FX Energy 10K 2009 Annual report

FX Energy (FXEN) Inactive 10-K2009 FY Annual report

Content analysis

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, 2009

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 o No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of June 30, 2009, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $156,186,000.

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 15, 2010, FX Energy had outstanding 43,260,517 shares of its common stock, par value $0.001.

DOCUMENTS INCORPORATED BY REFERENCE. FX Energy’s definitive Proxy Statement in connection with the 2010 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, 2009

TABLE OF CONTENTS

Item		Page
	Part I
--	Special Note on Forward-Looking Statements	3
1	Business	5
1A	Risk Factors	11
1B	Unresolved Staff Comments	20
2	Properties	20
3	Legal Proceedings	32
4	[RESERVED]	32

	Part II
5	Market for Registrant’s Common Equity, Related Stockholder Matters
	and Issuer Purchases of Equity Securities	33
6	Selected Financial Data	34
7	Management’s Discussion and Analysis of Financial Condition and Results of Operation	36
7A	Quantitative and Qualitative Disclosures about Market Risk	49
8	Financial Statements and Supplementary Data	50
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
9A	Controls and Procedures	51
9B	Other Information	51

	Part III
10	Directors, Executive Officers and Corporate Governance	51
11	Executive Compensation	52
12	Security Ownership of Certain Beneficial Owners and Management and Related
	Stockholder Matters	52
13	Certain Relationships and Related Transactions, and Director Independence	52
14	Principal Accounting Fees and Services	52

	Part IV
15	Exhibits, Financial Statement Schedules	53
--	Signatures	58
--	Management’s Report on Internal Control over Financial Reporting	F-1
--	Report of Independent Registered Public Accounting Firm	F-2

SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS

This report contains statements about the future, sometimes referred to as “forward-looking” statements. Forward-looking statements are typically identified by the use of the words “believe,” “may,” “could,” “should,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “intend,” and similar words and expressions. Statements that describe our future strategic plans, goals, or objectives are also forward-looking statements. We intend that the forward-looking statements will be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Readers of this report are cautioned that any forward-looking statements, including those regarding us or our management’s current beliefs, expectations, anticipations, estimations, projections, strategies, proposals, plans, or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as:

·	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 oil and gas 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 oil and gas 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 oil and gas 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 the Polish Oil and Gas Company, or POGC, and other third parties with which we conduct business and on which we rely to supply goods and services and to purchase our oil and gas production;

·	exploration and development priorities and the financial and technical resources of POGC, our principal joint venture and strategic partner in Poland, PL Energia S.A., another 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 oil and gas interests, including exploitation fees, royalty rates, and other matters;

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

·	other factors that are not listed above.

The forward-looking information is based on present circumstances and on our predictions respecting events that have not occurred, that may not occur, or that may occur with different consequences from those now assumed or anticipated. Actual events or results may differ materially from those discussed in the forward-looking statements. The forward-looking statements included in this report are made only as of the date of this report.

PART I

ITEM 1. BUSINESS

Introduction

We are an independent oil and gas exploration and production company with principal production, reserves, and exploration activities in Poland and 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 United Kingdom, Dutch, and German sectors. For most of the twentieth century, Poland was closed to exploration by foreign oil and gas companies. Consequently, we think the Polish Permian Basin is underexplored and underexploited and, therefore, has high potential for discovering significant amounts of oil and gas.

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 oil and gas reserves at 50.4 billion cubic feet of natural gas equivalent, or Bcfe, at year-end 2009. The PV-10 Value of these reserves at year-end 2009 was approximately $146 million, which is equal to approximately $3.39 (after tax) per share of stock outstanding at year-end. Our oil and gas reserve volumes in Poland have increased at a compound annual growth rate of 30% since 2003. Our production volume has increased at a compound annual growth rate of 52% from 2005 to 2009. At year-end 2009 we were producing approximately 12.0 million cubic feet of natural gas per day, or MMcfd. We have three additional wells that are expected to add a further 6.9 MMcfd at year-end 2010. These increases are attributable to our exploration success in Poland. With a view to future growth in reserves and production, we now hold 4.7 million gross acres (4.2 million net acres) in Poland and continually review additional acquisition opportunities.

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 “Oil and Gas 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, 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 oil and gas 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 continues to result 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 oil and gas 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.”

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 five Tcf of Rotliegend gas has been discovered in Poland by POGC, which until Poland was opened to foreign exploration, conducted all oil and gas exploration and production in the country. We believe political and capital constraints impaired POGC’s ability to explore and develop the Polish portion of the basin.

(2) In the last 25 years, very little exploration focused on the Rotliegend has been conducted in Poland, except in our core Fences concession.

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 POGC, which owns and produces gas from the field. We have emphasized improved seismic data acquisition and processing in our exploration, using technology developed by others for Rotliegend exploration in the Southern North Sea.

From 2004 through 2009, in the course of our Polish exploration with this approach, we have made commercially successful discoveries in seven of the ten wells we have drilled on Rotliegend structural trap targets. In the aggregate, these seven discoveries found gross estimated proved reserves of 120 Bcf of gas. We have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers in the Fences concession, and plan to acquire 3-D seismic data over more of the concession. Using the data acquired to date, 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, but we expect that we will drill some 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 3.8 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 oil and gas 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, we will continue to devote the greatest portion of our efforts and capital resources over the next several years to the Rotliegend structural trap gas prospects in our core area.

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

Key Personnel for Poland

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

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 an oil and natural gas producer in Poland.

Our U.S. Presence

Unlike our position in Poland, the U.S. operation does not have substantial exploration potential. It provides a modest amount of cash flow and is not capital intensive. It consists mostly of shallow, oil-producing wells in the Cut Bank Oil Field of Montana. As of December 31, 2009, our U.S. reserves were estimated at 463,000 barrels of crude oil with a PV-10 Value of approximately $3.5 million. At year-end 2009, U.S. reserves were approximately 6% of total reserves on a gas equivalent basis. Our oil wells produce approximately 175 barrels of oil per day, net to our interest. From our field office in Montana, we also provide oilfield services, which provided approximately $1.9 million in revenue during 2009.

