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, 2006

Commission File Number: 000-25386

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
	Facsimile (801) 486-5575

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of each exchange on which registered
Common Stock, Par Value $0.001	NASDAQ Global Market

Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o

No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

Yes o

No x

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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o

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, 2006, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $158,234,000.

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 2, 2007, FX Energy had outstanding 35,571,680 shares of its common stock, par value $0.001.

DOCUMENTS INCORPORATED BY REFERENCE. FX Energy’s definitive Proxy Statement in connection with the 2007 Annual Meeting of Stockholders is incorporated by reference in response to Part II, Item 5, and Part III of this Annual Report.

FX ENERGY, INC.

Form 10-K for the fiscal year ended December 31, 2006

TABLE OF CONTENTS

Item		Page
	Part I
--	Special Note on Forward-Looking Statements	3
1	Business	4
1A	Risk Factors	9
1B	Unresolved Staff Comments	15
2	Properties	15
3	Legal Proceedings	25
4	Submission of Matters to a Vote of Security Holders	25

	Part II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
6	Selected Financial Data	27
7	Management’s Discussion and Analysis of Financial Condition and Results of Operation	29
7A	Quantitative and Qualitative Disclosures about Market Risk	38
8	Financial Statements and Supplementary Data	39
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	39
9A	Controls and Procedures	39
9B	Other Information	39

	Part III
10	Directors, Executive Officers and Corporate Governance	40
11	Executive Compensation	40
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	40
13	Certain Relationships and Related Transactions, and Director Independence	40
14	Principal Accountant Fees and Services	40

	Part IV
15	Exhibits and Financial Statement Schedules	41
--	Signatures	46
--	Management’s Report on Internal Control over Financial Reporting	F-1
--	Report of Independent Registered Public Accounting Firm	F-2

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,” “could,” “should,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “intend” and similar words and expressions. Statements that describe our future strategic plans, goals or objectives are also forward-looking statements. 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.

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, strategies, proposals, plans or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as:

•

future drilling and other exploration schedules and sequences for wells and other activities;

•

the future results of drilling individual wells and other exploration and development activities;

•

future variations in well performance as compared to initial test data;

•

the ability to economically develop and market discovered reserves;

•

the prices at which we may be able to sell oil or gas;

•

foreign currency exchange rate fluctuations;

•

exploration and development priorities and the financial and technical resources of the Polish Oil and Gas Company, our principal joint venture and strategic partner in Poland;

•

uncertainties inherent in estimating quantities of proved reserves and actual production rates and associated costs;

•

future events that may result in the need for additional capital;

•

the cost and availability of additional capital that we may require and possible related restrictions on our future operating or financing flexibility;

•

our future ability to attract industry or financial participants to share the costs of exploration, exploitation, development and acquisition activities;

•

future plans and the financial and technical resources of industry or financial participants;

•

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;

•

uncertainties regarding future political, economic, regulatory, fiscal, taxation and other policies in Poland and the European Union; and

•

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. The forward-looking statements included in this report are made only as of the date of this report.

PART I

ITEM 1. BUSINESS

Introduction

We are an independent oil and gas exploration and production company. Through 2006, most of our production operations have been in the United States, primarily in Montana. However, our most significant exploration activity has been, and will continue to be, in Poland. We have focused on Poland because it has provided us with attractive conventional oil and gas exploration and production opportunities. In our view, these opportunities exist because the country was closed to competition from foreign oil and gas companies for many decades. As a result, and given the continuous advances in exploration technology, we believe Poland remains relatively immature as an oil and gas producing province. We believe Poland is underexplored, underdeveloped and underexploited today.

Activities and Assets in Poland

As of December 31, 2006, we held approximately 3.5 million gross acres in Poland, including 3.2 million gross acres in western Poland’s Permian Basin where the gas-bearing Rotliegend sandstone reservoir rock is, in our opinion, a direct analog to the Southern North Sea gas basin offshore England and represents a largely untapped source of potentially significant gas reserves.

In February 2007, we announced plans to release approximately 557,000 acres in our ongoing efforts to highgrade our acreage and to maintain focus on our most prospective holdings. This will reduce our Permian basin acreage to 2.6 million acres.

We have identified a core area consisting of approximately 852,000 gross acres surrounding the Radlin field, a 390 billion cubic feet, or Bcf, Rotliegend gas field that was discovered in the 1980s by our joint venture partner, the Polish Oil and Gas Company (“POGC”). The primary focus of our exploration efforts in this core area is on structural traps in Rotliegend sandstones of the lower Permian. We have emphasized improved seismic processing and acquisition in our exploration, using technology developed for Rotliegend exploration in the Southern North Sea. With this approach we have made commercially successful discoveries in three of the four wells we have drilled on structural targets in the Rotliegend using two-dimensional, or 2-D, seismic data.

Based on these discoveries and associated technical work, we have identified a specific area, the Sroda area, as having high potential for substantial reserves and low drilling risk. Within the Sroda area we are now acquiring three-dimensional, or 3-D, seismic data over 100 square kilometers where we have identified a series of possible structural traps. We expect the 3-D seismic data will give us better definition of the targets and further reduce our drilling risk. Our goal is to have two rigs in the field to start an appraisal and development drilling program in the fourth quarter of 2007. We expect the resulting development project to yield substantial reserves and production, which can be used to support further exploration and development on our acreage in Poland.

We have made commercial discoveries in the course of our exploration, which at December 31, 2006, amounted to 19 Bcf of gas and 202,000 barrels of light crude oil, net to our interest, with estimated future net revenues, discounted to present value at 10% per annum, or PV-10 value, of approximately $59 million. This excludes the recent Winna Gora discovery, which was undergoing production testing as of March 2, 2007. With the two wells that started production in late 2006, we anticipate materially higher gross revenues from production in Poland for 2007. We have pledged our production and reserves in Poland in support of a $25 million line of credit with the Royal Bank of Scotland. The line of credit is intended primarily to fund development work in our core area which we anticipate will follow from the 3-D seismic survey currently underway.

While maintaining our focus on the Rotliegend structural trap play in our core area, we have also identified two other potential plays in this acreage: a stratigraphic gas trap play (“pinch-out”) in the Rotliegend and an oil and gas play in carbonates of the lower Permian. In eastern Poland, on our 250,000 gross-acre Block 255, we have one commercial success in the Carboniferous and have identified several additional Carboniferous leads. We anticipate continuing a modest level of exploration work on our non-core acreage and on the secondary plays in our core area, but we plan to focus the greatest portion of our efforts and resources on the structural trap gas play in our core Fences area.

We believe that we are uniquely situated because of our land position, our relationship with POGC, our significant working interests, and our current financial condition to exploit the untapped potential of western Poland’s Permian Basin and create substantial growth in oil and gas reserves and cash flows for our stockholders.

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. See “Oil and Gas Terms” at the end of this item for definitions of certain industry terms.

Strategy

We hold substantial acreage in productive fairways or geological trends where we believe we have the opportunity to find conventional significant gas and oil reserves with lower risk through the application of new exploration technology. Our strategy is to:

•

acquire large acreage positions in areas of known production, particularly where there has been little or no exploration for many years;

•

bring to bear exploration technology that has not previously been applied to the area or to the particular play type;

•

identify areas that appear to have substantial hydrocarbon resources, either in a single accumulation or in a series of similar accumulations, which would warrant a substantial, ongoing development effort with low drilling risk; and

•

use the reserves and production resulting from the first successful development project to fund other development projects and/or additional exploration on our substantial acreage holdings.

Our primary strategic relationship is with POGC, a fully integrated oil and gas company primarily owned by the Treasury of the Republic of Poland, which is Poland’s principal domestic oil and gas exploration, production, transportation and distribution entity. Under our existing agreements, POGC has provided us with access to exploration opportunities, previously collected exploration data, and technical and operational support. We also use geophysical and drilling services provided by POGC and sell our gas production to POGC.

Key Personnel for Poland

Our chief technical advisor is Richard Hardman, CBE, who has built a career in international exploration over the past 40 years in the upstream oil and gas industry as a geologist in Libya, Kuwait, Colombia and Norway. In the United Kingdom, his career encompasses almost the whole of the exploration history of the North Sea–1969 to the present. With Amerada Hess from 1983 to 2002 as Exploration Director and later Vice President of Exploration, he was responsible for key Amerada North Sea and international discoveries, including the Valhall, Scott and South Arne fields. Mr. Hardman was made Commander of the British Empire in the New Year Honours, 1998, and has served as the Chairman of the Petroleum Society of Great Britain, President of the Geological Society, and President of the European Region of AAPG Europe. Mr. Hardman was appointed to our board of directors in October 2003 and is Chairman of our Technical and Advisory Panel.

Our Country Manager in Poland is Zbigniew Tatys, the former General Director of POGC’s Upstream Exploration and Production Division. During his 20-year career with POGC, he rose through the ranks as a production engineer and was serving as Vice Chairman of POGC at the time of his retirement. Mr. Tatys has unique qualifications to lead us through our transition from a pure exploration company to an oil and natural gas producer in Poland.

Exploration, Development and Production Activities

Polish Exploration Rights

As of December 31, 2006, we held oil and gas exploration rights in Poland in the following gross acreage components:

	Operator		Gross	Working
	FX Energy	POGC	Acreage	Interest
Concession Area:
Fences (Fences I/II)		X	852,000	49%
Block 287(Fences III)	X		770,000	100%
Block 255/Wilga	X		250,000	82%
Northwest	X		1,608,000	100%
Total gross acreage			3,480,000

As we explore and evaluate our acreage in Poland, we expect to increasingly focus our operational and financial efforts on higher potential, lower risk areas. As we do so, we may elect not to retain our interest in acreage that we determine carries a higher exploration risk or lower potential. See “Wells and Acreage” below for further information.

Exploratory Activities in Poland

Our ongoing activities in Poland are conducted in four project areas: Fences (formerly described as Fences I/II, Block 287 (formerly described as Fences III), Northwest, and the Block 255/Wilga area. Our exploration activities are currently focused primarily on the core Fences area, where the gas-bearing Rotliegend sandstone reservoir rock is a direct analog to the Southern North Sea gas basin offshore England. We are focused on this core area because there have been substantial gas reserves developed and produced by POGC, we have made three commercial discoveries, and we have concluded that there is likely to be substantial additional natural gas in the same horizons that can be identified through the application of geophysical techniques that had not previously been applied in this area in Poland.

Fences Area

The Fences concession area is 852,000 acres (3,790 sq. km.) in western Poland’s Permian Basin surrounding POGC’s Radlin gas field. The Radlin field and several other POGC gas fields located in the Fences area are “fenced” or excluded from our exploration acreage. These fields, discovered by POGC between 1974 and 1982, produce from structural traps in the Rotliegend sandstone.

We entered into agreements in 2000 and 2003 with POGC to farm-in this area and by December 31, 2004, had spent the required $20.0 million on exploration costs and earned our 49% interest. POGC holds a 51% interest and is the operator. In 2003 we farmed-out half of our 49% interest in a 45,000 acre parcel (approximately 2.5% of our interest in the Fences area) to CalEnergy Gas (Holdings) Ltd., the upstream gas business unit of MidAmerican Energy Holdings Company.

The Rotliegend is the primary target horizon throughout most of the Fences concession area, at depths from approximately 2,500 to 4,000 meters. There are two types of traps in the Rotliegend in this general area: structural traps and stratigraphic (“pinch-out”) traps, both of which are known to produce gas in the area. In addition, we have identified what appear to be carbonates in the lower Permian, a third type of trap that is known to produce both oil and gas in the area.

During 2000, we drilled the Kleka 11, our first Rotliegend 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 data processing and to assure careful handling of velocities in seismic data interpretation. Since that time, we have emphasized the use of acquisition, processing and interpretation techniques that have been used successfully in the Rotliegend gas fields of the United Kingdom’s offshore Southern Gas Basin.

With Rotliegend structures as our target, and utilizing improved seismic processing and acquisition techniques, we completed the Zaniemysl-3 exploratory well in the Fences concession area as a commercial well in February 2004. Zaniemysl-3 contains gross proved reserves for the well estimated at approximately 24 Bcf of gas (5.7 Bcf net to our interest). See Item 2. Properties: Proved Reserves. The Zaniemysl well began producing gas in October of 2006, and is currently producing at 10 million cubic feet of natural gas per day, or MMcfD. In April 2005 we completed the Sroda-4 well as a commercial success (with production anticipated to begin in 2008) with gross proved reserves for the well estimated at approximately 16 Bcf of gas (7.9 Bcf net to our interest). In January 2006, we determined the Sroda-5 well to be noncommercial, largely due to cementation in the top 15 meters of the otherwise porous Rotliegend sandstone. This kind of cementation can be the result of faulting, and our technical group will review new 3-D seismic data to determine whether to recommend drilling a near offset to Sroda-5. In January 2007, we completed the Winna Gora well as a commercial success with reserves not yet determined. Production testing at Winna Gora was underway as of March 2, 2007. We began drilling the Roszkow-1 well in February of 2007.

With Rotliegend stratigraphic trapping (“pinch-outs”) as our target, in January 2005 we drilled the Rusocin-1 well, the first well in Poland intentionally focused on a stratigraphic trap in the Rotliegend. In a drill stem test the well flowed gas from an 8 meter (26 feet) section of the Rotliegend sandstone target reservoir and may have encountered the lower edge of a pinch-out trap. In December 2005 we determined that our second stratigraphic test well, the Lugi-1 well southeast of the Rusocin-1 well, was noncommercial.

We have identified what appears to be a carbonate target in the Zechstein (Ca2) horizon of the lower Permian, but have not yet drilled a target of this type.

Based on our technical work to date and on the results of the exploratory wells we have drilled in the Fences area, we are focusing our technical and financial resources on that part of the Fences area that is prone to structural traps in the Rotliegend. To that end we are currently acquiring 100 square kilometers of 3-D seismic data in the area where the Sroda-4, Sroda-5 and Winna Gora wells are located. During the remainder of 2007, we plan to complete this 3-D seismic acquisition project and prepare to drill appraisal and development wells as warranted. We may also consider drilling a Zechstein (Ca2) test well.

Block 287 Concession Area

The Block 287 concession area is 213,000 acres (863 sq. km.) located approximately 25 miles south of the Fences concession area. We own 100% of the exploration rights. Block 287 is part of a larger concession area, 770,000 acres, called Fences III. In early 2006 we drilled a dry hole, Drozdowice, in Fences III. Based on the well results and the technical work that preceded the well, and in light of our other opportunities, we have elected to surrender all of our acreage in this area, with the exception of Block 287, in 2007. The total area dropped will be approximately 557,000 acres.

Within Block 287 there are three Rotliegend gas wells referred to as the Grabowka gas field. Originally drilled by POGC in 1983-85, these three wells were tested for production but never produced commercially. In early 2007, we entered into a joint venture agreement under which all costs of re-entering and completing the wells and building production facilities will be paid by our joint venture partner in exchange for discounted pricing on gas deliveries. If commercial, the project is expected to come on-stream in about one year at a rate of approximately 1 MMcfD, based on the original test data and subject to successful re-entry of the wells. The joint venture partner is PL Energia S.A., headquartered in Krzywoploty, Poland.

We do not plan to conduct further technical work on Block 287 until we can assess the results of the Grabowka re-entry project.

Block 255 Concession Area

The Block 255/Wilga concession area in east central Poland consists of exploration rights on approximately 250,000 gross acres held by us and POGC. We have an 82% working interest and are the operator; POGC holds the remaining 18% working interest. We have one producing well, Wilga-2, in Block 255, the result of an exploration project several years ago by us and Apache Corporation. The Wilga well was drilled in 2000 and as of December 31, 2006, had gross proved reserves of approximately 6 Bcf of gas and 247,000 barrels of light crude oil (4.9 Bcf and 202,000 barrels, net to our interest). Wilga-2 is currently producing approximately 3 million cubic feet, or Mcf, of high methane gas and 150 barrels of light crude oil per day from sands in the Carboniferous.

