10-K

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, 2008
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 incorporation or organization)	(I.R.S. Employer 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o

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

Yes oNo 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, 2008, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $205,436,000.

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 10, 2009, FX Energy had outstanding 42,451,978 shares of its common stock, par value $0.001.

DOCUMENTS INCORPORATED BY REFERENCE. FX Energy’s definitive Proxy Statement in connection with the 2009 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, 2008

___________________________________________________________________________________________

TABLE OF CONTENTS

Item		Page
	Part I
--	Special Note on Forward-Looking Statements	3
1	Business	4
1A	Risk Factors	11
1B	Unresolved Staff Comments	18
2	Properties	19
3	Legal Proceedings	29
4	Submission of Matters to a Vote of Security Holders	29
	Part II
5	Market for Registrant’s Common Equity, Related Stockholder Matters
	and Issuer Purchases of Equity Securities	30
6	Selected Financial Data	31
7	Management’s Discussion and Analysis of Financial Condition and Results of Operation	32
7A	Quantitative and Qualitative Disclosures about Market Risk	45
8	Financial Statements and Supplementary Data	46
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	46
9A	Controls and Procedures	46
9B	Other Information	46
	Part III
10	Directors, Executive Officers and Corporate Governance	47
11	Executive Compensation	47
12	Security Ownership of Certain Beneficial Owners and Management and Related
	Stockholder Matters	47
13	Certain Relationships and Related Transactions, and Director Independence	47
14	Principal Accounting Fees and Services	47
	Part IV
15	Exhibits, Financial Statement Schedules	48
--	Signatures	53
--	Management’s Report on Internal Control over Financial Reporting	F-1
--	Report of Independent Registered Public Accounting Firm	F-2

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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:

• whether we will be able to discover and produce gas or oil in commercial quantities from any exploration prospect;

• whether we will be able to borrow funds to develop our gas and oil discoveries in Poland from the Royal Bank of Scotland, our current principal lender, or from any other commercial lender, even if we increase substantially the quantity and value of our reserves that we may be willing to encumber to secure repayment of such borrowings;

• whether the quantities of gas or oil we discover will be as large as our initial estimate of an exploration target area’s gross unrisked potential;

• whether the estimated proved quantities of gas and oil reserves that we report using deterministic methods currently mandated by the Securities and Exchange Commission will be as large as the estimated quantities of proved or probable gas and oil reserves that we otherwise publicly announce may be present using probabilistic methods;

• whether actual exploration risks, schedules, and sequences will be consistent with our plans and forecasts;

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

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

• foreign currency exchange rate fluctuations;

• the financial and operating viability and stability of third parties with which we conduct business and on which we rely to supply goods and services and to purchase our gas and oil production;

• 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 or other future partners;

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

• 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;

• uncertainties of certain terms to be determined in the future relating to our gas and oil 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.

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PART I

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ITEM 1. BUSINESS

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Introduction

We are an independent gas and oil exploration and production company with principal production, reserves, and exploration activities in Poland, although we have modest oil production and oilfield service activities in the United States. We believe Poland is a unique international exploration opportunity. Relatively little gas has been discovered in Poland’s sector of the North European Permian Basin, compared to the discoveries in the UK, Dutch, and German sectors. For most of the 20^th century, Poland was closed to exploration by foreign gas and oil companies. Consequently, we think the Polish Permian Basin is underexplored and underexploited, and therefore has high potential for discovering significant amounts of gas and oil.

Acting on this thesis, we have acquired a large land position and we are conducting a focused exploration program. Independent engineers estimated our total proved gas and oil reserves at 45.9 billion cubic feet of natural gas equivalent, or Bcfe, at year-end 2008. The PV-10 Value of these reserves at year-end 2008 was approximately $118 million, which is equal to approximately $2.79 per share of stock outstanding at year-end. Our gas and oil reserve volumes in Poland have increased at a compound annual growth rate of 34% since 2003 and by 46% in just the last year. Our production volume has increased at an annual rate of 52% from 2005 to 2008. These increases are attributable to our exploration in Poland. With a view to future growth in reserves and production, we now hold 5.4 million gross acres (4.9 million net acres) in Poland.

We are acutely aware of the global economic crisis and we are mindful of the need to stay alert and act reasonably. We believe our business strategy is sound and that our resources and opportunities, carefully managed, will allow us to continue growing through the next several years. See “Adapting to the Global Economic Crisis” below.

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. Our headquarters are in Salt Lake City, Utah, and we have operations offices in Warsaw, Poland, and Oilmont, Montana. See “Gas and Oil Terms” at the end of this item for definitions of certain industry terms.

Corporate Strategy

Our general strategy is to focus our resources on Poland. More specifically, we plan to direct the bulk of our available funds and management and technical resources to our core Fences concession area in Poland. We currently are concentrating our drilling activities in our core area in an effort to lower drilling risk, shorten the time to first production from successful wells, and optimize opportunities for robust revenue growth. At the same time, we do plan to acquire, hold, and explore acreage outside our core area, where we believe we have the opportunity to find significant gas and oil reserves. We currently hold substantial acreage in areas of Poland that we consider underexplored and underdeveloped and, therefore, subject to greater exploration risk than our core area. In order to diversify risk, we plan to allocate a relatively small portion of available funds to carry out preliminary exploration work on this non-core acreage. We plan to rely on industry farmouts for the bulk of early-stage drilling. To the extent our strategy of focusing on our core area results in substantial revenue growth, we plan to cautiously increase our funding of exploration projects over a wider area in Poland.

Current Activities and Assets in Poland

Our strategy focuses on Poland because we believe Poland has substantial undiscovered hydrocarbon potential. We think the Polish portion of the Permian Basin is underexplored and underdeveloped today because the country was closed to competition and capital from foreign gas and oil companies for many decades. The continuous advances in exploration technology around the world were not immediately applied in Poland during the period it was behind the “Iron Curtain.”

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            We concentrate our exploration efforts in Poland primarily on the Rotliegend sandstones of the Permian Basin. We were attracted to the Rotliegend sandstones in Poland by two observations:

(1)          Since the 1960s, dozens of western exploration companies working in the North Sea and onshore Europe portions of the North European Permian Basin have identified approximately 200 trillion cubic feet, or Tcf, of Rotliegend gas. While the Permian Basin extends well into Poland, only 5 Tcf of Rotliegend gas has been discovered in Poland. We believe political and capital restraints impaired POGC’s ability to explore and develop the Polish portion of the Basin.

(2)          In the last 20 years, very little exploration focused on the Rotliegend has been conducted in Poland.

We have identified a core area consisting of approximately 852,000 gross acres surrounding the Radlin Field. This 390 billion cubic feet, or Bcf, Rotliegend gas field was discovered in the 1980s by our joint venture partner, the Polish Oil and Gas Company, or POGC, which owns and produces gas from it. We have emphasized improved seismic data acquisition and processing in our exploration, using technology developed for Rotliegend exploration in the Southern North Sea.

From 2004 through 2008, in the course of our Polish exploration with this approach, we have made commercially successful discoveries in five of the seven wells we have drilled on Rotliegend structural trap targets. In the aggregate, these five discoveries found gross estimated proved reserves of 107 Bcf of gas. Based on these discoveries and associated technical work, we have identified a subset of our core area acreage, the Sroda area, as having significant natural gas potential and low drilling risk compared to the balance of our core area. Within the Sroda area and along trend immediately to the southeast, we have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers. Using this data, we have identified a number of possible structural traps. We believe the 3-D seismic data gives us better definition of the targets and might further reduce our drilling risk, although we expect that we will continue to drill wells that do not establish production or reserves. We plan to direct the bulk of our available funds to carry out a multi-year exploration, appraisal, and development drilling program in our core area. These operations focus on the first element of our general strategy – to increase production and reserves in our core area.

While maintaining our focus on the Rotliegend structural trap exploration model in our core Fences area, we are also carrying out exploration work on other potential exploration models. These include non-Rotliegend prospects in our core area and various exploration opportunities on our 4.5 million net acres outside our core area. We have accumulated this large land position in known productive regions or geologic trends and in selected “rank wildcat” areas in Poland. We have assembled a sophisticated technical team experienced with using modern exploration tools and generated a number of attractive gas and oil prospects. We are inviting industry participation in the early-stage drilling of these prospects. To the extent our overall strategy results in substantial revenue growth, we plan to direct more of our own funds toward exploration outside our core area. However, the Rotliegend structural trap gas prospects in our core area will continue to receive the greatest portion of our efforts and capital resources over the next several years.

Some of our Polish operations are conducted in partnership with POGC. POGC is a fully integrated gas and oil company, which is largely owned by the Treasury of the Republic of Poland. POGC is Poland’s principal domestic gas and oil 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. He also serves on our board of directors. Mr. Hardman has built a career in international exploration over the past 40 years in the upstream gas and oil 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

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Petroleum Society of Great Britain, President of the Geological Society of London, and President of the European Region of American Association of Petroleum Geologists Europe. Mr. Hardman was appointed to our board of directors in October 2003 and is Chairman of our Technical and Advisory Panel.

Jerzy Maciolek is a director of the Company and heads our exploration team as Vice President of International Exploration. He joined the Company in 1995 specifically to lead it into Poland where he had identified the exploration opportunity that today is our core asset. Mr. Maciolek has over 25 years of experience as a geophysicist with POGC, Gulf Oil Research, and as an independent consultant. He received an M.S. in exploration geophysics from the Mining and Metallurgical Academy in Krakow, Poland.

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 a natural gas and oil producer in Poland.

Our U.S. Presence

Unlike our position in Poland, the U.S. operation does not have substantial exploration potential. It is fairly mature. It provides a modest amount of cash flow and is not capital intensive. It consists mostly of shallow, oil-producing wells in the CutBank Oil Field of Montana. As of December 31, 2008, our U.S. reserves were estimated at 45,000 barrels of crude oil with a PV-10 Value of approximately $318,000. Our oil wells produce approximately 180 barrels of oil per day, net to our interest. From our field office in Montana, we also provide oilfield services, which provided approximately $4.3 million in revenue during 2008.

Adapting to the Global Economic Crisis

The impact on the gas and oil industry of the current global economic crisis has been sudden, dramatic, and wide-ranging. As with most companies in this industry, we are not immune from many of the negative effects of this crisis. In Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, we identify and discuss some of the following areas of concern, and provide some discussion as to our plans to protect and exploit our assets and continue to methodically increase our shareholder value.

• Global oil prices have dropped rapidly from unprecedented mid-2008 highs to significantly lower prices at year-end. In Poland, all of our gas production is sold to POGC and is tied to published tariffs for gas sold to wholesale consumers that in turn are based in large part on the historical cost of Russian imported gas. With the recent drop in oil prices, there is a possibility that the cost of imported gas may decline, which in turn may cause the Polish regulator to decrease the cost of gas sold by POGC and thereby reduce the price POGC pays to us.

• We see a greater impact on our revenues and reserves from the declines in oil prices than from changes in gas prices. Year-end 2007 prices in Montana averaged approximately $94 per barrel and reached a monthly high of approximately $120 per barrel in June 2008. At year-end, our average price in Montana was approximately $25 per barrel, and our year-end price in Poland was approximately $37 per barrel.

• The decline in oil prices has the following principal adverse effects:

o The reduction in oil revenues will impact our ability to execute a robust capital program during 2009.

o Price declines also reduce both the value and the economic volumes of our proved oil reserves in the United States and led to impairment charges at existing wells, where the estimated year-end 2008 reserve values, calculated at year-end prices, are no longer sufficient to cover the existing capitalized costs.

• We do not know what impact the distress in the banking industry in general, and on the Royal Bank of Scotland, or RBS, in particular, will have on us. Despite the fact that we believe we have reserve volumes and values that would warrant a sizable increase in this facility in normal economic times, there is no guarantee that RBS will, in fact, increase the amount of funds available to us, which may, in turn, restrict the amount of capital we are able to apply in our development programs in Poland.

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• Our stock price has declined more than 70% from its 2008 peak and, as of early March 2009, 46% over the preceding 12 months, which may restrict the amount of capital we will be able to apply in our development programs in Poland.

• Because of the circumstances discussed above, we are acutely aware of the need to preserve and be judicious in our use of existing capital and are adjusting our capital and operating budgets. We are not initiating new capital projects in 2009 until the commencement of production at our Roszkow well in Poland, and we are reducing cash overhead costs by approximately 10% from 2008 levels, primarily by reducing compensation and other controllable costs.

• The drop in oil prices and the adjusted timing of our capital budget caused us to record property impairment charges during 2008 of $11.0 million related to two of our recent drilling projects in Poland due to adjustments in the timing of our capital plans and $3.8 million related to our producing oil wells in the United States due to lower reserve values.

• During the past 12 months, the Polish zloty has fluctuated between a low of 2.02 zlotys per U.S. dollar in August of 2008 to a high of 3.88 zlotys per dollar in late February of 2009. As the U.S. dollar strengthens, the U.S. dollar denominated amount of revenue paid in zlotys declines; conversely, when the U.S. dollar weakens, the U.S. dollar denominated amount of revenues paid in zlotys increases. Should exchange rates in effect during early 2009 continue throughout the year, we expect the exchange rates to have a negative impact on our U.S. dollar denominated revenues, but a corresponding positive impact on the U.S. dollar cost of our capital expenditures in Poland.

• During October 2008, we drew down the remaining $14 million available under our Senior Credit Facility and purchased approximately $14.7 million in Polish zloty forward contracts at a rate which, at the time, was a 52-week low for the zloty. The amount of these forward contracts was matched to our committed capital expenditures in Poland. Further, in connection with contracts maturing in the first quarter of 2009, we recorded an additional loss of approximately $888,000 when we marked them to market at December 31, 2008, at which time the exchange rate was 2.9 zlotys per U.S. dollar.

Exploration, Development and Production Activities

Polish Exploration Rights

As of December 31, 2008, we held gas and oil exploration rights in Poland in nine separately designated project areas encompassing approximately 5.4 million gross acres. We are currently the operator in all areas except our core area, the 852,000 gross acres Fences project area in which we hold a 49% working interest and in which POGC is the operator. We own a 100% working interest in approximately 4.3 million gross acres. Of the remaining approximately 1.1 million gross acres, we hold approximately 0.6 million net acres.

As we build revenues in our core area and further explore and evaluate our acreage in Poland, we expect to increasingly focus our operational and financial efforts on areas with larger potential reserves. As we do so, we may add new concessions that we believe have high potential and relinquish acreage that we believe has lower potential. See “Wells and Acreage” below for further information.

Exploratory Activities in Poland

Our ongoing activities in Poland are conducted in nine project areas: Fences, Block 255, Block 287, Northwest, Kutno, Warsaw South, Edge, Block 229, and Block 246. Our drilling 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 the United Kingdom. We are focused on this core area because substantial gas reserves have already been discovered and developed by POGC, we have made five commercial gas discoveries, together with POGC, containing proved gas reserves of over 100 Bcf gross (43 Bcf net to our interest), and we have concluded that there is likely to be substantial additional natural gas in the same geologic horizon. We are selling gas from wells located in the Fences area and Block 255, and expect to be selling gas in early 2009 from a well in Block 287. We are developing longer-term exploration prospects in the remaining six areas.

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Fences Area

The Fences concession area is 852,000 gross acres (3,450 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 off” or excluded from our exploration acreage. These fields, discovered by POGC between 1974 and 1982, produce from structural traps in the Rotliegend sandstone. We hold a 49% interest in approximately 807,000 acres and a 24.5% interest in the remaining 45,000 acres in the Fences area.

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 Rotliegend traps in the region: structural traps and stratigraphic (“pinch-out”) traps. Both of these trap types are known to produce gas in the region. In addition, we have identified what appear to be carbonates in the Zechstein formation, a third type of trap that is known to produce both gas and oil in the region.

       Fences Area: Structural Traps

Based on our drilling experience since 2000 in the Fences area, we have emphasized the use of seismic 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 data processing and acquisition techniques, we have drilled seven wells targeting Rotliegend structures through the end of 2008. Five of these wells are commercial, with aggregate proved gas reserves of over 100 Bcf gross (43 Bcf net to our interest).

In September 2008, we completed the Kromolice-1 well as a commercial success (with production anticipated to begin during 2010). Kromolice-1 is located some five kilometers northwest and on the same fault trend as our 2005 Sroda-4 discovery well. The 2008 natural gas discovery at the Kromolice-1 well contributed the greatest portion of our year-over-year increase in proved reserves. At year-end, gross proved reserves for the well were estimated at approximately 20 Bcf of gas (9.8 Bcf net to our 49% interest). Sroda-4 well reserves also increased as the Sroda-4 to Kromolice-1 trend was determined to be part of a single accumulation.

In November 2008, we suspended drilling operations at the Sroda-6 well. Despite the fact that the well drilled 30 meters of good quality Rotliegend reservoir rock, removing one of the major uncertainties of the Sroda City structure, the well came in significantly structurally low to prognosis and on a drill stem test recovered only gas cut brine. Analysis of the geophysical data from this well, along with existing 3-D seismic data, suggests structural development slightly to the northwest of the Sroda-6 well location. A pre-stack depth migration study, which was underway in early 2009, is being carried out at both Sroda-6 and regionally to determine the highest point on the Sroda-6 structure and to determine whether a higher structural position can be reached by deviating the current well and thereby testing the closure in an optimal location.

As part of our focus on that part of the Fences area that is prone to Rotliegend structural traps, we have acquired several hundred square kilometers of 3-D seismic data in the area where the Kromolice-1 and -2, Sroda-4, and -5, and Winna Gora wells are located and along the trend to the southeast. Processing on this block of seismic data is complete, and the data is being evaluated. We also acquired approximately 167 kilometers of two-dimensional, or 2-D, seismic data over a lead, Taczanow, that lies on the trend southeast from the Zaniemysl and Roszkow wells, our two biggest discoveries to date. Final interpretation of this seismic data is due in 2009.

Finally, in the northernmost part of our Fences concession and lying within the area covered by our recent 3-D seismic data, we have identified a very large upthrown block, or horst, of Rotliegend sandstone that encompasses approximately 50 square kilometers, or 12,000 acres, within our Fences concession and continues into the area north of our concession. One well, the 1984 Plawce-1, was drilled by POGC on this Rotliegend block within what is now our Fences concession. Five other wells have been drilled by others (4 of these more than 20 years ago) in this horst block north of our concession boundary. All six of these wells had substantial gas columns, and all but the most recent well were plugged due to relatively tight reservoir rocks. The one new well, Trzek-1, located about six kilometers north of our concession, was drilled in 2007 and reportedly tested gas at rates between 2.5 and 7.5 million cubic feet of natural gas per day, or MMcfD, after high-pressure, hydraulic fracturing.

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We are continuing to evaluate our data and are working with POGC on a plan to appraise and explore the gas resource in the Plawce area. We acquired 45 square kilometers of 3-D seismic data in 2008 that will enhance the quality of our existing 3-D seismic and appraisal data in the Plawce area, once the data is interpreted during 2009.

       Fences Area: Stratigraphic Traps

In the southwestern portion of the Fences concession there is potential for stratigraphic trapping, or pinch-outs, in the Rotliegend. Based on data from the Rusocin-1 and the Lugi-1 wells we drilled in 2005, and based on the presence of wells that produce from stratigraphic traps further to the west from our concession, we believe it is necessary to acquire 3-D seismic data that will help us determine the next steps in exploring the pinch-out area. It is unlikely that we will pursue this play during 2009.

      Fences Area: Carbonate (Reef) Traps

In the northeastern portion of the Fences concession we have identified carbonate (reef) targets in the Zechstein (Ca2) horizon of the lower Permian, just above the Rotliegend. In February 2008, we began drilling the Grundy-1 well to test a possible Ca2 reef build-up identified on 2-D seismic. The Grundy-1 is located approximately 30 kilometers east of our Sroda area. The nearest significant Ca2 producing fields, the BMB and Miedzychód-Lubiatow-Grotów gas and oil fields owned by POGC, are located approximately 60 to 80 kilometers northwest of the Grundy well and reportedly contain approximately 125 million barrels of oil and 500 Bcf of gas.

In September 2008, an open hole DST of the Grundy-2 well was completed, testing the Rotliegend interval from a depth of 4,240 meters to 5,001 meters. During the test, gas shows were recorded without any produced water, but the gas-bearing zone appeared to be too tight (low porosity or permeability) for commercial production without stimulation. The well has been shut-in since that time to allow detailed analysis of drilling, logging, core and DST data, which will take a number of months. Following this analysis, the well may be re-entered with a workover rig to conduct high-pressure, hydraulic fracturing of the Rotliegend intervals with the best reservoir properties.

Block 255 Concession Area

The Block 255/Wilga concession area in east central Poland consists of an 82% working interest in approximately 236,000 gross acres (957 sq. km.). We have one producing well, Wilga-2 in Block 255, the result of an exploration project conducted several years ago by us and Apache Corporation. As of December 31, 2008, the Wilga well had remaining gross proved reserves of approximately 2.3 Bcf of gas and 58,000 barrels of light crude oil (1.9 Bcf and 47,000 barrels, net to our interest). In January 2009, we successfully hung a coiled tubing string in the 2 7/8” tubing to lift fluids from the well, without a break in production. We anticipate connecting the Wilga well to a medium pressure pipeline during the first quarter of 2009, which will enable us to extend the productive life of the 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 was part of a larger concession area that we relinquished in 2007 based on our technical evaluation and on a dry hole that we drilled in 2006.

