) (17,089) ------------- ------------- Total..................................................................... $ -- $ -- ============= ============= The change in the valuation allowance during 2002, 2001 and 2000 is as follows: Year Ended December 31, ------------------------------------------- 2002 2001 2000 ------------- ------------- ------------- (In thousands) Valuation allowance: Balance, beginning of year..................................... $ (17,089) $ (16,113) $ (12,848) Decrease due to property and equipment basis differences....... (577) 136 109 Increase due to net operating loss............................. (632) (1,956) (2,931) Other.......................................................... (446) 844 (443) ------------- ------------- ------------- Total...................................................... $ (18,744) $ (17,089) $ (16,113) ============= ============= =============
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, 2002 and 2001. United States NOL At December 31, 2002, the Company had net operating loss ("NOL") carryforwards in the United States of approximately $33,446,000 available to offset future taxable income, of which approximately $18,749,000 expires from 2008 through 2012 and 14,697,000 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, 2002, the Company had NOL carryforwards in Poland totaling approximately $11,324,600, including $882,262, $1,925,220 and $5,734,913 generated in 2002, 2001 and 2000, 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. F-13 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - The domestic and foreign components of our net loss are as follows:
Year Ended December 31, ------------------------------------------- 2002 2001 2000 ------------- ------------- ------------- (In thousands) Domestic....................................................... $ (3,570) $ (1,585) $ (4,295) Foreign........................................................ (2,355) (6,825) (6,548) ------------- ------------- ------------- Total...................................................... $ (5,925) $ (8,410) $ (10,843) ============= ============= =============
Note 9: Private Placement of Common Stock During 2000, the Company completed a private placement of 2,969,000 shares of common stock that resulted in net proceeds of $9,272,453 ($10,391,500 gross). The proceeds from this placement were used to partially fund ongoing exploration and development activities in Poland and for general corporate purposes. Note 10: 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 shareholders at each of the Company's annual meetings. As of the date of this report, no options had been issued under the 2002 Stock Option and Award Plan. The following table summarizes information regarding the Company's stock option and award plans as of December 31, 2002:
Weighted Number of Number of Average Shares Shares Exercise Available Authorized Price of for Future Under Plan Outstanding Issuance Shares ------------- --------------- ------------- Equity compensation plans approved by shareholders: 1995 Stock Option and Award Plan................................ 500,000 $ 8.38 -- 1996 Stock Option and Award Plan................................ 500,000 6.65 14,500 1997 Stock Option and Award Plan................................ 500,000 7.79 57,400 1998 Stock Option and Award Plan................................ 500,000 6.46 12,000 1999 Stock Option and Award Plan................................ 500,000 4.40 5,333 2000 Stock Option and Award Plan................................ 600,000 2.44 31,750 2001 Stock Option and Award Plan................................ 600,000 2.40 230,000 ------------- --------------- ------------- Total......................................................... 3,700,000 $ 6.09 350,983 ============= =============== =============
The above table excludes 1,195,000 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 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. The Company has not issued any stock awards through the date of this report under the terms of the above stock option and award plans. F-14 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - The following table summarizes fixed option activity for 2002, 2001 and 2000:
2002 2001 2000 -------------------------- ------------------------ ------------------------- Weighted Weighted Weighted Average Average Average Number of Exercise Number of Exercise Number of Exercise Shares Price Shares Price Shares Price ------------- ----------- ----------- ----------- ------------ ----------- Fixed Options Outstanding: Beginning of year......... 4,785,585 $ 4.87 4,322,917 $ 5.15 3,896,501 $ 5.25 Granted................... 551,000 2.40 501,750 2.44 501,750 4.06 Exercised................. (3,000) 1.50 -- -- (75,000) 3.00 Canceled.................. (114,568) 6.00 (33,082) 5.00 (334) 8.63 Expired................... (675,000) 2.61 (6,000) 5.75 -- -- ------------- ----------- ------------ End of year........... 4,544,017 $ 4.68 4,785,585 $ 4.87 4,322,917 $ 5.15 ============= =========== ============ Exercisable at year-end....... 3,515,867 $ 5.41 3,669,356 $ 5.28 2,744,183 $ 5.61 ============= =========== ============