We plan to conduct a detailed reservoir test of Wilga-2 after at least six months of production that will allow us to measure reserves with greater accuracy and help us to decide whether to drill an offset well. We are also allocating technical resources to the Block 255/Wilga area in an effort to understand the two noncommercial wells that were drilled following the commercially successful Wilga-2 and to identify other potential targets in the block. We anticipate carrying out additional technical work during 2007.

New Concession Areas

In 2006, we acquired 100% interest in several concession blocks covering 1,608,000 acres (6,509 sq. km.) that together constitute our Northwest concession area. We have applied for additional concession blocks in Poland and anticipate that they will be issued in the very near term. We will allocate modest technical and financial resources to these areas during 2007, primarily in the form of data collection and seismic reprocessing, with a view to ascertaining relative hydrocarbon potential and exploration risk.

Activities and Assets in the United States

Nevada

During 2006, we drilled and abandoned one wildcat oil well, the West Bacon Flat-1, in Railroad Valley, Nevada. We plan to drill a small number of exploratory wells again in 2007 on land that is near our existing producing properties in Nevada. Our actual cash costs to drill each well is approximately $100,000. We are able to maintain very low drilling costs due to an agreement with our 50% partner whereby our partner contributes drilling equipment and we contribute drilling labor, consisting of our existing employees in Montana.

Montana

During 2006, we drilled and abandoned a single test well at a heavy oil prospect, the Teton River-1 located in western Montana. We have no plans for further drilling in this area during 2007.

ITEM 1A. RISK FACTORS

Risk Factors

Our business is subject to a number of material risks, including, but not limited to, the following factors related directly and indirectly to our business activities in the United States and Poland.

Risks Relating to our Business

Our success depends largely on our discovery of economic quantities of oil or gas in Poland.

We currently have a limited amount of production in the United States and Poland. While during 2007 we anticipate that we will generate revenues substantially in excess of our general and administrative costs, these revenues are not sufficient to cover all of our exploration and development costs, and we will continue to rely on existing working capital and possibly on funds from external sources to cover these costs. Our exploration programs in Poland are based on interpretations of geological and geophysical data. The factors listed below, most of which are outside our control, may prevent us from establishing additional commercial production or substantial reserves as a result of our exploration, appraisal and development activities in Poland:

•

we cannot assure that any future well will encounter commercial quantities of oil or gas;

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there is no method to predict in advance of drilling and testing whether any prospect encountering oil or gas will yield oil or gas in sufficient quantities to cover drilling or completion costs or to be economically viable;

•

one or more appraisal wells may be required to confirm the commercial potential of an oil or gas discovery;

•

we may continue to incur exploration costs in specific areas even if initial appraisal wells are plugged and abandoned or, if completed for production, do not result in production of commercial quantities of oil or gas; and

•

drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including operating problems encountered during drilling, weather conditions, compliance with governmental requirements, shortages or delays in the delivery of equipment or availability of services, and other factors.

We have limited control over our exploration and development activities in Poland.

Our partner, POGC, holds the majority interest and is operator of our Fences project area and has a minority interest in our Wilga project area. As a paying partner, we rely to a significant extent on the financial capabilities of POGC. If POGC were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on us. In particular, we have prepared our exploration budget through 2007 based on the participation of and funding to be provided by POGC. Although we have rights to participate in exploration and development activities on some POGC-controlled acreage, we have limited rights to initiate such activities. Further, we have no direct interest in some of the underlying agreements, licenses and grants from the Polish agencies governing the exploration, exploitation, development or production of acreage controlled by POGC. Thus, our program in Poland involving POGC-controlled acreage would be adversely affected if POGC should elect not to pursue activities on such acreage, if the relationship between us and POGC should deteriorate or terminate, or if POGC or the governmental agencies should fail to fulfill the requirements of or elect to terminate such agreements, licenses or grants.

We cannot assure the exploration models we are using in Poland will lead to finding oil or gas in Poland.

We cannot assure the exploration models we and POGC have developed will provide a useful or effective guide for selecting exploration prospects and drilling targets. We will have to revise or replace these exploration models as a guide to further exploration if ongoing drilling results do not confirm their validity. These exploration models may be based on incomplete or unconfirmed data and theories that have not been fully tested. The seismic data, other technologies, and the study of producing fields in the area do not enable us to know conclusively prior to drilling that oil or gas will be present in commercial quantities. We cannot assure that the analogies that we draw from available data from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects.

We cannot accurately predict the size of exploration targets or foresee all related risks.

Notwithstanding the accumulation and study of 2-D and 3-D seismic data, drilling logs, production information from established fields, and other data, we cannot predict accurately the oil or gas potential of individual prospects and drilling targets or the related risks. Our predictions are only rough, preliminary geological estimates of the forecasted volume and characteristics of possible reservoirs and are not an estimate of reserves. In some cases, our estimates may be based on a review of data from other exploration or producing fields in the area that ultimately may be found not to be similar to our exploration prospects. We may require several test wells and long-term analysis of test data and history of production to determine the oil or gas potential of individual prospects.

We have had limited exploratory success in Poland.

We have participated in drilling 24 exploratory wells in Poland, including six exploratory successes (the Wilga 2, Kleka 11, Zaniemysl-3, Sroda-4, Winna Gora-1 and Rusocin-1), and eighteen exploratory dry holes. Of our six exploratory successes in Poland, we are currently producing gas at our Wilga 2, Zaniemysl-3 and Kleka 11 wells.

We may not achieve the results anticipated in placing our current or future discoveries into production.

We may encounter delays in commencing the production and the sale of gas in Poland, including our recent gas discoveries and other possible future discoveries. The possible delays may include obtaining rights-of-way to connect to the POGC pipeline system, obtaining construction permits, availability of materials and contractors, the signing of oil or gas purchase/sales contracts, and other factors. Such delays would correspondingly delay the commencement of cash flow and may require us to obtain additional short-term financing pending commencement of production. Further, we may design proposed surface and pipeline facilities based on possible estimated results of additional drilling. We cannot assure that additional drilling will establish additional reserves or production that will provide an economic return for planned expenditures for facilities. We may have to change our anticipated expenditures if costs of placing a particular discovery into production are higher, if the project is smaller, or if the commencement of production takes longer than expected.

Privatization/Nationalization of POGC could affect our relationship and future opportunities in Poland.

Our activities in Poland have benefited from our relationship with POGC, which has provided us with exploration acreage, seismic data and production data under our agreements. The Polish government commenced the privatization of POGC by selling POGC’s refining assets. In late 2005, POGC successfully completed an initial public offering on the Warsaw stock exchange, and approximately 15% of POGC is now owned by the public. Complete privatization or a re-nationalization of POGC may result in new policies, strategies or ownership that could adversely affect our existing relationship and agreements, as well as the availability of opportunities with POGC in the future.

We have a history of operating losses and may require additional capital in the future to fund our operations.

From our inception in January 1989 through December 31, 2006, we have incurred cumulative net losses of approximately $94 million. We expect that our exploration and production activities may continue to result in net losses and that our accumulated deficit may increase. We anticipate that we will continue to incur losses through 2007 and possibly beyond, depending on whether our activities in Poland and the United States result in sufficient revenues to cover related operating expenses.

Until sufficient cash flow from operations can be obtained, we expect we will need additional capital to fully fund our ongoing planned exploration, appraisal, development and property acquisition programs in Poland. We may seek required funds from the issuance of additional debt, equity or hybrid securities, project financing, strategic alliances or other arrangements. 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. In addition to planned activities in Poland, we may require additional funds for general corporate purposes.

The loss of key personnel could have an adverse impact on our operations.

We rely on our officers and key employees and consultants and their expertise, particularly David N. Pierce, President and Chief Executive Officer; Thomas B. Lovejoy, Chairman of the Board and Executive Vice President; Andrew W. Pierce, Vice President-Operations; Jerzy B. Maciolek, Vice President-Exploration; Zbigniew Tatys, Poland Country Manager; and Richard Hardman, Director and Chairman of our technical committee. The loss of the services of any of these individuals may materially and adversely affect us. We have entered into employment agreements with our key executives. We do not maintain key-man insurance on any of our employees.

The price we receive for gas we sell will likely be lower than free market gas prices in western Europe.

Our limited number of wells and reserves means we cannot assure uninterruptible supply in sufficient quantities to meet the anticipated requirements of industrial users, so we currently are dependent on selling gas to POGC at prices generally lower than prevailing in western Europe. The market for the sale of gas in Poland is open to competition, but there are not yet many participants. Accordingly, we expect that the prices we receive for the gas we produce will be lower than would be the case in a fully competitive setting and may be lower than prevailing western European prices, at least until a fully competitive market develops in Poland or until we are able to assure potential purchasers other than POGC that we have sufficient wells and reserves to assure an uninterruptible supply in sufficient quantities. Further, there is no established market relationship between gas prices in short-term and long-term sales agreements. Notwithstanding the strong demand for gas in Poland, the availability of abundant quantities of gas from former members of the Soviet Union and the low cost of electricity from coal-fired generating facilities may also tend to depress gas prices in Poland.

Substantially all of the oil and gas currently produced in Poland is sold to a single customer or its affiliates.

We currently sell substantially all of the oil and gas produced in Poland to POGC or one of its affiliates. If POGC were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on us. As discussed previously, the market for the sale of gas in Poland is open to competition, but there are not yet many participants. While our contracts provide us with the ability to market gas to other purchasers, including those outside of Poland, it may take a considerable amount of time to replace POGC as our primary customer.

Oil and gas price decreases and volatility could adversely affect our operations and our ability to obtain financing.

Oil and gas prices have been and are likely to continue to be volatile and subject to wide fluctuations in response to the following factors:

•

the market and price structure in local markets;

•

changes in the supply of and demand for oil and gas;

•

market uncertainty;

•

political conditions in international oil and gas producing regions;

•

the extent of production and importation of oil and gas into existing or potential markets;

•

the level of consumer demand;

•

weather conditions affecting production, transportation and consumption;

•

the competitive position of oil or gas as a source of energy, as compared with coal, nuclear energy, hydroelectric power and other energy sources;

•

the availability, proximity and capacity of gathering systems, pipelines and processing facilities;

•

the refining and processing capacity of prospective oil or gas purchasers;

•

the effect of governmental regulation on the production, transportation and sale of oil and gas; and

•

other factors beyond our control.

We have not entered into any agreements to protect us from price fluctuations and may or may not do so in the future.

Our industry is subject to numerous operating risks. Insurance may not be adequate to protect us against all these risks.

Our oil and gas drilling and production operations are subject to hazards incidental to the industry. These hazards include blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. To lessen the effects of these hazards, we maintain insurance of various types to cover our domestic and international operations. We cannot assure that the insurance policies carried by us can continue to be obtained on reasonable terms. POGC, as operator of the Fences project area, is self-insured. While we do carry limited third-party liability and all-risk insurance in Poland, we do not plan to purchase well control insurance on wells we drill in the Fences project area and may elect not to purchase such insurance on wells drilled in other areas in Poland as well. The current level of insurance does not cover all of the risks involved in oil and gas exploration, drilling and production. Where additional insurance coverage does exist, the amount of coverage may not be sufficient to pay the full amount of such liabilities. We may not be insured against all losses or liabilities that may arise from all hazards because such insurance is unavailable at economic rates, because of limitations on existing insurance coverage, or other factors. For example, we do not maintain insurance against risks related to violations of environmental laws. We would be adversely affected by a significant adverse event that is not fully covered by insurance. Further, we cannot assure that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

Risks Relating to Conducting Business in Poland

Polish laws, regulations and policies may be changed in ways that could adversely impact our business.

Our oil and gas exploration, development and production activities in Poland are and will continue to be subject to ongoing uncertainties and risks, including:

•

possible changes in government personnel, the development of new administrative policies, and practices and political conditions in Poland that may affect the administration of agreements with governmental agencies or enterprises;

•

possible changes to the laws, regulations and policies applicable to us and our partners or the oil and gas industry in Poland in general;

•

uncertainties as to whether the laws and regulations will be applicable in any particular circumstance;

•

uncertainties as to whether we will be able to enforce our rights in Poland;

•

uncertainty as to whether we will be able to demonstrate, to the satisfaction of the Polish authorities, our and POGC’s compliance with governmental requirements respecting exploration expenditures, results of exploration, environmental protection matters, and other factors;

•

the inability to recover previous payments to the Polish government made under the exploration rights or any other costs incurred respecting those rights if we were to lose or cancel our exploration and exploitation rights at any time;

•

political instability and possible changes in government;

•

export and transportation tariffs;

•

local and national tax requirements;

•

expropriation or nationalization of private enterprises and other risks arising out of foreign government sovereignty over our acreage in Poland; and

•

possible significant delays in obtaining opinions of local authorities or satisfying other governmental requirements in connection with a grant of permits to conduct exploration and production activities.

Poland has a developing regulatory regime, regulatory policies and interpretations.

Poland has a developing regulatory regime governing exploration and development, production, marketing, transportation and storage of oil and gas. These provisions were recently promulgated and are relatively untested. Therefore, there is little or no administrative or enforcement history or established practice that can aid us in evaluating how the regulatory regime will affect our operations. It is possible those governmental policies will change or that new laws and regulations, administrative practices or policies or interpretations of existing laws and regulations will materially and adversely affect our activities in Poland. For example, Poland’s laws, policies and procedures were changed to conform to the requirements that had to be met before Poland was admitted as a full member of the European Union.

Our oil and gas operations are subject to changing environmental laws and regulations that could have a negative impact on our operations.

Operations on our project areas are subject to environmental laws and regulations in Poland that provide for restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas exploration and development. Additionally, if significant quantities of gas are produced with oil, regulations prohibiting the flaring of gas may inhibit oil production. In such circumstances, the absence of a gas gathering and delivering system may restrict production or may require significant expenditures to develop such a system prior to producing oil and gas. We are required to prepare and obtain approval of environmental impact assessments by governmental authorities in Poland prior to commencing oil or gas production, transportation and processing functions. We are also subject to the requirements of Natura 2000, which is an ecological network in the territory of the European Union. In May 1992, governments of the European Union adopted legislation designed to protect the most seriously threatened habitats and species across Europe.

We and our partners cannot assure that we have complied with all applicable laws and regulations in drilling wells, acquiring seismic data or completing other activities in Poland to date. The Polish government may adopt more restrictive regulations or administrative policies or practices. The cost of compliance with current regulations or any changes in environmental regulations could require significant expenditures. Further, breaches of such regulations may result in the imposition of fines and penalties, any of which may be material. These environmental costs could have an adverse effect on our financial condition, results of operations, or cash flows in the future.

Certain risks of loss arise from our need to conduct transactions in foreign currency.

The amounts in our agreements relating to our activities in Poland are sometimes expressed and payable in United States dollars and sometimes in Polish zlotys. Conversions between United States dollars and Polish zlotys are made on the date amounts are paid or received. In the future, our financial results and cash flows in Poland may be affected by fluctuations in exchange rates between the Polish zloty and the United States dollar. We have not hedged our foreign currency activities in the past and do not plan to do so. Currencies used by us may not be convertible at satisfactory rates. In addition, the official conversion rates between United States and Polish currencies may not accurately reflect the relative value of goods and services available or required in Poland. Further, inflation may lead to the devaluation of the Polish zloty.

Risks Related to an Investment in our Common Stock

Our stockholder rights plan and bylaws discourage unsolicited takeover proposals and could prevent our stockholders from realizing a premium on our common stock.

We have a stockholder rights plan that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the stockholder rights plan would cause substantial dilution to a person or group that attempts to acquire us on terms not approved in advance by our board of directors. In addition, our articles of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that our stockholders may consider to be in their best interests that include:

•

provisions that members of the board of directors are elected and retire in rotation; and

•

the ability of the board of directors to designate the terms of, and to issue new series of, preferred shares.

Together, these provisions and our stockholder rights plan may discourage transactions that otherwise could involve payment to our stockholders of a premium over prevailing market prices for our common shares.

Our common stock price has been and may continue to be extremely volatile.