Within Block 287 there are three Rotliegend gas wells known as the Grabowka wells. Originally drilled by POGC in 1983-85, these three wells tested gas but never produced commercially. In early 2007, we entered into a joint venture agreement with an unrelated party, PL Energia S.A., headquartered in Krzywoploty, Poland, under which all costs of re-entering and completing the three Grabowka wells and building production facilities will be paid by our joint venture partner in exchange for discounted pricing on gas.

In June 2008, we successfully re-entered the first well, Grabowka-12. Since that time, production facilities have been constructed, and we expect to see first production from this field in the first half of 2009. We plan to monitor the performance of the first well before attempting to recomplete either of the remaining two wells. We did not have any proved reserves assigned to the Grabowka field at year-end 2008.

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Northwest Concession Area

In 2006, we acquired a 100% interest in a concession in west-central Poland covering 1.6 million acres. The concession is in Poland’s Permian Basin directly north of POGC’s BMB and Miedzychód-Lubiatow-Grotów gas and oil fields. As in our Fences concession, the Northwest concession has three separate possible exploration models: Rotliegend sands trapping gas in structural closures; Rotliegend sands trapping gas in stratigraphic traps or s; and Zechstein Ca2 dolomitic sands, reefs, and talus trapping gas and oil.

During 2007 we reviewed the existing sparse, 20-year-old geological and geophysical data from the area. In an area of 1.6 million acres, there were only about 2,500 kilometers of 2-D seismic data and only three wells drilled to target depths. As a result of this review, we elected to relinquish approximately 500,000 acres from the northeast corner of this concession, retaining 1.1 million acres. During 2008, we acquired portions of two additional blocks, increasing our acreage to 1.4 million acres. We also acquired 245 kilometers of new 2-D seismic data over several of the leads we had identified previously.

In early 2009, we announced that we had reached a preliminary agreement with POGC to explore a portion of the Northwest concession area. Plans include drilling one well in 2009. Definitive agreements are expected to be completed in early 2009, with the well commencing shortly thereafter.

We are seeking industry participation on the remaining blocks, while continuing to carry out early-stage exploration work on our own.

Kutno Concession Area

In 2007, we acquired a 100% interest in a concession in central Poland covering 284,000 acres; in 2008, we added additional blocks bringing the total to 706,000 acres (2,856 sq. km.). The area encompasses a Rotliegend mega-structure (“Kutno”) with projected four-way dip closure. Depth of the structure is estimated at approximately 6,000 meters (19,200 feet). In view of the depth and cost, we are seeking industry participation to drill Kutno.

Warsaw South Concession Area

In 2007, we acquired a 100% interest in several concession blocks in east central Poland; in 2008, we dropped two of the blocks, leaving a total of 638,000 acres (2,581 sq. km.). The Warsaw South concession has several possible exploration opportunities, including carboniferous sands with structural or truncation trapping and Zechstein reefs trapped by overlying evaporates and salt. Our technical group has reviewed the geological and geophysical data from the area and identified a dozen carboniferous leads and two possible Zechstein reef targets. We are seeking industry participation while continuing to carry out early-stage exploration work on our own.

Edge Concession Area

In 2008, we acquired a 100% interest in four concessions in north central Poland covering approximately 881,000 acres (3,567 sq. km.). Having reprocessed existing 2-D seismic data, we identified a number of leads including several Permian age Ca2 reefs and a large Devonian structure. We are soliciting industry support to shoot additional seismic and drill two or more exploratory wells to confirm the plays.

Block 246 Concession Area

In 2008, we acquired a 100% interest in a concession in west central Poland covering approximately 241,000 acres (975 sq. km.). Block 246 is contiguous with the southwest corner of the Fences concession and appears to have Rotliegend potential. We are reprocessing existing 2-D seismic data to identify possible leads.

Block 229 Concession Area

In 2008, we acquired a 100% interest in a concession east of our Fences project area covering approximately 233,000 acres (941 sq. km.). We have identified a number of possible Ca2 reef build-ups on 2-D seismic in Block 229. We plan to seek industry participation while continuing to carry out early-stage exploration work on our own.

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Additional Concession Acreage

We may apply for more concession blocks in Poland in 2009. We will allocate modest technical and financial resources to these areas during 2009, 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 2008, we drilled one shallow dry hole in Nevada. We may drill one well in 2009 on land that is near our existing producing properties.

Montana

During 2008, we drilled two shallow exploratory wells using our own drilling rig. Both wells were plugged and abandoned. We have no plans for further drilling in Montana during 2009.

Segment Information

Further information concerning our financial and geographic segments can be found in the footnotes to the consolidated financial statements.

Available Information

We make available, free of charge, either on our website (www.fxenergy.com) or by contacting our main office in Salt Lake City, Utah at (801) 486-5555, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable as we file such material with, or furnish it to, the Securities and Exchange Commission. 

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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 gas or oil in Poland.

We currently have a limited amount of production in Poland and the United States. Our production volumes vary significantly because the limited number of producing wells in Poland makes our total production sensitive to individual well performance, as evidenced by the production volume declines during 2008 in Poland, where production from our Wilga well declined substantially below previous levels. We anticipate that our production will increase in 2009 as previously drilled wells are placed into production and that we will generate revenues in excess of direct lease operating costs. However, these revenues are not expected to be sufficient to cover all of our exploration and development costs. Accordingly, we will continue to rely on existing working capital, including borrowings under our Senior Credit Facility with RBS, and additional funds obtained from external sources, including industry partners, to cover these costs.

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Our development efforts in Poland may be limited by the unavailability of additional borrowings.

We have drawn the entire $25.0 million available under our Senior Credit Facility with RBS. This credit facility is based on RBS’s evaluation of our reserves in Poland as of November 2006 when we established the facility. Our reserves have increased substantially since establishing the credit facility with RBS, and we expect our reserve values to continue to increase if we make additional discoveries and as we place other wells into production. We believe a sizeable increase in our credit facility would be warranted but for the current global economic crisis. Due to extreme shortages of capital and liquidity, RBS, which had a market capitalization of over $105.0 billion two years ago, now has a market capitalization of less than $10.0 billion. After equity infusions aggregating about $45.0 billion during the last year, RBS will now be between 70% and 95% owned by the United Kingdom government and is undergoing substantial management and staff reorganization. Accordingly, we cannot predict how RBS will respond to requests for increased borrowings, notwithstanding our compliance with the terms of our credit facility agreement and substantial increases in reserve quantities and values.

In view of the current global banking and economic crisis, there is a severe shortage of available capital for project financing in general, and we have no other established borrowing relationships with banks or other sources of project financing. Therefore, we cannot assure that we can obtain borrowings from other sources to supplement or replace our current credit facility with RBS. Our inability to expand our borrowings would restrict the amount of capital we are able to apply in our development programs in Poland.

The over 70% decline in our stock price from its 2008 high and the prevailing condition in the equity markets make additional equity financing currently unlikely.

Our stock price has declined more than 70% from its 2008 peak and, as of early March 2009, 46% over the preceding 12 months. These price declines are typical throughout the equity markets generally and in the gas and oil segment specifically. In these market conditions we cannot assure that the equity markets will be accessible or that we would be willing to sell equity at the prices that may be required in order to attract capital.

The recent sharp decline in global oil prices below mid-2008 unprecedented highs could have a future negative impact on the price we receive for gas in Poland.

Global oil prices have dropped rapidly from unprecedented mid-2008 highs to lower prices at year-end, and gas prices in the United States have also decreased significantly. The decline in world oil prices may, in the future, depress the prices at which we sell gas in Poland to POGC pursuant to published tariffs for gas sold to wholesale consumers. Such tariffs are determined in part by reference to the cost of Russian imported gas, which in turn is priced based on trailing, historical oil prices. The trailing impact of such lower prices may influence tariff price reductions and so may reduce the price that we may receive for our gas from POGC.

Declining oil prices have a direct impact on our domestic revenues. The fall in oil prices means our oil revenues will decline until such time as prices recover. Declining oil prices resulted in property impairments of $3.8 million related to our domestic producing properties during 2008, and further impairments of the remaining $0.3 million would be likely in the event of further price declines.

We may incur additional losses due to exchange rate fluctuations.

Continuing fluctuations in the rates at which U.S. dollars are exchanged into Polish zlotys may result in exchange rate losses in addition to the approximately $888,000 in losses related to open Polish forward contracts that we recognized at December 31, 2008. Increases in the exchange rate above the rate of 2.9 zlotys per dollar at December 31, 2008, would result in additional losses during the current quarter. We could also suffer additional future losses if we purchase new forward contracts in an effort to protect against further exchange rate fluctuations. We are subject to exchange rate fluctuations as we transfer dollar denominated funds from the United States to Poland for exploration and development and receive payment for the gas we sell in Poland in zlotys. We record receivables and payables in U.S. dollars and recognize a gain or loss when the receivables or payables are subsequently settled at different exchange rates. As the U.S. dollar strengthens, our U.S. dollar denominated revenue received in Polish zlotys declines; conversely, when the U.S. dollar weakens, our U.S. dollar denominated revenue received in Polish zlotys increases. Should exchange rates in effect during early 2009 continue throughout the year, we expect the exchange rates to have a negative impact on our U.S. dollar denominated revenues, but a corresponding positive impact on the U.S. dollar cost of our capital expenditures in Poland.

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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 2009 and beyond 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 gas or oil 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 gas or oil will be present in commercial quantities. The fact that some prospects may appear to have similar geological or geophysical subsurface features or may be located in proximity to previous wells cannot assure that such prospects are in fact similar or that drilling results will be comparable. Every prospect must be evaluated individually. 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 use various methods to evaluate various categories of potential gas or oil accumulations.

This report contains estimates of quantities and values of proved reserves as estimated in accordance with deterministic methods and criteria established by the Securities and Exchange Commission. We also use probabilistic methods commonly used in Europe and other parts of the world for estimating the quantity and value of gas and oil accumulations for various purposes, including determining the amount that we may borrow under our Senior Credit Facility with RBS. For purposes of management decisions and risk analysis, we use other geological and geophysical techniques to determine gross, unrisked resource potential. These various methods are important in making many kinds of management decisions at various stages during the exploration, development, and production process, but the quantities and values arrived at through these various methods are not comparable and should not be compared. We cannot assure that any gas or oil quantities or values that we estimate using probabilistic methods will ever be converted through additional exploration and production into PV-10 Values estimated in accordance with deterministic methods required by the Securities and Exchange Commission.

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 gas or oil potential of individual prospects and drilling targets or the related risks. We sometimes predict the gross potential gas or oil in a particular area as part of our evaluation of the exploration potential and related risks. Our predictions are only rough, preliminary geological estimates of the forecasted volume and characteristics of possible reservoirs and the calculated potential gas or oil that could be contained if present and are unqualified by any risk evaluation. Such forecasts are not an assurance that our exploration will be successful or that we will be able to establish reserves equal to such forecasts. 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 gas or oil potential of individual prospects.

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We have had limited exploratory success in Poland.

Since 1995, we have participated in drilling 28 exploratory wells in Poland, including seven commercial discoveries (the Wilga 2, Kleka 11, Zaniemysl-3, Sroda-4, Winna Gora-1, Roszkow-1, and Kromolice-1), and 21 noncommercial wells. Of our seven commercial successes in Poland, we were producing gas at our Wilga 2, Zaniemysl-3, and Kleka 11 wells as of December 31, 2008.

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 arise in obtaining rights-of-way to connect to the POGC pipeline system, obtaining construction permits, availability of materials and contractors, the signing of gas or oil 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 the mid-90s and by successfully completing an initial public offering of approximately 15% of its stock. 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, 2008, we have incurred cumulative net losses of approximately $160 million. We expect that our exploration and production activities may continue to result in net losses through 2009 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, 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 and Advisory Panel. 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.

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

We currently sell substantially all of the gas and oil 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.

Gas and oil price decreases and volatility could adversely affect our operations and our ability to obtain financing.

Gas and oil 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 gas and oil;

• market uncertainty;

• political conditions in international gas and oil producing regions;

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

• the level of consumer demand;

• weather conditions affecting production, transportation, and consumption;

• the competitive position of gas or oil 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 gas or oil purchasers;

• the effect of governmental regulation on the production, transportation, and sale of gas and oil; 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 gas and oil 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 or by POGC, as operator of the Fences area, can continue to be obtained on reasonable terms. 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

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gas and oil 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 gas and oil 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 gas and oil 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 regulatory regime governing exploration and development, production, marketing, transportation, and storage of gas and oil. These provisions were promulgated during the past two decades 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.

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Our gas and oil 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 gas and oil 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 gas and oil. We are required to prepare and obtain approval of environmental impact assessments by governmental authorities in Poland prior to commencing gas or oil 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 U.S. dollars and sometimes in Polish zlotys. Conversions between U.S. dollars and Polish zlotys are typically 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 U.S. dollar. 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.

The interests that we hold in concessions and usufructs owned in the name of POGC may be jeopardized or lost, without compensation to us, in the event of POGC’s bankruptcy, persistent breaches of laws such as environmental requirements, winding up, or other circumstances.

The Poland Ministry of the Environment, which administers the Geologic and Mining Law, has the authority to terminate concessions and usufructs in the name of POGC and in which we have a fractional undivided interest if POGC is declared bankrupt, persistently violates environmental regulations or other laws, is wound up, rescinds the concession, or otherwise breaches material usufruct or concession terms. There can be no assurance that POGC’s current 85% government ownership will continue or that the Poland government will in any circumstance intervene to prevent POGC’s insolvency or bankruptcy. We may not be able to implement effective measures to preserve and protect our property interests by curing any concession or usufruct default by POGC, assuring fair compensation in the event of any such loss, or implementing new legal strategies that would insulate our interests from loss due to POGC’s actions or condition.

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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 $2.05 and as high as $8.66 during intraday trading between January 1, 2008, 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;

• turmoil in the financial sector which may impact our revolving credit facility;

• prevailing world prices for gas and oil;

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

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

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

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ITEM 1B. UNRESOLVED STAFF COMMENTS

_____________________________________________________________________________________

None.

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_____________________________________________________________________________________

ITEM 2. PROPERTIES

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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 gas and oil 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, 2008, of $36.56 per barrel of oil, or Bbl, and $5.29 per thousand cubic feet, or Mcf, of gas in Poland and $24.58 per Bbl for oil in the United States. The determination of gas and oil 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 Polish gas reserves were prepared by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved United States oil reserves were prepared by Larry Krause Consulting, an independent engineering firm in Billings, Montana. No estimates of our proved reserves were filed with or included in any report to any other federal agency during 2008.

            The following summary of proved reserve information as of December 31, 2008, represents discounted, after tax estimates net to us only, and should not be construed as exact:

	Poland			United States		Total
	Oil	Gas	PV-10 Value	Oil	PV-10 Value	PV-10 Value
	(MBbls)	(MMcf)	(In thousands)	(MBbls)	(In thousands)	(In thousands)
Proved reserves	47	45,312	$117,250	45	$318	$117,568

Drilling Activities

The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2008, 2007, and 2006:

	Years Ended December 31,
	2008		2007		2006
	Gross	Net	Gross	Net	Gross	Net
Exploratory productive wells:
Poland	1.0	0.5	2.0	1.0	--	--
United States	--	--	--	--	--	--
Total	1.0	0.5	2.0	1.0	--	--
Exploratory dry holes:
Poland	2.0	1.0	--	--	1.0	1.0
United States	3.0	1.5	--	--	2.0	1.5
Total	5.0	2.5	--	--	3.0	2.5
Total wells drilled	6.0	3.0	2.0	1.0	3.0	2.5

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Wells and Acreage

As of December 31, 2008, our producing gross and net well count consisted of the following:

	Number of Wells
	Gross	Net
Well count:
Poland(1)	3.0	1.6
United States(2)	134.0	127.0
Total	137.0	128.6

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(1) As of December 31, 2008, we had four wells in Poland awaiting the construction of production facilities.

(2) 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 gas and oil acreage as of December 31, 2008:

	Developed		Undeveloped
	Gross	Net	Gross	Net
Poland:(1)
Fences project area	225	110	852,000	406,000
Wilga project area	543	441	250,000	205,000
Northwest project area	--	--	1,362,000	1,362,000
Kutno project area	--	--	706,000	706,000
Warsaw South project area			638,000	638,000
Block 287 project area	--	--	213,000	213,000
Edge project area	--	--	881,000	881,000
Block 246 project area			241,000	241,000
Block 229 project area			233,000	233,000
Total Polish acreage	768	551	5,376,000	4,885,000
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
Total Acreage	11,900	11,097	5,389,482	4,895,768

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(1) All gross and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.

Polish Properties

Producing Properties

A summary of our average daily production, average working interest, and net revenue interest for our Poland producing properties during 2008 follows:

	Average Daily Production (Mcfe)		Average Working	Average Net Revenue
	Gross	Net	Interest	Interest
Fences project area	2,717	2,690	37%	37%
Block 255/Wilga	771	763	82%	82%
	3,488	3,453

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Production, Transportation and Marketing

We did not place any new discoveries into production in Poland during 2008, and production from our Wilga well declined sharply, which resulted in an overall decline in production during 2008. We expect production will increase as we place four previous discoveries into production in 2009 and 2010.

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 2008, 2007, and 2006:

		2008		2007		2006
Average daily net gas production (Mcf)(1)		3,428		5,039		837
Average sales price per Mcf	$	5.92	$	4.95	$	3.88
Average daily net oil production (Bbls)(1)		10		69		106
Average sales price per Bbl	$	107.68	$	58.68	$	56.58
Average daily net Mcfe production(1)		3,488		5,453		1,473
Average production costs per Mcfe(2)	$	0.70	$	0.58	$	0.56

_______________

(1) Average daily net production amounts shown are calculated based on days of actual production.

(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 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 gas or oil we produce, we will be required to obtain prior governmental approval.

We are currently selling substantially all of our gas and oil 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 2008 follows:

	Average Daily Production (Mcfe)		Average Working	Average Net Revenue
	Gross	Net	Interest	Interest
Montana	201	167	98%	85%
Nevada	51	13	31%	29%
Total United States producing properties	252	180

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, producing since the 1940s from an average depth of approximately 2,900 feet, is from a waterflood program with 120 producing oil wells, 30 active injection wells, and one active water supply well. The Bears Den field, under waterflood since 1990, is producing oil from five wells at a depth of approximately 2,430 feet, with one active water injection well. 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.

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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. In the Trap Springs field, discovered in 1976, we produce oil from a depth of approximately 3,700 feet from one well. In the Munson Ranch field, discovered in 1988, we produce oil at an average depth of 3,800 feet from five wells. In the Bacon Flat field, discovered in 1981, we produce oil from one well at a depth of approximately 5,000 feet.

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 2008, 2007, and 2006:

	Years Ended December 31,
	2008	2007	2006
United States producing property data:
Average daily net oil production (Bbls)	181	192	209
Average sales price per Bbl	$86.91	$61.75	$56.07
Average production costs per Bbl(1)	$38.89	$34.12	$27.65

_______________

(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 93% 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.

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 free-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 gas and oil exploration by actively encouraging investment by foreign companies. 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).

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Prior to becoming a parliamentary democracy during 1989, the exploration and development of Poland’s gas and oil 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.

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 gas and oil 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.

Under current law, the concession authority requires that concessions and related usufructs be owned by a single entity, without recognizing any minority record ownership such as would reflect our interest in those areas in which we previously have been granted a minority ownership. As such, our ownership is subject to continued compliance with applicable law, the usufruct and concession terms, and, with regards to the Fences area, the solvency of POGC as the record owner.

The concession authority has granted POGC gas and oil exploration rights on the Fences project area, and has granted us gas and oil exploration rights on all other project areas in which we have an interest. The agreements divide these areas into blocks, containing up to 300,000 acres.

If commercially viable gas or oil is discovered, the concession owner may produce it for two years based on the exploration concession, then apply 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. 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.

We believe all material concession terms have been satisfied to date.

Existing Project Areas

Fences Project Area

The Fences project area consists of four gas and oil 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 July 2009 to July 2014. The total remaining work commitment includes: acquiring 100 kilometers of 2-D seismic data, 180 square kilometers of 3-D seismic data, and drilling three wells. POGC has filed an application for an extension for the concession expiring in 2009, which we expect to be granted.

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Wilga/Block 255 Project Area

The Wilga project area consists of a single gas and oil exploration concession held by us that expires in August 2009. The remaining period carries a work commitment of 80 kilometers of 2-D seismic data. We plan to file an application for extension for this concession in 2009, which we expect to be granted.

Block 287 Project Area

The Block 287 project area consists of a single gas and oil exploration concession held by us. Several producing fields also lie within this concession’s boundaries, but are excluded from the Block 287 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 was a drilling requirement of a second well that will be satisfied by re-entering and producing the Grabowka gas field in 2009. We plan to file an application for extension for this concession in 2009, which we expect to be granted.

Northwest Project Area

The Northwest project area consists of seven gas and oil exploration concessions granted at various times in 2006, 2007 and 2008, with expiration dates ranging from October 2012 through September 2014. The total work commitment for three of the blocks was outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years:  acquiring 800 kilometers of new 2-D seismic data; Phase III – three years: drilling three wells. The total work commitment for the remaining four blocks is outlined in two phases: Phase I – either two or three years: reprocessing and reinterpretation of existing data and acquiring 210 kilometers of 2-D seismic data; Phase II – three years: drilling four wells.