The weighted average fair value per share of options granted during 2002, 2001 and 2000 was $1.80, $1.16 and $2.56, respectively. The above table excludes shares that would be issued to RRPV should they exercise the option to convert their debt to stock as described in Note 6. The following table summarizes information about fixed stock options outstanding as of December 31, 2002:
Outstanding Exercisable ------------------------------------------------------ ------------------------------- Weighted Average Number of Remaining Weighted Number of Weighted Exercise Options Contractual Life Average Options Average Price Range Outstanding (in years) Exercise Price Exercisable Exercise Price -------------------------------------- -------------------- --------------- -------------- --------------- $1.50 - $3.00......... 2,155,750 3.70 $ 2.72 1,284,923 $ 2.93 $4.06 - $6.75......... 1,288,100 3.68 5.37 1,130,777 5.55 $7.25 - $10.25........ 1,100,167 1.87 8.51 1,100,167 8.51 --------------- -------------------- --------------- -------------- --------------- Total.......... 4,544,017 3.25 $ 4.87 3,515,867 $ 5.52 =============== ==================== =============== ============== ===============
The above table excludes shares that would be issued to RRPV should they exercise the option to convert their debt to 1,000,000 shares of stock as described in Note 6. Warrants The following table summarizes changes in outstanding and exercisable warrants during 2002, 2001 and 2000:
2002 2001 2000 --------------------------- --------------------------- --------------------------- Number of Price Number of Price Number of Price Shares Range Shares Range Shares Range ------------ -------------- ------------ -------------- ------------ -------------- Warrants outstanding: Beginning of year... 100,000 $ 3.00 250,000 $ 3.00 - $6.90 270,572 $1.65 - $6.90 Exercised........... -- -- -- -- (20,572) 1.65 Expired............. (100,000) $ 3.00 (150,000) $ 6.90 -- -- ----------- ---------- ------------ End of year....... -- $ -- 100,000 $ 3.00 250,000 $3.00 - $6.90 =========== ========== ============
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. F-15 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - On August 4, 2000, the Company extended the term of options and warrants to purchase 678,000 shares of the Company's common stock that were to expire during 2000 for a period of two years, with a one-year vesting period. The Company incurred deferred compensation costs of $1,565,974, including $1,188,332 covering the intrinsic value applicable to officers and employees and $377,642 covering the fair market value calculated using the Black-Scholes model for a consultant, which was amortized to expense over the one-year vesting period. These options have now expired. 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 at a price of $2.63 per share, the closing price of the Company's stock on November 8, 2001. Note 11: Related Party Transactions Notes Receivable from Officers On February 17, 1998, two of the Company's officers exercised options to purchase 300,000 shares of the Company's common stock at $1.50 per share that were scheduled to expire on May 6, 1998. The officers paid for the cost of exercising the options by utilizing a contractual bonus of $100,000 each issued to them during 1997 and signing a full recourse note payable to the Company for $125,000 each with interest accrued at 7.7%. On April 10, 1998, in consideration of the agreement of the two officers to not sell the Company's common stock in market transactions, the Company agreed to advance the officers, on a non-recourse basis, additional funds to cover their tax liabilities and other considerations. As of December 31, 1999, the officers had been advanced a total amount of $1,837,920. The carrying value of the notes receivable from officers was $773,055 as of December 28, 2000, including principal of $1,837,920 and accrued interest of $338,824, which was reduced by an impairment allowance of $1,403,689 based on the market value of 233,340 shares of the Company's common stock held as collateral. On December 28, 2000, the officers surrendered the collateralized shares to the Company in return for the cancellation of the notes receivable from officers and the Company recorded 233,340 shares of treasury stock at a cost of $773,055. Note 12: Quarterly Financial Data (Unaudited) Summary quarterly information for 2002 and 2001 is as follows:
Quarter Ended --------------------------------------------------------------------------- December 31 September 30 June 30 March 31 ----------------- ----------------- ------------------ ------------------ (In thousands, except per share amounts) 2002: Revenues....................... $ 708 $ 977 $ 607 $ 450 Net operating loss............. (2,833) (271) (751) (1,000) Net loss....................... (3,664) (373) (870) (1,018) Basic and diluted net loss per common share................. $ (0.21) $ (0.02) $ (0.05) $ (0.06) 2001: Revenues....................... $ 635 $ 1,174 $ 1,363 $ 641 Net operating loss............. (3,254) (1,283) (1,855) (2,196) Net loss....................... (3,251) (1,195) (1,807) (2,157) Basic and diluted net loss per common share................. $ (0.19) $ (0.07) $ (0.10) $ (0.12)