Our common stock has traded as low as $3.98 and as high as $8.37 during intraday trading between January 1, 2006, and the date of this report. Some of the factors leading to this volatility include:

•

the outcome of individual wells or the timing of exploration efforts in Poland;

•

the potential sale by us of newly issued common stock to raise capital or by existing stockholders of restricted securities;

•

price and volume fluctuations in the general securities markets that are unrelated to our results of operations;

•

the investment community’s view of companies with assets and operations outside the United States in general and in Poland in particular;

•

actions or announcements by POGC that may affect us;

•

prevailing world prices for oil and gas;

•

the potential of our current and planned activities in Poland; and

•

changes in stock market analysts’ recommendations regarding us, other oil and gas companies or the oil and gas industry in general.

Exploration failures in Poland may adversely affect the trading prices for our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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. The Polish government credits foreign investment as a forceful growth factor in successfully creating a stable free-market economy.

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 taken steps to harmonize Polish legislation with that of the European Union, which it joined in May of 2004.

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. In September of 2005, POGC sold 15% of its stock in an initial public offering on the Warsaw Stock Exchange, raising a total of 2.7 billion Polish zlotys (approximately US $900 million).

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 of these and other factors, 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.

Polish Properties

Legal Framework

General Usufruct and Concession Terms

All of our rights in Poland have been awarded to us or to POGC pursuant to the Geological and Mining Law, which specifies the process for obtaining domestic exploration and exploitation rights. Under the Geological and Mining Law, the concession authority enters into mining usufruct (lease) agreements that grant the holder the exclusive right to explore for oil and gas in a designated area or to exploit the designated oil and/or gas field for a specified period under prescribed terms and conditions. The holder of the mining usufruct covering exploration must also acquire an exploration concession by applying to the concession authority and providing the opportunity for comment by local governmental authorities. The usufruct agreements include provisions that give the usufruct holder a claim for an extension of the usufruct (and the underlying concession), subject to having fulfilled all obligations under the usufruct and/or concession agreements.

The concession authority has granted us oil and gas exploration rights on the Block 287 (Fences III) and Wilga project areas, and has granted POGC oil and gas exploration rights on the Fences (Fences I/II) project areas. The agreements divide these areas into blocks, generally containing approximately 250,000 acres each. Concessions have been acquired for exploration in all areas that lie within existing usufructs. The 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 discovered, the concession owner, during the first two years of production, then applies for an exploitation concession, as provided by the usufructs, generally with a term of 25 to 30 years or as 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 high-methane gas is currently less than $0.05 per Mcf. This rate could be increased or decreased by the Council of Ministers to a rate between $0.02 and $0.10 per Mcf (the current statutory minimum and maximum royalty rates). Local governments will receive 60% of any royalties paid on production. The holder of the exploitation concession must also acquire rights to use the land from the surface owner and 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 (Fences I/II) Project Area

The Fences (Fences I/II) project area consists of five oil and gas exploration concessions controlled by POGC. Three producing fields (Radlin, Kleka and Kaleje) lie within the concession boundary, but are excluded from the Fences concessions. The concessions have expiration dates ranging from August 2007 to July 2009. Remaining work commitments in the aggregate include acquiring 170 kilometers of 3-D seismic data, which is currently in process, and drilling one well. The westernmost Steszew concession, which expired in December of 2006, was dropped due to lack of prospectivity. POGC has filed an extension for all concessions that expire in 2007, which we expect to be granted.

Block 287 (Fences III) Project Area

The Fences III project area consists of a single oil and gas exploration concession held by us. Several producing fields lie within the concession boundaries, but are excluded from the Fences III project area. The concession is for a period of six years ending in December 2009. Work commitments included acquiring 100 kilometers of new 2-D seismic data or drilling one well, which was satisfied by the drilling of the Drozdowice-1 well, and analysis and interpretation of existing well data. Beginning in the fourth year, there is a drilling requirement of a second well that will be satisfied by re-entering and producing the Grabowka gas field. We have elected to surrender in 2007 all of the Fences III project area except for Block 287, which contains the Grabowka gas field.

Wilga/Block 255 Project Area

The Wilga project area consists of a single oil and gas exploration concession that expires in August 2009. The period carries a work commitment of trial production of the Wilga gas-condensate field and 165 kilometers of 2-D seismic data.

Northwest Concession

The new northwest concession consists of seven blocks, awarded in October 2006. The total work commitment for the seven blocks is outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 960 kilometers of new 2-D seismic data; Phase III – three years: drilling seven wells.

As of December 31, 2006, all required usufruct/concession payments had been made for each of the above project areas. Usufruct/concession payments on new concessions obtained beginning in 2006 are payable in annual installments over a three-year period.

Production, Transportation and Marketing

The following table sets forth our net daily gas and oil production, average sales price, and average production costs associated with our Polish production during 2006, 2005, and 2004:

		2006		2005		2004

Average daily net gas production (Mcf)⁽¹⁾		837		--		--
Average sales price per Mcf	$	3.88	$	--	$	--

Average daily net oil production (Bbls)⁽¹⁾		106		--		--
Average sales price per Bbl	$	56.58	$	--	$	--

Average production costs per Mcfe⁽²⁾	$	0.56	$	--	$	--

_______________

(1)	Average daily net production amounts shown are calculated based on days of actual production. See “Commencement of Polish Gas Production” in Item 7 below.

(2)

Production costs include lifting costs (electricity, fuel, water, disposal, repairs, maintenance, transportation and similar items), and contract operator fees. Production costs do not include such items as general and administrative costs; depreciation, depletion and amortization; or Polish income taxes.

Poland has a network of gas pipelines and crude oil pipelines traversing the country 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 oil and/or light crude oil, or LCO, produced can 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.

We are currently selling all of our oil and gas production in Poland to POGC or one of its affiliates. Gas is sold pursuant to long-term sales contracts, typically for the life of each well, which obligate POGC to purchase all gas produced. Individual oil sales are negotiated with POGC-affiliated entities and are not subject to sales contracts.

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 2006 follows:

	Average Daily Production (Bbls)		Average Working	Average Net Revenue
	Gross	Net	Interest	Interest
United States producing properties:
Montana:
Cut Bank	218	188	99.6%	86.4%
Bears Den	7	5	98.0	78.3
Rattlers Butte	15	1	6.3	5.1
Total	240	194
Nevada:
Trap Springs	7	1	21.6	18.9
Munson Ranch	31	10	36.0	34.0
Bacon Flat	23	4	16.9	12.5
Total	61	15
Total United States producing properties	301	209

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 99.6% in 99 producing oil wells, 25 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 98% 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 Springs and Munson Ranch fields and have an interest in the Bacon Flat field, which is operated by an industry partner. The Trap Springs field was discovered in 1976. In the Trap Springs 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.

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 2006, 2005 and 2004:

	Years Ended December 31,
	2006	2005	2004
United States producing property data:
Average daily net oil production (Bbls)	209	217	234
Average sales price per Bbl	$56.07	$48.09	$36.34
Average production costs per Bbl⁽¹⁾	$27.65	$26.79	$18.85

(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 general and administrative costs; depreciation, depletion and amortization; 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. We sell all of our Montana production, which represents over 94% of our total oil sales, to CENEX, a regional refiner and marketer. 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, through our drilling subsidiary, FX Drilling Company, Inc., 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.

Proved Reserves

Proved reserves are the estimated quantities of crude oil and natural gas 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, and interest expense. The proved reserve quantity and value information is based on the weighted average price on December 31, 2006, of $51.66 per barrel, or Bbl, for oil in the United States and $49.49 per Bbl of oil and $4.89 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 estimating quantities and values of proved reserves, projecting future rates of production and the timing and amount of development expenditures. The estimated present value, discounted at 10% per annum, of the future net cash flows, the Standardized Measure of Future Net Cash Flows (“SMOG”), or PV-10 Value, was determined in accordance with Statement of Financial Accounting Standards (“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 RPS Energy, an independent engineering firm in the United Kingdom. No estimates of our proved reserves were filed with or included in any report to any other federal agency during 2006.

The following summary of proved reserve information as of December 31, 2006, represents discounted, after tax estimates net to us only, and should not be construed as exact:

	United States			Poland				Total
	Oil	PV-10 Value		Oil	Gas	PV-10 Value		PV-10 Value
(MBbls)		(In thousands)		(MBbls)	(MMcf)	(In thousands)		(In thousands)
Proved reserves:
Developed producing	382	$	4,565	202	11,382	$	40,370	$	44,935
Undeveloped	—		—	—	7,882		18,822		18,822
Total	382	$	4,565	202	19,264	$	59,192	$	63,757

Drilling Activities

The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2006, 2005 and 2004:

	Years Ended December 31,
	2006		2005		2004
	Gross	Net	Gross	Net	Gross	Net
Discoveries:
United States	--	--	--	--	--	--
Poland	--	--	2.0	0.7	2.0	0.7
Total	--	--	2.0	0.7	2.0	0.7

Exploratory dry holes:
United States	2.0	1.5	4.0	2.0	--	--
Poland	1.0	1.0	2.0	1.0	--	--
Total	3.0	2.5	6.0	3.0	--	--

Total wells drilled	3.0	2.5	8.0	3.7	2.0	0.7

In January of 2007, we announced a commercial discovery at our Winna Gora-1 well in western Poland, in which we have a 49% working interest. The Winna Gora well is not included in the above table.

Wells and Acreage

As of December 31, 2006, our producing gross and net well count consisted of the following:

	Number of Wells
	Gross	Net
Well count:
United States⁽¹⁾	127.0	120.0
Poland	3.0	1.6
Total	130.0	121.6

(1)	All of our producing United States wells are oil wells. We have no gas production in the United States.

The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2006:

	Developed		Undeveloped
	Gross	Net	Gross	Net

United States:
Montana	10,732	10,418	4,510	4,417
Nevada	400	128	9,332	6,351
Total	11,132	10,546	13,482	10,768

Poland: ⁽¹⁾
Fences project area (Fences I/II)	225	110	852,000	406,000
Block 287 (Fences III) project area⁽²⁾	--	--	770,000	770,000
Wilga project area	543	441	250,000	205,000
Northwest project area	--	--	1,608,000	1,608,000
Total Polish acreage	768	551	3,480,000	2,989,000

Total Acreage	11,900	11,097	3,493,482	2,999,768

(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)	We have determined to surrender approximately 557,000 gross acres in Fences III project area during 2007.

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.

We expect Poland will continue to pass further legislation aimed at harmonizing Polish environmental law with that of the European Union. The European Union Treaty of Accession will require divestment by the Polish government of certain portions of its oil and gas business. Changes in the industry ownership may affect the business climate where we operate.

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 operating 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 that 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.” 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 consists 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. Our activities on these properties 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. Our 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, 2006, we had 42 employees, consisting of nine in Salt Lake City, Utah; 22 in Oilmont, Montana; one in Greenwich, Connecticut; three in Houston, Texas; and seven in Poland. Our employees are not represented by a collective bargaining 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. Our executive officers and other management employees regularly travel to Poland to supervise activities conducted by our staff and others under contract on our behalf.

Offices and Facilities

Our corporate offices, located at 3006 Highland Drive, Salt Lake City, Utah, contain approximately 3,500 square feet and are rented at $3,400 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. During 2005, we opened an office in Warsaw, located at Ul. Chalubinskiego 8, where we rent an office for approximately $4,300 per month.

Oil and Gas Terms

The following terms have the indicated meaning when used in this report:

“Appraisal well” means a well drilled following a successful exploratory well used to determine the physical extent, reserves and likely production rate of a field.

“Bbl” means oilfield barrel.

“Bcf” means billion cubic feet of natural gas.

“Bcfe” means billion cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.

“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 mean the total number of acres or wells, as the case may be, in which an interest is owned, either directly or through 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.

“LCO” means light crude oil.

“MBbls” means thousand oilfield barrels.

“Mcf” means thousand cubic feet of natural gas.

“MMcf” means million cubic feet of natural gas.

“MMcfD” means million cubic feet of natural gas per day.

“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%, the Standardized Measure of Future Net Cash Flows (“SMOG”). These amounts are calculated net of estimated production costs, future development costs and future income taxes, using prices and costs in effect as of a certain date, without escalation and without giving effect to non property-related expenses, such general and administrative costs, debt service, and 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.

“Usufruct” means the Polish equivalent of a U.S. oil and gas lease.

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, 2006.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY,

RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

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 Global Market, or its predecessor, Nasdaq National Market:

	Low	High
2007:
First Quarter (through March 2, 2007)	$ 5.83	$ 7.88

2006:
Fourth Quarter	4.72	7.00
Third Quarter	4.19	5.48
Second Quarter	3.98	5.71
First Quarter	4.04	8.37

2005:
Fourth Quarter	7.98	12.35
Third Quarter	9.58	12.08
Second Quarter	9.31	12.23
First Quarter	10.65	15.98

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 2, 2007, we had approximately 10,000 stockholders.

Equity Compensation Plans

The information from the definitive proxy statement for the 2007 annual meeting of stockholders under the caption “Equity Compensation Plans” is incorporated herein by reference.

Recent Sales of Unregistered Securities

On November 17, 2006, we entered into a $25.0 million Senior Facility Agreement with the Royal Bank of Scotland plc. As part of the fees for establishing this facility, we issued two-year warrants to purchase 110,000 shares of our common stock at $6.00 per share. No underwriter participated in this transaction.

These warrants were issued to a non-United States person outside the jurisdiction of the Securities Act of 1933 in reliance on Regulation S promulgated thereunder.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for the five years ended December 31, 2006, are derived from our audited consolidated financial statements and notes thereto, certain of which are included in this report. The selected financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and the notes thereto included elsewhere in this report:

	Years Ended December 31,
	2006	2005	2004	2003		2002
	(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales	$ 6,533	$ 3,805	$ 3,096		$ 2,230		$ 2,209
Oilfield services	1,696	2,132	710		98		533
Total revenues	8,229	5,937	3,806		2,328		2,742
Operating costs and expenses:
Lease operating expenses ⁽¹⁾	2,647	2,462	1,946		1,546		1,365
Exploration costs ⁽²⁾	5,608	8,369	3,013		523		1,031
Recovery of previously expensed Input VAT	--	(2,121)	--		--		--
Impairment of oil and gas properties ⁽³⁾	3,583	--	--		161		1,548
Oilfield services costs	1,245	1,689	551		190		540
Depreciation, depletion and amortization	1,290	903	636		599		618
Accretion expense	53	45	41		37		--
Amortization of deferred compensation (G&A)	2,759	125	--		--		55
Stock compensation (G&A)⁽⁴⁾	--	76	5,859		--		--
General and administrative (G&A)	5,606	6,592	4,909		3,253		2,440
Total operating costs and expenses	22,791	18,140	16,955		6,309		7,597

Operating loss	(14,562)	(12,203)	(13,149)		(3,981)		(4,855)

Other income (expense):
Interest and other income	795	780	529		36		119
Interest expense	--	--	--		(788)		(1,189)
Total other income (expense)	795	780	529		(752)		(1,070)

Loss before cumulative effect of change in accounting principle	(13,767)	(11,423)	(12,620)		(4,733)		(5,925)

Cumulative effect of change in accounting principle	--	--	--		1,800		--

Net loss	$ (13,767)	$ (11,423)	$ (12,620)		$ (2,933)		$ (5,925)

– Continued –

	Years Ended December 31,
	2006	2005		2004		2003	2002
	(In thousands)
Basic and diluted net loss per share:

Basic and diluted loss per common share before cumulative effect of change in accounting principle	$ (0.39)		$ (0.33)		$ (0.41)	$ (0.41)		$ (0.34)

Cumulative effect of change in accounting principle	--		--		--	0.09		--

Basic and diluted net loss per common share	$ (0.39)		$ (0.33)		$ (0.41)	$ (0.32)		$ (0.34)

Basic and diluted weighted average shares outstanding	35,163		34,733		30,691	19,885		17,641

Cash Flow Statement Data:
Net cash used in operating activities	$ (5,303)		$(10,105)		$ (5,886)	$ (5,561)		$ (2,162)
Net cash provided by (used in) investing activities	8,135		4,656		(41,492)	(1,446)		(295)
Net cash (used in) provided by financing activities	(578)		4,055		33,791	23,673		5

Balance Sheet Data:
Working capital (deficit)	$ 11,967		$ 27,715		$ 33,777	$ 16,032		$ (9,150)
Total assets	39,167		48,271		52,962	23,769		5,441
Long-term debt	--		--		--	--		--
Stockholders’ equity (deficit)	31,965		42,280		48,556	21,459		(4,869)

(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 and unproved property write-downs relating to our properties in the United States and Poland.