Kutno Project Area

The Kutno project area consists of three gas and oil exploration concessions. The first concession was granted in 2007 for a period of six years, and two new concessions were added in 2008 for a period of three years. The total work commitment for the initial concession is outlined in three phases: Phase I – one and one half years: reprocessing and reinterpretation of existing data; Phase II – two years: drilling one well or acquiring 100 kilometers of 2-D seismic; Phase III – two and a half years: drilling one well. The work commitments for the 2008 concessions are outlined in two phases: Phase 1 – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 200 kilometers of 2-D seismic data.

Warsaw South Project Area

This project area is adjacent to Block 255 and consists of four exploration concessions with expiration dates ranging from September 2012 to July 2013. The total work commitment for the four concessions is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 450 kilometers of new 2-D seismic data; Phase III – three years: drilling four wells.

As of December 31, 2008, all required usufruct/concession payments had been made for each of the above project areas.

Project Areas added in 2008

Edge Project Area

The Edge project area consists of four gas and oil exploration concessions granted for the period of five years. The total work commitment is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 350 kilometers of 2-D seismic data; Phase III – two years: drilling four wells.

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Block 246 Project Area

The Block 246 project area is adjacent to the Fences project area in the south and consists of a single concession granted for six years. The work commitment is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 120 kilometers of 2-D seismic data; Phase III – three years: drilling one well.

Block 229 Project Area

The Block 229 project area is adjacent to the Fences project area and consists of two explorations concessions granted for the period of six years. The total work commitment is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 300 kilometers of 2-D seismic data; Phase III – three years: drilling two wells.

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 (as amended), and the Protection and Management of the  Environment Act dated as  of January 31,  1980 (as amended),  which are the current primary

statutes governing environmental protection. Agreements with the government of Poland respecting our exploration and production areas create certain standards to be met regarding environmental protection. Participants in gas and oil 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 continue to develop, Polish requirements.

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 gas and oil 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 gas and oil 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 gas and oil, including provisions regarding deliverability. Such statutes and related regulations are generally intended to prevent waste of gas and oil and to protect correlative rights to produce gas and oil between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of gas and oil produced by assigning allowable rates of production to each well or proration unit.

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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 gas and oil 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 gas and oil industry in the future, such as proposals made in Congress and at the state level from time to time, that would reclassify certain gas and oil 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 gas and oil exploration and production.

Federal and Indian Leases

A substantial part of our producing properties in Montana consists of gas and oil 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 gas and oil 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.

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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 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 gas and oil 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, 2008, we had 47 employees, consisting of nine in Salt Lake City, Utah; 22 in Oilmont, Montana; one in Greenwich, Connecticut; three in Houston, Texas; and twelve 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. We also have an office in Warsaw, Poland, located at Ul. Chalubinskiego 8, which we rent for approximately $4,300 per month.

Gas and Oil 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.

“Ca1” and “Ca2” refer to specific geological formations.

“Development well” means a well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

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“Exploratory well” means a well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil 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.

“MBbls” means thousand oilfield barrels.

“Mcf” means thousand cubic feet of natural gas.

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

“Tcf” means trillion cubic feet of natural gas.

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

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_____________________________________________________________________________________

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, except as follows:

In November and December 2007, three actions were filed in the United States District Court for the District of Utah against us and officers or directors David N. Pierce, Clay Newton, Thomas B. Lovejoy, Andrew W. Pierce, and Richard Hardman, by three separate plaintiffs, each seeking class certification to proceed on behalf of all others similarly situated and alleging violations by the defendants of the antifraud provisions of the federal securities laws set forth in Section 10(b) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder relating to our public statements about our oil and gas activities and prospects in Poland between March 2004 and January 2006. The complaints seek damages to be determined at trial, interest, and costs, together with such other relief as the court may deem appropriate. The three actions have now been consolidated into a single matter, In re FX Energy, Inc., Securities Litigation, US District Court, District of Utah, case no. 2:07-cv-00874, and the lead plaintiffs and counsel have been specified. The consolidated actions have not been certified to proceed as a class action.

A consolidated complaint has been filed by the lead plaintiff that alleges that the defendants violated the antifraud provisions of Section 10(b) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder by making material misrepresentations and omissions regarding our Sroda-5 and Lugi-1 projects between January 20, 2005, and January 5, 2006. The consolidated complaint seeks damages to be determined at trial, interest, costs and such other relief as the court may deem appropriate. On June 20, 2008, we filed a motion to dismiss, with a supporting memorandum, for failure to state a claim upon which relief can be granted. Plaintiffs filed an opposition to the defendants’ motion on August 19, 2008, to which defendants filed a reply on October 3, 2008. Following a hearing on February 23, 2009, on defendants’ motion to dismiss, the matter is under advisement by the court. We intend to defend vigorously this consolidated action on behalf of all defendants.

Another pending action filed in the United States District Court for the District of Utah entitled Leilani York, derivatively on behalf of nominal defendant FX Energy, Inc., plaintiff, v. David N. Pierce, Dennis B. Goldstein, Arnold S. Grundvig, Jr., Richard Hardman, Tom Lovejoy, Jerzy Maciolek, Clay Newton, Andrew W. Pierce, and David Worrell, defendants, and FX Energy, Inc., nominal defendant, case no. 2:08-cv-00143, asserts

derivative claims on our behalf against certain of current and former our directors and certain of our current and former executive officers, arising out of the same set of facts, has been stayed pending final resolution of the In re FX Energy, Inc., Securities Litigation.

_____________________________________________________________________________________

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, 2008.

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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
2009:
First Quarter (through March 10, 2009)	$ 2.13	$ 3.54
2008:
Fourth Quarter	2.05	7.20
Third Quarter	4.95	8.66
Second Quarter	4.44	5.81
First Quarter	3.98	5.94
2007:
Fourth Quarter	5.68	8.19
Third Quarter	6.03	9.29
Second Quarter	7.79	10.39
First Quarter	5.83	7.88

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 10, 2009, we had approximately 10,500 stockholders.

Equity Compensation Plans

The information from the definitive proxy statement for the 2009 annual meeting of stockholders under the caption “Equity Compensation Plans” is incorporated herein by reference.

Recent Sales of Unregistered Securities

None.

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_____________________________________________________________________________________

ITEM 6. SELECTED FINANCIAL DATA

_____________________________________________________________________________________

The following selected financial data for the five years ended December 31, 2008, 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,
	2008	2007(5)	2006(5)	2005(5)		2004(5)
	(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Gas and oil sales	$ 13,494	$ 14,903	$ 6,533		$ 3,805		$ 3,096
Oilfield services	4,347	3,093	1,696		2,132		710
Total revenues	17,841	17,996	8,229		5,937		3,806
Operating costs and expenses:
Lease operating expenses (1)	3,441	3,538	2,647		2,462		1,946
Exploration costs (2)	15,389	10,624	5,608		8,369		3,013
Recovery of previously expensed
Input VAT	--	--	--		(2,121)		--
Impairment of gas and oil properties (3)	14,746	2,299	3,583		--		--
Oilfield services costs	2,751	1,998	1,245		1,689		551
Depreciation, depletion and
amortization	1,720	2,064	1,290		903		636
Accretion expense	84	78	53		45		41
Amortization of deferred
compensation	2,367	2,604	2,759		125		--
Stock compensation (4)	--	--	--		76		5,859
Bad debt expense	460	--	--		--		--
General and administrative (G&A)	7,030	7,061	5,728		6,420		4,649
Total operating costs and expenses	47,988	30,266	22,913		17,968		16,695
Operating loss	(30,147)	(12,270)	(14,684)		(12,031)		(12,889)
Other income (expense):
Interest and other income (expense)	394	818	795		780		529
Foreign exchange gain (loss)	(24,279)	146	122		(172)		(260)
Interest expense	(672)	(385)	--		--		--
Total other income (expense)	(24,557)	579	917		608		269
Net loss	$ (54,704)	$ (11,691)	$ (13,767)		$ (11,423)		$ (12,620)

– Continued –

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	Years Ended December 31,
	2008	2007	2006	2005		2004
	(In thousands, except per share amounts)
Basic and diluted net loss per common share	$ (1.35)	$ (0.32)	$ (0.39)		$ (0.33)		$ (0.41)
Basic and diluted weighted average
shares outstanding	40,420	36,694	35,163		34,733		30,691
Cash Flow Statement Data:
Net cash used in operating activities	$(14,248)	$(1,581)	$(5,303)		$(10,105)		$ (5,886)
Net cash provided by (used in) investing    activities	(11,772)	(13,152)	8,135		4,656		(41,492)
Net cash (used in) provided by financing    activities	40,121	14,351	(578)		4,055		33,791
Balance Sheet Data:
Working capital	$ 13,965	$ 15,374	$ 11,967		$ 27,715		$ 33,777
Total assets	54,802	46,369	39,167		48,271		52,962
Long-term debt	25,000	--	--		--		--
Stockholders’ equity	15,154	37,542	31,965		42,280		48,556

_______________

(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 in 2004.

(5) Certain amounts have been reclassified to conform to 2008 presentation. There was no impact on total assets, net income or cash flows.

_____________________________________________________________________________________

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 Financial Data, and 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 (Poland and United States), our financial results show a distinct dichotomy. Our Polish operations are still early in their development and growth phase, while our U.S. operations are relatively mature. Beginning in 2006, our results began to show substantial changes and improvement as we began gas and oil production in Poland. See “Results of Operations by Business Segment” below.

Through 2006, most of our gas and oil production, revenues, and lease operating expenses were attributable to our U.S. operations. Our oilfield service revenues and costs have been and will continue to be exclusively from the United States. Our U.S. operations have historically 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 during the past several years 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.

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We are acutely aware of the global economic crisis and we are mindful of the need to stay alert and act reasonably. We believe our business strategy is sound and that our resources and opportunities, carefully managed, will allow us to continue growing through the next several years.

Following is a brief discussion concerning certain significant operational and capital events that occurred during 2008 and the first quarter of 2009, as well as discussion concerning the impact of the current world economic situation on us.

Gas and Oil Reserves

As a result of our ongoing drilling and production successes in Poland, 2008 was the fifth consecutive year that we reported record year-end proved reserve values. The following table highlights year-end reserve volumes and values, and shows the change from 2007 to 2008:

	2008	2007	Change
Proved Reserve Volumes:	(In thousands)
Gas Reserves (Mcf)	45,312	31,116	+46%
Oil Reserves (Bbls)	92	496	-81%
Total Reserves (Mcfe)	45,864	34,092	+35%
Proved Reserve Values:
Reserves PV-10 Value	$117,568	$102,968	+14%

            The 2008 natural gas discovery at the Kromolice-1 well contributed the greatest portion of our year-over-year increase in proved reserves. At year-end, gross proved reserves for the well were estimated at approximately 20 Bcf of gas (9.8 Bcf net to our 49% interest). The Sroda-4 well proved reserves also increased by 1.3 Bcf as the Sroda-4 to Kromolice-1 trend was determined to be part of a single accumulation. A 30% increase in Zaniemysl proved reserves of 1.9 Bcf following a 2008 reservoir test was also a positive development.

In early 2009, we announced the successful drilling of the Kromolice-2 well, located two kilometers southwest of the Kromolice-1 well. The well flowed gas on a successful DST and is being completed for production. Reserves from the Kromolice-2 well will be included in our 2009 reserve report, and will likely enable us to report record reserve values for a sixth consecutive year.

Adapting to the Global Economic Crisis

The impact on the gas and oil industry of the current global economic crisis has been sudden, dramatic, and wide-ranging. As with the bulk of companies in this industry, we are not immune from many of the negative effects. In the following paragraphs, we identify some of the areas of concern, and provide some discussion as to our plans to protect and exploit our assets and continue to methodically increase our shareholder value.

Gas and Oil Prices. Global oil prices have dropped rapidly from unprecedented highs in mid-2008 to significantly lower prices at year-end. Gas prices in the United States have also decreased significantly. The European gas market, however, operates quite differently than the domestic market. In Poland, all of our gas production is sold to POGC and is tied to published tariffs set by the public utility regulator from time to time for gas sold to wholesale consumers. During 2008, the Polish regulator granted two price increases, the first in April and the second in October. Since that time, gas prices have remained constant. A major component of the tariff calculation is the cost of Russian imported gas, which in turn is priced based on trailing, historical oil prices. With the recent drop in oil prices, there is a possibility that the cost of imported gas may decline, which in turn may cause the Polish regulator to decrease the cost of gas sold by POGC and thereby reduce the price we receive. The other major component of the tariff calculation is the cost of gas provided by POGC itself. Historically, this cost has been low, reflecting the relatively low cost of finding and producing domestic gas. Natural gas prices in Poland are, and for years have been, below European Union average prices for both households and industry, because the prices have been subsidized by the government. European Union rules require Poland to abandon market subsidies and bring Poland gas prices to free-market levels. This may act as a cushion against possible declines in prices. As of year-end 2008, gas prices in Poland remained firm and were higher than those of an equivalent BTU content in the United States. There was no significant price impact on the value and volumes of our gas reserves in Poland from 2007 to 2008.

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We see a greater impact on our revenues and reserves from the declines in oil prices than from changes in gas prices. Year-end 2007 prices in Montana averaged approximately $94 per barrel and reached a monthly high of approximately $120 per barrel in June 2008. At year-end 2008, our average price in Montana was approximately $25 per barrel, and our year-end price in Poland was approximately $37 per barrel. The fall in oil prices creates two primary issues:

• First, oil revenues will decrease significantly until such time as prices recover. In our case, more than 50% of our 2008 gas and oil revenues were from our gas wells in Poland, so the impact of lower oil prices on 2009 revenues, while measurable, will be lessened somewhat by our production mix and expected increases in 2009 gas production in Poland. The reduction in oil revenues will, however, impact our ability to execute a robust capital program during 2009. See “Capital and Operating Budgets” below for more discussion.

• Second, the price decline reduces both the value and volumes of our proved oil reserves in the United States. This, in turn, leads to impairment charges at existing wells, where the estimated year-end 2008 reserve values, calculated at year-end prices, are now less than the existing capitalized costs. See “Property Impairments” below for more discussion. We expect this type of charge to be commonplace among most gas and oil companies this year. In our case, domestic oil properties accounted for only 11% of our total reserve value at year-end 2007. Again, the impact on reserve volumes and values, while measurable, is lessened somewhat by our reserve weighting towards natural gas in Poland.

Credit Markets. We have a $25 million Senior Facility Agreement with the Royal Bank of Scotland, or RBS, in London, England. In October of last year, partly in response to the turmoil in the banking industry and to guarantee that we would have the cash on hand necessary to fund our 2009 commitments, we drew down the entire balance of the Facility. Since that time, through various bail-out initiatives, RBS has become majority owned by the government of the United Kingdom.

At present, we do not know what impact the distress in the banking industry in general, and on RBS in particular, will have on us. We are in compliance with all of the terms of the Facility and are in active discussions with RBS to extend and expand the terms and size of the Facility. Despite the fact that we believe we have reserve volumes and values that would command a sizable increase in the Facility in normal times, there is no guarantee that RBS will, in fact, increase the amount of funds available to us. This may, in turn, restrict the amount of capital we are able to apply in our development programs in Poland.

Equity Markets. Virtually every gas and oil company worldwide has seen its market capitalization value decline precipitously over the past six months. We are no exception. Our stock price has declined more than 60% from its 2008 peak and, as of late January, 42% over the preceding 12 months.

We have traditionally funded our exploration programs, both in Poland and in the United States, through the issuance of equity. While we believe that the equity markets remain accessible, we may be unwilling to issue new equity at current depressed stock prices to fund our capital expansion. Again, this may restrict the amount of capital we are able to apply in our development programs in Poland.

Capital and Operating Budgets. Because of the circumstances discussed above, we are acutely aware of the need to preserve and be judicious in the use of our existing capital. We are making adjustments to our capital and operating budgets as follows.

Other than for capital projects that were committed and in process at year-end 2008, we have determined, in consultation with our partner, POGC, to not initiate new capital projects in 2009 until the commencement of production at our Roszkow well in Poland. We currently expect production to commence sometime during the latter part of the second quarter. This means that any new seismic and drilling projects will not begin until the second half of 2009. Despite these changes in timing, however, we expect cash flow from the Roszkow well to help us to resume drilling in our core area in the second half of 2009.

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We have also taken steps to reduce our operating budget. For the year 2008, we reduced our cash overhead costs by approximately 10% from budgeted 2008 levels, primarily by reducing compensation costs. We currently expect to reduce 2009 cash overhead costs by an additional 10%, again by reducing compensation and other controllable costs.

Property Impairments. The drop in oil prices and the adjusted timing of our capital budget caused us to record property impairment charges during the fourth quarter of 2008. In the United States, we have impaired the cost of most of our producing oil wells due to lower reserve volumes and values. In Poland, we have impaired the cost of two of our recent drilling projects due to the adjusted timing of our capital plans. These impairments are noncash charges, and do not mean that we have abandoned or stopped production at any of the properties involved.

In the United States, we recorded an impairment charge at year-end 2008 of approximately $3.8 million related to our oil properties. This is the amount by which the year-end net book value of our producing properties exceeded the estimated discounted future cash flows, as determined using year-end oil prices from those properties. In each case, the wells continue to produce, and we continue to carefully monitor both oil prices and operating costs to ensure that we are producing the wells efficiently and economically.

In Poland, we have impaired the costs of two wells; the Grundy-1 well and the Sroda-6 well. According to the provisions of FASB Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Companies,” capitalized costs of exploratory wells are required to be expensed if reserves cannot be classified as proved after one year following the completion of drilling. Accordingly, we have recorded an impairment charge of $7.2 million associated with the Grundy-1 well and $3.8 million associated with the Sroda-6 well in 2008.

Foreign Currency Volatility. We enter into various agreements in Poland denominated in the Polish zloty. The Polish zloty is subject to exchange rate fluctuations that are beyond our control. During the past 12 months, the zloty has fluctuated between a low of 2.02 zlotys per U.S. dollar in August of 2008 to a high of 3.88 zlotys per dollar in late February of 2009. We have historically used the U.S. dollar as our functional currency for U.S. financial reporting purposes. We record receivables and payables at fixed amounts in U.S. dollars on their respective transaction dates; when the receivables and payables are subsequently settled at different exchange rates, we recognize foreign currency gains or losses in our statements of operations. In addition, variations in exchange rates also affect the U.S. dollar denominated amount of revenue we receive in Polish zlotys. As the U.S. dollar strengthens, our U.S. dollar denominated revenue received in Polish zlotys declines; conversely, when the U.S. dollar weakens, our U.S. dollar denominated revenue received in Polish zlotys increase. Should exchange rates in effect during early 2009 continue throughout the year, we expect the exchange rates to have a negative impact on our U.S. dollar denominated revenues.

At the same time, however, our U.S. denominated costs of conducting business in Poland, which includes drilling, geological and geophysical, and overhead costs, will also decline at the same rate. We are also generating revenues in Poland in Polish zlotys, and we keep those zlotys in Poland and use them to pay zloty-based invoices.

Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues.

During October 2008, we drew down the remaining $14 million of availability under our Senior Credit Facility to ensure that we had the necessary capital on hand to meet existing commitments. At the same time, we purchased approximately $14.7 million in Polish zloty forward contracts. These contracts matured at the end of each month, beginning in October 2008 and concluding in March, 2009. The rate for each of the contracts was 2.50 zlotys per U.S. dollar, which, at the time, was a 52 week low for the zloty. Due to rapidly deteriorating exchange rates during the final two months of the year, these contracts, coupled with other transaction losses, caused us to record foreign exchange transaction losses during the year of $2.5 million. As of year-end 2008, we had three outstanding contracts denominated in U.S. dollars as follows: $2.5 million that matured January 30, 2009; $2.1 million that matured February 27, 2009; $1.1 million that matures March 31, 2009. In connection with these outstanding contracts, we recorded an additional loss of approximately $888,000 when we marked them to market at December 31, 2008, when the exchange rate was 2.96 zlotys per U.S. dollar.

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            Effective October 1, 2008, we changed the functional currency of our Polish subsidiary from the U.S. dollar to the Polish zloty. During the fourth quarter of 2008, for the first time, we entered into forward zloty purchase contracts. In early 2009, we entered into construction and revenue agreements that would recognize the results of increasingly significant levels of production and corresponding revenues in Polish zloty. In recognition of these economic events combined with the resulting increases in future zloty revenues and expenditures of the Polish entity, we determined that it was appropriate to change the functional currency of FX Energy Poland to the Polish zloty.

SFAS No. 52, “Foreign Currency Translation,” requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Because FX Energy Poland's functional currency is now the Polish zloty, translation adjustments will result from the process of translating its financial statements into the U.S. dollar reporting currency. Translation adjustments will not be included in determining net income but shall be reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities affected by the change are adjusted to reflect the difference between the exchange rate when the asset or liability arose and the exchange rate on the date of the change. Upon the change in functional currency, we recorded a cumulative translation adjustment (“CTA”) of approximately $3.3 million, which is shown in the consolidated statement of stockholders’ equity (deficit). Because of the change in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period. At December 31, 2008, the CTA was approximately $17.1 million reflecting the impact of exchange rate fluctuations.

The change in functional currency will also affect the amounts we report for our Polish assets, liabilities, revenues, and expenses from those that would be reported had we maintained the U.S. dollar as the functional currency for our Polish operations. The differences will depend on changes in period-average and period-end exchange rates. During the fourth quarter of 2008, we recorded foreign currency transaction losses of approximately $24.3 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. Future transaction gains or losses may be significant given the amount of intercompany loans and the volatility of the exchange rate.