Exploration, Development, and Production Activities

Polish Exploration Rights

As of December 31, 2009, we held oil and gas exploration rights in Poland in nine separately designated project areas encompassing approximately 4.7 million gross acres. We are currently the operator in all areas except our core area, the 852,000 gross-acre Fences project area, in which we hold a 49% working interest in approximately 807,000 acres and a 24.5% interest in the remaining 45,000 acres. POGC is the operator. We own a 100% working interest in approximately 3.8 million gross 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 246, Block 287, Block 229, Warsaw South, Block 255, Kutno, Edge, and Northwest. 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 and POGC have discovered proved gas reserves of over 120 Bcf gross (53 Bcf net to our interest) in seven commercial wells, 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 287. We are developing longer-term exploration prospects in the remaining seven areas.

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 oil and gas 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 ten wells targeting Rotliegend structures through the end of 2009. Seven of these wells are commercial, with aggregate proved gas reserves of over 120 Bcf gross (53 Bcf net to our interest).

Three of these wells are currently producing. We are finalizing the permitting and design for the construction of production facilities for another three of these wells, known as the “KSK” (Kromolice-1, Sroda-4, and Kromolice-2) wells. We expect production to begin near year-end 2010. We expect the KSK wells to collectively produce 14 MMcfd (6.9 MMcfd net to us) at a constant rate for several years. The seventh well, Winna Gora, is expected to begin producing in the second half of 2011.

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 2010 we plan to drill more of the leads interpreted on this 3-D seismic data.

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, continuing 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 (four 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 MMcfd after high-pressure, hydraulic fracturing. 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.

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 hydrocarbon potential. We are reprocessing existing two-dimensional, or 2-D, seismic data to identify possible play-types and prospect leads. We have also identified an opportunity to work over three wells in an oil and gas field (“Zakowo”) that was discovered in the 1970s but never produced. We have reviewed logs, cores, drillstem tests, and other materials and believe three of the Zakowo wells are capable of producing oil and gas in commercial quantities. We plan to work over these wells in the second half of 2010.

Block 287 Concession Area

The Block 287 concession area is 13,000 acres (52 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 a portion of in 2007 and 2008.

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 would 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 production began in July 2009. We plan to recomplete the remaining two wells in the second half of 2010. At year-end 2009, gross proved reserves of approximately 1.7 Bcf were assigned to the Grabowka-12 well.

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.). Beginning in 2006, we produced oil and gas from a single well, Wilga-2, which was depleted in 2009. We plan to plug the well and dismantle the facility in 2010.

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 exploration leads, including carboniferous sands with structural or truncation trapping and Zechstein reefs trapped by overlying evaporites 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.

Northwest Concession Area

In 2006, we acquired a 100% interest in a concession in west-central Poland covering 0.9 million gross acres. The concession is in Poland’s Permian Basin directly north of POGC’s BMB and MLG oil and gas fields. The Northwest concession has at least two separate possible exploration models: Rotliegend sands trapping gas in structural closures and Zechstein Ca2 dolomitic sands, reefs, and talus trapping oil and gas.

During 2007 we reviewed the existing sparse, 20-year-old geological and geophysical data from the area. In the original concession 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. During 2009, we subsequently dropped two other blocks, resulting in our current 0.9 million acreage position. We also acquired 245 kilometers of new 2-D seismic data over several of the leads we had identified previously.

In 2009, we drilled the Ostrowiec well in the Northwest concession. The well was designed to test a Ca2 target at a depth of 3,800 meters and a potential Rotliegend target at a depth of 4,100 meters. The well did not encounter commercial hydrocarbons in the Ca2 target and was plugged before reaching target depth for the Rotliegend. The well was drilled on 2-D seismic data and was operated and owned 51% by us. POGC paid 100% of the cost to drill the well.

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 gross 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.

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 gather additional seismic data and drill two or more exploratory wells to confirm the exploration model.

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 possible Rotliegend prospect and a number of possible Ca2 reef build-ups on 2-D seismic data in Block 229. We plan to seek industry participation while continuing to carry out early-stage exploration work on our own.

Additional Concession Acreage

We may apply for more concession blocks in Poland in 2010. If we acquire more concession blocks, we will allocate modest technical and financial resources to these areas during 2010, 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 2009, we drilled one shallow dry hole in Nevada. We have no plans for further drilling in Nevada during 2010.

Montana

We did not drill any wells in Montana during 2009. We have no plans for drilling in Montana during 2010.

Segment Information

Further information concerning our financial and geographic segments can be found in the notes 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.

ITEM 1A. RISK FACTORS

Our business is subject to a number of material risks, including the following factors related directly and indirectly to our business activities in the United States and Poland.

Risks Relating to our Business

Our long-term success depends largely on our discovery and production of economic quantities of gas or oil in Poland.

We anticipate that our production will increase in 2010 as previously drilled wells are placed into production and that we will generate revenues in excess of direct lease operating costs, as well as anticipated general and administrative costs. However, these revenues may not be sufficient to cover all of our planned exploration and development costs. Accordingly, we may continue to rely on existing working capital, borrowings under expanded or new credit facilities, additional funds obtained from external sources, including the sale of equity securities, and industry partners to cover these costs.

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 Royal Bank of Scotland, or RBS, which was based on RBS’s evaluation of our reserves in Poland as of November 2006 when we established the facility. We believe the subsequent sizeable increase in our reserves in Poland may warrant increased borrowings, but our ability to increase our borrowings with RBS or others may be hampered by continuing global economic conditions. Accordingly, we cannot predict how RBS or any other financial institution 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 may be a 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.

Our recent stock prices, as compared to pre-2009 prices, may make additional equity financing less attractive than prior to 2009.