(4)	Includes noncash compensation charge of $5.8 million associated with the cashless exercise of certain employee stock options.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 a result of the very different characteristics of our two major operating areas (the U.S. and Poland), our financial results show a distinct dichotomy. Our U.S. operations are relatively mature, while our Polish operations are early in their initial development. See “Results of Operations by Business Segment” below.

Through 2006, most of our oil and gas production, revenues and lease operating expenses have been attributable to our U.S. operations. The same is true of our oilfield service revenues and costs. Our U.S. operations have been the source of essentially all of our operating cash flow. These operations are relatively stable, with only modest growth or decline on an annual basis.

Most of our exploration costs have been attributable to our efforts in Poland. We expect our Polish operations will continue to represent the bulk of our exploration costs, reflecting the nature of our exploration efforts there. However, with our recent commencement of oil and gas production in Poland in late 2006, we expect these operations will begin to contribute significantly to our revenues, lease operating expenses and depreciation, depletion and amortization (“DD&A). Consequently, our results through 2006 may not be indicative of our future operations.

Following is a brief discussion concerning certain significant events in Poland that occurred during 2006.

Commencement of Polish Gas Production

Our exploration efforts in Poland have led to our first meaningful production in 2006, as we began producing and selling gas from two of our drilling successes, the Wilga and Zaniemysl wells. After spending almost a year obtaining permits, designing and constructing the production facilities and preparing the necessary sales and operating agreements, production at our Wilga well, located southeast of Warsaw, officially commenced on September 18th, and production began at our Zaniemysl well, located in western Poland, on October 12th.

Zaniemysl-3

Production at the Zaniemysl well reached its targeted initial production rate of 10 MMcfD in early November 2006, and has remained essentially constant since that time. We contracted with POGC for Zaniemysl gas sales nearly a year ago with a base price of approximately $2.40 per Mcf. The contract, which is for the life of the field, contains an escalator clause based on consumer gas prices in Poland. As of January 1, 2007, we were selling gas at the wellhead at a price of $3.70 per Mcf at current exchange rates. At this price and assuming the well maintains its targeted production rate, we believe we will realize gross revenues of approximately $3 million from our 24.5% share of the well in 2007.

We plan to conduct a detailed reservoir test after six months of plateau production. This test, together with the production up to that point, will allow us to measure reserves with greater accuracy than is possible today and help us to decide whether to drill an offset well. At December 31, 2006, the Zaniemysl-3 well had approximately 24 Bcf of gross proved reserves (5.7 Bcf net to our interest), but based upon 3-D seismic data and study to date, we believe that the reservoir contains significant additional reserves that may be captured through a second well on the structure.

Wilga-2

The Wilga well has been a complex engineering endeavor. The well is capable of producing approximately 2 MMcf and between 90 and 125 barrels of LCO per day from each of the three zones. Our plan is to produce two zones simultaneously, when conditions permit, switching one out every six months so that each zone will be on for twelve months and off for six months. Initial production of 4 MMcf and 220 barrels of LCO per day was reached in mid-November. The capability of the Wilga well to continually produce these volumes of gas is constrained to some extent by our ability to sell all of the LCO produced, as we have a fixed amount of LCO storage on site.

At the commencement of production, we had a single purchaser contracted to take all of the LCO produced. Due to unforeseen circumstances, the purchaser was unable to fulfill its commitment to take all of our LCO production. Accordingly, shortly after reaching our targeted initial production levels, we were required to reduce production from the well to a single zone, pending obtaining additional LCO purchasers. Since that time, we have begun selling our LCO to several different purchasers. Production levels in early 2007 have varied between 2 and 3 MMcf and 110 and 170 barrels of LCO per day. We are negotiating with several LCO purchasers to take higher LCO quantities and expect the LCO marketing situation to be resolved in the first half of 2007, allowing the well to return to its targeted initial production levels. As with the Zaniemysl well above, the Wilga well is likely to significantly alter our production, revenues and expenses for 2007 and beyond.

We contracted for Wilga gas sales nearly a year ago at a price based on consumer gas prices in Poland. Effective January 1, 2007, the tariff used as our basis at Wilga was increased, and we are currently selling gas at approximately $6.43 per Mcf at current exchange rates. All gas is sold to a subsidiary of POGC. Our LCO is priced at a slight discount to Brent, which varies from 7% to 12% depending on the purchaser. Assuming current prices remain in effect, and assuming daily production of 4 MMcf and 200 barrels of LCO is reached by the end of the first quarter of 2007, we should realize gross revenues of approximately $10 million from our 82% share of the well in 2007. These figures will vary depending on our ability to market 100% of our LCO production.

As with our Zaniemysl well, we plan to conduct a detailed reservoir test after six months of production that will allow us to measure reserves with greater accuracy and help us to decide whether to drill an offset well. At December 31, 2006, the Wilga-2 well had approximately 6 Bcf of gross proved gas reserves and 247,000 barrels of LCO (4.9 Bcf and 202,000 barrels, net to our interest), but based upon 2-D seismic data and study to date, we believe that the reservoir contains significant additional reserves that may be captured through additional drilling on the structure.

Establishment of $25 million Senior Credit Facility

In November of 2006, we entered into a $25 million Senior Facility Agreement (the Facility) with The Royal Bank of Scotland plc (RBS). We believe our arrangement with RBS is the first onshore gas project financing in Poland. The Facility is provided to FX Energy Poland Sp. z o.o., a wholly owned subsidiary of FX Energy, Inc. Funds from the Facility, which became available to us in March, 2007, will cover infrastructure and development costs at a variety of our Polish gas projects. The Facility is collateralized by our commercial wells and production in Poland.

The Facility is significant to us on a number of levels. First, and foremost, we view the Facility as a validation by a respected international financial institution of the value of our reserves, production and land in Poland. Second, it provides us with the ability to leverage our balance sheet and finance the development of our gas projects in Poland at a reasonable cost. Third, it provides us with a potentially important initial relationship in the financial community.

Under the terms of the Facility, the initial commitment is for approximately $18.6 million, which is based solely on the proved reserve values of our Wilga, Zaniemysl and Kleka wells. Once we achieve certain amounts of net cumulative production from these wells, the ongoing commitment amount will be based on proved and probable reserves, which should cause the commitment amount to increase to close to the entire face amount of the Facility. The terms of the Facility call for interest payments only through the end of 2010. The principal amount of the Facility will begin to be reduced at that time, terminating at the end of 2012, unless we have been successful in

adding additional properties and/or reserves to our borrowing base. Interest will be accrued at LIBOR plus an applicable margin, which is currently 1.25%, but which will be reduced to 0.625% upon the attainment of the above-discussed cumulative production thresholds. We expect to satisfy those production requirements sometime during the second quarter of 2007.

In consideration for the Facility, we paid a 1% origination fee and issued warrants to purchase 110,000 shares of our common stock, valid for two years at an exercise price of $6.00 per share. The Black-Scholes value of these warrants (approximately $305,000), along with the loan origination fee and associated legal fees, have been capitalized as deferred financing costs, and will be amortized over the six-year term of the loan, beginning in 2007. An annual unused commitment fee of 1/2% will be charged quarterly based on the average daily unused portion of the Facility.

Polish Gas Prices and the Value of Polish Gas Reserves

Poland has historically subsidized the cost of gas it imports from Russia and other countries for its consumers. However, subsequent to joining the European Union, and in an effort to create a more transparent gas market, Poland has recently begun raising consumer prices in-country, and appears likely to do so over the next few years.

We are a direct beneficiary of these price increases. As discussed above, gas production from all of our currently producing Polish wells is sold to POGC, or one of its affiliates, subject to gas sales agreements that are in effect for the entire life of the fields. In the cases of Wilga and Zaniemysl, the agreements provide for price change mechanisms that are tied to Polish consumer gas prices. Increases in consumer prices in Poland would have several effects. First, and most important, higher prices mean increased revenues and cash flows. Second, the price increases at our properties would increase the value of our reserves. Third, an increase in the value in our reserves would increase our borrowing capacity for project financing purposes. It should be noted that a decrease in Polish consumer prices in the future would have the opposite and negative effects. Nevertheless, the following table illustrates the effect that recent price increases had on the pre-tax PV-10 value of our Polish gas reserves from 2005 to 2006 (excluding the Kleka 11 well):

	2006		2005
	Net Proved Reserves (Bcfe)	Pre-Tax PV-10 value (MM$)	Net Proved Reserves (Bcfe)	Pre-Tax PV-10 value (MM$)	$ Change in PV-10 (MM$)	% Change in PV-10
Well:
Wilga-2	6.037	$29.14	6.298	$17.37	$11.77	68%
Zaniemysl-3	5.717	13.96	5.888	8.85	5.11	58%
Sroda-4	7.882	18.82	7.882	14.16	4.66	33%
Total	19.636	$61.92	20.068	$40.38	$21.54	53%

Rusocin Property Impairment

During the second half of 2004, we and POGC drilled the Rusocin-1 well, the first well intentionally focused on a stratigraphic trap in the Rotliegend. In a January 2005 initial drill stem test, the well flowed gas from an 8 meter section of the Rotliegend sandstone target reservoir. Results of the initial drill stem test indicated that the reservoir may extend beyond the mapped faults, suggesting a larger reservoir along the Wolsztyn High. We believe the well may have discovered the lower edge of a pinch-out at the top of the Rotliegend sandstone with 20-25% porosity, and that the well contains commercial quantities of natural gas.

Following the Rusocin discovery, however, our exploration and production efforts have been focused in other areas and play types, primarily in the Sroda area, and it is likely that this focus will continue in the near term. During the fourth quarter of 2006, we determined to delay steps to place the Rusocin well into production as we focus on the Sroda area in 2007. Our future plans may include further exploration and development along the pinch-out trend.

In accordance with the provisions of FASB Staff Position 19-1, “Accounting for Suspended Well Costs,” the capitalized costs associated with this well of $3.4 million were charged to expense in the fourth quarter of 2006.

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 net capitalized costs of unproved properties, on a property-by-property basis, are not considered 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. 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. 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.

As of December 31, 2006, we had $2.4 million of capitalized exploratory well costs pending the determination of proved reserves. Further information can be found in note 1 to the consolidated financial statements.

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, depletion and amortization (“DD&A”) rates.

Despite the inherent imprecision in these engineering estimates, these estimates are used in determining DD&A expense and impairment expense and in disclosing the supplemental standardized measure of discounted future net cash flows relating to proved oil and gas properties. DD&A 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 DD&A expense. Also, estimated reserves are used to calculate future cash flows from our oil and gas operations, which serve as an indicator of fair value in determining whether a property is impaired or not. The larger the estimated reserves, the less likely the property is impaired.

Stock-based Compensation

Effective January 1, 2006, we adopted the provisions of SFAS No. 123R, “Share-Based Payments” (“SFAS No. 123R”). Under SFAS No. 123R, share-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. We adopted SFAS No. 123R using the modified prospective transition method. Under this method, prior periods are not revised for comparative purposes. The provisions of SFAS No. 123R apply to new awards and to awards that are outstanding on the effective date that are subsequently modified or cancelled. Compensation expense for unvested awards at the effective date will be recognized over the remaining requisite service period using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”).

See notes 1 and 10 in the notes to the consolidated financial statements for information on the adoption of SFAS 123(R), “Share-Based Payments.”

Results of Operations by Business Segment

We operate within two segments of the oil and gas industry: the exploration and production, or E&P, segment in Poland and the United States, and the oilfield services segment in the United States. 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, interest income, other income, interest expense, and other costs, which are not allocated to individual operating segments for management or segment reporting purposes, are discussed in their entirety following the segment discussion. The following table summarizes the results of operations by segment for the years ended December 31, 2006, 2005 and 2004 (in thousands):

	Reportable Segments
	Exploration & Production
	U.S.	Poland	Oilfield Services	Non-Segmented	Total
Year ended December 31, 2006:
Revenues	$ 4,260	$ 2,273	$ 1,696	$ --	$ 8,229
Net income (loss)⁽¹⁾	463	(6,779)	296	(7,747)	(13,767)

Year ended December 31, 2005:
Revenues	$ 3,805	$ --	$ 2,132	$ --	$ 5,937
Net income (loss)⁽²⁾	(84)	(6,238)	78	(5,179)	(11,423)

Year ended December 31, 2004:
Revenues	$ 3,096	$ --	$ 710	$ --	$ 3,806
Net income (loss)⁽³⁾	(228)	(3,532)	692	(9,552)	(12,620)

(1)	Nonsegmented reconciling items for 2006 include $5,606 of general and administrative costs, $2,759 of noncash stock compensation expense, $795 of other income, and $177 of corporate DD&A.

(2)	Nonsegmented reconciling items for 2005 include $5,551 of general and administrative costs, $201 of noncash stock compensation expense, $711 of other income, and $138 of corporate DD&A.

(3)	Nonsegmented reconciling items for 2004 include $4,136 of general and administrative costs, $5,859 of noncash stock compensation expense, $525 of other income, and $82 of corporate DD&A.

A comparison of the results of operations by business segment and the information regarding nonsegmented items for each of the years presented follows. Further information concerning our business segments can be found in Note 11, Business Segments, in the consolidated financial statements.

Exploration and Production Segment

Gas Revenues. As discussed previously, we began gas production in Poland during 2006, and we expect the related gas revenues to rapidly become the primary component of our revenue. Revenues from gas sales were $1.8 million during 2006, compared to $0 in both 2005 and 2004.

Gas revenue and production information for each of our three producing wells during 2006 was as follows:

	Volumes (Mcf)	Revenue	Price per Mcf
Wilga-2	159,691	$963,254	$6.15
Zaniemysl-3	164,183	572,504	3.49
Kleka 11	137,429	253,763	1.85

_______________

Note:

Gas prices vary from property to property based primarily on the energy content of the gas, as well the year in which the gas sales contract was consummated.

Our Wilga-2 well, located just southeast of Warsaw, commenced production on September 19, 2006. This well has three separate productive zones, is capable of producing from two zones simultaneously, and produces both gas and light crude oil (LCO). Estimated peak production with two zones producing simultaneously is approximately 4 MMcf and 220 Bbls of LCO per day. During the fourth quarter of 2006, we did produce from two zones for a short period of time; however, our LCO purchaser was unable to take all of the contracted LCO quantities produced, which caused us to reduce production back to a single zone until we can find a suitable replacement purchaser or purchasers. We expect to remedy this situation during the first quarter of 2007, and resume our estimated initial production rates.

Gas production began at our Zaniemysl-3 well, located in western Poland, on October 12, 2006. Initial production of 10 MMcfD was reached on November 9, 2006, and has remained essentially constant since that time.

Production from our Kleka 11 well remains fairly constant from month to month, averaging approximately 770 MMcfD. We did not record any gas revenues during 2005 and 2004 from the Kleka 11 well. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation: Introduction—Fences I Commitment and Settlement, related to settling our Fences I obligation with POGC.

Oil Revenues. Oil revenues were $4.7 million, $3.8 million and $3.1 million for the years ended December 31, 2006, 2005 and 2004, respectively. Included in 2006 revenues were approximately $483,000 related to the sale of a total of 8,549 barrels of LCO in Poland during 2006. All other oil revenues during the three years were derived from our producing properties in the United States. During these three years, oil revenues fluctuated primarily due to volatile oil prices and changing production rates that are a function of normal property declines. U.S. oil revenues in 2006 increased from 2005 levels by approximately $607,000 due to higher oil prices, offset by approximately $151,000 related to production declines. Oil revenues in 2005 increased from 2004 levels by approximately $922,000 due to higher oil prices, offset by approximately $213,000 related to lower oil production.