The change in functional currency will have no impact on our actual zloty-based revenues and expenditures in Poland.

Oil and Gas Revenues and Pricing

Revenues and Production. As we expected and forecasted in our 2007 Form 10-K, production at our Wilga well in Poland declined sharply in 2008 from its 2007 production levels. Production at our Wilga well declined from 764 Mcfe to 248 Mcfe in 2008, a decline of 68%. However, higher prices for both gas and oil, coupled with an increase in our drilling services revenues, mostly offset our production volume declines. The following table highlights revenues and production volumes and shows the change from 2007 to 2008:

	2008	2007	Change
Revenues:	(In thousands)
Oil & Gas Sales	$ 13,494	$ 14,903	-9%
Total Revenues	$ 17,841	$ 17,996	-1%
Production:
Gas Production (Mcf)	1,251	1,840	-32%
Oil Production (Bbls)	69	95	-27%
Total Production (Mcfe)	1,666	2,412	-31%

We expect to see an upward trend in production during 2009 as we anticipate bringing the Roszkow well in Poland into production.

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Results of Operations by Business Segment

We operate within two segments of the gas and oil 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, 2008, 2007, and 2006 (in thousands). See Footnote 12 to the consolidated financial statements for additional detail concerning our segment results.

	Reportable Segments
			Oilfield
	Exploration & Production		Services
	Poland	U.S.		Non-Segmented	Total
Year ended December 31, 2008:
Revenues	$    7,798	$   5,695	$ 4,348	$           --	$   17,841
Net income (loss)(1)	(19,548)	(1,847)	726	(34,035)	(54,704)
Year ended December 31, 2007:
Revenues	$  10,567	$  4,336	$ 3,093	$           --	$   17,996
Net income (loss)(2)	(4,415)	1,102	828	(9,206)	(11,691)
Year ended December 31, 2006:
Revenues	$   2,273	$  4,260	$ 1,696	$           --	$    8,229
Net income (loss)(3)	(6,779)	463	296	(7,747)	(13,767)

_______________

(1) Nonsegmented reconciling items for 2008 include $7,030 of general and administrative costs, $2,367 of noncash stock compensation expense, $24,279 of foreign exchange losses, $278 of other expense, and $81 of corporate DD&A.

(2) Nonsegmented reconciling items for 2007 include $7,061 of general and administrative costs, $2,604 of noncash stock compensation expense, $146 of foreign exchange gains, $433 of other income, and $120 of corporate DD&A.

(3) Nonsegmented reconciling items for 2006 include $5,728 of general and administrative costs, $2,759 of noncash stock compensation expense, $122 of foreign exchange gains, $795 of other income, and $177 of corporate DD&A.

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $7.4 million during 2008, compared to $9.1 million and $1.8 million in 2007 and 2006, respectively. As we expected, production in 2008 at our Wilga well declined sharply from 2007 levels. Consequently, Company-wide gas production for 2008 was 32% lower than 2007 production. Conversely, two price increases, the first effective May 1 and the second effective November 1, 2008, coupled with favorable exchange rates for the zloty against the U.S. dollar for much of the year, resulted in higher effective gas prices, which increased 20% from 2007 to 2008. Gas revenues in 2008 increased from 2007 levels by approximately $1.2 million due to higher gas prices, offset by approximately $2.9 million related to production declines. Gas revenues in 2007 increased from 2006 levels by approximately $2.0 million due to higher gas prices, coupled with approximately $5.3 million related to higher production.

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A summary of the amount and percentage change, as compared to their respective prior-year period, for gas revenues, average gas prices, gas production volumes, and lifting costs per Mcf for the years ended December 31, 2008, 2007, and 2006, is set forth in the following table:

	For the year ended December 31,
	2008	2007	2006
Revenues	$7,404,000	$9,098,000	$1,790,000
Percent change versus prior year	-19%	+408%	NA
Average price (per Mcf )	$5.92	$4.95	$3.88
Percent change versus prior year	+20%	+28%	NA
Production volumes (Mcf)	1,251,129	1,839,504	461,303
Percent change versus prior year	-32%	+299%	NA
Lifting costs per Mcf (1)	$0.65	$0.63	$0.54
Percent change versus prior year	+3%	+17%	NA

_______________

(1) Lifting costs per Mcf are computed by dividing the related lease operating expenses by the total volume of gas produced.

Oil Revenues. Oil revenues were $6.1 million, $5.8 million, and $4.7 million for the years ended December 31, 2008, 2007, and 2006, respectively. As with our gas production, oil production at Wilga declined 86% from 2007 to 2008, which contributed significantly to the overall production decrease of 27%. Production from our U.S. properties also declined by 7%, due to normal production declines and decreased workovers and maintenance. These production declines, however, were more than offset by higher oil prices. Our average oil price during 2008 was $88.01 per barrel, a 45% increase over $60.86 per barrel received during 2007.

Included in oil revenues were approximately $394,000, $1.5 million, and $484,000 related to the sale of oil at the Wilga well for the years ended December 31, 2008, 2007, and 2006, respectively. All other oil revenues during the three years were derived from our producing properties in the United States. U.S. oil revenues in 2008 increased from 2007 levels by approximately $1.5 million due to higher oil prices, offset by approximately $300,000 related to production declines. U.S. oil revenues in 2007 increased from 2006 levels by approximately $398,000 due to higher oil prices, offset by approximately $322,000 related to production declines.

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, 2008, 2007, and 2006, is set forth in the following table (in thousands, except for prices and percentages):

	For the year ended December 31,
	2008	2007	2006
Revenues	$6,090,000	$5,804,000	$4,744,000
Percent change versus prior year	+5%	+22%	+25%
Average price (per Bbl )	$88.01	$60.86	$56.13
Percent change versus prior year	+45%	+8%	+16%
Production volumes (Bbl)	69,192	95,242	84,520
Percent change versus prior year	-27%	+13%	+78%
Lifting costs per Bbl (1)	$38.07	$27.04	$25.23
Percent change versus prior year	+41%	+7%	-6%

_______________

(1) Lifting costs per barrel are computed by dividing the related lease operating expenses by the total barrels of oil produced. Light crude oil lifting costs in Poland are based on an allocation of total costs based on relative revenues between gas and oil. Lifting costs include production taxes incurred in the United States.

Lease Operating Costs. Lease operating costs were $3.4 million in 2008, $3.5 million in 2007, and $2.6 million in 2006. Operating costs decreased slightly in 2008 as we negotiated lower indirect costs at our non-operated properties in Poland. The higher costs in 2007 compared to 2006 were reflective of the first full year’s production in Poland. Poland operating costs rose from $289,000 in 2006 to $1.1 million in 2007.

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Exploration Costs. Our exploration efforts are focused in Poland, and the expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes. Exploration costs were $15.4 million, $10.6 million, and $5.6 million for the years ended December 31, 2008, 2007, and 2006, respectively.

Geological and geophysical costs, or G&G costs, were $15.0 million, $10.6 million, and $4.0 million for the years ended December 31, 2008, 2007, and 2006, respectively. During all three years, most of our G&G costs were spent on acquiring, processing, and interpreting new 3-D and 2-D seismic data in the Fences areas.

Exploratory dry-hole costs were $0.4 million, $0, and $1.6 million for the years ended December 31, 2008, 2007, and 2006, respectively. During 2008, we drilled three shallow dry holes, two in Montana and one in Nevada. During 2007, all wells drilled during the year were determined to be commercial, and were completed for future production. Our 2006 exploration costs included approximately $800,000 associated with the Drozdowice-1 well in our Fences III concession area in Poland, along with additional amounts for two dry holes in Montana and Nevada.

Impairment Costs. Impairments of gas and oil properties were $14.7 million, $2.3 million, and $3.6 for the years ended December 31, 2008, 2007, and 2006, respectively. As discussed previously, during 2008 we impaired $7.2 million and $3.8 million related to our Grundy and Sroda-6 wells in Poland, respectively, and an additional $3.8 million related to our producing properties in Montana. During 2007 we impaired $2.3 million related to our Wilga well, and in 2006 we impaired the entire amount of capitalized costs associated with our Rusocin-1 well.

DD&A Expense - Producing Operations. DD&A expense for producing properties was $1.2 million, $1.7 million, and $957,000 for the years ended December 31, 2008, 2007, and 2006, respectively. The 29% decrease from 2007 to 2008 resulted primarily from the $2.3 million impairment in 2007 for our Wilga well, as those costs were removed from our depletion base. The 78% increase from 2006 to 2007 was a reflection of a full-year’s worth of production in Poland, discussed earlier. DD&A expense in Poland was $935,000 in 2007. The remaining increase is due to capital cost additions in 2006 at our Montana producing properties.

Future DD&A costs are expected to generally, but not completely, follow future production trends. However, future DD&A rates can be very different depending upon future capitalized costs.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $4.3 million, $3.1 million, and $1.7 million for the years ended December 31, 2008, 2007, and 2006, respectively. We drilled 23 wells for third parties during 2008, along with additional well service work, compared to 16 wells and 12 wells during 2007 and 2006, respectively. 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 $2.8 million, $2.0 million, and $1.2 million for the years ended December 31, 2008, 2007, and 2006, respectively, or 63%, 65%, and 73% of oilfield servicing revenues, respectively. The year-to-year increases in costs were primarily due to increased drilling activity. 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 own properties, and other factors.

DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $411,000, $267,000, and $155,000 for the years ended December 31, 2008, 2007, and 2006, respectively. We spent $1,008,000, $911,000, and $295,000 on upgrading our oilfield servicing equipment during 2008, 2007, and 2006 respectively. These capital additions resulted in higher DD&A expenses for this segment during 2007 and 2008.

Bad Debt Expense – Oilfield Services. Bad debt expense was $460,000, $0, and $0 for the years ended December 31, 2008, 2007, and 2006, respectively. During 2008, we wrote off as uncollectable $460,000 related to revenue recognized during 2007 for third-party drilling services. This was the first bad debt charged to expense in our history. We do not expect to incur future bad debt charges.

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Nonsegmented Items

G&A Costs - Corporate. G&A costs were $7.0 million, $7.1 million, and $5.7 million for the years ended December 31, 2008, 2007, and 2006, respectively. Lower employee compensation costs in 2008 were offset by increases in accounting, insurance, and consulting costs. In addition, legal fees associated with our ongoing litigation increased by approximately $90,000 over 2007 levels. See Item 3, Legal Proceedings, for additional information. Higher employee compensation costs in 2007, associated in part with an expansion of our Poland operations office, coupled with higher legal, insurance, and software maintenance costs, resulted in an increase in 2007 G&A of $1.3 million over 2006 levels.

Stock Compensation. We adopted the provisions of SFAS No. 123R, “Share-Based Payments, (“SFAS No 123R”), on January 1, 2006, using the modified prospective method. Stock compensation expense recorded for 2008 represents $2.3 million of amortization related to restricted stock granted in 2008, 2007, and 2006. Stock compensation expense recorded for 2007 represents $1.8 million of amortization related to restricted stock granted in 2007, 2006, and 2005 and $842,000 of amortization of unvested stock options granted prior to 2005, using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No 123R”). Stock compensation expense recorded for 2006 represents $1.1 million of amortization related to restricted stock granted in 2006 and 2005 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 (Expense) - Corporate. Interest and other income (expense) was ($278,000), $433,000, and $795,000 for the years ended December 31, 2008, 2007, and 2006, respectively. During 2008, we amortized $210,000 related to fees incurred in securing our Senior Credit Facility to interest expense and paid $111,000 in commitment fees for the facility. We also paid $351,000 in interest on outstanding borrowings. These interest-related costs were offset by interest income of $394,000. During 2007, amortized fees and semiannual commitment fees for the facility totaled $385,000 in interest-related charges. These charges offset interest income of $818,000, an increase over 2006 levels due to higher cash balances available for investment.

Foreign Exchange. As discussed previously, we incurred foreign exchange losses of $24.3 million, and foreign exchange gains of $146,000 and $122,000 for the years ended December 31, 2008, 2007, and 2006, respectively. Included in the 2008 losses was $888,000 related to mark-to-market adjustments to outstanding year-end Polish zloty forward contracts.

Income Taxes. We incurred net losses of $36.5 million, $11.7 million, and $13.8 million for the years ended December 31, 2008, 2007, and 2006, 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

Throughout our history, 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. With the establishment of proved reserves in Poland, in November 2006, we established a $25.0 million Senior Credit Facility with the Royal Bank of Scotland to fund infrastructure and development costs in Poland. As of December 31, 2008, we had drawn down the full $25.0 million available under this facility. In addition, cash flow from our production operations has been providing a portion of our capital expenditures for the past 24 months. As of December 31, 2008, we have classified approximately $4.1 million of auction-rate securities as Level 3 financial assets. See Note 7 to these financial statements for additional information concerning fair value accounting for our investments. We believe we will be able to convert all remaining auction-rate securities to cash within our normal operating cycle.

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The recent strengthening of the U.S. dollar will, if it continues, have a negative impact on our 2009 revenue and operating profit; conversely, our U.S. dollar denominated capital costs in Poland will decrease at the same rate. We expect our exploration and development programs will continue in spite of the economic downturn, although at a slower pace than in previous years. As we discussed previously, other than for capital projects that were committed and in process at year-end 2008, we have determined, in consultation with our partner, POGC, to not initiate new capital projects in 2009 until after the commencement of production at our Roszkow well in Poland. This will enable us to conserve cash until the expected increases in revenue occurs. Our expected operating cash flow combined with our cash resources and marketable securities as of December 31, 2008, should more than enable us to meet our capital needs in the United States and Poland for the next 12 months, without accessing the capital or debt markets for additional funding.

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. As our reserves increase above the amounts estimated when we established our $25.0 million Senior Credit Facility with the Royal Bank of Scotland, we may seek to expand our borrowings from it or other lenders. As discussed elsewhere in this report, in view of the current global economic and credit crises and the particular impact on the Royal Bank of Scotland, we cannot assure that our efforts to increase borrowings will be successful.

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 $14.0 million as of December 31, 2008, a decrease of $1.4 million from December 31, 2007. Amounts borrowed under our Senior Credit Facility, coupled with proceeds from the exercise of warrants, were used to fund a record level of drilling and seismic activities during 2008.

Operating Activities. We used net cash of $14.2 million, $1.6 million, and $5.3 million in our operating activities during 2008, 2007, and 2006, respectively, primarily as a result of the net losses, excluding noncash charges, incurred in those years. Revenues from gas and oil sales in Poland, which commenced in late 2006, helped us reduce the amount of cash used in operations in all three years. Our current assets at year-end 2008 included approximately $1.1 million in accrued gas and oil sales from both the United States and Poland, $1.2 million in receivables related to our oilfield services segment, and $2.5 million in refundable Input VAT that we expect to receive during the first six months of 2009. Our current liabilities at year-end included approximately $6.3 million in costs related to our exploration activities in Poland that were paid in early 2009.

Investing Activities. We used net cash in investing activities of $11.8 million and $13.1 million in 2008 and 2007, respectively, and received net cash from investing activities of $8.1 million in 2006. In 2008 we received $11.3 million from the maturities of marketable securities. We invested $186,000 in marketable securities. We spent $21.8 million for gas and oil property additions, $20.0 million of which was related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $169,000 upgrading our office equipment and $1.0 million adding to our oilfield services equipment.

In 2007 we received $4.9 million from the maturities of marketable securities. We invested $9.6 million in marketable securities. We spent $7.5 million for gas and oil property additions, $7.0 million of which was related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $73,000 upgrading our office equipment and $893,000 adding to our oilfield services equipment.

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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 gas and oil 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.

Financing Activities. We received net cash from financing activities of $40.1 million and $14.4 million in 2008 and 2007, respectively, and used net cash in financing activities of $578,000 in 2006. During 2008, we borrowed $25 million under our Senior Credit Facility with RBS and $3.4 million as a loan from UBS related to auction rate securities, of which $546,000 was repaid by December 31, 2008. In addition, 3,648,369 options and warrants were exercised, resulting in proceeds to us of $12.3 million.

During 2007, we sold 1.5 million shares of stock in a registered direct offering, resulting in net proceeds to us of $12.4 million. In addition, 672,165 options and warrants were exercised during the year, resulting in proceeds to us of an additional $1.9 million.

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.

Contractual Obligations and Contingent Liabilities and Commitments

Contractual Obligations. At December 31, 2008, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:

	Total	2009	2010	2011	2012	2013
	(In thousands)
Senior credit facility	$25,000	$   --	$ 5,000	$ 10,000	$ 10,000	$    --
Interest payments on long-term debt	2,132	718	718	487	209	--

We had no other significant contractual obligations or commitments as of December 31, 2008. We are subject to certain work commitments with respect to our exploration concessions that must be satisfied in order to maintain our interest in those concessions. These work commitments are optional on our part; however, they must be satisfied in order to maintain our interest in those concessions.

Our gas and oil 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 gas and oil exploration, drilling, and production. We would be adversely affected by a significant event that is not fully covered by insurance or by our inability to maintain adequate insurance in the future at rates we consider reasonable.

               Asset Retirement Obligation. We also have liabilities of $1.9 million related to asset retirement obligations on our Consolidated Balance Sheet at December 31, 2008, excluded from the table above. Due to the nature of these obligations, we cannot determine precisely when the payments will be made to settle these obligations.

New Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No. 160”). This statement improves the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS No. 160 affects those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The adoption of this statement is not expected to have any effect on our financial statements.

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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No. 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS No. 161 applies to all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. SFAS No. 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of this statement is not expected to have a material effect on our financial statements.

In October 2008, FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” to clarify guidance on determining the fair value of a financial asset under SFAS No. 157, “Fair Value Measurements,” in a market that is not active. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The adoption of this statement was effective October 1, 2008, and did not have a material impact on our financial position or results of operations.

In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010, for reporting 2009 reserve information. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure requirements also require companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new requirements also will allow companies to disclose their probable and possible reserves to investors. The new disclosure requirements also require companies to report the independence and qualifications of a reserves preparer or auditor. We will adopt the provisions of the final rule in connection with our December 31, 2009 Form 10-K filing. We are currently evaluating the impact of the final rule.

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

Critical Accounting Policies

Gas and Oil Activities

We follow the successful efforts method of accounting for our gas and oil 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 gas and oil 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. Revenues associated with gas and oil 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. 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.

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Gas and Oil Reserves

Engineering estimates of our gas and oil 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 gas and oil 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 gas and oil 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 gas or oil 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 gas and oil 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.” 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.”

See notes 1 and 10 in the notes to the consolidated financial statements for information on the adoption of SFAS No. 123R, “Share-Based Payment.”

_____________________________________________________________________________________

ITEM 7A. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

_____________________________________________________________________________________

Price Risk

Realized pricing for our oil production in the United States and Poland 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 is expected to continue in the foreseeable future.

Substantially all of 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, Zaniemysl, and Kleka wells, are tied to published tariffs. The tariffs are set from time to time by the public utility regulator in Poland. Although we are not directly subject to such tariffs, we have elected to link our price to these tariffs in our contracts with POGC. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in an unregulated setting and may be lower than prevailing western European prices. We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.

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We currently do not engage in any hedging activities to protect ourselves against market risks associated with gas and oil price fluctuations, although we may elect to do in the future.

Foreign Currency Risk

We enter into various agreements in Poland denominated in the Polish zloty. The Polish zloty is subject to exchange rate fluctuations that are beyond our control. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues.

During the past 12 months, the zloty has fluctuated between a low of 2.02 zlotys per U.S. dollar in August of 2008 to a high of 3.88 zlotys per dollar in late February of 2009. We have historically used the U.S. dollar as our functional currency for U.S. financial reporting purposes. We record receivables and payables at fixed amounts in U.S. dollars on their respective transaction dates; when the receivables and payables are subsequently settled at different exchange rates, we recognize foreign currency gains or losses in our statements of operations. In addition, variations in exchange rates also affect the U.S. dollar denominated amount of revenue we receive in Polish zlotys. As the U.S. dollar strengthens, our U.S. dollar denominated revenue received in Polish zlotys declines; conversely, when the U.S. dollar weakens, our U.S. dollar denominated revenue received in Polish zlotys increases. Should exchange rates in effect during early 2009 continue throughout the year, we expect the exchange rates to have a negative impact on our U.S. dollar denominated revenues.

At the same time, however, our U.S. denominated costs of conducting business in Poland, which includes drilling, geological and geophysical, and overhead costs, will also decline at the same rate. We are also generating revenues in Poland in Polish zlotys, and we keep those zlotys in Poland and use them to pay zloty-based invoices. In terms of actual zloty purchasing power, our gas prices are in fact 25% higher today than they were earlier this year, due to the two price increases discussed earlier.

During October 2008, we drew down the remaining $14 million available under our Senior Credit Facility to ensure that we had the necessary capital on hand to meet existing commitments. At the same time, we purchased approximately $14.7 million in Polish zloty forward contracts. These contracts matured at the end of each month, beginning in October 2008 and concluding in March 2009. The rate of the contract was 2.5 zlotys per U.S. dollar, which, at the time, was a 52-week low for the zloty. As of year-end 2008, we had three outstanding contracts denominated in U.S. dollars as follows: $2.5 million that matured January 30, 2009; $2.1 million that matured February 27, 2009; $1.1 million that matures March 31, 2009. In connection with these outstanding contracts, we recorded an additional loss of $888,000 when we marked them to market at December 31, 2008, when the exchange rate was 2.9 zlotys per U.S. dollar.