Our intraday stock prices for 2009 were a high of $4.97 per share and a low of $2.12 per share, and to date in 2010, were a high of $3.48 per share and a low of $2.84 per share, as compared to a 2008 high of $8.68 per share and a low of $1.95 per share. These price declines after 2008 are typical throughout the equity markets generally and in the oil and gas segment specifically. In these market conditions, the current equity markets are a less attractive funding alternative than prior to 2008. 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. In addition, any sale of equity securities at current prices may dilute the interests of investors who purchased shares at higher prices.

Fluctuations in global oil and gas prices impact the price we receive for gas in Poland.

The prices at which we sell gas in Poland to POGC are determined 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 lower oil prices may have a depressing effect on such tariff, and so may reduce the price that we receive for our gas from POGC. Conversely, because the tariffs are determined, in part, by trailing prices, increases in oil prices may result in higher tariffs for the gas we sell in Poland.

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. 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. 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 2010 continue throughout the year, we expect the exchange rates to have a positive impact on our U.S. dollar-denominated revenues in 2010 compared to 2009, but a corresponding negative impact on the U.S. dollar cost of our capital expenditures in Poland.

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, where our principal production and reserves are located, 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 2010 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. Similarly, as operator, POGC controls the level of production as well as other day-to-day operating details. 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. In our Block 287 area, we are dependent on the financial ability of PL Energia S.A. to pay the costs of re-entering and recompleting two additional wells. We may undertake this work at our own cost if PL Energia S.A. fails to pay these costs.

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 develop will provide a useful or effective guide for selecting exploration prospects and drilling targets. We continually review and revise or replace these exploration models as a guide to further exploration based on ongoing drilling results. These exploration models are typically 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 near previous wells cannot assure that such prospects are in fact similar or that drilling results will be comparable. Every prospect is unique and must be evaluated individually. We cannot assure that the analogies that we draw from available data from other wells, fully explored prospects, or producing fields will be applicable to our drilling prospects or will enable us to forecast accurately drilling results.

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 oil and gas accumulations for various purposes, including determining the amount available for us to borrow under our Senior Credit Facility with RBS and in seeking expanded or replacement borrowings. For purposes of management decisions and risk analysis, we use a variety of geological, engineering, and geophysical techniques to estimate probable or possible reserves and gross, unrisked resource potential. These various methods are important in making many kinds of management decisions during the exploration, development, and production process, but the quantities and values estimated through these methods are not comparable and should not be compared. We cannot assure that any gas or oil quantities or values that we estimate through alternative methods will ever be converted through additional exploration and production into reserves.

Our estimates of proved and probable oil and gas reserves are subject to various risks and uncertainties and this year include new, voluntarily disclosed information.

Our estimates of oil and gas reserves are based on various assumptions and estimates and are very complex and interpretative, as there are numerous uncertainties inherent in estimating quantities and values of proved and probable reserves, projecting future sales of production, and the timing and amount of development expenditures. Many of these factors are beyond our control. Our proved and probable reserve estimates are subject to continuing revisions as additional information becomes available or assumptions change. Although they rely in part on objective information, engineering evaluations of oil and gas reservoirs are essentially subjective processes of estimating the size and recoverability of underground accumulations of oil and gas that cannot be measured in any exact manner. The actual production that we obtain from our oil and gas properties may vary substantially from the factors and assumptions that have been used in completing these estimates, including:

·	the geological, geophysical, and engineering characteristics of the underground reservoir;

·	known production from other properties that we believe are an analogue to our own wells;

·	the assumed effects of regulatory requirements and government payments;

·	the costs of the construction of production facilities and pipeline connections and the timing of completing those facilities;

·	production and other operating policies and practices of POGC, the operator of most of our productive wells;

·	the effect of certain terms to be determined in the future, including gas and oil exploitation fees, royalty rates, and similar items; and

·	market prices and demand for the oil and gas we produce.

Because of the foregoing, the estimates of the economically recoverable quantities of oil and gas attributable to any particular property, the classifications of those reserves based on risk or probability of recovery, and estimates of the future net cash flows expected from such properties prepared by different engineers or by the same engineers but at different times may vary substantially. Therefore, reserve estimates may be subject to upward or downward adjustments, and actual production, revenue, and related expenditures are likely to vary, in some cases materially, from estimates.

In accordance with Securities and Exchange Commission revisions to the rules for estimating oil and gas reserves that we adopted effective December 31, 2009, our reserve estimates are based on 12-month average prices, rather than year-end prices. The application of these new rules results in the use of lower prices for estimating reserves as of December 31, 2009, than under the previous rules, which resulted in a decrease in proved developed reserves of approximately 990,000 cubic feet of natural gas equivalent. Furthermore, our estimates of probable reserves as of December 31, 2009, are calculated using probabilistic, as distinguished from deterministic methods used in estimating proved reserves. The larger quantity of proved plus probable reserves, as compared to proved reserves only, is attributable largely to using a less conservative interpretation of reservoir size and recovery factor in estimating probable reserves.

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 engineering, geological, and geophysical data, we cannot predict accurately the gas or oil potential of individual prospects and drilling targets or the related risks. We sometimes estimate the gross potential or possible reserves of gas or oil in a particular area as part of our evaluation of the exploration potential and related risks. Our estimates are only rough, preliminary geological forecasts of the 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 of possible reserves or oil and gas potential 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 analogous 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.

We have had limited exploratory success in Poland.

Since 1995, we have participated in drilling 29 exploratory wells in Poland, including eight commercial discoveries (Wilga 2, Kleka 11, Zaniemysl-3, Sroda-4, Winna Gora-1, Roszkow-1, Kromolice-1, and Kromolice-2), and 21 noncommercial wells. Of our eight commercial successes in Poland, we were producing gas at our Roszkow-1, Zaniemysl-3, and Kleka 11 wells as of December 31, 2009. Production has been terminated at the Wilga 2 well.