A summary of the amount and percentage change, as compared to their respective prior-year period, for oil revenues, average oil prices, oil production volumes, and lifting costs per barrel for the years ended December 31, 2006, 2005 and 2004, is set forth in the following table:

	For the year ended December 31,
	2006	2005	2004
Revenues	$4,744,000	$3,805,000	$3,096,000
Percent change versus prior year	+24.7%	+22.9%	+38.8%
Average price (per Bbl )	$56.13	$48.45	$36.44
Percent change versus prior year	+15.9%	+32.9%	+38.6%
Production volumes (per Bbl)	84,520	78,534	84,970
Percent change versus prior year	+7.6%	-7.5%	+.10%
Lifting costs per Bbl ⁽¹⁾	$25.23	$26.79	$18.85
Percent change versus prior year	-5.8%	+42.1%	+5.9%

(1)	Lifting costs per barrel are computed by dividing the related lease operating expenses by the total barrels of oil produced. LCO lifting costs in Poland are based on an allocation of total costs based on relative revenues between oil and gas. Lifting costs do not include production taxes.

Lease Operating Costs. Lease operating costs were $2.6 million in 2006, $2.5 million in 2005 and $1.9 million in 2004. Operating costs rose slightly from 2005 to 2006 as we commenced gas and LCO production at our Wilga well in Poland. Lease operating costs at our Kleka and Zaniemysl wells were not significant in 2006. We also continued recompleting wells in Montana, adding nine producing wells. Operating costs rose from 2004 to 2005 as we took advantage of higher oil prices and revenues to work over and recomplete several wells in Montana, which increased our operating costs by approximately $440,000. In addition, the higher oil revenues in 2005 resulted in higher value-based production taxes of approximately $34,000.

Exploration Costs. Our exploration efforts are focused in Poland, and the expenses consist of oil and gas leasehold impairments. Exploration costs were $5.6 million, $8.4 million and $3.0 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Geological and geophysical costs, or G&G costs, were $4.2 million, $3.3 million and $2.5 million for the years ended December 31, 2006, 2005 and 2004, respectively. During all three years, most of our G&G costs were spent on acquiring, processing and interpreting new seismic data on the Fences I and II areas, including our new 3-D seismic survey in the Sroda area which began shooting in late 2006.

Exploratory dry-hole costs were $1.6 million, $5.1 million and $472,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Our 2006 exploration costs include approximately $800,000 associated with the Drozdowice-1 well in our Fences III prospect in Poland, along with additional amounts for two dry holes in Montana and Nevada. During 2005, we plugged and abandoned two wells in Poland, the Sroda-5 and Lugi 1 wells, for a total cost of approximately $4.6 million. In addition, we plugged and abandoned four exploratory wells in Nevada for a total cost of approximately $713,000. As part of the abandonment of our Pomeranian project area, we were required to plug and abandon the Tuchola 108-2 well in 2004.

Impairment Costs. Impairments of oil and gas properties were $3.6 million, $0 and $0 for the years ended December 31, 2006, 2005 and 2004, respectively. As discussed previously, during 2006 we impaired the entire amount of capitalized costs associated with our Rusocin-1 well. There were no similar impairments during 2005 or 2004.

DD&A Expense - Producing Operations. DD&A expense for producing properties was $957,000, $511,000 and $259,000 for the years ended December 31, 2006, 2005 and 2004, respectively. The increase from 2005 to 2006 was due primarily to the commencement of production at our properties in Poland, which accounted for $304,000 of the $446,000 increase. The remaining increase is due to capital cost additions in 2006 at our Montana producing properties. The increase from 2004 to 2005 was due primarily to a reduction in oil reserves associated with higher operating costs, offset by lower production volumes.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $1.7 million, $2.1 million and $710,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Activity in the contract drilling industry where we operate picked up significantly during 2004, increased again in 2005, and slowed somewhat in 2006. 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 own properties, and other factors. We cannot accurately predict future oilfield services revenues.

Oilfield Services Costs. Oilfield services costs were $1.2 million, $1.7 million and $551,000 for the years ended December 31, 2006, 2005 and 2004, respectively, or 73%, 79% and 78% of oilfield servicing revenues, respectively. 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 $155,000, $243,000 and $290,000 for the years ended December 31, 2006, 2005 and 2004, respectively. We spent $295,000, $264,000 and $99,000 on upgrading our oilfield servicing equipment during 2006, 2005 and 2004, respectively.

Nonsegmented Items

G&A Costs - Corporate. G&A costs were $5.6 million, $6.6 million and $4.9 million for the years ended December 31, 2006, 2005 and 2004, respectively. During 2006, we made significant reductions in legal and consulting fees, reducing our G&A by approximately $612,000. Decreases in other G&A areas were offset to some extent by higher employee costs, as we increased headcount in our Poland office. During 2005, we opened a new office in Warsaw, Poland, hiring five experienced individuals to assist in our exploration and production efforts. A portion of the G&A increase in 2005 was attributable to these new office costs, including salaries, taxes and benefits. In addition, we added administrative staff in the United States, where we also experienced higher compensation related costs.

Stock Compensation (G&A). Stock compensation expense recorded in 2005 represents the amortization of stock and options issued to consultants prior to the adoption of SFAS No. 123R. In 2004, two of our officers exercised options to acquire a total of approximately 650,000 shares of our common stock at an exercise price of $3.00 per share, by canceling options to purchase approximately 350,000 shares and applying the option equity to pay the exercise price on the options exercised. The 10-year options were due to expire during the second quarter. In connection with this cashless exercise, we recorded a stock compensation charge of approximately $5.8 million, which is equal to the difference between the exercise price and fair value of the options on the date of exercise, and a corresponding increase in additional paid-in capital. This noncash transaction had no impact on our working capital, cash flows or stockholders’ equity.

Amortization of Deferred Compensation (G&A). As discussed above, we adopted the provisions of SFAS No. 123R on January 1, 2006, using the modified prospective method. Under this method, prior periods are not revised for comparative purposes. Stock-based awards that are granted prior to the effective date continue to be accounted for in accordance with SFAS No. 123, except that stock option expense for unvested options must be recognized in the consolidated statement of operations. Stock compensation expense recorded for 2006 represents $1.0 million of amortization related to restricted stock granted in November 2005 and December 2006 and $1.7 million of amortization of unvested stock options granted prior to 2005, using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123.

Interest and Other Income - Corporate. Interest and other income was $817,000, $725,000 and $529,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Increases in both yearly periods are due to higher cash balances generally available for investment, coupled with rising interest rates over the two-year period.

Income Taxes. We incurred net losses of $13.8 million, $11.4 million and $12.6 million for the years ended December 31, 2006, 2005 and 2004, respectively. SFAS No. 109, “Accounting for Income Taxes,” requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our consolidated statement of operations for these years.

Liquidity and Capital Resources

To date, we have financed our operations principally through the sale of equity securities, issuance of debt securities, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. We believe our cash resources and marketable securities at December 31, 2006, together with anticipated revenues in 2007 and availability under our $25 million Senior Facility Agreement, are sufficient to cover our planned exploration program and ongoing operations in the United States and Poland for the next 12 months.

We may seek to obtain additional funds for future capital investments from the sale of additional securities, project financing to help finance the completion of successful wells, 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 will allocate our existing capital as well as funds we may obtain in the future among our various projects at our discretion. We may change the allocation of capital among the categories of anticipated expenditures depending upon future events. For example, we may change the allocation of our expenditures based on the actual results and costs of future exploration, appraisal, development, production, property acquisition and other activities. In addition, we may have to change our anticipated expenditures if costs of placing any particular discovery into production are higher, if the field is smaller, or if the commencement of production takes longer than expected.

Working Capital (current assets less current liabilities). Our working capital was $12.0 million as of December 31, 2006, a decrease of $15.7 million from December 31, 2005. The decrease is due primarily to costs associated with our drilling and seismic activities during 2006, coupled with the costs of production facilities at our Wilga and Zaniemysl wells.

Operating Activities. We used net cash of $5.3 million, $10.1 million and $5.9 million in our operating activities during 2006, 2005 and 2004, respectively, primarily as a result of the net losses, excluding noncash charges, incurred in those years. Our current assets at year-end included approximately $1.6 million in accrued oil and gas sales from both the United States and Poland, and $710,000 in refundable Input VAT that we expect to receive during the first six months of 2007. Our current liabilities at year-end included approximately $3.1 million in costs related to our exploration activities in Poland that were paid in early 2007.

Investing Activities. We received net cash from investing activities of $8.1 million and $4.7 million in 2006 and 2005, respectively, and used net cash of $41.5 million in investing activities in 2004. In 2006 we received $16.8 million from the maturities of marketable securities. We invested $782,000 in marketable securities. We spent $7.5 million for oil and gas property additions, $6.9 million of which was related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $67,000 upgrading our office equipment and $295,000 adding to our oilfield services equipment.

In 2005 we received $6.8 million from the sale of marketable securities and $1.9 million from the recovery of previously capitalized Input VAT. We invested $627,000 in marketable securities. We spent $3.8 million for oil and gas property additions, $3.3 million of which was related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $158,000 upgrading our office equipment and $264,000 upgrading our oilfield services equipment.

In 2004 we transferred $32.7 million to our investment portfolio of marketable securities. We also spent $8.4 million for oil and gas property additions, $7.7 million of which was related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $395,000 upgrading our office equipment and purchasing new oilfield technical software.

Financing Activities. We used net cash in financing activities of $578,000 in 2006, and received net cash of $4.1 million and $33.8 million from our financing activities during 2005 and 2004, respectively. All the cash used in financing activities in 2006 was used to pay the loan origination fees and associated legal costs related to our $25 million Senior Credit Facility. All of the proceeds in 2005 were from the exercise of stock options and warrants. In 2004 we received a total of $20.7 million in net proceeds from the sale of securities. In addition, the exercise of warrants and options provided additional proceeds of $13.1 million.

Contractual Obligations and Contingent Liabilities and Commitments

We had no significant contractual obligations or commitments as of December 31, 2006.

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 and Poland operations and also 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.

New Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board issued FASB Interpretation Number 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. The provisions of FIN 48 are effective as of the beginning of our 2007 fiscal year, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We do not believe the adoption of this pronouncement will have an affect on our consolidated financial statements.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 are effective for the Company for the December 31, 2006 year-end. The provisions of SAB 108 had no impact on our consolidated financial position, results of operations or cash flows.

We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position or cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on our current or future earnings or operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

Price Risk

Realized pricing for our oil production in the United States is primarily driven by the prevailing worldwide price of oil, subject to gravity and other adjustments for the actual oil sold. Historically, oil prices have been volatile and unpredictable. Price volatility relating to our oil production in the United States is expected to continue in the foreseeable future.

Our gas in Poland is sold to POGC or its subsidiaries under contracts that extend for the life of each field. Prices are determined contractually and, in the case of our Wilga and Zaniemysl wells, are tied to published tariffs. Gas sold at Kleka is sold at a fixed price without regard to any published tariff or index. The currently limited volumes and sources of our gas production mean 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 by limiting our market for potential customers. POGC is the primary purchaser of domestic gas in Poland. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in a more 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 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 denominated in the Polish zloty. 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 immediate future; our policy is to use zloty-based revenues generated in Poland to pay for all zloty-based invoices, supplemented as needed by transferring US dollars to Poland to cover invoices that exceed the generated revenues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements, including the independent registered public accounting firm’s report on our consolidated financial statements, are included beginning at page F-2 immediately following the signature page of this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

During the year ended December 31, 2006, we have not disagreed with our independent registered public accounting firm on any items of accounting treatment or financial disclosure.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2006, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2006, our disclosure controls and procedures were effective.

Internal Control over Financial Reporting

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management’s report on internal control over financial reporting and the report of PricewaterhouseCoopers LLP, our independent registered public accounting firm, on management’s assessment and the effectiveness of internal control over financial reporting are included on pages F-1 and F-2 of this report and are incorporated in this Item 9A by reference.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information from the definitive proxy statement for the 2007 annual meeting of stockholders under the captions “Corporate Governance,” “Proposal 1. Election of Directors,” and “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information from the definitive proxy statement for the 2007 annual meeting of stockholders under the caption “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 2007 annual meeting of stockholders under the caption “Principal Stockholders” is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information from the definitive proxy statement for the 2007 annual meeting of stockholders under the captions “Certain Relationships and Related Transactions” and “Director Independence” is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information from the definitive proxy statement for the 2007 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	The following documents are filed as part of this report or incorporated herein by reference.

Financial Statements. See the following beginning at page F-1:

	Page
Management’s Report on Internal Control over Financial Reporting	F-1
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2006 and 2005	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004	F-6
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2006, 2005 and 2004	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	F-8
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2006, 2005 and 2004	F-9
Notes to the Consolidated Financial Statements	F-10

Supplemental Schedules. The supplemental schedules have been omitted because they are not applicable or the required information is otherwise included in the accompanying consolidated financial statements and the notes thereto.

Exhibits. The following exhibits are included as part of this report:

Exhibit Number*	Title of Document	Location

Item 3	Articles of Incorporation and Bylaws
3.01	Restated and Amended Articles of Incorporation	Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended September 30, 2000, filed November 7, 2000.

3.02	Bylaws	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2005, filed March 14, 2006.

3.03	Articles of Amendment to the Restated Articles of Incorporation of FX Energy, Inc.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2005, filed March 14, 2006.

Item 4	Instruments Defining the Rights of Security Holders
4.01	Specimen Stock Certificate	This filing.

4.03	Form of Rights Agreement dated as of April 4, 1997, between FX Energy, Inc. and Fidelity Transfer Corp.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

Item 10	Material Contracts
10.26	Frontier Oil Exploration Company 1995 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.27	FX Energy, Inc. 1996 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.28	FX Energy, Inc. 1997 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.29	FX Energy, Inc. 1998 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.30	Employment Agreements between FX Energy, Inc. and each of David Pierce and Andrew Pierce, effective January 1, 1995**	Incorporated by reference from the registration statement on Form SB-2, SEC File No. 33-88354-D.

10.32	Form of Stock Option with related schedule (D. Pierce and A. Pierce)**	Incorporated by reference from the registration statement on Form SB-2, SEC File No. 33-88354-D.

10.39	Employment Agreement between FX Energy, Inc. and Jerzy B. Maciolek**	Incorporated by reference from the registration statement on Form S-1, SEC File No. 333-05583, filed June 10, 1996.

10.42	Employment Agreement between FX Energy, Inc. and Scott J. Duncan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.52	Form of Indemnification Agreement between FX Energy, Inc. and certain directors, with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.53	Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to Fences I project area	Incorporated by reference from the current report on Form 8-K filed May 2, 2000.

10.59	Sales / Purchase Agreement Special Provisions between Plains Marketing Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

10.60	Form of Non-Qualified Stock Option awarded August 14, 2002, with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

10.62	Agreement Regarding Cooperation within the Poznan Area (Fences II) entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

10.63	Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

10.64	Farmout Agreement Entered into by and between FX Energy Poland 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	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

10.67	FX Energy, Inc. 1999 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.68	FX Energy, Inc. 2000 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.69	FX Energy, Inc. 2001 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.70	FX Energy, Inc. 2003 Long-Term Incentive Plan	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

10.74	Greater Zaniemysl Area Agreement made as of March 12, 2004, among FX Energy Poland Sp. z o.o. and CalEnergy Resources Poland Sp. z o.o.	Incorporated by reference from the quarterly report on Form 10-Q for the period ended March 31, 2004, filed May 11, 2004.

10.75	Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**	This filing.

10.76	Supplemental Indemnification Agreement between FX Energy, Inc. and Dennis B. Goldstein**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2004, filed March 15, 2005.

10.77	Description of compensation arrangement with executive officers and directors**	This filing.

10.78	Form of Employment Agreement with related schedule**	This filing.

10.79	Change in Control Compensation Agreement with related schedule**	This filing.

10.81	FX Energy, Inc. 2004 Long-Term Incentive Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2004, filed March 15, 2005.