_____________________________________________________________________________________

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.

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_____________________________________________________________________________________

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

_____________________________________________________________________________________

During the year ended December 31, 2008, 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 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, 2008, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2008, 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 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.

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PART III

_____________________________________________________________________________________

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

_____________________________________________________________________________________

The information from the definitive proxy statement for the 2009 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 2009 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 2009 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 2009 annual meeting of stockholders under the captions “Certain Relationships and Related Party Transactions” and “Director Independence” is incorporated herein by reference.

_____________________________________________________________________________________

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

_____________________________________________________________________________________

The information from the definitive proxy statement for the 2009 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.

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PART IV

_____________________________________________________________________________________

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

_____________________________________________________________________________________

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

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

	Page
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, 2008 and 2007	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006	F-6
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2008, 2007 and 2006	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	F-8
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2008, 2007 and 2006	F-9
Notes to the Consolidated Financial Statements	F-10

2. 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.

3. 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, as amended January 2, 2008	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2007, filed March 10, 2008.
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.
3.04	Amendment to Articles of Incorporation Revising and Restating Designation of Rights, Privileges, and Preferences of Series A Preferred Stock	Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.

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Exhibit Number*	Title of Document	Location
Item 4	Instruments Defining the Rights of Security Holders
4.01	Specimen Stock Certificate	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
4.04	Rights Agreement dated as of April 4, 2007, between FX Energy, Inc. and Fidelity Transfer Corp.	Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.
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.
10.52	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.

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Exhibit Number*	Title of Document	Location
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**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.

50

Exhibit Number*	Title of Document	Location
10.79	Change in Control Compensation Agreement with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
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	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.84	Common Stock Purchase Warrant dated November 17, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.85	Agreement for Pledges over Shares in FX Energy Poland Sp. z o.o., dated December 18, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.86	Subordination Deed dated December 21, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.87	Restated FX Energy, Inc. 401(k) Stock Bonus Plan dated January 25, 2007**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.88	Agreement for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Mazowiecka Spolka Gazownictwa Sp. z o.o., dated December 29, 2005	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
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	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
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	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.91	Form of Stock Purchase Agreement	Incorporated by reference from the current report on Form 8-K filed July 5, 2007.

51

Exhibit Number*	Title of Document	Location
10.92	Exhibit 10.92, Amendment and Reconfirmation of Supplemental Indemnification Agreement between FX Energy, Inc. and Dennis B. Goldstein	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, 2007, filed March 10, 2008.
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.

52

_____________________________________________________________________________________

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 13, 2009	By:	/s/ David N. Pierce
		David N. Pierce
		President and Chief Executive Officer
Dated: March 13, 2009	By:	/s/ Clay Newton
		Clay Newton
		Principal Financial Officer

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

	/s/ Thomas B. Lovejoy
Dated: March 13, 2009	Thomas B. Lovejoy, Director
	/s/ David N. Pierce
Dated: March 13, 2009	David N. Pierce, Director
	/s/ Dennis B. Goldstein
Dated: March 13, 2009	Dennis B. Goldstein, Director
	/s/ Arnold S. Grundvig, Jr.
Dated: March 13, 2009	Arnold S. Grundvig, Jr., Director
	/s/ Jerzy B. Maciolek
Dated: March 13, 2009	Jerzy B. Maciolek, Director
	/s/ Richard Hardman
Dated: March 13, 2009	Richard Hardman, Director
	/s/ H. Allen Turner
Dated: March 13, 2009	H. Allen Turner, Director

53

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 by 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 2008 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, 2008, 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.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, independent registered public accounting firm, as stated in its report appearing on pages F-2 and F-3.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

 of FX Energy, Inc. and its subsidiaries

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of 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 at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide 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.

F-2

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 13, 2009

F-3

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

As of December 31, 2008 and 2007

(in thousands)

	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	16,588	$	4,262)
Marketable securities		4,105		15,202
Receivables:
Accrued oil and gas sales		1,093		1,906
Other receivables		1,720		805
Input VAT receivable		2,514		446
Inventory		211		178
Other current assets		450		365
Total current assets		26,681		23,164
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		28,600		23,491
Unproved		2,770		2,001
Other property and equipment		6,667		5,590
Gross property and equipment		38,037		31,082
Less accumulated depreciation, depletion and amortization		(11,164)		(9,197)
Net property and equipment		26,873		21,885
Other assets:
Certificates of deposit		406		406
Loan fees		842		914
Total other assets		1,248		1,320
Total assets	$	54,802	$	46,369

-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, 2008 and 2007

(in thousands, except share data)

-Continued-

	2008		2007
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	7,779	$	4,432
Accrued liabilities		4,937		3,358
Total current liabilities		12,716		7,790
Long-term liabilities:
Notes payable		25,000		--
Asset retirement obligation		1,932		1,037
Total long-term liabilities		26,932		1,037
Total liabilities		39,648		8,827
Commitments and Contingencies (Note 6)
Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
December 31, 2008 and 2007; no shares outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized as of
December 31, 2008 and 2007; 42,202,878 and 38,196,357 shares issued
and outstanding as of December 31, 2008 and 2007, respectively		42		38
Additional paid-in capital		158,075		142,901
Cumulative translation adjustment		17,137		--
Accumulated other comprehensive loss		--		(1)
Accumulated deficit		(160,100)		(105,396)
Total stockholders’ equity		15,154		37,542
Total liabilities and stockholders’ equity	$	54,802	$	46,369

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, 2008, 2007 and 2006

(in thousands, except per share amounts)

	2008		2007		2006
Revenues:
Oil and gas sales	$	13,494	$	14,903	$	6,533
Oilfield services		4,347		3,093		1,696
Total revenues		17,841		17,996		8,229
Operating costs and expenses:
Lease operating expenses		3,441		3,538		2,647
Exploration costs		15,389		10,624		5,608
Impairment of oil and gas properties		14,746		2,299		3,583
Oilfield services costs		2,751		1,998		1,245
Depreciation, depletion and amortization (DD&A)		1,720		2,064		1,290
Accretion expense		84		78		53
Stock compensation		2,367		2,604		2,759
Bad debt expense		460		--		--
General and administrative costs (G&A)		7,030		7,061		5,728
Total operating costs and expenses		47,988		30,266		22,913
Operating loss		(30,147)		(12,270)		(14,684)
Other income (loss):
Interest income (net of interest expense) and
other income (expense)		(278)		433		795
Foreign exchange gain (loss)		(24,279)		146		122
Total other income (expense)		(24,557)		579		917
Net loss	$	(54,704)	$	(11,691)	$	(13,767)
Basic and diluted net loss per common share	$	(1.35)	$	(0.32)	$	(0.39)
Basic and diluted weighted average number of shares outstanding		40,420		36,694		35,163

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, 2008, 2007 and 2006

(in thousands)

		2008		2007	2006
Net loss	$	(54,704)	$	(11,691)	$	(13,767)
Other comprehensive income (loss)
Foreign currency translation adjustment		13,584		--		--
Increase (decrease) in market value of    marketable securities		1		71		(14)
Comprehensive loss	$	(41,119)	$	(11,620)	$	(13,781)

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, 2008, 2007 and 2006

(in thousands)

		2008		2007		2006
Cash flows from operating activities:
Net loss	$	(54,704)	$	(11,691)	$	(13,767)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization		1,720		2,064		1,290
Impairment of oil and gas properties		14,746		2,299		3,583
Accretion expense		84		78		53
(Gain) loss on property dispositions		(5)		--		--
Stock compensation (G&A)		2,367		2,604		2,759
Foreign exchange losses		22,306		--		--
Common stock issued for services (G&A)		498		242		517
Increase (decrease) from changes in working capital items:
Receivables		(3,056)		(583)		1,451
Inventory		(33)		28		(110)
Other current assets		(85)		(43)		(52)
Other assets		74		(56)		(25)
Accounts payable and accrued liabilities		1,840		3,479		(995)
Asset retirement obligation		--		(2)		(7)
Net cash used in operating activities		(14,248)		(1,581)		(5,303)
Cash flows from investing activities:
Additions to oil and gas properties		(21,808)		(7,517)		(7,521)
Additions to other property and equipment		(1,077)		(966)		(362)
Additions to marketable securities		(186)		(9,610)		(782)
Proceeds from maturities of marketable securities		11,284		4,941		16,800
Proceeds from sale of assets		15		--		--
Net cash provided by (used in) investing activities		(11,772)		(13,152)		8,135
Cash flows from financing activities:
Payment of loan fees		--		--		(578)
Proceeds from issuance of common stock, net of    offering costs		--		12,436		--
Proceeds from loan related to auction rate securities		3,354		--		--
Payments on loan related to auction rate securities		(546)		--		--
Proceeds from notes payable		25,000		--		--
Proceeds from exercise of stock options and warrants		12,313		1,915		--
Net cash provided by (used in) financing activities		40,121		14,351		(578)
Effect of exchange rate changes on cash		(1,775)		--		--
Net increase (decrease) in cash		12,326		(382)		2,254
Cash and cash equivalents at beginning of year		4,262		4,644		2,390
Cash and cash equivalents at end of year	$	16,588	$	4,262	$	4,644

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, 2008, 2007 and 2006

(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, 2005	--	35,097	$	35	$	(2,975)	$	125,216	$	(58)	$	(79,938)	$	42,280
Common stock issued for services    and other	--	464		1		--		706		--		--		707
Elimination of deferred compensation
upon adoption of SFAS No. 123R	--	--		--		2,975		(2,975)		--		--		--
Stock 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
Common stock issued for services    and other	--	463		--		--		242		--		--		242
Exercise of stock options and warrants	--	672		1		--		1,915		--		--		1,916
Issuance of common stock	--	1,500		1		--		12,434		--		--		12,435
Stock compensation	--	--		--		--		2,604		--		--		2,604
Other comprehensive income	--	--		--		--		--		71		--		71
Net loss for year	--	--		--		--		--		--		(11,691)		(11,691)
Balance as of December 31, 2007	--	38,196	$	38	$	--	$	142,901	$	(1)	$	(105,396)	$	37,542
Common stock issued for services    and other	--	488		--		--		498		--		--		498
Exercise of stock options and warrants	--	3,519		4		--		12,309		--		--		12,313
Stock compensation	--	--		--		--		2,367		--		--		2,367
Cumulative translation adjustment due
to change in functional currency at
October 1, 2008	--	--		--		--		--		3,553		--		3,553
Other commprehensive income	--	--		--		--		--		13,585				13,585
Net loss for year	--	--		--		--		--		--		(54,704)		(54,704)
Balance as of December 31, 2008	--	42,203	$	42	$	--	$	158,075	$	17,137	$	(160,100)	$	15,154

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, 2008, the Company owned 100% of the voting common stock or other equity securities of its subsidiaries.

Cash and Cash Equivalents and Marketable Securities

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company determines the appropriate classification of its investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluates such designation at each balance sheet date.

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments, including cash and cash equivalents, marketable securities, accounts receivable, accounts payable and accrued liabilities, approximate fair value because of their generally short maturities.

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, 2008 and 2007. 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 one financial institution in Utah.

Derivative Instruments

Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), requires derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of derivative instruments depends on their intended use and resulting hedge designation. For derivative instruments designated as hedges, the changes in fair value are recorded in the balance sheet as a component of accumulated other comprehensive income. Changes in the fair value of derivative instruments not designated as hedges are recorded in the Consolidated Statements of Operations, generally as a component of interest and other income (expense). At December 31, 2008 and 2007, the Company had no derivative instruments designated as hedges.

F-10

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 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.

Low year-end oil prices resulted in a negative revision to the Company’s oil reserves and their estimated future net revenues in the United States for 2008. As a result of the negative revisions, the net book value of the Company’s domestic oil properties was greater than their estimated future net revenues at December 31, 2008. According to the provision of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets” (“SFAS No. 144”), the Company recorded an impairment of capitalized costs in the amount of $3,773,614 in 2008. The impairment amount was calculated by reducing the net capitalized costs of the U.S. oil properties to their fair value at year-end. The fair value of the properties was equal to their remaining estimated discounted future net cash flows.

During 2008, the Company impaired the costs of the Grundy-1 and Sroda-6 wells. According to the provisions of FASB Staff Position No. 19-1, “Accounting for Suspended Well Costs” (“FSP No. 19-1”), capitalized costs of exploratory wells are required to be expensed if the enterprise is not making sufficient progress assessing the reserves and economic viability of the project. Under current economic conditions, the Company does not have firm plans to further develop these two wells. Accordingly, the Company has recorded an impairment charge of $7,219,871 associated with the Grundy-1 well and $3,752,122 associated with the Sroda-6 well in 2008.

The Wilga well in Poland began to experience significant water encroachment from one of its three productive zones during the fourth quarter of 2007, and production engineering data suggested that the well might experience a decline in oil and gas production over the course of the succeeding 12-18 months as a result. As a consequence of the water encroachment, the proved reserves at Wilga were reduced at year-end 2007. According to the provisions of SFAS No. 144, the Company recorded an impairment of capitalized costs in the amount of $2,299,534 in 2007. The impairment amount was calculated by reducing the net capitalized costs of the well to its fair value at year-end. The fair value of the well was equal to its remaining estimated discounted future net cash flows.

F-11

The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves, during 2008, 2007 and 2006.

	December 31,
	2008		2007		2006
				(In thousands)
Beginning balance at January 1	$	669	$	2,386	$	3,435
Additions to capitalized exploratory well costs pending
the determination of proved reserves		2,390		669		2,386
Reclassifications to wells, facilities and equipment
based on the determination of proved reserves		--		(2,386)		--
Capitalized exploratory well costs charged to expense		(669)		--		(3,435)
Ending balance at December 31	$	2,390	$	669	$	2,386

The 2008 balance includes drilling costs incurred for the Kromolice-2 well in Poland, which was drilling at the end of the year. The 2007 balance includes equipment costs incurred for the Grundy well in Poland, which began drilling in early 2008. The provisions of FSP No. 19-1 required the costs associated with this well, which included approximately $669,000 at year-end December 31, 2007, to be impaired at December 31, 2008. The 2006 balance includes costs associated with the Winna Gora and Roszkow wells in Poland, which were in process at year-end. Both wells were completed in 2007 as successful gas wells. As a result of its focus in the Sroda area, the Company determined in 2006 to delay assessing the reserves and the economic and operating viability of its Rusocin well in Poland. Pursuant to FSP No. 19-1, costs associated with this well, approximately $3.4 million, were impaired at December 31, 2006.

Other Property and Equipment

Other property and equipment, including oilfield servicing equipment, is stated at cost. Depreciation of other property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 40 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of other property and equipment sold, or otherwise disposed of, and the related accumulated depreciation are removed from the accounts and any gain or loss is reflected in current operations.

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

						Estimated
	December 31,					Useful Life
	2008		2007			(in years)
	(In thousands)
Other property and equipment:
Drilling rigs	$	5,101	$		4,180	6
Other vehicles		309			320	5
Building		108			108	40
Office equipment and furniture		1,149			982	3 to 6
Total cost		6,667		5,590
Accumulated depreciation		(4,663)		(4,250)
Net other property and equipment	$	2,004	$		1,340

F-12

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,
	2008		2007		2006
	(In thousands)
Noncash investing transactions:
Additions to properties included in current liabilities	$	1,892	$	428	$	2,359

	Year Ended December 31,
	2008		2007		2006
	(In thousands)
Cash paid for interest and income taxes:
Cash paid during the year for interest	$	418	$	125	$	--
Cash paid during the year for income taxes		--		--		--

Cash paid for interest in 2008 includes $188,715 in commitment fees on the Company’s Senior Facility Agreement. Cash paid for interest in 2007 includes $119,040 in commitment fees paid on the Company’s Senior Facility Agreement.

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.

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 Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“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 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 Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”).

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.

F-13

The Company adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109,” (“FIN 48”), effective January 1, 2007. The Company did not have any unrecognized tax benefits, and there was no effect on its financial condition or results of operations as a result of implementing FIN 48. The Company did not have any unrecognized tax benefits at December 31, 2008. The Company is subject to audit by the IRS and various states for the prior three years. The Company does not believe there will be any material changes in its unrecognized tax positions over the next 12 months. The Company’s policy is that it recognizes interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any tax-related interest expense recognized during the year ended December 31, 2008.

New Accounting Standards

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Non-controlling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No. 160”). This statement improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS No. 160 affects those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The adoption of this statement is not expected to have any effect on the Company’s financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No. 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS No. 161 applies to all derivative instruments within the scope of SFAS No. 133, as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. SFAS No. 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of this statement is not expected to have a material effect on the Company’s financial statements.

In October 2008, Financial Accounting Standards Board issued FASB Staff Position 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP No. 157-3”), to clarify guidance on determining the fair value of a financial asset under Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”), in a market that is not active. FSP No. 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The adoption of this statement was effective October 1, 2008, and did not have a material impact on the Company’s financial position or results of operations.

In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which is effective January 1, 2010, for reporting 2009 reserve information. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure requirements also require companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior twelve-month period rather than year-end prices. The new requirements also will allow companies to disclose their probable and possible reserves to investors. The new disclosure requirements also require companies to report the independence and qualifications of a reserves preparer or auditor. The Company will adopt the provisions of the final rule in connection with its December 31, 2009 Form 10-K filing. The Company is currently evaluating the impact of the final rule.

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.

F-14

Foreign Operations

Effective October 1, 2008, the Company changed the functional currency of its Polish subsidiary from the U.S. dollar to the Polish zloty.  During the fourth quarter of 2008, for the first time, the Company entered into forward zloty purchase contracts.  In early 2009, the Company entered into construction and revenue agreements that would recognize the results of increasingly significant levels of production and corresponding revenues in Polish zloty.  In recognition of these economic events combined with the resulting increases in future zloty revenues and expenditures of the Polish entity, the Company determined that it was appropriate to change the functional currency of FX Energy Poland to the Polish zloty.

Financial Accounting Statement No. 52 “Foreign Currency Translation,” requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation.  Because FX Energy Poland's functional currency is now the Polish zloty, translation adjustments will result from the process of translating its financial statements into the U.S. dollar reporting currency. Translation adjustments will not be included in determining net income but shall be reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities affected by the change are adjusted to reflect the difference between the exchange rate when the asset or liability arose and the exchange rate on the date of the change.  Upon the change in functional currency, the Company recorded a cumulative translation adjustment (“CTA”) of approximately $3.3 million, which is shown in the consolidated statement of stockholders' equity (deficit).  Because of the change in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.  At December 31, 2008, the CTA was approximately $17.1 million reflecting the impact of exchange rate fluctuations.

The change in functional currency will also affect the amounts the Company reports for its Polish assets, liabilities, revenues and expenses from those that would be reported had it maintained the U.S. dollar as the functional currency for its Polish operations. The differences will depend on changes in period-average and period-end exchange rates. During the fourth quarter of 2008, the Company recorded foreign currency transaction losses of approximately $24.3 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.  Future transaction gains or losses may be significant given the amount of intercompany loans and the volatility of the exchange rate.

The change in functional currency will have no impact on the Company's actual zloty-based revenues and expenditures in Poland.

Use of Estimates

The preparation of the consolidated 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 revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of derivative instruments, future development and abandonment costs, estimates to certain oil and gas revenues and expenses, and estimates of proved oil and natural gas reserve quantities used to calculate depletion, depreciation and impairment of proved oil and natural gas properties and equipment.

Net Loss per Share

Basic earnings per share are 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.

F-15

Outstanding options, warrants and unvested restricted stock as of December 31, 2008, 2007 and 2006, were as follows:

	Options, Warrants and Unvested Restricted Stock	Price Range
Balance sheet date:
December 31, 2008	2,694,862	$0.00 - $10.65
December 31, 2007	6,320,602	$0.00 - $10.65
December 31, 2006	6,859,106	$0.00 - $10.65

The Company had a net loss in 2008, 2007 and 2006. 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.

Reclassifications

Certain amounts in the 2007 and 2006 Consolidated Statements of Operations have been reclassified to conform to current year presentation. There was no change on previously reported net income.

Note 2: Asset Retirement Obligation

The Company accounts for future site restoration costs according to Statement of Financial Accounting Standards 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 $83,739, $78,087 and $53,038 in 2008, 2007 and 2006, respectively. At December 31, 2008, 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, 2008 and 2007:

	December 31,
	2008		2007
	(In thousands)
Asset retirement obligations:
Beginning balance	$	1,037	$	961
Current year revisions		811		--
Liabilities settled		--		(2)
Accretion expense		84		78
Ending balance	$	1,932	$	1,037

At year-end 2008, the economic life of the Company’s oil reserves in Montana was shortened considerably due to low year-end oil prices. Accordingly, the Company increased the asset retirement obligation to reflect the shortened time period before plugging costs might be incurred.

Note 3: Other Assets

As of December 31, 2008, the Company had replacement bonds with federal and state agencies in the face amount of $731,500, which were collateralized by certificates of deposit totaling $381,500. In addition, there are certificates of deposit totaling $25,000 covering performance bonds in other states. The bond face amount at December 31, 2007, was $463,000.

F-16

Note 4: Accrued Liabilities

The Company’s accrued liabilities as of December 31, 2008 and 2007, were comprised of the following:

	December 31,
	2008		2007
	(In thousands)
Accrued liabilities:
Credit facility commitment fees	$	2	$	78
Partner share of oil & gas revenue and joint operating costs		356		1,737
Compensation-related costs		841		1,543
Interest expense		42		--
Foreign currency derivative contracts		888		--
UBS loan related to auction-rate securities (Note 7)		2,808		--
Total	$	4,937	$	3,358

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. At December 31, 2008, the Company had drawn the full $25 million available under the Facility.