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 sale of gas in Poland, including our recent gas discoveries and other possible future discoveries. We may face delays in obtaining rights-of-way to connect to the POGC pipeline system, construction permits, and materials and contractors; signing gas or oil purchase/sales contracts; receiving commitments for required capital expenditures by POGC, and other factors. Such delays could correspondingly postpone the commencement of cash flow and may require us to obtain additional short-term financing pending commencement of production. Further, we may design and construct surface and pipeline facilities to accommodate anticipated production from additional drilling. We cannot assure that additional drilling will establish additional reserves or production that will provide an economic return for 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, 2009, we have incurred cumulative net losses of approximately $161 million. We expect that our exploration and production activities may continue to result in net losses through 2010 and possibly beyond, depending on whether our activities in Poland and the United States are successful and 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.

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

We currently sell substantially all of the oil and gas we produce 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 market participants. While our contracts provide us with the ability to market gas to other purchasers, including those outside of Poland, we do not expect to have the opportunity to diversify our gas markets in the foreseeable future.

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

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

·	the market and price structure in local markets;

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

·	market uncertainty;

·	the impact of potential climate change on oil and gas demand and prices;

·	political conditions in international oil and gas producing regions;

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

·	the level of consumer demand;

·	weather conditions affecting production, transportation, and consumption;

·	the competitive position of 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 oil and gas; and

·	other factors beyond our control.

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

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

Our oil and gas drilling and production operations are subject to hazards incidental to the industry. These hazards include blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas, and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. To lessen the effects of these hazards, we maintain insurance of various types to cover our domestic and international operations. We cannot assure that the insurance policies carried by us 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 oil and gas exploration, drilling, and production. Where additional insurance coverage does exist, the amount of coverage may not be sufficient to pay the full amount of such liabilities. We may not be insured against all losses or liabilities that may arise from all hazards because such insurance is unavailable at economic rates, because of limitations on existing insurance coverage, or other factors. For example, we do not maintain insurance against risks related to violations of environmental laws. We would be adversely affected by a significant adverse event that is not fully covered by insurance. Further, we cannot assure that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

The effects of global climate change could adversely impact the market demand for oil and gas products and negatively impact our business.

The value of our oil and gas exploration, development, and production activities is and will continue to be a function of the market demand for oil and gas products. If global climate change results in rising average global temperatures, the market demand for oil and gas products used in residential and commercial heating fuels may decrease. This could result in a decrease in demand for oil and gas products and negatively impact our business.

Concerns regarding global climate change could spur legislation or regulation, globalized through treaties or otherwise, that could diminish global demand for oil and gas products and negatively impact our business.

Our oil and gas exploration, development, and production activities in Poland are subject to Poland’s laws and regulations, some of which are designed to meet the requirements of the European Union. Future legislation and regulation could be a part of globalized efforts similar to the Kyoto Protocol, regional systems such as the European Union Emissions Trading Scheme, or other campaigns in response to concerns regarding global climate change. Such laws or regulations could result in taxes or direct limitations on the production of fossil fuels that could diminish global market demand for oil and gas products or curtail or limit our activities in Poland and correspondingly have a negative impact on our business.

Risks Relating to Conducting Business in Poland

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

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

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

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

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

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

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

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

·	political instability and possible changes in government;

·	export and transportation tariffs;

·	local and national tax requirements;

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

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

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

Poland has a regulatory regime governing exploration and development, production, marketing, transportation, and storage of oil and gas. 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, many of Poland’s laws, policies, and procedures were changed to conform to the requirements that had to be met before Poland was admitted as a full member of the European Union.

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

Operations on our project areas are subject to environmental laws and regulations in Poland that provide for restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with oil and gas exploration and development. Additionally, if significant quantities of gas are produced with oil, regulations prohibiting the flaring of gas may inhibit oil production. In such circumstances, the absence of a gas-gathering and delivering system may restrict production or may require significant expenditures to develop such a system prior to producing oil and gas. We are required to prepare and obtain approval of environmental impact assessments by governmental authorities in Poland prior to commencing 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. 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.

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 $2.12 and as high as $4.97 during intraday trading between January 1, 2009, 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;

·	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 that may impact our revolving credit facility;

·	prevailing world prices for oil and gas;

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

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

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

New rules may make it difficult for us to obtain a stockholder meeting quorum required for a valid meeting to elect directors and transact other business.

Since our last annual meeting, the New York Stock Exchange changed the rules so that brokerage firms and other institutions holding stock of record in their name for the benefit of others may not vote such shares for the election of directors and other nonroutine matters without specific voting instructions from beneficial owners. As a result, brokerage firms and other institutions may not return sufficient proxies to constitute a quorum if the beneficial owners of such shares do not provide instructions. Even if a quorum is obtained, these recently adopted provisions may reduce substantially the number of votes cast for the election of directors, which may result in the failure to elect one or more directors. Notwithstanding the failure to elect directors at the annual meeting, such directors may hold-over and continue to serve until their successors are elected at a subsequent meeting. If this were to occur, the board would include directors not recently elected by the stockholders.

Our current rating by third-party corporate governance consultants advising institutional stockholders may result in recommendations that incumbent directors not be reelected.

Various corporate governance consultants advising institutional investors and others provide scores or ratings of our governance measures, nominees for election as directors, and other matters that may be submitted to the stockholders for consideration. Although the full details of such scores or ratings by consultants are not available to us, we expect that certain nominees or matters that we propose for approval from time to time may not merit a favorable score or rating or may result in a negative score or rating or recommendation that the nominee or matter be rejected. We believe that approximately 25% of our stock may be held by institutions that may be advised by such consultants. Accordingly, unfavorable scores or ratings by such consultants could adversely affect our ability to obtain reelection of incumbent directors or the approval of other matters in accordance with management’s recommendations. We have reviewed certain governance measures, such as our classified board and stockholder rights plan, that we believe contribute to our low scores and ratings and have determined that such governance provisions are in the best interests of our stockholders notwithstanding the adverse effect of such provisions on such scores or ratings.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Proved Reserves Disclosures

Recent Securities and Exchange Commission Rule-Making Activity

·	Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on the use of unweighted, 12-month first day of the month historical average prices adjusted for basis and quality differentials, rather than year-end prices.