F-16 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - 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. The net operating loss for the fourth quarter of 2001 includes $3,048,137 in dry hole costs and $525,355 in property impairment costs. Note 13: 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 85.0% of the Company's oil sales in the United States were to Cenex during 2000, 2001 and the first half of 2002. During the second half of 2002, over 85% of the Company's oil sales were to Plains Marketing Canada, LP. 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 2000. The Company 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, non-producing leasehold impairments and Apache Poland G&A costs (in 2000)), 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, impairment of notes receivable from officers, 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. Information on the Company's operations by business segment for 2002, 2001 and 2000 is summarized as follows:
2002 ------------------------------------------- Oilfield E&P Services Total ------------- ------------- ------------- (In thousands) Operations summary: Revenues (1)................................................... $ 2,209 $ 533 $ 2,742 Cash operating costs........................................... (2,396) (540) (2,936) Non-cash operating costs....................................... (1,545) -- (1,545) ------------- ------------- ------------- Operating income or (loss) before DD&A expense............. (1,732) (7) (1,739) DD&A expense.................................................. (281) (310) (591) ------------- ------------- ------------- Operating loss................................................ $ (2,013) $ (317) $ (2,330) ============= ============= ============= Identifiable net property and equipment: Unproved properties - Poland.................................. $ 146 $ -- $ 146 Unproved properties - Domestic................................. 8 -- 8 Proved properties - Poland..................................... 1,931 -- 1,931 Proved properties - Domestic................................... 957 -- 957 Equipment and other............................................ -- 791 791 ------------- ------------- ------------- Total...................................................... $ 3,042 $ 791 $ 3,833 ============= ============= ============= Net Capital Expenditures: Property and equipment(2) $ 1,012 $ 116 $ 1,128 ------------- ------------- ------------- Total...................................................... $ 1,012 $ 116 $ 1,128 ============= ============= ============= -------------------------
(1) E&P revenues include $1,924,000 generated in the United States and $285,000 generated in Poland. (2) E&P includes $418,000 of pipeline costs, $586,000 of proved property additions and $8,000 of unproved property additions. F-17
FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - 2001 ------------------------------------------- Oilfield E&P Services Total ------------- ------------- ------------- (In thousands) Operations summary: Revenues (1)................................................... $ 2,229 $ 1,584 $ 3,813 Cash operating costs........................................... (5,751) (1,300) (7,051) Non-cash operating costs (2)................................... (2,727) -- (2,727) ------------- ------------- ------------- Operating income or (loss) before DD&A expense............. (6,249) 284 (5,965) DD&A expense.................................................. (322) (308) (630) ------------- ------------- ------------- Operating loss................................................ $ (6,571) $ (24) $ (6,595) ============= ============= ============= Identifiable net property and equipment: Unproved properties - Poland.................................. $ 648 $ -- $ 648 Unproved properties - Domestic................................. 8 -- 8 Proved properties - Poland..................................... 2,324 -- 2,324 Proved properties - Domestic................................... 877 -- 877 Equipment and other............................................ -- 985 985 ------------- ------------- ------------- Total...................................................... $ 3,857 $ 985 $ 4,842 ============= ============= ============= Net Capital Expenditures: Property and equipment(3)...................................... $ 1,745 $ 248 $ 1,993 ------------- ------------- ------------- Total...................................................... $ 1,745 $ 248 $ 1,993 ============= ============= ============= -----------------------
(1) E&P revenues include $1,815,000 generated in the United States and $414,000 generated in Poland. (2) E&P includes accrued exploratory dry hole costs of $880,000, accrued 3-D seismic costs of $1,799,000, stock options issued for services valued at $36,000, a $572,000 credit pertaining to reversing accrued compensation and an impairment charge of $584,000 for unproved Polish properties. (3) E&P includes a $894,000 of exploratory dry hole costs, $320,000 of proved property additions and $531,000 of unproved property additions.