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 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 are being amortized over the six-year term of the loan, beginning in 2007. An annual unused commitment fee of one-half of the applicable margin is charged quarterly based on the average daily unused portion of the Facility.

The following table provides a summary of changes in notes payable (in thousands):

	For the Year Ended  December 31, 2008
Balance at January 1, 2008	$         --
Proceeds from borrowings	25,000
Balance at December 31, 2008	$ 25,000

Interest on borrowed funds is accrued at LIBOR plus 1.25%. The average interest rate on the outstanding balance at December 31, 2008, was 2.87% per annum. The Facility is an interest-only facility until December 31, 2010, on which date the Facility’s principal amount is currently scheduled to be reduced to $20 million. The carrying value of the long term debt at December 31, 2008 approximately its fair value.

The borrowing base is redetermined at the beginning of each year based on reserve volumes and values estimated by independent engineers as of the last day of the prior year. As the Company increased both its reserve volumes and values from year-end 2007 to year-end 2008, it does not anticipate any reductions in its borrowing base amount.

F-17

Note 6: Commitments and Contingencies

In November and December 2007, three actions were filed in the United States District Court for the District of Utah against the Company and its officers or directors David N. Pierce, Clay Newton, Thomas B. Lovejoy, Andrew W. Pierce, and Richard Hardman, by three separate plaintiffs, each seeking class certification to proceed on behalf of all others similarly situated and alleging violations by the defendants of the antifraud provisions of the federal securities laws set forth in Section 10(b) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder relating to the Company’s public statements about its oil and gas activities and prospects in Poland between March 2004 and January 2006. The complaints seek damages to be determined at trial, interest, and costs, together with such other relief as the court may deem appropriate. The three actions have now been consolidated into a single matter, In re FX Energy, Inc., Securities Litigation, United States District Court for the District of Utah, case no. 2:07-cv-00874, and the lead plaintiffs and counsel have been specified. The consolidated actions have not been certified to proceed as a class action.

A consolidated complaint has been filed by the lead plaintiff that alleges that the defendants violated the antifraud provisions of Section 10(b) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder by making material misrepresentations and omissions regarding the Company’s Sroda-5 and Lugi-1 projects between January 20, 2005, and January 5, 2006. The consolidated complaint seeks damages to be determined at trial, interest, costs and such other relief as the court may deem appropriate. On June 20, 2008, the Company filed a motion to dismiss, with a supporting memorandum, for failure to state a claim upon which relief can be granted. Plaintiffs filed an opposition to the defendants’ motion on August 19, 2008, to which defendants filed a reply on October 3, 2008. Following a hearing on February 23, 2009, on defendants’ motion to dismiss, the matter is under advisement by the court. The Company intends to defend vigorously this consolidated action on behalf of all defendants.

Another pending action filed in the United States District Court for the District of Utah entitled Leilani York, derivatively on behalf of nominal defendant FX Energy, Inc., plaintiff, v. David N. Pierce, Dennis B. Goldstein, Arnold S. Grundvig, Jr., Richard Hardman, Tom Lovejoy, Jerzy Maciolek, Clay Newton, Andrew W. Pierce, and David Worrell, defendants, and FX Energy, Inc., nominal defendant, case no. 2:08-cv-00143, which asserts derivative claims on the Company’s behalf against certain of its current and former directors and certain of its current and former executive officers, arising from the same set of facts, has been stayed pending final resolution of the In re FX Energy, Inc., Securities Litigation.

Note7: Fair Value Measurements and Marketable Securities

Fair Value Measurements

Effective January 1, 2008, the Company partially adopted SFAS No. 157, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). This statement establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. FASB Staff Position No. 157-2, “Effective Date of FASB Statement No. 157,” delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities measured on a nonrecurring basis. The Company is currently evaluating the impact of implementation with respect to nonfinancial assets and liabilities measured on a nonrecurring basis on the consolidated financial statements, which will be primarily limited to asset retirement obligations.

Fair Value Hierarchy

In accordance with SFAS No. 157, the Company has categorized its cash and cash equivalents, marketable securities, and foreign currency contracts based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

F-18

Financial assets recorded on the Consolidated Balance Sheets are categorized based on the inputs to the valuation techniques as follows:

Level1.  Financial assets whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that the Company has the ability to access.

Level2.  Financial assets whose values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Level 2 inputs include the following:

(a) quoted prices for similar assets in active markets;

(b) quoted prices for identical or similar assets in non-active markets;

(c) pricing models whose inputs are observable for substantially the full term of the asset; and

(d) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

Level3.  Financial assets whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. During the first quarter of 2008, certain assets were classified as Level 3 assets. This classification primarily relates to investments in auction-rate securities.

Recurring Fair Value

As required by SFAS No. 157, the Company’s assessment of the significance of a particular input to fair value requires judgment and may affect the fair value of assets and their placement within the fair value hierarchy.

The following table presents the Company’s fair value hierarchy for those assets and liabilities measured at fair value on a recurring basis as of December 31, 2008 (in thousands):

	December 31,
	2008	Level 1(1)	Level 2(2)	Level 3(3)
Assets:
Cash equivalents:
Money market funds	$  1,122	$  1,122
Treasury bills	1,400	1,400
Treasury bill funds	8,907	8,907
Marketable securities:
Auction-rate securities	4,105			$ 4,105
Auction-rate securities “put” rights	545			545
Liabilities:
Foreign currency derivative contracts	$     888	$     888

_______________

(1) Quoted prices in active markets for identical assets.

(2) Significant other observable inputs.

(3) Significant unobservable inputs.

F-19

Level 3 assets include $4,105,000 of auction-rate securities and $545,000 related to certain “put” rights associated with the auction-rate securities. The receivable for the “put” rights is included in other receivables as of December 31, 2008.

The following table provides a summary of changes in fair value of the Company’s Level 3 marketable securities (in thousands):

	For the Year Ended
	December 31, 2008
Balance at January 1, 2008	$ 9,700
Transfers in	545
Purchases, issuances and settlements	(5,596)
Unrealized gains included in other comprehensive income	1
Balance at December 31, 2008	$ 4,650

Marketable Securities

Marketable securities on the Consolidated Balance Sheets include investments held by the Company that are classified in accordance with the provisions of Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The marketable securities have historically been classified as available-for-sale. The Company’s marketable securities as of December 31, 2008, included $4,104,711 of auction-rate securities at their fair market value.

In August of 2008, UBS Financial Services (“UBS”), the Company’s financial advisor, announced a settlement plan to restore liquidity to its clients holding auction-rate securities. According to the terms of the settlement agreement, the Company has the ability to borrow from UBS up to 75% of the par value of its auction-rate securities at an interest rate that is equivalent to the yield of the underlying securities. As of December 31, 2008, the Company had borrowed a total of $2,808,000 from UBS, using certain auction-rate securities as collateral. These loans are included in accrued liabilities on the balance sheet. As individual auction-rate securities are redeemed by their issuers, the proceeds from those redemptions will be used to reduce the loans.

As part of the settlement, the Company also received certain “put” rights, which enable the Company to require UBS to purchase, at par value plus accrued interest, all of the auction-rate securities at fixed, future dates. As of December 31, 2008, the Company had certain auction-rate securities with a market value of $2,535,000 that are eligible to be “put” to UBS on January 2, 2009, and certain other auction-rate securities with a market value of $1,570,000 that are eligible to be “put” to UBS on June 30, 2010. Subsequent to December 31, 2008, auction-rate securities valued at $2,535,000 on December 31, 2008, with a put date of January 2, 2009, were redeemed at their full par value of $3,000,000. The proceeds from the redemption were used to satisfy a loan relating to those securities at December 31, 2008, of $1,944,000.

In February of 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115” (“SFAS No. 159”). This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.

The Company has elected to use the provisions of SFAS No. 159 to determine a fair value for the UBS “put” rights. The Company has determined the value of the “put” rights to be $545,000, which is the difference between the par value and the fair value of the auction-rate securities. This amount has been recorded as a current receivable on the balance sheet, with a corresponding gain of $545,000 recorded as other income in the statement of operations.

In order to record the receivable associated with the “put” rights, the Company also changed the classification of its marketable securities from ‘available-for-sale’ to ‘trading’ securities. This change resulted in a loss of $545,000 associated with transferring the historical temporary losses related to auction-rate securities from other comprehensive income (loss) to earnings. The loss is recorded as other expense in the statement of operations. There was no cash impact on the Company’s balance sheet or statements of operations and cash flow associated with the gain and loss that resulted from these transactions.

F-20

Liabilities

At December 31, 2008, the Company had three outstanding zloty forward purchase contracts denominated in U.S. dollars as follows: $2,500,000 that matured January 30, 2009; $2,100,000 that matured February 27, 2009; and $1,100,000 that matures March 31, 2009. The exchange rate for each contract is 2.50 zlotys per U.S. dollar. In connection with these outstanding contracts, the Company recorded a foreign exchange loss of $887,599 when the contracts were marked to market at December 31, 2008, using the year-end exchange rate of 2.96 zlotys per U.S. dollar.

Note 8: Income Taxes

The Company recognized no income tax benefit from the losses generated during 2008, 2007 and 2006. The components of the net deferred tax asset as of December 31, 2008 and 2007, are as follows:

	December 31,
	2008		2007
	(In thousands)
Deferred tax liability:
Property and equipment basis differences	$	(288)	$	(2,388)
Deferred tax asset:
Net operating loss carryforwards:
United States		27,795		25,615
Poland		5,607		9,252
Oil and gas properties		6,806		2,713
Foreign exchange translation losses		8,320		--
Options issued for services		1,256		1,359
Asset retirement obligation		721		387
Valuation allowance		(50,217)		(36,938)
Total	$	--	$	--

The change in the valuation allowance during 2008, 2007 and 2006 is as follows:

		Year Ended December 31,
		2008		2007		2006
		(In thousands)
Valuation allowance:
Balance, beginning of year	$	(36,938)	$	(32,028)	$	(24,887)
Change in property and equipment basis differences		(6,193)		(1,249)		2,511
Increase due to foreign exchange translation loss		(8,320)		--		--
Decrease (Increase) due to net operating loss		1,465		(2,179)		(8,875)
Other		(231)		(1,482)		(777)
Total	$	(50,217)	$	(36,938)	$	(32,028)

Statement of Financial Accounting Standards 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, 2008, 2007 and 2006. Due to the full valuation allowance, the Company’s effective income tax rate for all three years was zero percent.

F-21

United States NOL

At December 31, 2008, the Company had net operating loss (“NOL”) carryforwards in the United States of approximately $74,518,000 available to offset future taxable income. The carryforwards begin to expire in 2009 and will fully expire  in 2028.  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 $19,664,000 relating to tax deductions resulting from the exercise of stock options. The tax benefit from adjusting the valuation allowance related to this portion of the NOL carryforward will be credited to additional paid-in capital.

Polish NOL

As of December 31, 2008, the Company had NOL carryforwards in Poland totaling approximately $29,512,000. The NOLs began to expire in 2008 and will fully expire in 2013. 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 following table lists the years of expiration for the Company’s net operating losses:

	United States	Poland
	(In thousands)
Year of NOL expiration:
2009	$  1,052	$  4,644
2010	3,565	6,755
2011	8,368	10,612
2012	4,995	--
2013 and thereafter	56,538	7,501

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

	Year Ended December 31,
	2008	2007	2006
	(In thousands)
Domestic	$  (11,230)	$   (6,078)	$   (6,764)
Foreign	(24,922)	(5,613)	(7,003)
Total	$  (36,152)	$ (11,691)	$ (13,767)

Note 9: Stockholders’ Equity

The Company received proceeds from the exercise of 3,648,369 stock options and warrants of $12,312,649 during 2008.

During 2007, the Company sold 1.5 million shares of stock in a registered direct offering, resulting in net proceeds to the Company of $12,434,475. In addition, 672,165 options and warrants were exercised during the year, resulting in proceeds to the Company of an additional $1,914,598.

Note 10: Stock Options, Warrants and Restricted Stock

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-22

The following table summarizes information regarding the Company’s stock option and award plans as of December 31, 2008:

		Weighted	Number of
	Number	Average	Options
	of Shares	Exercise Price of	Available for
	Authorized	Outstanding	Future
	Under Plan	Options	Issuance
Equity compensation plans approved by stockholders:
1995 Stock Option and Award Plan	500,000	$7.49	--
1996 Stock Option and Award Plan	500,000	3.55	--
1997 Stock Option and Award Plan	500,000	5.87	--
1998 Stock Option and Award Plan	500,000	5.63	--
1999 Stock Option and Award Plan	500,000	8.37	78
2000 Stock Option and Award Plan	600,000	2.61	958
2001 Stock Option and Award Plan	600,000	3.22	1,891
2003 Long Term Incentive Plan	800,000	6.64	9,484
2004 Long Term Incentive Plan	1,000,000	8.43	214,330
Total	5,500,000	$5.65	226,741

All stock option and award plans are administered by the Compensation Committee (the “Committee”), consisting of the independent 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 2008, 2007 and 2006:

	2008		2007		2006
		Weighted		Weighted		Weighted
	Number	Average	Number	Average	Number	Average
	of	Exercise	of	Exercise	of	Exercise
	Options	Price	Options	Price	Options	Price
Options outstanding:
Beginning of year	2,315,441	$5.19	2,836,833	$5.08	3,193,333	$5.16
Granted	--	--	--	--	--	--
Exercised	(335,000)	2.44	(466,726)	4.13	--	--
Cancelled	--	0.00	(54,666)	8.42	--	--
Expired	--	--	--	--	(356,500)	5.82
End of year	1,980,441	$5.65	2,315,441	$5.19	2,836,833	$5.08
Exercisable at year-end	1,980,441	$5.65	2,303,776	$5.16	2,497,177	$4.61

In 2008, the Company recognized $15,508 in expense related to unvested stock options granted prior to the adoption of SFAS No. 123R. There was no unamortized expense related to unvested options at December 31, 2008. All options outstanding at December 31, 2008, are fully vested.

During 2008, the Company issued 367,000 shares of restricted stock resulting in deferred compensation of $1,005,580, which will be amortized ratably over the three-year vesting period. Expense recognized during 2008 totaled $9,184.

During 2007, the Company issued 370,925 shares of restricted stock resulting in deferred compensation of $2,284,991, which will be amortized ratably over the three-year vesting period. Expense recognized for these shares during 2008 and 2007 totaled $761,805 and $52,088, respectively.

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 for these shares during 2008, 2007 and 2006 totaled $684,608, $684,557 and $18,756, respectively.

F-23

In November of 2005, the Company issued 298,950 shares of restricted stock resulting in deferred compensation of $3,096,600, which will be amortized ratably over the three-year vesting period. Expense recognized for these shares during 2008, 2007 and 2006 totaled $895,805, $1,024,862 and $1,028,633, respectively.

The following table summarizes information about stock options outstanding as of December 31, 2008:

	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 - $2.40	435,000	.62	2.40	435,000	2.40
$3.14 - $3.20	51,000	1.69	3.19	51,000	3.19
$3.98 - $3.98	587,109	1.82	3.98	587,109	3.98
$6.06 - $6.06	4,167	2.07	6.06	4,167	6.06
$8.37 - $8.37	843,165	2.67	8.37	843,165	8.37
$9.00 - $10.65	60,000	2.86	9.52	60,000	9.52
Total	1,980,441	1.95	$5.65	1,980,441	$5.65

The aggregate intrinsic value of outstanding stock options at December 31, 2008, was $169,650. The aggregate intrinsic value of unvested restricted stock at December 31, 2008, was $1,993,235. The aggregate intrinsic value represents the total pretax intrinsic value, based on the Company’s stock price of $2.79 as of December 31, 2008, 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 vested or exercised as of that date.

Restricted Stock

The following table summarizes restricted stock activity during 2008, 2007 and 2006:

	2008	2007	2006
	Number of Shares	Number of Shares	Number of Shares
Unvested restricted stock outstanding:
Beginning of year	679,788	516,900	298,950
Issued	367,000	370,925	318,400
Forfeited	(8,690)	(4,020)	(1,200)
Vested	(323,677)	(204,017)	(99,250)
End of year	714,421	679,788	516,900

Warrants

The following table summarizes warrant activity during 2008, 2007 and 2006:

	2008		2007		2006
	Number of Shares	Price Range	Number of Shares	Price Range	Number of Shares	Price Range
Warrants outstanding and exercisable:
Beginning of year	3,325,373	$3.60--$6.00	3,615,373	$3.60--$6.00	3,505,373	$3.60--$3.75
Issued	--	--	--	--	110,000	$6.00
Exercised	(3,215,373)	$3.66	(290,000)	$3.60	--	--
Expired	(110,000)	$6.00
End of year	--		3,325,373	$3.60--$6.00	3,615,373	$3.60--$6.00

F-24

Note 11: Business Segments

The Company operates within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. The Company’s revenues associated with its E&P activities are comprised of oil sales from its producing properties in the United States and oil and gas sales from its producing properties in Poland. Over 90% of the Company’s oil sales in the United States were to Cenex during 2008, 2007 and 2006. During 2008, 2007 and 2006 all sales of oil and gas in Poland were made to POGC or its affiliated companies. 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 that 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.

Information on the Company’s operations by business segment for 2008, 2007 and 2006 is summarized as follows:

	2008
	Exploration & Production				Oilfield		Total
	U.S.		Poland		Services		(In thousands)
Operations summary:
Revenues	$	5,695	$	7,799	$	4,347	$	17,841
Lease operating expense		(2,548)		(893)		--		(3,441)
Oilfield services costs		--		--		(2,751)		(2,751)
Exploration expense		(464)		(14,925)		--		(15,389)
Impairment expense		(3,774)		(10,972)		--		(14,746)
Accretion expense		(56)		(28)		--		(84)
Bad debt expense		--		--		(460)		(460)
DD&A expense		(700)		(529)		(411)		(1,640)
Operating income (loss)	$	(1,847)	$	(19,548)	$	725	$	(20,670)
Identifiable net property and equipment:
Unproved properties	$	20	$	2,750	$	--	$	2,770
Proved properties		261		21,839		--		22,100
Equipment and other		--		101		1,772		1,873
Total	$	281	$	24,690	$	1,772	$	26,743
Net Capital Expenditures:
Property and equipment	$	1,828	$	22,811	$	1,020	$	25,659
Total	$	1,828	$	22,811	$	1,020	$	25,659

F-25

	2007
	Exploration & Production				Oilfield		Total
	U.S.		Poland		Services		(In thousands)
Operations summary:
Revenues	$	4,336	$	10,567	$	3,093	$	17,996
Lease operating expense		(2,390)		(1,148)		--		(3,538)
Oilfield services costs		--		--		(1,998)		(1,998)
Exploration expense		(52)		(10,572)		--		(10,624)
Impairment expense		--		(2,299)		--		(2,299)
Accretion expense		(50)		(28)		--		(78)
DD&A expense		(742)		(935)		(267)		(1,944)
Operating income (loss)	$	1,102	$	(4,415)	$	828	$	(2,485)
Identifiable net property and equipment:
Unproved properties	$	61	$	1,940	$	--	$	2,001
Proved properties		3,167		15,377		--		18,544
Equipment and other		--		--		1,178		1,178
Total	$	3,228	$	17,317	$	1,178	$	21,723
Net Capital Expenditures:
Property and equipment	$	494	$	5,092	$	893	$	6,479
Total	$	494	$	5,092	$	893	$	6,479

	2006
	Exploration & Production				Oilfield		Total
	U.S.		Poland		Services		(In thousands)
Operations summary:
Revenues	$	4,260	$	2,273	$	1,696	$	8,229
Lease operating expense		(2,358)		(289)		--		(2,647)
Oilfield services costs		--		--		(1,245)		(1,245)
Exploration expense		(739)		(4,869)		--		(5,608)
Impairment expense		--		(3,583)		--		(3,583)
Accretion expense		(46)		(7)		--		(53)
DD&A expense		(654)		(304)		(155)		(1,113)
Operating income (loss)	$	463	$	(6,779)	$	296	$	(6,020)
Identifiable net property and equipment:
Unproved properties	$	--	$	2,912	$	--	$	2,912
Proved properties		3,124		12,898		--		16,022
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

F-26

A reconciliation of the segment information to the consolidated totals for 2008, 2007 and 2006 follows:

	2008		2007		2006
	(In thousands)
Revenues:
Reportable segments	$	17,841	$	17,996	$	8,229
Non-reportable segments		--		--		--
Total revenues	$	17,841	$	17,996	$	8,229
Net loss:
Operating loss, reportable segments	$	(20,669)	$	(2,485)	$	(6,020)
Expense or (revenue) adjustments:
Corporate DD&A expense		(81)		(120)		(177)
General and administrative costs (G&A)		(7,030)		(7,061)		(5,728)
Amortization of deferred compensation (G&A)		(2,367)		(2,604)		(2,759)
Total net operating loss		(30,147)		(12,270)		(14,684)
Non-operating income:
Interest income (net of interest expense) and other income		(278)		433		795
Foreign exchange gain (loss)		(24,279)		146		122
Net loss	$	(54,704)	$	(11,691)	$	(13,767)
Net property and equipment:
Reportable segments	$	26,743	$	21,723	$	19,490
Corporate assets		130		162		205
Net property and equipment	$	26,873	$	21,885	$	19,695
Property and equipment capital expenditures:
Reportable segments	$	25,659	$	6,479	$	9,916
Corporate assets		20		73		59
Total property and equipment capital expenditures	$	25,679	$	6,552	$	9,975

Note 12: Quarterly Financial Data (Unaudited)

Summary quarterly information for 2008 and 2007 is as follows:

		Quarter Ended
		December 31		September 30		June 30		March 31
		(In thousands, except per share amounts)
2008:
Revenues	$	3,325	$	5,096	$	5,195	$	4,225
Net operating loss		(23,002)		(3,602)		(1,564)		(4,315)
Net loss		(45,236)		(3,688)		(1,488)		(4,292)
Basic and diluted net loss per common share	$	(1.09))	$	(0.09)	$	(0.04)	$	(0.11)
2007:
Revenues	$	4,064	$	5,243	$	4,511	$	4,178
Net operating loss		(6,728)		(53)		(2,711)		(2,632)
Net income (loss)		(6,550)		166		(2,682)		(2,625)
Basic and diluted net loss per common share	$	(0.17))	$	(0.00)	$	(0.08)	$	(0.07)

The net operating loss for the fourth quarter of 2008 includes a $7.2 million and $3.8 million impairment loss associated with the Grundy-1 and Sroda-6 wells in Poland and a $3.7 million impairment loss on properties located in Montana. The net loss for 2008 includes a foreign exchange loss of $24.3 million primarily related to FX Energy Poland’s intercompany loans from FX Energy, Inc. The net operating loss for the fourth quarter of 2007 includes a $2.3 million impairment loss associated with the Wilga well in Poland.