·	Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

·	Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

·	Third-Party Reserves Preparation – If a company represents that its estimates of reserves are prepared or audited by a third party, the company must file a report of the third party as an exhibit to the relevant registration statement or report.

·	Use of Probabilistic Methods – Reserves may be estimated using probabilistic methods in which there is at least a 90% probability of recovery of “proved” reserves, at least a 50% probability of recovery of “probable” reserves, and at least a 10% probability of recovery of “possible” reserves.

·	Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total oil and gas proved reserves.

Additional disclosure as provided below was also required by the Securities and Exchange Commission revisions. We adopted the rules effective December 31, 2009.

Effect of Adoption

Application of the new rules resulted in the use of lower prices at December 31, 2009, for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009, as required by the new rules, resulted in a decrease in proved developed oil reserves of approximately 990,000 cubic feet of natural gas equivalent. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.

Internal Controls over Reserves Estimates

Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the Securities and Exchange Commission’s definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Responsibility for compliance in reserves bookings is delegated to our operations and finance staff, who submit technical and financial data to third-party engineering firms.

Estimates of our proved Polish reserves were calculated by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved domestic reserves were calculated by Hohn Engineering, an independent engineering firm in Billings, Montana. The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both RPS Energy and Hohn Engineering are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Proved Undeveloped Reserves

As of December 31, 2009, our proved undeveloped reserves totaled 27.3 Bcf of natural gas. All of our proved undeveloped reserves are located in Poland, and all are associated with wells that have been drilled, tested, and completed for production. We do not have any proved undeveloped reserves attributable to undrilled locations. These reserves are classified as proved undeveloped because relatively major expenditures are required for the completion of production facilities, which includes the construction of pipelines to connect the wells to the existing pipeline in order to fully develop the reserves and commence production. The development of such undeveloped reserves is not dependent on additional drilling on undrilled acreage. All development activities will be completed within five years.

Changes in Proved Undeveloped Reserves

Changes in proved undeveloped reserves that occurred during the year were primarily due to:

·	conversion of approximately 14.6 Bcf of existing proved undeveloped reserves into proved developed reserves upon the commencement of production at our Roszkow well; and

·	new proved undeveloped reserves of approximately 4.6 Bcf associated with the Kromolice-2 well that we completed in early 2009.

Development Costs

Costs incurred relating to the development of proved undeveloped reserves were approximately $3.7 million in 2009, all of which was attributable to the construction of production facilities at Roszkow.

Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $8.2 million in 2010 and $3.9 million in 2011. The estimated development costs are for the design and construction of facilities at our KSK wells in 2010 and our Winna Gora well in 2011.

For more information see the following:

·	Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Proved Reserves for a discussion of changes in proved reserves;

·	Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Oil and Gas Reserves for further discussion of our reserves estimation process;

Item 8, Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.

Other Reserves Information

Since January 1, 2009, no crude oil or natural gas reserves information has been filed with, or included in any report to, any other federal authority or agency.

Reserve Volumes and Values

The following table sets forth our estimated proved developed, proved undeveloped, and probable reserves volumes as of December 31, 2009:

	United States	Poland	Total
	MBbls	MMcf	MMcfe
Proved developed reserves	463	20,409	23,187
Proved undeveloped reserves	--	27,259	27,259
Total proved reserves	463	47,668	50,446
Probable reserves	--	42,265	42,265
Total proved plus probable reserves	463	89,933	92,711

The following table sets forth the estimated PV-10 (after tax) values of our proved plus probable reserves as of December 31, 2009:

	Total Net		PV-10
	Reserves		Value
	(MMcfe)	(In thousands)

Proved	50,446		$ 145,823
Probable	42,265		68,283
Total Proved and Probable	92,711		$ 214,107

Our proved reserves were calculated using both deterministic and probabilistic methods. Our proved reserves were calculated using deterministic methods. Our probable reserves were calculated using probabilistic methods and represent the 50% probability that the actual quantities recovered will be equal to or greater than the proved plus probable estimate. No additional drilling is required at any of our Polish wells to achieve the recovery of the probable reserves. The larger quantity of proved reserves plus probable reserves, as compared to proved reserves only, is attributable largely to using a less conservative interpretation of reservoir size and recovery factor in estimating probable reserves.

Drilling Activities

The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2009, 2008, and 2007:

	Years Ended December 31,
	2009		2008		2007
	Gross	Net	Gross	Net	Gross	Net
Exploratory productive wells:
Poland	1.0	0.5	1.0	0.5	2.0	1.0
United States	--	--	--	--	--	--
Total	1.0	0.5	1.0	0.5	2.0	1.0

Exploratory dry holes:
Poland	--	--	2.0	1.0	--	--
United States	1.0	0.5	3.0	1.5	--	--
Total	1.0	0.5	5.0	2.5	--	--

Total wells drilled	2.0	1.0	6.0	3.0	2.0	1.0

Wells and Acreage

As of December 31, 2009, our producing gross and net well count consisted of the following:

	Number of Wells
	Gross	Net
Well count:
Poland(1)	3.0	1.2
United States(2)	129.0	122.3
Total	132.0	123.5

_______________

(1)	As of December 31, 2009, 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 oil and gas acreage as of December 31, 2009:

	Developed		Undeveloped
	Gross	Net	Gross	Net

Poland: (1)
Fences project area	350	171	852,000	406,000
Block 255 project area	543	441	236,000	194,000
Northwest project area	--	--	943,000	943,000
Kutno project area	--	--	706,000	706,000
Warsaw South project area			638,000	638,000
Block 287 project area	--	--	13,000	13,000
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	893	612	4,743,000	4,255,000

United States:
Montana	10,732	10,418	4,510	4,417
Nevada	400	128	9,332	6,351
Total	11,132	10,546	13,842	10,768

Total Acreage	12,025	11,158	4,756,842	4,265,768

_______________

(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 2009 follows:

	Average Daily		Average	Average
	Production (Mcfe)(1)		Working	Net Revenue
	Gross	Net	Interest	Interest
Fences project area	25,410	9,974	41%	41%
Grabowka	488	488	100%	100%
Block 255/Wilga	238	196	82%	82%
Total	26,136	10,658

_______________

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

Production, Transportation and Marketing

We began producing and selling gas from our Roszkow well in late 2009. Production from our Wilga well ceased during 2009. We expect production will increase as we place four previous discoveries into production in 2010 and 2011.