2000 ------------------------------------------- Oilfield E&P Services Total ------------- ------------- ------------- (In thousands) Operations summary: Revenues........................................................$ 2,521 $ 1,290 $ 3,811 Cash operating costs............................................ (8,710) (1,084) (9,794) Non-cash operating costs (1).................................... (983) -- (983) ------------- ------------- ------------- Operating income or (loss) before DD&A expense.............. (7,172) 206 (6,966) DD&A expense.................................................... (73) (247) (320) ------------- ------------- ------------- Operating loss..................................................$ (7,245) $ (41) $ (7,286) ============= ============= ============= Identifiable net property and equipment: Unproved properties - Poland (2)...............................$ 3,014 $ -- $ 3,014 Unproved properties - Domestic.................................. 18 -- 18 Proved properties - Poland...................................... 2,429 -- 2,429 Proved properties - Domestic.................................... 623 -- 623 Equipment and other............................................. -- 1,045 1,045 ------------- ------------- ------------- Total.......................................................$ 6,084 $ 1,045 $ 7,129 ============= ============= ============= Net Capital expenditures: Property and equipment (3)......................................$ 6,988 $ 780 $ 7,768 ------------- ------------- ------------- Total.......................................................$ 6,988 $ 780 $ 7,768 ============= ============= ============= ------------------------
(1) E&P includes stock options valued at $81,000 issued to a Polish citizen for consulting services, accrued bonuses of $228,000 and a non-producing property impairment of $674,000. (2) E&P includes $2,157,000 relating to the Mieszkow 1, which was in the process of being drilled as of December 31, 2000 and was subsequently determined to be an exploratory dry hole during 2001. (3) E&P includes $2,034,000 of costs that were reclassed to exploratory dry hole expense, $2,631,000 of proved property additions and $2,323,000 of unproved property additions. F-18 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - A reconciliation of the segment information to the consolidated totals for 2002, 2001 and 2000 follows:
2002 2001 2000 ------------- ------------- ------------- (In thousands) Revenues: Reportable segments...............................................$ 2,742 $ 3,813 $ 3,811 Non-reportable segments........................................... -- -- -- ------------- ------------- ------------- Total revenues...................................................$ 2,742 $ 3,813 $ 3,811 ============= ============= ============= Operating loss: Reportable segments...............................................$ (2,333) $ (6,595) $ (7,286) Expense or (revenue) adjustments: Corporate DD&A expense.......................................... (27) (32) (66) Amortization of deferred compensation (G&A)..................... (55) (1,078) (652) General and administrative expenses............................. (2,440) (883) (2,654) Other........................................................... -- -- (1) ------------- ------------- ------------- Total net operating loss......................................$ (4,855) $ (8,588) $ (10,659) ============= ============= ============= Net property and equipment: Reportable segments...............................................$ 3,833 $ 4,842 $ 7,129 Corporate assets.................................................. 76 100 126 ------------- ------------- ------------- Net property and equipment.......................................$ 3,909 $ 4,942 $ 7,255 ============= ============= ============= Property and equipment capital expenditures: Reportable segments...............................................$ 1,128 $ 1,993 $ 7,768 Corporate assets.................................................. 2 6 33 ------------- ------------- ------------- Net property and equipment capital expenditures..................$ 1,130 $ 1,999 $ 7,801 ============= ============= =============
Note 14: Disclosure about Oil and Gas Properties and Producing Activities (unaudited) Capitalized Oil and Gas Property Costs Capitalized costs relating to oil and gas exploration and production activities as of December 31, 2002 and 2001 are summarized as follows:
United States Poland Total --------------- --------------- --------------- (In thousands) December 31, 2002: Proved properties..........................................$ 2,360 $ 2,394 $ 4,754 Unproved properties........................................ 8 146 154 --------------- --------------- --------------- Total gross properties................................... 2,368 2,540 4,908 Less accumulated depreciation, depletion and amortization.. (1,404) (462) (1,866) --------------- --------------- --------------- Total...............................................$ 964 $ 2,078 $ 3,042 =============== =============== =============== December 31, 2001: Proved properties..........................................$ 2,208 $ 2,581 $ 4,789 Unproved properties........................................ 8 648 656 --------------- --------------- --------------- Total gross properties................................... 2,216 3,229 5445 Less accumulated depreciation, depletion and amortization.. (1,331) (257) (1,588) --------------- --------------- --------------- Total...............................................$ 885 $ 2,972 $ 3,857 =============== =============== ===============
F-19 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 subject to any federal or local income taxes due to its operating losses. Total production costs for 2002, 2001 and 2000 were $1,365,454, $1,358,304 and $1,348,399, respectively. Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities during 2002, 2001 and 2000, whether capitalized or expensed, are summarized as follows:
United States Poland Total --------------- --------------- --------------- (In thousands) Year ended December 31, 2002: Acquisition of properties: Proved.................................................$ -- $ -- $ -- Unproved............................................... -- 8 8 Exploration costs.......................................... -- 1,031 1,031 Development costs.......................................... 153 851 1,004 --------------- --------------- --------------- Total..................................................$ 153 $ 1,890 $ 2,043 =============== =============== =============== Year ended December 31, 2001: Acquisition of properties: Proved.................................................$ -- $ -- $ -- Unproved............................................... -- 525 525 Exploration costs.......................................... -- 6,542 6,542 Development costs.......................................... 319 2 321 --------------- --------------- --------------- Total..................................................$ 319 $ 7,069 $ 7,388 =============== =============== =============== Year ended December 31, 2000: Acquisition of properties: Proved.................................................$ -- $ -- $ -- Unproved............................................... -- 21 21 Exploration costs (1)...................................... 692 11,200 11,892 Development costs.......................................... 202 -- 202 --------------- --------------- --------------- Total..................................................$ 894 $ 11,221 $ 12,115 =============== =============== =============== ---------------------
(1) Includes $2,429,000 relating to the Kleka 11, which was categorized as proved property as of December 31, 2000. Impairment of Unproved Oil and Gas Properties During 2002, 2001, and 2000 the Company recorded impairment expenses of $1,547,860, $583,855 and $674,158, respectively. 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 $3,051,871, including cash expenditures of $2,171,750 and accrued costs of $880,121. F-20 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - Note 15: 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, 2002 of $25.00 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:
Crude Oil Natural Gas -------------------------------- -------------------------------- United States Poland United States Poland --------------- --------------- --------------- --------------- (in thousand barrels of oil) (In millions of cubic feet) Proved Developed Reserves: December 31, 2002......................... 1,015 -- -- 1,374 December 31, 2001......................... 1,075 -- -- 2,167 December 31, 2000......................... 1,161 -- -- -- The following unaudited summary of proved developed and undeveloped reserve quantity information represents estimates only and should not be construed as exact: Crude Oil Natural Gas -------------------------------- -------------------------------- United States Poland United States Poland --------------- --------------- --------------- --------------- (in thousand barrels of oil) (In millions of cubic feet) December 31, 2002: Beginning of year....................... 1,100 114 -- 5,010 Extensions or discoveries............... -- -- -- -- Revisions of previous estimates......... 33 -- -- (620) Production.............................. (91) -- -- (180) --------------- --------------- --------------- --------------- End of year......................... 1,042 114 -- 4,210 =============== =============== =============== =============== December 31, 2001: Beginning of year....................... 1,220 -- -- 2,381 Extensions or discoveries............... -- 114 -- 2,844 Revisions of previous estimates......... (26) -- -- 35 Production.............................. (94) -- -- (250) --------------- --------------- --------------- --------------- End of year......................... 1,100 114 -- 5,010 =============== =============== =============== =============== December 31, 2000: Beginning of year....................... 1,080 -- -- -- Extensions and discoveries.............. -- -- -- 2,381 Revisions of previous estimates......... 236 -- -- -- --------------- --------------- --------------- --------------- Production.............................. (96) -- -- -- =============== =============== =============== =============== End of year......................... 1,220 -- -- 2,381 =============== =============== =============== ===============