F-27

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, 2008 and 2007, are summarized as follows:

		United States		Poland		Total
				(In thousands)
December 31, 2008:
Proved properties	$	3,514	$	25,086	$	28,600
Unproved properties		20		2,750		2,770
Total gross properties		3,534		27,836		31,370
Less accumulated depreciation, depletion and amortization		(3,254)		(3,247)		(6,501)
	$	280	$	24,589	$	24,869
December 31, 2007:
Proved properties	$	5,986	$	17,505	$	23,491
Unproved properties		61		1,940		2,001
Total gross properties		6,047		19,445		25,492
Less accumulated depreciation, depletion and amortization		(2,819)		(2,128)		(4,947)
	$	3,228	$	17,317	$	20,545

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 2008, 2007 and 2006 were $3,440, $3,538 and $2,647, respectively.

Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities during 2008, 2007 and 2006, whether capitalized or expensed, are summarized as follows:

		United States		Poland		Total
				(In thousands)
Year ended December 31, 2008:
Acquisition of unproved properties	$	67	$	1,810	$	1,877
Exploration costs		691		35,436		36,127
Development costs		1,760		126		1,886
Total	$	2,518	$	37,372	$	39,890
Year ended December 31, 2007:
Acquisition of unproved properties	$	61	$	744	$	805
Exploration costs		77		14,884		14,961
Development costs		434		10		444
Total	$	572	$	15,638	$	16,210

F-28

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

(continued)

		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

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):

	2008	2007	2006
Impairment of properties	$14,746	$2,299	$3,583

Exploratory dry hole costs

Total dry hole costs in 2008 included three wells plugged and abandoned in the United States in the amount of $463,744. There were no dry holes drilled in 2007. During 2006, the Company plugged and abandoned the one well in Poland and two wells in Nevada, incurring total dry hole costs of $1,572,749.

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, 2008, of $24.58 per bbl for oil in the United States and $36.56 per bbl of oil and $5.29 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.

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.

F-29

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

(continued)

Proved Developed Reserves:

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)
December 31, 2008	45	47	--	7,873
December 31, 2007	482	14	--	5,288
December 31, 2006	382	202	--	11,382

Total Proved Reserves:

The following unaudited summary of proved developed and undeveloped reserve quantity information represents estimates only and should not be construed as exact:

	Crude Oil		Natural Gas
	United States	Poland	United States	Poland
	(In thousand barrels of oil)		(In millions of cubic feet)
December 31, 2008:
Beginning of year	482	14	--	31,116
Extensions or discoveries (1)	--	--	--	11,295
Revisions of previous estimates (2)	(371)	37	--	4,152
Production	(66)	(4)	--	(1,251)
End of year	45	47	--	45,312
December 31, 2007:
Beginning of year	382	202	--	19,264
Extensions or discoveries (3)	--	--	--	17,939
Revisions of previous estimates (4)	170	(163)	--	(4,247)
Production	(70)	(25)	--	(1,840)
End of year	482	14	--	31,116
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

_______________

(1) Volume increase in Poland attributable to new Kromolice-1 well drilled during 2008.

(2) Positive gas revisions in Poland attributable to Sroda-4 and Zaniemysl-3 wells due to additional technical data acquired during 2008. Negative oil revisions due to lower year-end oil prices in the United States.

(3) Volume increase in Poland attributable to new Roszkow-1 well drilled during 2007.

(4) Negative oil and gas revisions in Poland attributable to Wilga-4 well due to water encroachment. Positive oil revisions due to higher year-end oil prices in the United States.

F-30

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 Statement of Financial Statements 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% 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.

The components of SMOG are detailed below:

		United States		Poland		Total
				(In thousands)
December 31, 2008:
Future cash flows	$	1,103	$	239,220	$	240,323
Future production costs		(510)		(14,310)		(14,820)
Future development costs		--		(16,720)		(16,720)
Future income tax expense		--		(29,270)		(29,270)
Future net cash flows		593		178,920		179,513
10% annual discount for estimated timing of cash flows		(275)		(61,670)		(61,945)
Discounted net future cash flows	$	318	$	117,250	$	117,568
December 31, 2007:
Future cash flows	$	39,056	$	179,698	$	218,754
Future production costs		(22,459)		(15,051)		(37,510)
Future development costs		--		(10,029)		(10,029)
Future income tax expense		--		(16,835)		(16,835)
Future net cash flows		16,597		137,783		154,380
10% annual discount for estimated timing of cash flows		(5,130)		(46,282)		(51,412)
Discounted net future cash flows	$	11,467	$	91,501	$	102,968
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

F-31

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

(continued)

The principal sources of changes in SMOG are detailed below:

		Year Ended December 31,
		2008			2007			2006
					(In thousands)
SMOG sources:
	Balance, beginning of year	$	102,968	$		63,757	$		41,915
	Sale of oil and gas produced, net of production costs		(10,053)			(11,364)			(3,886)
	Net changes in prices and production costs		(9,220)			7,866			16,111
	Acquisition of minerals in place		--			--			--
	Extensions and discoveries, net of future costs		27,000			62,343			--
	Changes in estimated future development costs		(4,940)			(5,022)			3,953
	Previously estimated development costs incurred during the year		--			420			580
	Revisions in previous quantity estimates		10,383			(13,561)			(169)
	Accretion of discount		10,297			6,376			4,192
	Net change in income taxes		(7,941)			(8,008)			1,911
	Changes in rates of production and other		(926)			161			(850)
	Balance, end of year	$	117,568	$		102,968	$		63,757

F-32

EX-10.75

Exhibit 10.75

INDEMNIFICATION AGREEMENT

THIS INDEMNIFICATION AGREEMENT (this “Agreement”) is entered into effective as of December 12, 2008, by and between FX ENERGY, INC., a Nevada corporation (the “Corporation”), and [name of indemnitee] (“Indemnitee”), based on the following:

PREMISES

A.         The Restated Articles of Incorporation of the Corporation (the “Articles”) and the Bylaws (the “Bylaws”) provide for indemnification of the Corporation’s directors and officers to the fullest extent permitted by any applicable and controlling Nevada law, statute, rule, decision, or finding (collectively, “Nevada Law”) and contemplate that contracts and other arrangements may be entered into respecting indemnification of officers and directors.

B.         The parties recognize the continued difficulty in obtaining liability insurance for the Corporation’s directors, officers, employees, stockholders, controlling persons, agents, and fiduciaries, the significant increases in the cost of such insurance, and the general reductions in the coverage of such insurance. Furthermore, the parties further recognize the substantial increase in corporate litigation in general, subjecting directors, officers, employees, controlling persons, stockholders, agents, and fiduciaries to expensive litigation risks at the same time as the availability and coverage of liability insurance have been severely limited.

C.         Indemnitee does not regard the current protection available under the Articles, Bylaws, and insurance as adequate under the present circumstances, and Indemnitee and other directors, officers, employees, stockholders, controlling persons, agents, and fiduciaries of the Corporation may not be willing to serve in such capacities without additional protection. Moreover, the Corporation (i) desires to attract and retain the involvement of highly qualified persons, such as Indemnitee, to serve the Corporation and, in part, in order to induce Indemnitee to be involved with the Corporation, (ii) wishes to provide for the indemnification and advancing of expenses to Indemnitee to the maximum extent permitted by law, and (iii) wishes to assure Indemnitee that there will be increased certainty of adequate protection in the future.

D.         In addition to any insurance purchased by the Corporation on behalf of Indemnitee, it is reasonable, prudent, and necessary for the Corporation to obligate itself contractually to indemnify Indemnitee so that he may remain free from undue concern that he will not be adequately protected both during his service as an executive officer and a director of the Corporation and following any termination of such service.

E.         This Agreement is a supplement to and in furtherance of the Articles and Bylaws and shall not be deemed a substitute therefor or to abrogate any rights of Indemnitee thereunder.

F.          The directors of the Corporation have duly approved this Agreement and the indemnification provided herein with the express recognition that the indemnification arrangements provided herein exceed that which the Corporation would be required to provide pursuant to Nevada Law.

AGREEMENT

NOW, THEREFORE, in consideration of the premises and the covenants contained herein, the Corporation and Indemnitee do hereby covenant and agree as follows:

1.             Definitions. As used in this Agreement:

(a)         The term “Indemnifiable Matter” means any event, occurrence, status, or condition that takes place either prior to or after the execution of this Agreement, including any threatened, pending, or completed action, suit, proceeding or alternative dispute resolution activity, whether brought by or in the right of the Corporation or otherwise and whether of a civil, criminal, administrative, or investigative nature, in which Indemnitee was, is, or believes might be involved as a party, witness, or otherwise (except any of the foregoing initiated by Indemnitee pursuant to section 17(a) to enforce Indemnitee’s rights under this Agreement), by reason of the fact, in whole or in part, that Indemnitee is or was actually or allegedly a director, officer, agent, or advisor of the Corporation; by reason of any action actually or allegedly taken by him or of any inaction or omission on his part while acting as a director, officer, agent, or advisor of the Corporation; by reason of the registration, offer, sale, purchase, or ownership of any securities of the Corporation; by reason of any duty owed to, respecting, or in connection with the Corporation; or by reason of the fact, in whole or in part, that he is or was actually or allegedly serving at the request of the Corporation as a director, officer, employee, agent, or advisor of another corporation, partnership, joint venture, trust, limited liability company, or other entity or enterprise, in each case whether or not he is acting or serving in any such capacity at the time any loss, liability, or expense is incurred for which indemnification or reimbursement can be provided under this Agreement and even though Indemnitee may have ceased to serve in such capacity.

(b)        The term “Losses” means any and all losses, claims, damages, expenses, liabilities, judgments, fines, penalties and actions in respect thereof, as they are incurred, against Indemnitee in connection with an Indemnifiable Matter; amounts paid by Indemnitee in settlement of an Indemnifiable Matter; any indirect, consequential, or incidental damages suffered or incurred by Indemnitee; and all attorneys’ fees and disbursements, accountants’ fees and disbursements, private investigation fees and disbursements, retainers, court costs, payments of attachment, appeal or other bonds or security, transcript costs, fees of experts, fees and expenses of witnesses, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, and all other disbursements or expenses reasonably incurred by or for Indemnitee in connection with prosecuting, defending, preparing to prosecute or defend, investigating, appealing, or being or preparing to be a witness in any threatened or pending Indemnifiable Matter or establishing Indemnitee’s right or entitlement to indemnification for any of the foregoing.

(c)         Reference to “other enterprise” shall include employee benefit plans; references to “fines” shall include any excise tax assessed with respect to any employee benefit plan; references to “serving at the request of the Corporation” shall include any service as a director, officer, employee, agent, or advisor with respect to an employee benefit plan, its participants, or beneficiaries; and a person who acted in good faith and in a manner he reasonably believed to be in the interests of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interests of the Corporation” as referred to in this Agreement.

(d)        The term “Indemnitee” shall include the Indemnitee named in the first paragraph of this Agreement and such Indemnitee’s actual or alleged alter egos, spouse, family members, and corporations, partnerships, limited liability companies, trusts, and other enterprises or entities of any form whatsoever under the control of any of the foregoing, and the property of all of the foregoing. The term “control” (including the terms “controlling,” “controlled by,” and “under common control with”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person or entity, whether through the ownership of voting securities, by contract, or otherwise, as interpreted under the Securities Act of 1933 or the Securities Exchange Act of 1934.

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(e)         The term “substantiating documentation” shall mean copies of bills or invoices for costs incurred by or for Indemnitee, or copies of court or agency orders, decrees, or settlement agreements, as the case may be, accompanied by a declaration, which need not be notarized, from Indemnitee that such bills, invoices, court or agency orders, decrees, or settlement agreements represent costs or liabilities meeting the definition of “Losses” herein.

(f)         Except as provided in section 15, the term “Independent Counsel” shall mean an attorney, law firm, or member of a law firm, who (or which) is licensed to practice law in the state of Nevada and is experienced in matters of corporation law and neither presently is, nor in the past five years has been, retained to represent (i) the Corporation or Indemnitee in any other matter material to either such party; or (ii) any other party to the Indemnifiable Matter giving rise to a claim for indemnification hereunder. Notwithstanding the foregoing, the term “Independent Counsel” shall not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Corporation or Indemnitee in an action to determine Indemnitee’s rights under this Agreement. From time to time, the Corporation may select and preapprove the names of persons or law firms that it deems qualified as Independent Counsel under the foregoing criteria. Further, at the request of Indemnitee, the Corporation shall review the qualifications and suitability under the foregoing criteria of persons or law firms selected by Indemnitee and preapprove them as Independent Counsel if they meet the foregoing criteria. An Independent Counsel that has already been preapproved by the board of directors may be appointed as Independent Counsel without any further evaluation, so long as such prospective Independent Counsel continues, as determined by the board of directors, to remain independent.

(g)        A “Change in Control” shall be deemed to have occurred if (i) any “person” (as such term is used in Section 13(d)(3) and 14(d)(2) of the Securities Exchange Act), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or a corporation owned directly or indirectly by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation, (1) that is or becomes the beneficial owner, directly or indirectly, of securities of the Corporation representing 20% or more of the combined voting power of the Corporation’s then-outstanding voting securities, increases its beneficial ownership of such securities by 5% or more over the percentage so owned by such person, or (2) becomes the “beneficial owner” (as defined in Rule 13d-3 under the Securities Exchange Act), directly or indirectly, of securities of the Corporation representing more than 30% of the total voting power represented by the Corporation’s then-outstanding voting securities, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the board of directors of the Corporation and any new director whose election by the board of directors or combination for election by the Corporation’s stockholders was approved by a vote of at least two-thirds of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority thereof, or (iii) the stockholders of the Corporation approve a merger or consolidation of the Corporation with any other corporation other than a merger or consolidation that would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least two-thirds of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation, or the stockholders of the Corporation approve a plan of complete liquidation of the Corporation or an agreement for the sale or disposition by the Corporation of (in one transaction or a series of transactions) all or substantially all of the Corporation’s assets.

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             2.          Indemnity of Indemnitee. The Corporation hereby agrees to indemnify, protect, defend and hold harmless Indemnitee against any and all Losses incurred by reason of the fact that Indemnitee is or was a director, officer, agent, or advisor of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee, agent or advisor of another corporation, partnership, joint venture, trust, limited liability company, or other entity or enterprise, to the fullest extent permitted by Nevada Law. The termination of any Indemnifiable Matter by judgment, order of the court, settlement, conviction, or upon a plea of nolo contendere, or its equivalent, shall not, of itself, create a presumption that Indemnitee is not entitled to indemnification, and with respect to any criminal proceeding, shall not create a presumption that such person believed that his conduct was unlawful. The indemnification provided herein shall be applicable whether or not the breach of any standard of care or duty, including a breach of a fiduciary duty, of the Indemnitee is alleged or proven, except as limited by section 3 herein. Notwithstanding the foregoing, in the case of any Indemnifiable Matter brought by or in the right of the Corporation, Indemnitee shall not be entitled to indemnification for any claim, issue, or matter as to which Indemnitee has been adjudged by a court of competent jurisdiction, after exhaustion of all appeals therefrom, to be liable to the Corporation or for amounts paid in settlement to the Corporation unless, and only to the extent that, the court in which the Indemnifiable Matter was brought or another court of competent jurisdiction determines, on application, that in view of all the circumstances, the person is fairly and reasonably entitled to indemnity for such expenses as the court deems proper.

3.          Limit on Indemnification. Notwithstanding any breach of any standard of care or duty, including breach of a fiduciary duty, by the Indemnitee, the Corporation shall indemnify Indemnitee except when a final adjudication establishes that Indemnitee’s acts or omissions involved intentional misconduct, fraud, or a knowing violation of law and were material to the cause of action.

4.          Choice of Counsel. Indemnitee shall be entitled to employ and be reimbursed for the fees and disbursements of counsel separate from that chosen by any other person or persons whom the Corporation is obligated to indemnify with respect to the same or any related or similar Indemnifiable Matter.

5.          Advances of Losses. Losses (other than judgments, penalties, fines, and settlements) incurred by Indemnitee shall be paid by the Corporation, in advance of the final disposition of the Indemnifiable Matter, within 10 days after receipt of Indemnitee’s written request accompanied by substantiating documentation.

6.          Officer and Director Liability Insurance. The Corporation shall, from time to time, make the good faith determination whether or not it is practicable for the Corporation to obtain and maintain a policy or policies of insurance with reputable insurance companies providing the officers and directors of the Corporation with coverage for losses, or to ensure the Corporation’s performance of its indemnification obligations under this Agreement. Among other considerations, the Corporation will weigh the costs of obtaining such insurance coverage against the protection afforded by such coverage. The Corporation shall consult with and be heard by Indemnitee in connection with the Corporation’s actions hereunder. In all policies of director and officer liability insurance, (a) Indemnitee shall be named as an insured in such a manner as to provide Indemnitee the same rights and benefits as are accorded to the most favorably insured of the Corporation’s directors, if Indemnitee is a director, or of the Corporation’s officers, if Indemnitee is not a director of the Corporation but is an officer; and (b) the policy shall provide that it shall not be cancelled or materially modified without 30 days’ prior written notice to Indemnitee. Notwithstanding the foregoing, the Corporation shall have no obligation to obtain or maintain such insurance if the Corporation determines in good faith that such insurance is not reasonably available, if the premium costs for such insurance are disproportionate to the amount of coverage provided, if the coverage provided by such insurance is limited by exclusions so as to provide an insufficient benefit, or if Indemnitee is covered by similar insurance maintained by a subsidiary or parent of the Corporation.

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             7.          Indemnification Trust Fund or Other Financial Arrangements. Pursuant to Nevada Revised Statutes § 78.752 or any successor Nevada Law, the Corporation may establish an indemnification trust fund or make other financial arrangements acceptable to Indemnitee for Indemnitee’s benefit. Indemnitee shall be an intended third-party beneficiary of any such fund or arrangement, with the right, power, and authority of the Indemnitee to sue for, enforce, and collect the same, in the name, place, and stead of the Corporation or otherwise, for Indemnitee’s benefit. Such fund or other arrangements shall be available to Indemnitee for payment of Losses upon the Corporation’s failure, inability, or refusal to pay Losses incurred by the Indemnitee.

8.          Right of Indemnitee to Indemnification upon Application; Selection of Independent Counsel; Procedure upon Application.

(a)         Any application for indemnification under this Agreement, other than when Losses are paid in advance of any final disposition pursuant to section 5 hereof, shall be submitted to the board of directors. If a quorum of the board of directors were not parties to the action, suit, proceeding or other matter, a majority of the directors who were not parties to the action, suit, proceeding or other matter may determine whether indemnification of the applicant is not prohibited by law or may have such determination made by Independent Counsel in a written decision. If a quorum of the board directors who were not parties to the action cannot be obtained, the board of directors shall have such determination made by Independent Counsel in a written decision. Notwithstanding the foregoing, however, the board of directors may under any circumstances submit the determination of whether indemnification is proper in the circumstances to the stockholders. The board of directors shall respond to a request for indemnification or initiate the process of submitting the determination to the stockholders within 45 days after receipt by the Corporation of the written application for indemnification.

(b)        If required, Independent Counsel shall be selected by the board of directors, and the Corporation shall give written notice to Indemnitee advising him of the identity of Independent Counsel so selected. Indemnitee may, within seven days after such written notice of selection shall have been given, deliver to the Corporation a written objection to such selection. Such objection may be asserted only on the ground that Independent Counsel so selected does not meet the requirements of “Independent Counsel,” as defined in section 1, and the objection shall set forth with particularity the factual basis of such assertion. If such written objection is made, Independent Counsel so selected may not serve as Independent Counsel unless and until a court has determined that such objection is without merit. If, within 20 days after submission by Indemnitee of a written objection to the Independent Counsel selected, the Corporation has failed to identify a replacement Independent Counsel, the Indemnitee may petition any court of competent jurisdiction for resolution of any objection that shall have been made by Indemnitee to the Corporation’s selection of Independent Counsel and for appointment as Independent Counsel of a person selected by such court or by such other person as such court shall designate, and the person with respect to whom an objection is so resolved or the person so appointed shall act as Independent Counsel. The Corporation shall pay any and all reasonable fees and expenses of Independent Counsel incurred by such Independent Counsel in connection with its fees and expenses incident to the procedures of this section 8 regardless of the manner in which such Independent Counsel was selected or appointed.