The following table sets forth our net daily oil and gas production, average sales price, and average production costs associated with our Polish production during 2009, 2008, and 2007:

	2009	2008	2007

Average daily net gas production (Mcf)(1)	10,644	3,428	5,039
Average sales price per Mcf	$5.01	$5.92	$4.95

Average daily net oil production (Bbls)(1)	2	10	69
Average sales price per Bbl	$54.96	$107.68	$58.68

Average daily net Mcfe production(1)	10,658	3,488	5,453
Average production costs per Mcfe(2)	$0.51	$0.70	$0.58

_______________

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

United States Properties

Producing Properties

In the United States, we currently produce oil in Montana and Nevada. All of our producing properties, except for the Rattlers Butte field (an exploratory discovery during 1997), were purchased during 1994. A summary of our average daily production, average working interest, and net revenue interest for our United States producing properties during 2009 follows:

	Average Daily		Average	Average
	Production (Bbls)		Working	Net Revenue
	Gross	Net	Interest	Interest
Montana	191	163	99%	85%
Nevada	49	12	31%	29%
Total United States producing properties	240	175

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 115 producing oil wells, 28 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.

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 2009, 2008, and 2007:

	Years Ended December 31,
	2009	2008	2007
United States producing property data:
Average daily net oil production (Bbls)	175	181	192
Average sales price per Bbl	$51.92	$86.91	$61.75
Average production costs per Bbl(1)	$39.62	$38.89	$34.12

_______________

(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 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 oil and gas 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).

Prior to becoming a parliamentary democracy during 1989, the exploration and development of Poland’s oil and gas resources were hindered by a combination of foreign influence, a centrally controlled economy, limited financial resources, and a lack of modern exploration technology. As a result of these and other factors, Poland is currently a net energy importer. Oil is imported primarily from countries of the former Soviet Union and the Middle East, and gas is imported primarily from Russia.

During 2009, Poland was the only country in Europe to record positive gross domestic product, or GDP, growth. Current forecasts project that Poland will again lead all European countries in economic performance in 2010.

Legal Framework

General Usufruct and Concession Terms

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

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 respecting the Fences area, the continuity of POGC as the record owner.

The concession authority has granted POGC oil and gas exploration rights on the Fences project area and has granted us oil and gas exploration rights on all other project areas in which we have an interest. The agreements divide these areas into blocks, each 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 low-methane gas such as we produce is currently less than $0.04 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 oil and gas exploration concessions controlled by POGC. Three producing fields (Radlin, Kleka, and Kaleje) lie within the concession boundaries, but are excluded from the Fences area in which we participate. The Fences concessions have expiration dates ranging from August 2012 to July 2015. The total joint remaining work commitment, which must be satisfied by us and POGC according to our respective working interests, includes: acquiring 50 kilometers of 2-D seismic data, acquiring 250 square kilometers of 3-D seismic data, and drilling five wells.

Wilga/Block 255 Project Area

The Wilga project area consists of a single oil and gas exploration concession held by us that expires in August 2012. The remaining period carries a work commitment of 80 kilometers of 2-D seismic data and optional drilling of up to three wells.

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, 40 kilometers of which have already been completed; Phase III – three years: drilling four wells.

Block 287 Project Area

The Block 287 project area consists of a single oil and gas 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 expires in December 2012. Work commitment includes re-entering and producing the Grabowka gas field; reconstruction of one out of three wells was completed and production began in 2009.

Northwest Project Area

The Northwest project area consists of seven oil and gas 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 - three years (extended from two): acquiring 800 kilometers of new 2-D seismic data; Phase III – two years (reduced from three): 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. We are in the process of terminating two of the seven concessions and reducing the work commitment to a total of 700 kilometers in the remaining five blocks, 240 kilometers of which have already been completed. Part of the drilling commitment was satisfied during 2009 by drilling the Ostrowiecz well.

Kutno Project Area

The Kutno project area consists of three oil and gas 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 data; 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.

Edge Project Area

The Edge project area consists of four oil and gas 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. The concession expires in September 2013.

Block 246 Project Area

The Block 246 project area is adjacent to the Fences project area in the southwest 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. The concession expires in December 2014.

Block 229 Project Area

The Block 229 project area is adjacent to the Fences project area in the east 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. The concession expires in August 2014.

As of December 31, 2009, all required usufruct/concession payments had been made for each of the above project areas.

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 oil and gas exploration, development, and production activities generally are required to: (1) adhere to good international petroleum industry practices, including practices relating to the protection of the environment; and (2) prepare and submit geological work plans, with specific attention to environmental matters, to the appropriate agency of state geological administration for its approval prior to engaging in field operations such as seismic data acquisition, exploratory drilling, and field-wide development. Poland’s regulatory framework respecting environmental protection is not as fully developed and detailed as that which exists in the United States. We intend to conduct our operations in Poland in accordance with good international petroleum industry practices and, as they 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 oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and impose certain requirements regarding the ratability of production.

Our oil production is affected to some degree by state regulations. States in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes and related regulations are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.