10.82	Letter of Engagement, H. Allen Turner, dated February 14, 2007	Incorporated by reference from the current report on Form 8-K filed February 20, 2007

10.83	US$25,000,000 Senior Facility Agreement among FX Poland Sp. z o.o., FX Energy, Inc., FX Energy Netherlands Partnership CV., FX Energy Netherlands BV., and The Royal Bank of Scotland PLC, dated November 17, 2006	This filing.

10.84	Common Stock Purchase Warrant dated November 17, 2006	This filing.

10.85	Agreement for Pledges over Shares in FX Energy Poland Sp. z o.o., dated December 18, 2006	This filing

10.86	Subordination Deed dated December 21, 2006	This filing.

10.87	Restated FX Energy, Inc. 401(k) Stock Bonus Plan dated January 25, 2007**	This filing.

10.88	Agreement for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Mazowiecka Spółka Gazownictwa Sp. z o.o., dated December 29, 2005	This filing.

10.89	Agreement No. PL/012216736/05-0030/DH/HB for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe I Gazownictwo S.A., dated December 8, 2005	This filing.

10.90	Agreement for the Sale of Wellhead Natural Gas between FX Energy Poland Sp. z o.o. and PL Energia S.A., dated January 26, 2007	This filing.

Item 21	Subsidiaries of the Registrant
21.01	Schedule of Subsidiaries	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.

Item 23	Consents of Experts and Counsel
23.01	Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm	This filing.

23.02	Consent of Larry D. Krause, Petroleum Engineer	This filing.

23.03	Consent of RPS Energy, Petroleum Engineers	This filing.

Item 31	Rule 13a-14(a)/15d-14(a) Certifications
31.01	Certification of Chief Executive Officer Pursuant to Rule 13a-14	This filing.

31.02	Certification of Chief Financial Officer Pursuant to Rule 13a-14	This filing.

Item 32	Section 1350 Certifications
32.01	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	This filing.

32.02	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	FX ENERGY, INC. (Registrant)


Dated: March 12, 2007	By:	/s/ David N. Pierce
		David N. Pierce
		President and Chief Executive Officer


Dated: March 12, 2007	By:	/s/ Clay Newton
		Clay Newton
		Principal Financial Officer

	/s/ Thomas B. Lovejoy
Dated: March 12, 2007	Thomas B. Lovejoy, Director
	/s/ David N. Pierce
Dated: March 12, 2007	David N. Pierce, Director
	/s/ Dennis B. Goldstein
Dated: March 12, 2007	Dennis B. Goldstein, Director
	/s/ David L. Worrell
Dated: March 12, 2007	David L. Worrell, Director
	/s/ Arnold S. Grundvig, Jr.
Dated: March 12, 2007	Arnold S. Grundvig, Jr., Director
	/s/ Jerzy B. Maciolek
Dated: March 12, 2007	Jerzy B. Maciolek, Director
	/s/ Richard Hardman
Dated: March 12, 2007	Richard Hardman, Director
	/s/ H. Allen Turner
Dated: March 12, 2007	H. Allen Turner, Director

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of FX Energy, Inc., together with its consolidated subsidiaries (the Company), is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles.

As of the end of the Company’s 2006 fiscal year, management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has determined that the Company’s internal control over financial reporting as of December 31, 2006, was effective.

The Company’s internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, independent registered public accounting firm, as stated in its report appearing on pages F-2 and F-3, which expresses unqualified opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

of FX Energy, Inc. and its subsidiaries

We have completed integrated audits of FX Energy, Inc.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive loss, of cash flows and of stockholders’ equity (deficit) present fairly, in all material respects, the financial position of FX Energy, Inc. and its subsidiaries (the Company) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based compensation on January 1, 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing on page F-1, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the

F-2

Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Salt Lake City, Utah

March 9, 2007

F-3

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

As of December 31, 2006 and 2005

(in thousands)

	2006		2005
ASSETS

Current assets:
Cash and cash equivalents	$	4,644)	$	2,390)
Marketable securities, available for sale		10,448		26,479
Receivables:
Accrued oil and gas sales		1,615		416
Joint interest and other receivables		263		1,592
Input VAT receivable		710		2,032
Inventory		206		96
Other current assets		322		270
Total current assets		18,208		33,275

Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		19,293		12,483
Unproved		2,912		3,739
Other property and equipment		4,624		4,262
Gross property and equipment		26,829		20,484
Less accumulated depreciation, depletion and amortization		(7,134)		(5,844)
Net property and equipment		19,695		14,640

Other assets:
Certificates of deposit		382		356
Loan fees		882		-
Total other assets		1,264		356

Total assets	$	39,167	$	48,271

-Continued-

The accompanying notes are an integral part of these consolidated financial statements.

F-4

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

As of December 31, 2006 and 2005

(in thousands, except share data)

-Continued-

	2006		2005
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	5,234	$	4,110
Accrued liabilities		1,007		1,450
Total current liabilities		6,241		5,560

Asset retirement obligation		961		431

Total liabilities		7,202		5,991

Commitments and contingencies (Note 6)

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of December 31, 2006 and 2005; no shares outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized as of December 31, 2006 and 2005; 35,560,744 and 35,097,279 shares issued and outstanding as of December 31, 2006 and 2005, respectively		36		35
Additional paid in capital		125,706		125,216
Deferred compensation		--		(2,975)
Accumulated other comprehensive loss		(72)		(58)
Accumulated deficit		(93,705)		(79,938)
Total stockholders’ equity		31,965		42,280

Total liabilities and stockholders’ equity	$	39,167	$	48,271

The accompanying notes are an integral part of these consolidated financial statements.

F-5

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

For the years ended December 31, 2006, 2005 and 2004

(in thousands, except per share amounts)

	2006		2005		2004
Revenues:
Oil and gas sales	$	6,533	$	3,805	$	3,096
Oilfield services		1,696		2,132		710
Total revenues		8,229		5,937		3,806
Operating costs and expenses:
Lease operating expenses		2,647		2,462		1,946
Exploration costs		5,608		8,369		3,013
Recovery of previously expensed Input VAT		--		(2,121)		--
Impairment of oil and gas properties		3,583		--		--
Oilfield services costs		1,245		1,689		551
Depreciation, depletion and amortization		1,290		903		636
Accretion expense		53		45		41
Stock compensation (G&A)		--		76		5,859
Amortization of deferred compensation (G&A)		2,759		125		--
General and administrative costs (G&A)		5,606		6,592		4,909
Total operating costs and expenses		22,791		18,140		16,955
Operating loss		(14,562)		(12,203)		(13,149)

Other income (expense):
Interest and other income		795		780		529
Total other income (expense)		795		780		529

Net loss	$	(13,767)	$	(11,423)	$	(12,620)

Basic and diluted net loss per common share	$	(0.39))	$	(0.33))	$	(0.41))
Basic and diluted weighted average number of shares outstanding		35,163		34,733		30,691

The accompanying notes are an integral part of these consolidated financial statements.

F-6

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Loss

For the years ended December 31, 2006, 2005 and 2004

(in thousands)

		2006		2005	2004
Net loss	$	(13,767)	$	(11,423)	$	(12,620)

Other comprehensive income (loss)
Increase (decrease) in market value of available for sale marketable securities		(14)		281		(339)
Comprehensive loss	$	(13,781)	$	(11,142)	$	(12,959)

The accompanying notes are an integral part of these consolidated financial statements.

F-7

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For the years ended December 31, 2006, 2005 and 2004

(in thousands)

		2006		2005		2004
Cash flows from operating activities:
Net loss	$	(13,767)	$	(11,423)	$	(12,620)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,290		903		636
Impairment of oil and gas properties		3,583		--		--
Property abandonment		--		242		--
Accretion expense		53		45		41
(Gain) loss on property dispositions		--		(18)		1
Stock compensation (G&A)		--		76		5,859
Amortization of deferred compensation (G&A)		2,759		125		--
Common stock issued for services (G&A)		517		610		406
Increase (decrease) from changes in working capital items:
Receivables		1,451		(2,438)		(1,077)
Inventory		(110)		(4)		(13)
Other current assets		(52)		(46)		(98)
Other assets		(25)		3		(10)
Accounts payable and accrued liabilities		(995)		1,848		989
Asset retirement obligation		(7)		(28)		--
Net cash used in operating activities		(5,303)		(10,105)		(5,886)

Cash flows from investing activities:
Additions to oil and gas properties		(7,521)		(2,989)		(8,437)
Additions to other property and equipment		(362)		(422)		(395)
Recovery of previously capitalized VAT		--		1,921		--
Additions to marketable securities		(782)		(627)		(32,660)
Proceeds from maturities of marketable securities		16,800		6,750		--
Proceeds from sale of assets		--		23		--
Net cash provided by (used in) investing activities		8,135		4,656		(41,492)

Cash flows from financing activities:
Payment of loan fees		(578)		--		--
Proceeds from issuance of common stock , net of offering costs		--		--		20,724
Proceeds from exercise of stock options and warrants		--		4,055		13,067
Net cash provided by (used in) financing activities		(578)		4,055		33,791

Net increase (decrease) in cash		2,254		(1,394)		(13,587)
Cash and cash equivalents at beginning of year		2,390		3,784		17,371

Cash and cash equivalents at end of year	$	4,644	$	2,390)	$	3,784)

The accompanying notes are an integral part of these consolidated financial statements.

F-8

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity (Deficit)

For the years ended December 31, 2006, 2005 and 2004

(in thousands)

		Common Stock								Accumulated
				Par Value				Additional		Other				Total
	Preferred	Shares		$0.001 Per		Deferred		Paid in		Comprehensive		Accumulated		Stockholders’
	Stock	Issued		Share		Compensation		Capital		Income (Loss)		Deficit		Equity (Deficit)
Balance as of December 31, 2003	--	27,300	$	27	$	--	$	77,327)	$	--	$	(55,895)	$	21,459
Common stock offering, net	--	3,103		3		--		20,721)		--		--		20,724
Common stock issued for services	--	43		--		--		406)		--		--		406
Exercise of stock options	--	554		--		--		2,987)		--		--		2,987
Stock compensation	--	710		1		--		5,858)		--		--		5,859
Exercise of warrants	--	2,688		3		--		10,077)		--		--		10,080
Other comprehensive loss	--	--		--		--		--		(339)		--		(339)
Net loss for year	--	--		--		--		--		--		(12,620)		(12,620)
Balance as of December 31, 2004	--	34,398		34		--		117,376)		(339)		(68,515)		48,556
Common stock issued for services	--	58		--		--		610)		--		--		610
Exercise of stock options	--	593		1		--		3,874)		--		--		3,875
Stock compensation	--	--		--		--		76		--		--		76
Deferred compensation	--	--		--		(3,100)		3,100		--		--		--
Amortization of deferred compensation	--	--		--		125		--		--		--		125
Exercise of warrants	--	48		--		--		180		--		--		180
Other comprehensive income	--	--		--		--		--		281		--		281
Net loss for year	--	--		--		--		--		--		(11,423)		(11,423)
Balance as of December 31, 2005	--	35,097		35		(2,975)		125,216		(58)		(79,938)		42,280
Common stock issued for services	--	464		1		--		706		--		--		707
Elimination of deferred compensation upon adoption of SFAS No. 123R	--	--		--		2,975		(2,975)		--		--		--
Amortization of deferred compensation	--	--		--		--		2,759		--		--		2,759
Other comprehensive loss	--	--		--		--		--		(14)		--		(14)
Net loss for year	--	--		--		--		--		--		(13,767)		(13,767)
Balance as of December 31, 2006	--	35,561	$	36	$	--	$	125,706	$	(72)	$	(93,705)	$	31,965

The accompanying notes are an integral part of these consolidated financial statements.

F-9

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 in partnership with the Polish Oil and Gas Company (“POGC”), other industry partners and for its own account. In the United States, the Company explores for and 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, 2006, 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

Excluding the receivable for Input VAT, which is due from the State Treasury Office of Poland, 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. Substantially all of the Company’s domestic receivables are with Cenex, a regional refiner and marketer, and substantially all of the Company’s Polish receivables are with the Polish Oil and Gas Company or one of its affiliates. The receivables are not collateralized. To date, the Company has experienced minimal bad debts, and has no allowance for doubtful accounts at December 31, 2006 and 2005. The majority of the Company’s cash and cash equivalents are held by four financial institutions in Utah, Montana, New York and Poland. The Company’s marketable securities are held by two financial institutions in Utah 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, or if the determination that proved reserves have been found cannot be made within one year, or if the Company is not making sufficient progress assessing the reserves and the economic and operating viability of the project, 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

F-10

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

and gas properties is provided on a field-by-field basis using the units-of-production method. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net revenues determined on a field-by-field 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.

The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves, during 2006, 2005 and 2004.

	December 31,
	2006		2005		2004
				(In thousands)
Beginning balance at January 1	$	3,435	$	8,779	$	--
Additions to capitalized exploratory well costs pending the determination of proved reserves		2,386		313		8,779
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		--		(5,559)		--
Capitalized exploratory well costs charged to expense		(3,435)		(98)		--
Ending balance at December 31	$	2,386	$	3,435	$	8,779

The 2006 balance includes costs associated with the Winna Gora and Roszkow wells in Poland, which were in process at year end. As of March 2, 2007, production tests were being conducted at the Winna Gora well, and the Roszkow well was still being drilled. As a result of its current focus in the Sroda area, the Company has determined to delay assessing the reserves and the economic and operating viability of its Rusocin well in Poland. The provisions of FASB Staff Position No. FAS 19-1, Accounting for Suspended Well Costs (FSP 19-1) require the costs associated with this well, approximately $3.4 million, to be impaired at December 31, 2006.

The 2005 balance included costs associated with the Rusocin well in Poland which was under evaluation. The 2004 balance included costs associated with the Rusocin and Sroda wells in Poland and the East Inselberg well in Nevada.

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.

F-11

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation, is summarized as follows:

					Estimated
	December 31,				Useful Life
	2006		2005		(in years)
	(In thousands)
Other property and equipment:
Drilling rigs	$	3,317	$	3,022	6
Other vehicles		290		290	5
Building		108		106	40
Office equipment and furniture		909		844	3 to 6
Total cost		4,624		4,262
Accumulated depreciation		(3,863)		(3,530)
Net property and equipment	$	761	$	732

Supplemental Disclosure of Cash Flow Information

Noncash investing and financing transactions not reflected in the consolidated statements of cash flows include the following:

	Year Ended December 31,
	2006	2005	2004
	(In thousands)
Noncash investing transactions:
Additions to properties included in current liabilities	$2,359	$798	$1,076
Recovery of previously capitalized VAT included in Input VAT receivable	--	254	--
Additions to properties previously included in other and current assets	--	--	490

Supplemental disclosure of cash paid for interest and income taxes:

	Year Ended December 31,
	2006		2005		2004
	(In thousands)
Supplemental disclosure:
Cash paid during the year for interest	$	--	$	--	$	--
Cash paid during the year for income taxes		--		--		--

Revenue Recognition

Revenues associated with oil and gas sales are recorded when title passes, which is upon delivery to the pipeline or purchaser, and are net of royalties. Oilfield service revenues are recognized when the related service is performed.

Investments

The cost and estimated market value of marketable securities at December 31, 2006, are as follows (in thousands):

		Gross	Estimated
		Unrealized	Market
	Cost	Losses	Value
Marketable securities	$10,520	$(72)	$10,448

F-12

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

The cost and estimated market value of marketable securities at December 31, 2005, were as follows (in thousands):

		Gross	Estimated
		Unrealized	Market
	Cost	Losses	Value
Marketable securities	$26,537	$(58)	$26,479

The investments consist primarily of U.S. government agency bonds and notes, whose value fluctuates with changes in interest rates. The Company believes all gross unrealized losses are temporary. The investments have been classified as available-for-sale, and are reported at fair value with unrealized gains and losses, if any, recorded as a component of other comprehensive income (loss).