F-21 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:
United States Poland Total --------------- --------------- --------------- (In thousands) December 31, 2002: Future cash flows........................................ $ 26,049 $ 10,964 $ 37,013 Future production costs.................................. (16,254) (455) (16,709) Future development costs................................. (115) (1,800) (1,915) Future income tax expense................................ -- -- -- --------------- --------------- --------------- Future net cash flows ................................... 9,680 8,709 18,389 10% annual discount for estimated timing of cash flows... (4,300) (3,869) (8,169) --------------- --------------- --------------- Discounted net future cash flows......................... $ 5,380 $ 4,840 $ 10,220 =============== =============== =============== December 31, 2001: Future cash flows......................................... $ 13,922 $ 7,749 $ 21,671 Future production costs................................... (9,464) (425) (9,889) Future development costs.................................. (73) (1,390) (1,463) Future income tax expense................................. -- -- -- --------------- --------------- --------------- Future net cash flows .................................... 4,385 5,934 10,319 10% annual discount for estimated timing of cash flows.... (2,213) (2,520) (4,733) --------------- --------------- --------------- Discounted net future cash flows.......................... $ 2,172 $ 3,414 $ 5,586 =============== =============== =============== December 31, 2000: Future cash flows......................................... $ 26,025 $ 3,532 $ 29,557 Future production costs................................... (16,216) (476) (16,692) Future development costs.................................. (195) -- (195) Future income tax expense................................. -- -- -- --------------- --------------- --------------- Future net cash flows .................................... 9,614 3,056 12,670 10% annual discount for estimated timing of cash flows.... (4,705) (545) (5,250) --------------- --------------- --------------- Discounted net future cash flows.......................... $ 4,909 $ 2,511 $ 7,420 =============== =============== ===============
F-22 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - The principal sources of changes in SMOG are detailed below:
Year Ended December 31, ------------------------------------------- 2002 2001 2000 ------------- ------------- ------------- (In thousands) SMOG sources: Balance, beginning of year......................................$ 5,586 $ 7,420 $ 5,460 Sale of oil and gas produced, net of production costs........... (843) (871) (1,172) Net changes in prices and production costs...................... 4,890 (2,241) (159) Extensions and discoveries, net of future costs................. -- 1,330 2,511 Changes in estimated future development costs................... (251) (686) (53) Previously estimated development costs incurred during the year.................................................... 586 321 202 Revisions in previous quantity estimates........................ 270 59 (31) Accretion of discount........................................... 559 742 546 Net change in income taxes...................................... -- -- -- Changes in rates of production and other........................ (577) (488) 116 ------------- ------------- ------------- Balance, end of year........................................$ 10,220 $ 5,586 $ 7,420 ============= ============= =============