Environmental Regulations

The federal government and various state and local governments have adopted laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and impose substantial liabilities for pollution resulting from our operations. These laws and regulations may also increase the costs of drilling and operating wells. We may also be held liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990, or OPA ‘90. In addition, we may be subject to other civil claims arising out of any such incident. As with any owner of property, we are also subject to clean-up costs and liability for hazardous materials, asbestos, or any other toxic or hazardous substance that may exist on or under any of our properties. We believe that we are in compliance in all material respects with such laws, rules, and regulations and that continued compliance will not have a material adverse effect on our operations or financial condition. Furthermore, we do not believe that we are affected in a significantly different manner by these laws and regulations than our competitors in the oil and gas industry.

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Furthermore, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

The Resource Conservation and Recovery Act, or RCRA, and regulations promulgated thereunder govern the generation, storage, transfer, and disposal of hazardous wastes. RCRA, however, excludes from the definition of hazardous wastes “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, gas, or geothermal energy.” Because of this exclusion, many of our operations are exempt from RCRA regulation. Nevertheless, we must comply with RCRA regulations for any of our operations that do not fall within the RCRA exclusion.

The OPA ‘90 and related regulations impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 establishes strict liability for owners of facilities that are the site of a release of oil into “waters of the United States.” While OPA ‘90 liability more typically applies to facilities near substantial bodies of water, at least one district court has held that OPA ‘90 liability can attach if the contamination could enter waters that may flow into navigable waters.

Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future, such as proposals made in Congress and at the state level from time to time, that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes” and make the reclassified wastes subject to more stringent and costly handling, disposal, and clean-up requirements. The impact of any such changes, however, would not likely be any more burdensome to us than to any other similarly situated company involved in oil and gas exploration and production.

Federal and Indian Leases

A substantial part of our producing properties in Montana consists of oil and gas leases issued by the Bureau of Land Management or by the Blackfeet Tribe under the supervision of the Bureau of Indian Affairs. Our activities on these properties must comply with rules and orders that regulate aspects of the oil and gas industry, including drilling and operating on leased land and the calculation and payment of royalties to the federal government or the governing Indian nation. Our operations on Indian lands must also comply with applicable requirements of the governing body of the tribe involved including, in some instances, the employment of tribal members. We believe we are currently in full compliance with all material provisions of such regulations.

Safety and Health Regulations

We must also conduct our operations in accordance with various laws and regulations concerning occupational safety and health. Currently, we do not foresee expending material amounts to comply with these occupational safety and health laws and regulations. However, since such laws and regulations are frequently changed, we are unable to predict the future effect of these laws and regulations.

Title to Properties

We rely on sovereign ownership of exploration rights and mineral interests by the Polish government in connection with our activities in Poland and have not conducted and do not plan to conduct any independent title examination. We regularly consult with our Polish legal counsel when doing business in Poland.

Nearly all of our United States working interests are held under leases from third parties. We typically obtain a title opinion concerning such properties prior to the commencement of drilling operations. We have obtained such title opinions or other third-party review on all of our producing properties, and we believe that we have satisfactory title to all such properties sufficient to meet standards generally accepted in the oil and gas industry. Our United States properties are subject to typical burdens, including customary royalty interests and liens for current taxes, but we have concluded that such burdens do not materially interfere with the use of such properties. Further, we believe the economic effects of such burdens have been appropriately reflected in our acquisition cost of such properties and reserve estimates. Title investigation before the acquisition of undeveloped properties is less thorough than that conducted prior to drilling, as is standard practice in the industry.

Employees and Consultants

As of December 31, 2009, we had 49 employees, consisting of nine in Salt Lake City, Utah; 23 in Oilmont, Montana; one in Greenwich, Connecticut; two in Houston, Texas; and 14 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 $7,700 per month.

Oil and Gas Terms

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

“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.

“BTU” means British thermal unit.

“Ca2” refers to specific calcium-rich geological formations, typically a dolomitic reef.

“Deterministic” means a method of estimating reserves in which a simple value for each parameter of geoscience, engineering, or economic data in the reserves calculation is used in the reserves estimation.

“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.

“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.

“Probabilistic” means a method of estimating reserves using the full range of values that could reasonably occur for each unknown from the geoscience and engineering data to generate a full range of possible outcomes and their associated probabilities of occurrence.

“Proved reserves” means the estimated quantities of crude oil, gas and gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. “Proved reserves” may be developed or undeveloped.

“PV-10 Value” means the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10.0%, the Standardized Measure of Future Net Cash Flows (“SMOG”). These amounts are calculated net of estimated production costs, future development costs, and future income taxes, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property-related expenses, such general and administrative costs, debt service, and depreciation, depletion, and amortization.

“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and that is distinct and separate from other reservoirs.

“Tcf” means trillion cubic feet of natural gas.

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

ITEM 3. LEGAL PROCEEDINGS

We are not a party to any material legal proceedings, and no material legal proceedings have been threatened by us or, to the best of our knowledge, against us, except as follows:

On June 26, 2009, the court dismissed all claims against all defendants for failure to state a claim upon which relief could be granted in the consolidated single matter, In re FX Energy, Inc., Securities Litigation, United States District Court, District of Utah, case no. 2:07-cv-00874. The lead plaintiff had alleged 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 between January 20, 2005, and January 5, 2006, regarding our Sroda-5 and Lugi-1 projects and sought damages to be determined at trial, interest, costs, and such other relief as the court may deem appropriate. The time for filing an appeal to this dismissal expired without an appeal being filed by plaintiff.

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 our current and former directors and certain of our current and former executive officers, arising out of the same set of facts. This action was stayed pending final resolution of the In re FX Energy, Inc., Securities Litigation matter, which has now been dismissed as noted above. There have been no further proceedings in the Leilani York matter.

ITEM 4. [RESERVED]

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
2010:
First Quarter (through March 15, 2010)	$ 2.85	$ 3.53

2009:
Fourth Quarter	2.39	3.28
Third Quarter	3.05	4.71
Second Quarter	2.91	4.56
First Quarter	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

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 15, 2010, we had approximately 10,000 stockholders.