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            (c)         The right to indemnification or advances as provided by this Agreement shall be enforceable by Indemnitee in any court of competent jurisdiction. The burden of proving that indemnification is not appropriate shall be on the Corporation. Neither the failure of the Corporation (including its board of directors or Independent Counsel) to have made a determination prior to the commencement of such action that indemnification is proper in the circumstances, nor an actual determination by the Corporation (including its board of directors or Independent Counsel) that indemnification is not proper in the circumstances, shall be a defense to the action, suit, proceeding, or other matter or create a presumption that indemnification is not proper in the circumstances.

9.          Notice to Insurers. If, at the time of the receipt of an application for indemnification pursuant to section 2 hereof or a request for advances of Losses pursuant to section 5 hereof, the Corporation has director and officer liability insurance in effect, the Corporation shall give prompt notice of the commencement of such Indemnifiable Matter to the insurers in accordance with the procedures set forth in the respective policies. The Corporation shall thereafter take all necessary or desirable action to cause such insurers to pay, on behalf of the Indemnitee, all amounts payable as a result of such Indemnifiable Matter in accordance with the terms of such policies.

10.        Undertaking by Indemnitee. Indemnitee hereby undertakes to repay to the Corporation any advances of Losses pursuant to this Agreement to the extent that it is ultimately determined that Indemnitee is not entitled to indemnification.

11.        Indemnification Hereunder Not Exclusive. The indemnification and advancement of Losses provided by this Agreement shall not be deemed exclusive of any other rights to which Indemnitee may be entitled under the Articles or Bylaws, the Nevada Law, any policy or policies of directors’ and officers’ liability insurance, any other agreement, any vote of stockholders or disinterested directors, or otherwise, both as to action in his official capacity and as to action in another capacity while holding such office (together, “Other Indemnification”). However, Indemnitee shall reimburse the Corporation for amounts paid to him under Other Indemnification and not under this Agreement in an amount equal to any payments received pursuant to such Other Indemnification, to the extent such payments duplicate any payments received pursuant to this Agreement.

12.        Continuation of Indemnity. All agreements and obligations of the Corporation contained herein shall continue during the period Indemnitee is a director, officer, employee, agent, or advisor of the Corporation (or is or was serving at the request of the Corporation as a director, officer, employee, agent, or advisor of another corporation, partnership, joint venture, trust, limited liability company, or other enterprise) and shall continue thereafter so long as Indemnitee shall be subject to any possible Indemnifiable Matter.

13.        Partial Indemnification. If Indemnitee is entitled under any provision of this Agreement to indemnification by the Corporation for some or a portion of Losses, but not, however, for the total amount thereof, the Corporation shall nevertheless indemnify Indemnitee for the portion of such Losses to which Indemnitee is entitled.

14.        Settlement of Claims. The Corporation shall not be liable to indemnify Indemnitee under this Agreement for any amounts paid in settlement of any Indemnifiable Matter effected without the Corporation’s written consent. The Corporation shall not settle any Indemnifiable Matter in any manner that would impose any penalty or limitation on Indemnitee’s rights under this Agreement without Indemnitee’s written consent. Neither the Corporation nor Indemnitee will unreasonably withhold its consent to any proposed settlement. The Corporation shall not be liable to indemnify Indemnitee under this Agreement with regard to any judicial award if the Corporation was not given a reasonable and timely opportunity, at its expense, to participate in the defense of such action.

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15.           Change in Control.

(a)         Notwithstanding the provisions of Section 6, any provision for the benefit of officers and directors existing immediately prior to a Change of Control, including officer and director liability insurance, an indemnification trust fund or other financial arrangements, shall be maintained for so long as Indemnitee is subject to any Indemnifiable Matter. In the case of officer and director liability insurance, such insurance shall be maintained with the same scope and amount of coverage, with no larger deductible or retention amounts, and otherwise on the same terms and conditions as were in effect immediately prior to such Change of Control unless such coverages, terms and conditions are no longer available.

(b)        With respect to all matters thereafter arising concerning the rights of Indemnitee to payments of Losses under this Agreement or any other agreement, or under the Articles or Bylaws as now or hereafter in effect, independent counsel shall be selected by the Indemnitee and approved by the Corporation (which approval shall not be unreasonably withheld). Such counsel, among other things, shall render its written opinion to the Corporation and Indemnitee as to whether and to what extent Indemnitee would be permitted to be indemnified under Nevada Law as determined in accordance with section 18(d). The Corporation agrees to abide by such opinion and to pay the reasonable fees of the independent counsel referred to above and to fully indemnify such counsel against any and all expenses (including attorneys’ fees), claims, liabilities and damages arising out of or relating to this Agreement or its engagement pursuant hereto.

16.          Termination of Previous Indemnification Agreement. Upon execution of this Agreement, the previous Indemnification Agreement dated [previous agreement date], by and between the Corporation and Indemnitee shall terminate and be of no further force or effect, provided that Indemnitee shall be entitled to all of the benefits and rights under this Agreement respecting any Losses arising from, related to, or in connection with Indemnifiable Matters prior to the date of this Agreement.

17. Enforcement.

(a)         The Corporation expressly confirms and agrees that it has entered into this Agreement and assumed the obligations imposed on the Corporation hereby in order to induce Indemnitee to serve as a director or officer of the Corporation, and acknowledges that Indemnitee is relying upon this Agreement in continuing as a director or officer. The Corporation shall be precluded from asserting in any action commenced pursuant to this section 17 that the procedures and presumptions in this section are not valid, binding and enforceable and shall stipulate in any such judicial proceedings that the Corporation is bound by all of the provisions of this Agreement.

(b)        In any action commenced pursuant to this section 17, Indemnitee shall be presumed to be entitled to indemnification and advancement of Losses in accordance with section 5 under this Agreement, as the case may be, and the Corporation shall have the burden of proof in overcoming such presumption and must show by clear and convincing evidence that Indemnitee is not entitled to indemnification or advancement of Losses, as the case may be.

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                (c)         The execution of this Agreement shall constitute the Corporation’s stipulation by which it shall be irrevocably bound in any action by Indemnitee for enforcement of Indemnitee’s rights hereunder that the Corporation’s obligations set forth in this Agreement are unique and special, and that failure of the Corporation to comply with the provisions of this Agreement will cause irreparable and immediate injury to Indemnitee, for which a remedy at law will be inadequate. As a result, in addition to any other right or remedy Indemnitee may have at law or in equity respecting a breach of this Agreement, Indemnitee shall be entitled to injunctive or mandatory relief directing specific performance by the Corporation of its obligations under this Agreement.

 (d)        In the event that Indemnitee shall deem it shall be necessary or desirable to retain legal counsel and/or incur other costs and expenses in connection with the interpretation or enforcement of any or all of Indemnitee’s rights under this Agreement, Indemnitee shall be entitled to recover from the Corporation, and the Corporation shall indemnify Indemnitee against, any and all fees, costs, and expenses (of the types described in the definition of Losses in section 1(b)) incurred by Indemnitee in connection with the interpretation or enforcement of said rights. The Corporation shall make payment to the Indemnitee at the time such fees, costs, and expenses are incurred by Indemnitee. If, however, the Indemnitee does not prevail in such action under this section 17, Indemnitee shall repay any and all such amounts to the Corporation. If it shall be determined in an action pursuant to this section 17 that Indemnitee is entitled to receive part but not all of the indemnification or advancement of fees, costs, and expenses or other benefit sought, the expenses incurred by Indemnitee in connection with an action pursuant to this section 17 shall be equitably allocated between the Corporation and Indemnitee. Notwithstanding the foregoing, if a Change in Control shall have occurred, Indemnitee shall be entitled to indemnification under this section 17 regardless of whether Indemnitee ultimately prevails in such judicial adjudication or arbitration. This section 17(b) is not subject to the provisions of section 8.

18.            Governing Law; Binding Effect; Amendment and Termination; Construction.

(a)         This Agreement shall be interpreted and enforced in accordance with Nevada Law.

(b)        This Agreement shall be binding upon the Corporation, its successors and assigns, and shall inure to the benefit of Indemnitee such Indemnitee’s actual or alleged alter egos, spouse, family members, and corporations, partnerships, limited liability companies, trusts, and other enterprises or entities of any form whatsoever under the control of any of the foregoing, the property of all of the foregoing, and the successors and assigns of all of the foregoing.

(c)         No amendment, modification, termination, or cancellation of this Agreement shall be effective unless in writing signed by the Corporation and Indemnitee.

(d)        This Agreement shall be construed liberally in favor of the Indemnitee to the fullest extent possible under Nevada Law, even if such indemnification is not specifically authorized by this Agreement or any other agreement, the Articles or Bylaws, or by Nevada Law. In the event Nevada Law is changed after the date of this Agreement, through statutory amendment, judicial interpretation, administrative regulations or otherwise, to allow additional indemnification or to remove or restrict current limitations on indemnification, this Agreement shall be deemed to be amended and reformed so that Indemnitee shall enjoy by this Agreement the greater benefits of such change. In the event of any change in Nevada Law that narrows or restricts the right of a Nevada corporation to indemnify Indemnitee, such change, to the extent not otherwise required by Nevada Law to be applied to Indemnitee in the relevant circumstances, shall have no effect on this Agreement or the rights and obligations of the parties hereunder.

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              19.           Mutual Acknowledgement. Both the Corporation and Indemnitee acknowledge that in certain instances, federal law or applicable public policy may prohibit the Corporation from indemnifying its directors and officers under this Agreement or otherwise. Indemnitee understands and acknowledges that the Corporation has undertaken, or may be required in the future to undertake with the Securities and Exchange Commission, to submit the question of indemnification to a court in certain circumstances for a determination of the Corporation’s right under public policy to indemnify Indemnitee.

 20.         Severability. If any provision of this Agreement shall be held to be invalid, illegal, or unenforceable:

(a)         the validity, legality, and enforceability of the remaining provisions of this Agreement shall not be in any way affected or impaired thereby; and

(b)        to the fullest extent possible, the provisions of this Agreement shall be construed so as to give effect to the intent manifested by the provision held invalid, illegal, or unenforceable.

Each section of this Agreement is a separate and independent portion of this Agreement. If the indemnification to which Indemnitee is entitled as respects any aspect of any claim varies between two or more sections of this Agreement, that section providing the most comprehensive indemnification shall apply.

 21.        Notice. Any notice, demand, request, or other communication permitted or required under this Agreement shall be in writing and shall be deemed to have been given as of the date so delivered, if personally served; as of the date so sent, if transmitted by facsimile and receipt is confirmed by the facsimile operator of the recipient; as of the date so sent, if sent by electronic mail and receipt is acknowledged by the recipient; one day after the date so sent, if delivered by overnight courier service; or three days after the date so mailed, if mailed by certified mail, return receipt requested, addressed as follows:

If to the Corporation: FX Energy, Inc.

3006 Highland Drive, Suite 206

Salt Lake City, UT 84106

Facsimile: (801) 486-5575

E-mail: davidpierce@fxenergy.com

If to Indemnitee, to: [name of Indemnitee]

[confidential address]

or such other addresses, facsimile numbers, or electronic mail address as shall be furnished in writing by any party in the manner for giving notices hereunder.

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            IN WITNESS WHEREOF, the parties hereto have executed this Agreement to be effective on and as of the day and year first above written.

Corporation:

FX ENERGY, INC.

By: /s/

Its officer

Indemnitee:

/s/

[name of indemnitee]

Related Schedule

Name of Indemnitee	Date of Superseded Agreement	Effective Date
Scott J. Duncan	December 9, 2004	December 12, 2008
Dennis B. Goldstein	December 9, 2004	December 12, 2008
Arnold S. Grundvig, Jr.	December 9, 2004	December 12, 2008
Richard F.P. Hardman	December 9, 2004	December 12, 2008
Thomas B. Lovejoy	December 9, 2004	December 12, 2008
Jerzy B. Maciolek	December 9, 2004	December 12, 2008
Clay Newton	December 9, 2004	December 12, 2008
Andrew W. Pierce	December 9, 2004	December 12, 2008
David N. Pierce	December 9, 2004	December 12, 2008
David L. Worrell	December 9, 2004	December 12, 2008
H. Allen Turner	February 20, 2007	December 12, 2008

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EX-10.77

Exhibit 10.77

SUMMARY OF COMPENSATORY ARRANGEMENTS

WITH DIRECTORS AND NAMED EXECUTIVE OFFICERS

Director Compensation. Each director who is not an employee or officer of the Company will receive the following compensation for his services as director in 2009:

• annual base compensation of $20,000;

• $2,000 per regularly scheduled board meeting attended;

• $750 per regularly scheduled audit committee meeting attended;

• $25,000 per year for service as the Audit Committee chairman;

• $20,000 per year for service as the Compensation Committee chairman;

• $20,000 per year for service as the Nomination and Governance Committee chairman;

• an annual grant of 6,000 shares of restricted common stock (12,000 for the chairman of the Nomination and Governance Committee); and

• reimbursement of reasonable out-of-pocket expenses incurred in attending board meetings.

Mr. Hardman, who is the Technical Advisor to the board of directors, is also a consultant to the Company. In this capacity, he receives $57,000 per year and is granted an additional 21,000 shares of restricted common stock as a consequence of his appointment to that position.

Named Executive Officer Compensation. The Company’s executive compensation program has several elements, all determined by individual and Company performance.

Base Salary Compensation

Base salaries for the Chief Executive Officer and the other named executive officers in 2009 have been established by reviewing a number of factors, including responsibilities, experience, demonstrated performance, potential for future contributions, and the level of salaries associated with similar positions at businesses that compete with the Company and other competitive factors. Base salary levels for named executive officers in 2009, which are unchanged from 2008 levels, have been determined as follows:

David N. Pierce	$367,500
Thomas B. Lovejoy	262,500
Andrew W. Pierce	283,500
Jerzy B. Maciolek	283,500
Clay Newton	210,000

Other Compensation

In addition to his base salary, each of the named executive officers is eligible to participate in the following:

• the Company’s various stock option and incentive plans, under which stock options or other equity compensation may be granted from time to time as determined by the board of directors, and which may be based on factors such as the level of base pay and individual performance;

• short-term incentive compensation, which is determined from time to time by the board of directors, under which cash bonuses in varying amounts may be granted based on the Company and individual achieving predetermined goals;

• the Company’s 401(k) profit-sharing plan and other health and benefit plans generally available to Company employees; and

• other compensation arrangements as determined by the board of directors.

EX-10.92

Exhibit 10.92

AMENDMENT AND RECONFIRMATION OF SUPPLEMENTAL INDEMNIFICATION AGREEMENT

THIS AMENDMENT AND RECONFIRMATION OF SUPPLEMENTAL INDEMNIFICATION AGREEMENT (this “Agreement”) is entered into effective as of December 12, 2008, by and between FX ENERGY, INC., a Nevada corporation (the “Corporation”), and DENNIS B. GOLDSTEIN (“Goldstein” or “Indemnitee”), based on the following premises.

Premises

A.         The Corporation has the power and authority pursuant to its Restated Articles of Incorporation (“Articles”) to engage in any lawful act for which corporations may be organized under the laws of the state of Nevada. Further, Section 78.060 of the Nevada Revised Statutes states that corporations may, at any time, exercise these rights, privileges, and powers consistent with the purposes and objects for which the corporation is organized and that the corporation is empowered to make contracts.

B.         Goldstein is currently a director of the Corporation, which agreed to indemnify, protect, and defend Goldstein and hold him harmless pursuant to that certain Indemnification Agreement effective December 9, 2004 (the “Director Indemnification”). Effective December 12, 2008, Goldstein and the Corporation terminated the Director Indemnification and entered into a new agreement pursuant to which the Corporation has agreed to indemnify, protect, and defend Goldstein and hold him harmless (the “Corporate Indemnity”).

C.         As a requirement of his professional association with the law firm of Jeffer, Mangels, Butler & Marmaro, LLP (the “Law Firm”), Goldstein has agreed to indemnify, protect, defend, and hold the Law Firm, and its partners, employees, and representatives harmless from and against any and all claims made or asserted against the Law Firm and its partners, employees, and representatives on account of an act or omission of Goldstein performed for the Corporation, whether or not such action could be considered as legal advice (the “Goldstein Indemnification”), as set forth in Recital F to that certain Supplemental Indemnity Agreement (as defined below).

D.         Goldstein and the Corporation are also parties to that certain Supplemental Indemnity Agreement effective December 9, 2004 pursuant to which the Corporation has agreed to further indemnify, protect, and defend Goldstein and hold him harmless from and against any and all losses, claims, damages, expenses, liabilities, judgments, fines, penalties and actions arising out of or related to the Goldstein Indemnification (the “Supplemental Indemnity Agreement”).

E.         In light of the fact that Goldstein and the Corporation have terminated the Director Indemnification and entered into the Corporate Indemnity, they desire to amend and reconfirm the Supplemental Indemnity Agreement.

Agreement

NOW, THEREFORE, for and in consideration of these premises, which are incorporated herein by reference, and the mutual promises and covenants contained herein, the Corporation and Indemnitee do hereby covenant and agree as follows:

              1.          Acknowledgement of the Corporate Indemnity. All references in the Supplemental Indemnity Agreement to the Director Indemnification are amended to refer to the Corporate Indemnity and all subsequent amendments thereto.

2.          Reconfirmation of Supplemental Indemnity Agreement. Goldstein and the Corporation agree and confirm that notwithstanding thefact that they have terminated the Director Indemnification and enteredinto the Corporate Indemnity, the Supplemental Indemnity Agreement continues in full force and effect in accordance with its terms and conditions, except as expressly amended by this Agreement.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement to be effective on and as of the day and year first above written.

Corporation:
	FX ENERGY, INC.
	By: /s/ David N. Pierce
	David N. Pierce, President
Indemnitee:
	/s/ Dennis B. Goldstein
	DENNIS B. GOLDSTEIN

2

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-80489, 333-110345, and 333-155718) and Form S-8 (Nos. 333-112717 and 333-128299) of FX Energy, Inc., and subsidiaries of our report dated March 16, 2009, relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Salt Lake City, Utah

March 13, 2009

EX-23.02

Exhibit 23.02

CONSENT OF PETROLEUM ENGINEERING CONSULTANT

I consent to the use of my report respecting the estimated oil reserve information as of December 31, 2008, for the Montana and Nevada producing properties of FX Energy, Inc. (the “Company”), and the discussion of such report as contained in the Company’s annual report on Form 10-K for the year ended December 31, 2008, and to the incorporation by reference of such report, as it is referred to in the Company’s annual report, into the following registration statements:

Form	SEC File No.	Effective Date
S-3	333-80489	June 30, 1999
S-3	333-110345	November 18, 2003
S-3	333-155718	November 26, 2008*
S-8	333-112717	February 11, 2004
S-8	333-128299	September 14, 2005

_______________

*  This registration statement is not yet effective. This is the original filing date.

/s/ Larry D. Krause

Larry D. Krause

Billings, Montana

March 13, 2009

EX-23.03

Exhibit 23.03

RPS Energy

309 Reading Road, Henley-on-Thames, Oxfordshire, RG9 IEL United Kingdom

T #44 (0) 1491 415400 F #44 (0) 1491 415415 www.rpsgroup.com

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name RPS Energy and of references to RPS Energy and to the inclusion of and references to our report, or information contained therein, dated February __, 2009, prepared for FX Energy in the FX Energy, Inc. annual report on Form 10-K for the year ended 31st December 2008, and the incorporation by reference to the report prepared by RPS Energy into FX Energy, Inc.'s previously filed registration statements listed below:

Form	SEC File No.	Effective Date
S-3	333-80489	June 30, 1999
S-3	333-110345	November 18, 2003
S-3	333-155718	November 26, 2008*
S-8	333-112717	February 11, 2004
S-8	333-128299	September 14, 2005

_______________

*  This registration statement is not yet effective. This is the original filing date.

/s/ Michiel Stofferis

RPS Energy

Michiel Stofferis

Petroleum Engineering Manager

13 March 2009

EX-31.01

Exhibit 31.01

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14

I, David N. Pierce, certify that:

1.          I have reviewed this annual report on Form 10-K of FX Energy, Inc.;

2.          Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.          Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.          The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)         designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)         designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)         evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)         disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.          The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)         all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)         any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: March 16, 2009

/s/ David N. Pierce

David N. Pierce

Chief Executive Officer

EX-31.02

Exhibit 31.02

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a-14

I, Clay Newton, certify that:

1.          I have reviewed this annual report on Form 10-K of FX Energy, Inc.;

2.          Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.          Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.          The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)         designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)         designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)         evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)         disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.          The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)         all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)         any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: March 16, 2009

/s/ Clay Newton

Clay Newton

Principal Financial Officer

EX-32.01

Exhibit 32.01

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of FX Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David N. Pierce, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ David N. Pierce

David N. Pierce

Chief Executive Officer

March 16, 2009

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.02

Exhibit 32.02

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of FX Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Clay Newton, Principal Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Clay Newton

Clay Newton

Principal Financial Officer

March 16, 2009

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.