Stock-Based Compensation

The Company maintains several share-based incentive plans. Under these plans, the Company may issue options or restricted stock awards. Options are granted at an option price equal to the market value of the stock at the date of grant, have terms ranging from five to seven years and vest in three equal annual installments. Restricted stock awards have similar terms and vesting requirements.

Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, “Share-Based Payments” (“SFAS No. 123R”). Under SFAS No. 123R, share-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. The Company adopted SFAS No. 123R using the modified prospective transition method. Upon adoption deferred compensation of $2,975,157 was eliminated against additional paid-in capital. Under this method, prior periods are not revised for comparative purposes. The provisions of SFAS No. 123R apply to new awards and to awards that are outstanding on the effective date that are subsequently modified or cancelled. Compensation expense for unvested awards at the effective date will be recognized over the remaining requisite service period using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”).

Prior to the adoption of SFAS No. 123R, the Company recorded compensation expense for employee stock options and restricted stock awards based on their intrinsic value on the date of grant pursuant to Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), and related interpretations and provided the pro forma disclosures required by SFAS No. 123. The pro forma effects of recognizing compensation expense under the fair value method required by SFAS No. 123 on net loss and net loss per common share were as follows (in thousands, except per share data):

	2005		2004
	(In thousands, except per share amounts)
Net loss:
Net loss, as reported	$	(11,423))	$	(12,620))
Add: Stock-based employee compensation expense included in reported net loss, net of any related tax effects		201		5,820
Less: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of any related tax effects		(1,959)		(1,412)
Pro forma net loss	$	(13,181)	$	(8,212)
Basic and diluted net loss per share:
As reported	$	(0.33)	$	(0.41)
Pro forma		(0.38)		(0.27)

F-13

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

The fair value of each option granted to employees and consultants during 2005, 2004 was 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 60% for 2005 and 70% for 2004; (2) expected life of three years; (3) risk-free interest rates at the date of grant ranging from 2.21% to 4.39%; and, (4) dividend yield of zero for each year.

During the second quarter of 2004, two of the Company’s officers exercised options to acquire a total of approximately 650,000 shares of common stock at an exercise price of $3.00 per share, by canceling options to purchase approximately 350,000 shares and applying the option equity to pay the exercise price on the options exercised. The ten-year options were due to expire during the second quarter. In connection with this cashless exercise, the Company recorded a stock compensation charge of approximately $5.8 million, which is equal to the difference between the exercise price and fair value of the options on the date of exercise, and a corresponding increase in additional paid-in capital. This noncash transaction had no impact on the Company’s working capital, cash flows or stockholders’ equity.

New Accounting Standards

In June 2006, the Financial Accounting Standards Board issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. The provisions of FIN 48 are effective as of the beginning of The Company’s 2007 fiscal year, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The Company does not believe the adoption of this pronouncement will have any affect on its financial statements.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 are effective for the Company for the December 31, 2006 year-end. The provisions of SAB 108 had no impact on the Company’s consolidated financial position, results of operations or cash flows.

The Company has reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on its consolidated results of operations, financial position and cash flows. Based on that review, the Company believes that none of these pronouncements will have a significant effect on current or future earnings or operations.

Income Taxes

Deferred income taxes are provided for the differences between the tax bases of assets or liabilities and their reported amounts in the consolidated financial statements. Such differences may result in taxable or deductible amounts in future years when the asset or liability is recovered or settled, respectively.

Foreign Operations

The Company uses the U.S. dollar as its functional currency for its operations and investments in Poland.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to the consolidated financial statements include the estimates of proved oil and gas reserve quantities and the related future net cash flows.

F-14

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Reclassification

Certain amounts in the Consolidated Financial Statements for 2005 and 2004 have been reclassified to conform to the 2006 presentation. These reclassifications had no impact on the Company’s total assets, liabilities, stockholders’ equity, net loss or cash flows.

Net Loss per Share

Basic earnings per share is computed by dividing the net loss applicable to common shares 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, warrants, unvested restricted stock, and convertible preferred stock or debt.

Outstanding options, warrants and unvested restricted stock as of December 31, 2006, 2005 and 2004, were as follows:

	Options, Warrants and
	Unvested Restricked
	Stock	Price Range
Balance sheet date:
December 31, 2006	6,859,106	$0.00 - $10.65
December 31, 2005	6,997,656	$0.00 - $10.65
December 31, 2004	7,405,106	$2.40 - $9.00

The Company had a net loss in 2006, 2005 and 2004. The above options, warrants and unvested restricted stock were not included in the computation of diluted earnings per share for the years presented because the effect would have been antidilutive.

Note 2: Asset Retirement Obligation

The Company accounts for future site restoration costs according to Statement No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). Under SFAS No. 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. The Company uses an expected cash flow approach to estimate its asset retirement obligations under SFAS No. 143. The Company recorded accretion expense of $53,038, $44,565 and $41,000 in 2006, 2005 and 2004, respectively. At December 31, 2006, there were no assets legally restricted for purposes of settling asset retirement obligations.

Following is a reconciliation of the yearly changes in the asset retirement obligation at December 31, 2006 and 2005 (in thousands):

Year ended December 31	2006	2005
Asset retirement obligation at January 1	$431	$414
Current year additions	484	--
Liabilities settled	(7)	--
Adjustment to asset retirement obligation	--	(28)
Accretion expense	53	45
Asset retirement obligation as of December 31	$961	$431

F-15

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Note 3: Other Assets

As of December 31, 2006 and 2005, the Company had a replacement bond with a federal agency in the amount of $463,000, which was collateralized by certificates of deposit totaling $231,500. In addition, there are certificates of deposit totaling $150,000 covering performance bonds in other states.

Note 4: Accrued Liabilities

The Company’s accrued liabilities as of December 31, 2006 and 2005, were comprised of the following:

	December 31,
	2006		2005
	(In thousands)
Accrued liabilities:
Exploratory dry hole costs			$	196
Drilling costs	$	439		387
Compensation related costs		568		867
Total	$	1,007	$	1,450

Note 5: Notes Payable

In November of 2006, the Company entered into a $25 million Senior Facility Agreement (the Facility) with The Royal Bank of Scotland plc (RBS). The Facility is provided to FX Energy Poland Sp. z o.o., a wholly owned subsidiary. Funds from the facility, which became available to the Company in March, 2007, will cover infrastructure and development costs at a variety of the Company’s Polish gas projects and are collateralized by its commercial wells and production in Poland.

Under the terms of the Facility, the initial commitment is for approximately $18.6 million, which is based solely on the proved reserve values of the Wilga, Zaniemysl and Kleka wells. Once the Company achieves certain amounts of net cumulative production from these wells, the ongoing commitment amount will be based on proved plus probable reserves. The terms of the Facility call for interest payments only through the end of 2010. The principal amount of the Facility will begin to be reduced at that time, terminating at the end of 2012, unless the Company has been successful in adding additional properties and/or reserves to its borrowing base. Interest will be accrued at LIBOR plus an applicable margin, which is currently 1.25%, but which will be reduced to 0.625% upon the attainment of cumulative production thresholds.

In consideration for the Facility, the Company paid a 1% origination fee and issued warrants to purchase 110,000 shares of common stock, valid for 2 years at an exercise price of $6.00 per share. The Black-Scholes value of these warrants (approximately $305,000), along with the loan origination fee and associated legal fees, have been capitalized as deferred financing costs, and will be amortized over the 6 year term of the loan, beginning in 2007. An annual unused commitment fee of 1/2% will be charged quarterly based on the average daily unused portion of the Facility.

Note 6: Commitments and Contingencies

Fences I Project Area

On April 11, 2000, the Company agreed to spend $16.0 million of exploration costs on the Fences I project area to earn a 49% interest. When expenditures exceeded $16.0 million, POGC would be obligated to pay its 51% share of further costs.

F-16

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

In early 2003, the Company entered into a settlement agreement with POGC to address the methods by which the Company would satisfy its then existing unpaid liability incurred in connection with meeting its spending commitment. Among other things, the Company agreed to assign to POGC all of its rights to prior production from the Kleka 11 well, and the liability was to be further offset by the value of the remaining gas reserves associated with the well. As of December 31, 2004, the Company’s share of the Kleka 11 well had estimated reserves with a value of approximately $1.3 million, equal to the accrued liability recorded in favor of POGC. Upon completion of the assignment of the Kleka 11 well, the Company’s previously unpaid liability was to have been settled in full.

Through the end of 2004, exclusive of the Kleka 11 well assignment, the Company incurred qualifying costs in excess of the commitment amount, which meant the Company had earned its 49% interest, and POGC was obligated to pay its 51% share of all qualifying project costs. Due to the fact that the Company exceeded its $16.0 million commitment through actual cash expenditures in 2004, the Company and POGC subsequently agreed that the Kleka 11 well would not be assigned to POGC, nor would POGC take credit for prior years’ gas sales. In addition, during the first half of 2005, POGC applied approximately $1.3 million in unused cash-call proceeds against the Company’s outstanding accrued liability. Accordingly, as of December 31, 2005, by virtue of the various transactions related to the Company’s Fences I exploration commitment, POGC now owed the Company an amount equal to the Company’s prior overpayment and its share of gas sales from the Kleka 11 well from inception through the end of 2005 ($1.4 million) and the Company owed POGC an amount attributable to prior costs and interest that were to have been settled against prior year gas sales from the Kleka 11 well ($0.4 million). At December 31, 2005, the receivable from POGC was included in Joint Interest and Other Receivables in the Consolidated Balance Sheets. In connection with settling its accounts, the Company recorded a net charge of approximately $55,000 which was included in Interest and Other Income in the Consolidated Statements of Operations in 2005.

During 2006, the Company collected this net receivable, a portion of which was paid to the Polish government in the form of value-added tax.

Note 7: Value Added Tax Refund

Throughout the Company’s operating history in Poland, until October 2005, the Company had been unable to obtain a refund of most of the value-added taxes paid in connection with goods and services purchased (Input VAT). Polish tax laws have restricted the refund of Input VAT for exploration activities to concession holders. In the Company’s case, the Polish Oil and Gas Company, or POGC, has traditionally been the concession holder, while the Company is a working interest owner by virtue of its agreements with POGC.

During 2004, Poland joined the European Union. This event caused changes to several tax laws, including the law that precluded the Company from obtaining refunds of Input VAT. In April 2005, the Company filed a refund application for approximately 13.7 million Polish zlotys, representing all Input VAT paid since the Company’s inception in Poland through March of 2005. The Polish taxing authorities began their review of the refund application in October, 2005.

As part of the normal course of the review, and in order to prevent interest accruing on the refund amount, the taxing authorities deposited 13.7 million zlotys in the Company’s bank account in Poland in October, 2005, equal to approximately $4.2 million at then-current exchange rates. The Company has since received all requested Input VAT refunds, as monthly tax returns have been filed in accordance with Polish tax regulations.

A portion of the past Input VAT was related to capital costs, with the remainder attributed to 2005 and prior years’ geological and geophysical costs, along with overhead and other expenses. Accordingly, for the $4.2 million refund received in 2005, the Company reduced its capital costs by approximately $1.9 million, 2005 expenses by $0.1 million, with the remaining $2.1 million related to prior years’ expenses shown as a Recovery of Previously Expensed Input VAT in the Consolidated Statements of Operations. In addition, the Company recorded an Input VAT receivable at December 31, 2005 of approximately $2.0 million, representing Input VAT paid since April 2005. This amount was collected in 2006. The Company expects to be Input VAT neutral from this point forward. The input VAT receivable at December 31, 2006 was $709,858.

F-17

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 2006, 2005 and 2004. The components of the net deferred tax asset as of December 31, 2006 and 2005 are as follows:

	December 31,
	2006		2005
	(In thousands)
Deferred tax liability:
Property and equipment basis differences	$	(3,637)	$	(1,126)
Deferred tax asset:
Net operating loss carryforwards:
United States		23,309		21,582
Poland		9,379		2,231
Oil and gas properties		1,855		1,855
Options issued for services		946		184
Asset retirement obligation		176		161
Valuation allowance		(32,028)		(24,887)
Total	$	--	$	--

The change in the valuation allowance during 2006, 2005 and 2004 is as follows:

	Year Ended December 31,
	2006	2005	2004
	(In thousands)
Valuation allowance:
Balance, beginning of year	$(24,887)	$(23,209)	$(19,766)
Change in property and equipment basis differences	2,511	(93)	881
Increase due to net operating loss	(8,875)	(1,538)	(4,747)
Other	(777)	(47)	423
Total	$(32,028)	$(24,887)	$(23,209)

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, 2006 and 2005.

United States NOL

At December 31, 2006, the Company had net operating loss (“NOL”) carryforwards in the United States of approximately $62,489,000 available to offset future taxable income. The carryforwards begin to expire in 2008. 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 $17,930,000 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.

F-18

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Polish NOL

As of December 31, 2006, the Company had NOL carryforwards in Poland totaling approximately $49,362,000, including $13,679,000, $6,874,000 and $5,598,000 generated in 2006, 2005 and 2004, respectively. During 2006 the Company received a favorable ruling from the Polish tax authorities which allows for a ten year carryover of prior year’s NOLs. This ruling allowed for the reinstatement of approximately $24 million of NOLs which had previously expired under the normal carryover rules. The NOLs will begin to expire in 2008. The ruling allows a ten year carryover period for losses incurred from 1997 to 2007. The normal carryforward period in Poland is five years. However, no more than 50% of the NOL carryforward for any given year may be applied against Polish income in succeeding years.

The domestic and foreign components of the Company’s net loss are as follows:

	Year Ended December 31,
	2006	2005	2004
	(In thousands)
Domestic	$ (6,764)	$ (5,199)	$ (9,107)
Foreign	(7,003)	(6,224)	(3,513)
Total	$(13,767)	$(11,423)	$(12,620)

Note 9: Stockholders’ Equity

The Company received proceeds from the exercise of 668,066 stock options and warrants of $4,054,646 during 2005.

The Company completed a registered offering during April of 2004 of 2,152,778 shares of common stock, resulting in proceeds of $14,348,298, net of offering costs of $1,151,704. In August of 2004, the Company placed privately an additional 950,000 shares of registered stock, resulting in proceeds of $6,375,286, net of offering costs of $464,714.

During 2004, warrant holders exercised warrants for 2,687,937 shares of common stock, resulting in proceeds to the Company of $10,079,763. In addition, option holders paid cash to exercise 553,701 shares of common stock, resulting in proceeds of $2,987,383.

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 stockholders at the Company’s annual meetings.

F-19

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

The following table summarizes information regarding the Company’s stock option and award plans as of December 31, 2006:

	Number of Shares Authorized Under Plan	Weighted Average Exercise Price of Outstanding Options	Number of Options Available for Future Issuance
Equity compensation plans approved by stockholders:
1995 Stock Option and Award Plan	500,000	$7.50	--
1996 Stock Option and Award Plan	500,000	3.97	--
1997 Stock Option and Award Plan	500,000	6.44	14
1998 Stock Option and Award Plan	500,000	6.37	43,320
1999 Stock Option and Award Plan	500,000	3.83	--
2000 Stock Option and Award Plan	600,000	2.51	10,667
2001 Stock Option and Award Plan	600,000	3.22	8,999
2003 Long Term Incentive Plan	800,000	6.64	74,000
2004 Long Term Incentive Plan	1,000,000	8.43	522,250
Total	5,500,000	$5.08	659,250

The above table excludes 50,000 options that have been granted outside of stockholder approved option plans.

All stock option and award plans are administered by a committee (the “Committee”) consisting of members of the board of directors. At its discretion, the Committee may grant stock, incentive stock options (“ISOs”) or non-qualified options to any employee, including officers. The granted options have terms ranging from five to seven years and vest in three equal annual installments. Under terms of the stock option award plans, the Company may also issue restricted stock.