Note 16: New Accounting Pronouncements In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 is effective for the Company beginning January 1, 2003. The most significant impact of this standard to the Company will be a change in the method of accruing for site restoration costs. Under SFAS No. 143, the fair value of asset retirement obligations will be recorded as liabilities when they are incurred, which are typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The Company is evaluating the impact of adopting No. SFAS 143. In June 2002, the FASB issued Statement No. 146 ("SFAS 146"), "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, Liabilities Recognition for Certain employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). This Statement requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS 146 will be effective for exit or disposal activities that are initiated after December 31, 2002. Management believes that the adoption of this standard will have no material impact on the Company's operating results and financial position. In December 2002, the FASB issued Statement No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation Transition and Disclosure." This Statement amends FASB Statement No. 123 ("SFAS 123"); "Accounting for Stock-Based Compensation," to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure provisions of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. As FX Energy will continue to account for stock-based compensation according to APB 25, adoption of SFAS 148 will require FX Energy to provide prominent disclosures about the effects of SFAS 123 on reported income and will require disclosure of these affects in the interim financial statements as well. SFAS 148 is effective for the financial statements for fiscal years ending after December 15, 2002 and subsequent interim periods. Management believes that the adoption of this standard will have no material impact on the Company's operating results and financial position. F-23 FX ENERGY, INC. AND SUBSIDIARIES Notes to the Consolidated Financial Statements - Continued - In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, which expands on the accounting guidance of Statements No. 5, 57, and 107 and incorporates without change the provisions of FASB Interpretation No. 34, which is being superseded. This Interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. In addition, guarantors are required to make significant new disclosures, even if the likelihood of the guarantor making payments under the guarantee is remote. The Interpretation's disclosure requirements are effective for the Company as of December 31, 2002. The recognition requirements of FIN 45 are to be applied prospectively to guarantees issued or modified after December 31, 2002. The Company has no significant guarantees and the adoption of this interpretation did not have a material impact on the Company's financial statements. In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"), Consolidation of Variable Interest Entities. The objective of this interpretation is to provide guidance on how to identify a variable interest entity and determine when the assets, liabilities, noncontrolling interests and results of operations of a variable interest entity need to be included in a company's consolidated financial statements. A company that holds variable interests in an entity will need to consolidate the entity if the company's interest in the variable interest entity is such that the company will absorb a majority of the variable interest entity's expected losses and/or receive a majority of the entity's expected residual returns, if they occur. The provisions of this interpretation became effective upon issuance. As of December 31, 2002, the Company did not have any variable interest entities that will be subject to FIN 46. 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 17: Subsequent Events Private Placement of Convertible Preferred Stock On March 13, 2003, the Company sold 2,250,000 shares of 2003 Series Convertible Preferred Stock in a private placement of securities, raising a total of $5.6 million after offering costs. Each share of preferred stock is convertible into one share of common stock and one warrant to purchase one share of common stock at $3.60 per share anytime between March 1, 2004, and March 1, 2008. The preferred stock has a liquidation preference equal to the sales price for the shares, which was $2.50 per share. The net proceeds from the offering, plus the Company's available cash, were used to reduce the obligation to RRPV,, fund ongoing geological and geophysical costs in Poland, and to support ongoing prospect marketing and general and administrative costs. Amendment of RRPV Note Payable In March, 2003, following the private placement of convertible preferred stock, the Company paid $2.2 million to RRPV. In return, RRPV extended the maturity date of the note to December 31, 2003. The Company has also agreed to pay 40% of the gross proceeds of any subsequent equity or debt offering concluded prior to the amended maturity date to RRPV. The Company also agreed to assign its rights to payments under the CalEnergy Gas agreement to RRPV, except for those amounts relating to the two wells required to be drilled under the agreement. All such payments will be used to offset the remaining principal and interest. In exchange for these payments, RRPV agreed to release its lien on interests earned by CalEnergy Gas under its agreement with the Company. The loan amendment contains 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, and an extension fee payment of $100,000. F-24