The following table summarizes option activity for 2006, 2005 and 2004:

	2006		2005		2004
	Number of Options	Weighted Average Exercise Price	Number of Options	Weighted Average Exercise Price	Number of Options	Weighted Average Exercise Price
Options outstanding:
Beginning of year	3,193,333	$4.72	3,851,733	$5.47	4,784,517	$4.42
Granted	--	.00	35,000	9.89	1,040,000	8.38
Exercised	--	.00	(620,066)	6.95	(1,743,701)	4.16
Canceled	--	5.82	(73,334)	8.27	(53,083)	4.26
Expired	(356,500)	--	--	--	(176,000)	7.75
End of year	2,836,833	$5.08	3,193,333	$5.16	3,851,733	$5.47

Exercisable at year-end	2,497,177	$4.61	2,270,685	$4.33	2,124,731	$4.67

The weighted average fair value per share of options granted during 2005 and 2004 was $9.72 and $4.00, respectively.

In 2006, the Company recognized $1,711,132 in expense related to unvested stock options granted prior to the adoption of FAS 123R. Total unamortized expense at December 31, 2006 related to unvested options was $864,455.

In December of 2006, the Company issued 318,400 shares of restricted stock resulting in deferred compensation of $2,053,680 which will be amortized ratably over the three year vesting period. Expense recognized during 2006 totaled $18,756.

F-20

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

In November of 2005, the Company issued 298,950 shares of restricted stock to employees resulting in deferred compensation of $3,109,080 which will be amortized ratably over the three year vesting period. Expense recognized during 2006 and 2005 totaled $1,028,633 and $124,563 respectively.

The following table summarizes information about stock options outstanding as of December 31, 2006:

	Outstanding			Exercisable
Exercise Price Range	Number of Options Outstanding	Weighted Average Remaining Contractual Life (in years)	Weighted Average Exercise Price	Number of Options Exercisable	Weighted Average Exercise Price
$2.40 - $2.44	794,666	2.30	2.42	794,666	2.42
$3.14 - $3.20	51,000	3.69	3.19	51,000	3.19
$3.98 - $3.98	652,000	3.82	3.98	652,000	3.98
$4.06 - $6.06	367,667	0.86	4.10	364,334	4.08
$8.37 - $8.37	886,500	4.67	8.37	590,175	8.37
$9.00 - $10.65	85,000	4.66	9.37	45,002	9.23
Total	2,836,833	3.30	$5.08	2,497,177	$4.61

Warrants

The following table summarizes warrant activity for during 2006, 2005 and 2004:

	2006			2005		2004
		Number of Shares	Price Range	Number of Shares	Price Range	Number of Shares	Price Range
Warrants outstanding and exercisable:
Beginning of year		3,505,373	$3.60--$3.75	3,553,373	$3.60--$3.75	6,241,310	$3.60--$3.75
Issued		110,000	$6.00	--		--
Exercised		- -	--	(48,000)	$3.75	(2,687,937))	$3.75
End of year		3,615,37 3	$3.60--$6.00	3,505,373 7	$3.60--$3.75	3,553,3733	$3.60--$3.75

The aggregate intrinsic value of exercisable and outstanding stock options at December 31, 2006 was $5,325,320 and $5,316,199, respectively. The aggregate intrinsic value of unvested restricted stock at December 31, 2006 was $3,189,273. The aggregate intrinsic value represents the total pretax intrinsic value, based on the Company’s stock price of $6.17 as of December 31, 2006, which would have been received by the restricted stock award and stock option holders had all in-the-money restricted stock awards and options been exercised as of that date.

Note 11: Quarterly Financial Data (Unaudited)

Summary quarterly information for 2006 and 2005 is as follows:

	Quarter Ended
	December 31	September 30	June 30	March 31
	(In thousands, except per share amounts)
2006:
Revenues	$ 3,165	$ 1,842	$ 2,137	$ 1,085
Net operating loss	(6,037)	(1,919)	(2,227)	(4,379)
Net loss	(5,795)	(1,728)	(2,054)	(4,190)
Basic and diluted net loss per common share	$ (0.16))	$ (0.05)	$ (0.06)	$ (0.12)

F-21

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

2005:
Revenues	$ 1,555	$ 2,491	$ 1,003	$ 888
Net operating loss	(6,804)	(1,478)	(1,724)	(2,197)
Net loss	(6,576)	(1,386)	(1,570)	(1,891)
Basic and diluted net loss per common share	$ (0.19))	$ (0.04)	$ (0.05)	$ (0.05)

The net operating loss for the fourth quarter of 2006 includes $3.4 million of impairment loss associated with the Rusocin well in Poland. The net operating loss for the fourth quarter of 2005 includes $2.2 million of income associated with the recovery of previously expensed VAT and $4.4 million in dry hole costs associated with the Sroda 5 and Lugi wells.

Note 12: 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 94% of the Company’s oil sales in the United States were to Cenex during 2006, 2005 and 2004. During 2006 all sales of oil and gas in Poland were made to POGC or its affiliated companies. There were no oil and gas sales in Poland during 2005 and 2004. The Company believes the purchasers of its oil production in the United States could be replaced, if necessary, without a loss in revenue. Gas sales in Poland are sold pursuant to long term sales contracts which obligate the buyer to purchase all gas produced. Individual oil sales are negotiated with POGC affiliated entities and are not subject to sales contracts.

E&P operating costs are comprised of: (1) exploration costs (geological and geophysical costs, exploratory dry holes, and proved property and non-producing leasehold impairments) and, (2) lease operating costs (lease operating expenses and production taxes). Substantially all exploration costs are related to the Company’s operations in Poland. The majority of lease operating costs are related to the Company’s domestic production.

The Company’s revenues associated with its oilfield services segment are comprised of contract drilling and well servicing fees generated by the Company’s oilfield servicing equipment in Montana. Oilfield servicing costs are comprised of direct costs associated with its oilfield services.

DD&A directly associated with a respective business segment is disclosed within that business segment. The Company does not allocate current assets, corporate DD&A, general and administrative costs, amortization of deferred compensation, interest income, interest expense, other income or other expense to its operating business segments for management and business segment reporting purposes. All material inter-company transactions between the Company’s business segments are eliminated for management and business segment reporting purposes.

F-22

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Information on the Company’s operations by business segment for 2006, 2005 and 2004 is summarized as follows:

	2006
	Exploration & Production
	U.S.		Poland		Oilfield Services		Total (In thousands)
Operations summary:
Revenues	$	4,260	$	2,273	$	1,696	$	8,229
Operating costs		(3,144)		(8,748)		(1,245)		(13,137)
DD&A expense		(653)		(304)		(155)		(1,112)
Operating income (loss)	$	463	$	(6,779)	$	296	$	(6,020)
Identifiable net property and equipment:
Unproved properties	$	--	$	527	$	--	$	527
Proved properties		3,124		15,283		--		18,407
Equipment and other		--		22		534		556
Total	$	3,124	$	15,832	$	534	$	19,490
Net Capital Expenditures:
Property and equipment	$	613	$	9,008	$	295	$	9,916
Total	$	613	$	9,008	$	295	$	9,916

		2005
		Exploration & Production
		U.S.		Poland		Oilfield Services		Total (In thousands)

Operations summary:
Revenues	$		3,805	$	--	$	2,132	$	5,937
Operating costs			(2,993)		(5,762)		(1,689)		(10,444)
DD&A expense			(511)		--		(243)		(754)
Operating income (loss)	$		301	$	(5,762)	$	200	$	(5,261)
Identifiable net property and equipment:
Unproved properties	$		143	$	161	$	--	$	304
Proved properties			3,139		10,465		--		13,604
Equipment and other			--		24		372		396
Total	$		3,282	$	10,650	$	372	$	14,304
Net Capital Expenditures:
Property and equipment	$		505	$	3,783	$	264	$	4,552
Total	$		505	$	3,783	$	264	$	4,552

F-23

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

		2004
		Exploration & Production
		U.S.		Poland		Oilfield Services		Total (In thousands)

Operations summary:
Revenues	$		3,096	$	--	$	710	$	3,806
Operating costs			(2,280)		(2,719)		(551)		(5,550)
DD&A expense			(259)				(290)		(549)
Operating income (loss)	$		557	$	(2,719)	$	(131)	$	(2,293)
Identifiable net property and equipment:
Unproved properties	$		47	$	308	$	--	$	355
Proved properties			3,336		10,436		--		13,772
Equipment and other					4		375		379
Total	$		3,383	$	10,748	$	375	$	14,506
Net Capital Expenditures:
Property and equipment	$		628	$	8,885	$	99	$	9,612
Total	$		628	$	8,885	$	99	$	9,612

A reconciliation of the segment information to the consolidated totals for 2006, 2005 and 2004 follows:

	2006		2005		2004
	(In thousands)
Revenues:
Reportable segments	$	8,229	$	5,937	$	3,806
Non-reportable segments		--		--		--
Total revenues	$	8,229	$	5,937	$	3,806
Net loss:
Operating loss, reportable segments	$	(6,020)	$	(5,261)	$	(2,293)
Expense or (revenue) adjustments:
Corporate DD&A expense		(177)		(149)		(88)
General and administrative costs (G&A)		(5,606)		(6,592)		(4,909)
Amortization of deferred compensation (G&A)		(2,759)		(125)		--
Stock compensation (G&A)		--		(76)		(5,859)
Total net operating loss		(14,562)		(12,203)		(13,149)
Non-operating income		795		780		529
Net loss	$	(13,767)	$	(11,423)	$	(12,620)
Net property and equipment:
Reportable segments	$	19,490	$	14,304	$	14,506
Corporate assets		205		336		328
Net property and equipment	$	19,695	$	14,640	$	14,834
Property and equipment capital expenditures:
Reportable segments	$	9,916	$	4,552	$	9,612
Corporate assets		59		158		296
Total property and equipment capital expenditures	$	9,975	$	4,710	$	9,908

F-24

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

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, 2006 and 2005, are summarized as follows:

	United States			Poland			Total
	(In thousands)
December 31, 2006:
Proved properties	$	5,552		$	13,741		$	19,293
Unproved properties		--			2,912			2,912
Total gross properties		5,552			16,653			22,205
Less accumulated depreciation, depletion and amortization		(2,428	)		(843	)		(3,271	)
	$	3,124		$	15,810		$	18,934
December 31, 2005:
Proved properties	$	4,991		$	7,492		$	12,483
Unproved properties		143			3,596			3,739
Total gross properties		5,134			11,088			16,222
Less accumulated depreciation, depletion and amortization		(1,852	)		(462	)		(2,314	)
	$	3,282		$	10,626		$	13,908

Results of Operations

Results of operations are reflected in Note 12, Business Segments. There is no tax provision as the Company is not likely to pay, nor has it received any benefit from, any federal or local income taxes due to its operating losses. Total production costs (in thousands) for 2006, 2005 and 2004 were $2,647, $2,462 and $1,946, respectively.

Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities during 2006, 2005 and 2004, whether capitalized or expensed, are summarized as follows:

	United States		Poland		Total
	(In thousands)
Year ended December 31, 2006:
Acquisition of unproved properties	$	4	$	366	$	370
Exploration costs		932		11,159		12,091
Development costs		580		5,762		6,342
Total	$	1,516	$	17,287	$	18,803
Year ended December 31, 2005:
Acquisition of unproved properties	$	95	$	30	$	125
Exploration costs		683		9,809		10,492
Development costs		366		520		886
Total	$	1,144	$	10,359	$	11,503

F-25

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

	United States		Poland		Total
	(In thousands)
Year ended December 31, 2004:
Acquisition of unproved properties	$	40	$	141	$	181
Exploration costs		103		11,752		11,855
Development costs		490		--		490
Total	$	633	$	11,893	$	12,526

Impairment of Oil and Gas Properties

The Company recorded impairment charges in its E&P segment related to oil and gas properties as follows (in thousands):

	2006		2005		2004
Impairment of properties	$	3,583	$	—	$	—

Exploratory dry hole costs

During 2006, the Company plugged and abandoned the Drozdowice well in Poland, the Teton River well in Montana and the West Bacon Flat well in Nevada, incurring total dry hole costs of $1,572,749. During 2005, the Company plugged and abandoned the Lugi, Sroda 5 and four wells in the Inselberg and Radio prospects in Nevada, incurring total dry hole costs of $5,065,586. During 2004, the Company plugged and abandoned the Tuchola 108-2 well, incurring dry hole costs of $471,883.

Summary Oil and Gas Reserve Data (Unaudited)

Estimated Quantities of Proved Reserves

Proved reserves are the estimated quantities of crude oil and natural gas that 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, and interest expense. The proved reserve quantity and value information is based on the weighted average price on December 31, 2006, of $51.65 per bbl for oil in the United States and $49.49 per bbl of oil and $4.89 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 estimating 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.

F-26

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

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 RPS Energy, 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, 2006	382	202	--	11,382
December 31, 2005	408	--	--	974
December 31, 2004	809	--	--	1,011

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		UnitedStates	Poland
	(In thousand barrels of oil)				(In millions of cubic feet)
December 31, 2006:
Beginning of year	408		209		--	19,788
Revisions of previous estimates	50		2		--	(63	)
Production	(76	)	(9	)	--	(461	)
End of year	382		202		--	19,264
December 31, 2005:
Beginning of year	809		111		--	10,198
Extensions or discoveries	--		--		--	7,882
Acquisition of minerals in place	--		98		--	2,199
Revisions of previous estimates	(322	)	--		--	(491	)
Production	(79	)	--		--	--
End of year	408		209		--	19,788
December 31, 2004:
Beginning of year	991		114		--	3,960
Extensions or discoveries	--		--		--	6,342
Revisions of previous estimates	(97	)	(3	)	--	(104	)
Production	(85	)	--		--	--
End of year	809		111		--	10,198

F-27

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--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, “Disclosures 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 future net cash flows for the Company’s Polish reserves are based on a gas and condensate sales contract the Company has with POGC.

F-28

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

The components of SMOG are detailed below:

	United States			Poland			Total
	(In thousands)
December 31, 2006:
Future cash flows	$	19,719		$	103,903		$	123,622
Future production costs		(13,511	)		(12,046	)		(25,557	)
Future development costs		--			(2,502	)		(2,502	)
Future income tax expense		--			(4,595	)		(4,595	)
Future net cash flows		6,208			84,760			90,968
10% annual discount for estimated timing of cash flows		(1,643	)		(25,568	)		(27,211	)
Discounted net future cash flows	$	4,565		$	59,192		$	63,757
December 31, 2005:
Future cash flows	$	20,833		$	73,114		$	93,947
Future production costs		(12,808	)		(2,504	)		(15,312	)
Future development costs		--			(7,658	)		(7,658	)
Future income tax expense		--			(7,742	)		(7,742	)
Future net cash flows		8,025			55,210			63,235
10% annual discount for estimated timing of cash flows		(2,189	)		(19,131	)		(21,320	)
Discounted net future cash flows	$	5,836		$	36,079		$	41,915
December 31, 2004:
Future cash flows	$	29,670		$	24,145		$	53,815
Future production costs		(21,779	)		(1,304	)		(23,083	)
Future development costs		(1	)		(2,780	)		(2,781	)
Future income tax expense		--			--			--
Future net cash flows		7,890			20,061			27,951
10% annual discount for estimated timing of cash flows		(2,756	)		(6,970	)		(9,726	)
Discounted net future cash flows	$	5,134		$	13,091		$	18,225

The principal sources of changes in SMOG are detailed below:

		Year Ended December 31,
		2006		2005		2004
		(In thousands)
SMOG sources:
	Balance, beginning of year		$ 41,915		$18,225		$ 9,856
	Sale of oil and gas produced, net of production costs		(3,886)		(1,343)		(1,150)
	Net changes in prices and production costs Acquisition of minerals in place		16,111 --		14,423 4,391		3,816 --
	Extensions and discoveries, net of future costs		--		16,243		4,135
	Changes in estimated future development costs		3,953		(3,232)		(638)
	Previously estimated development costs incurred during the year		580		886		588
	Revisions in previous quantity estimates		(169)		(4,384)		(211)
	Accretion of discount		4,192		1,823		986
	Net change in income taxes		1,911		(5,131)		--
	Changes in rates of production and other		(850)		14		843
	Balance, end of year		$63,757		$41,915		$18,225

F-29