Equity Compensation Plans

The information from the definitive proxy statement for the 2010 annual meeting of stockholders under the caption “Equity Compensation Plans” is incorporated herein by reference.

Recent Sales of Unregistered Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for the five years ended December 31, 2009, 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,
	2009	2008	2007	2006		2005
	(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales	$ 12,772	$ 13,494	$ 14,903		$ 6,533		$ 3,805
Oilfield services	1,892	4,347	3,093		1,696		2,132
Total revenues	14,664	17,841	17,996		8,229		5,937
Operating costs and expenses:
Lease operating expenses (1)	3,478	3,441	3,538		2,647		2,462
Exploration costs (2)	4,829	15,389	10,624		5,608		8,369
Recovery of previously expensed
Input VAT	--	--	--		--		(2,121)
Impairments / ARO revisions (3)	1,3335	14,746	2,299		3,583		--
Oilfield services costs	1,412	2,751	1,998		1,245		1,689
Depreciation, depletion and
amortization	1,602	1,720	2,064		1,290		903
Accretion expense	41	84	78		53		45
Amortization of deferred
compensation	1,693	2,367	2,604		2,759		125
Stock compensation	--	--	--		--		76
Bad debt expense	--	460	--		--		--
General and administrative (G&A)	7,257	7,030	7,061		5,728		6,420
Total operating costs and expenses	21,647	47,988	30,266		22,913		17,968

Operating loss	(6,983)	(30,147)	(12,270)		(14,684)		(12,031)

Other income (expense):
Interest and other income	54	394	818		795		780
Foreign exchange gain (loss)	7,053	(24,279)	146		122		(172)
Interest expense	(654)	(672)	(385)		--		--
Total other income (expense)	6,453	(24,557)	579		917		608

Net loss	$ (530)	$ (54,704)	$ (11,691)		$ (13,767)		$ (11,423)

– Continued –

	Years Ended December 31,
	2009	2008	2007	2006		2005
	(In thousands, except per share amounts)

Basic and diluted net loss
per common share	$ (0.01)	$ (1.35)	$ (0.32)		$ (0.39)		$ (0.33)

Basic and diluted weighted average
shares outstanding	42,529	40,420	36,694		35,163		34,733

Cash Flow Statement Data:
Net cash used in operating activities	$ (5,829)	$(14,248)	$ (1,581)		$ (5,303)		$(10,105)
Net cash (used in) provided by
investing activities	(3,999)	(11,772)	(13,152)		8,135		4,656
Net cash (used in) provided by
financing activities	(2,676)	40,121	14,351		(578)		4,055

Balance Sheet Data:
Working capital	$ 3,452	$ 13,965	$ 15,374		$ 11,967		$ 27,715
Total assets	42,070	54,802	46,369		39,167		48,271
Long-term debt	25,000	25,000	--		--		--
Stockholders’ equity	10,745	15,154	37,542		31,965		42,280

_______________

(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 and revisions to our asset retirement obligations.

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.

We are an independent energy company engaged in the exploration and production of natural gas and crude oil. We operate primarily in Poland and in the Rocky Mountains.

The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.

Overview

We explore for and produce natural gas and crude oil. Our strategy is to achieve growth in production, reserves, and earnings and cash flows through the continued expansion of a high quality portfolio of exploration and development projects in Poland.

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 oil and gas production in Poland. In 2009, with the commencement of production at our Roszkow well and our current facilities construction to place previously drilled wells into production, we now expect Poland to be the primary source of company revenues for the foreseeable future. See “Results of Operations by Business Segment” below.

Strategy

Our objective is to continue our strong historic growth trend (30% compound annual growth rate in proved reserves value from 2003 to 2009) to deliver superior value to our shareholders. We primarily focus on organic growth from exploration and development drilling on our own prospects. We concentrate on areas where we believe we have a strategic competitive advantage and which we believe offer superior returns. Our core operating area is the Permian basin of western Poland. 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 United Kingdom, Dutch, and German sectors. For most of the twentieth century, Poland was closed to exploration by foreign oil and gas companies. Consequently, we think the Polish Permian Basin is underexplored and underexploited and, therefore, has high potential for discovering significant amounts of oil and gas.

Oil and Gas Reserves

As a result of our ongoing drilling and production successes in Poland, 2009 was the sixth 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 2008 to 2009:

	2009	2008	Change
	(In thousands)
Proved Reserve Volumes:
Gas Reserves (Mcf)	47,668	45,312	+5%
Oil Reserves (Bbls)	463	92	+403%
Total Reserves (Mcfe)	50,446	45,864	+10%

Proved Reserve Values:
Reserves PV-10 Value	$145,823	$117,568	+24%

The 2009 natural gas discovery at the Kromolice-2 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 9.3 Bcf of gas (4.6 Bcf net to our 49% interest). We also recorded new reserves of 1.7 Bcf at our Grabowka re-entry project, where we own 100% of the concession. In addition to these two new projects, we also recorded upward revisions of approximately 418,000 barrels of oil in the United States, primarily due to higher oil prices resulting in more economically recoverable barrels. These additions were partially offset by negative revisions at our Wilga well, which stopped producing in late 2009. We are planning to plug the well and dismantle the facilities during 2010.

Operating and Financial Results

The oil and gas industry had a challenging year in 2009 due to the prolonged recession and commodity price volatility. Many companies in our industry were unable to react to these conditions and are facing significant challenges to their ability to survive. Stock prices for most companies our size continued to experience declines and depressed levels. Despite these conditions, we were able to reach record year-end production levels, move forward on two important development projects, pursue additional exploration opportunities (which resulted in the sixth consecutive year of growth in the value of our proved reserves), and position ourselves for continued growth in 2010 without diluting our shareholders’ interests or incurring additional debt in 2009. We believe we have adequate liquidity to continue our growth pattern in 2010.

Our 2009 operational and financial highlights included the following:

·	the discovery of commercial gas reserves at the Kromolice-2 well;

·	the completion of production facilities and the commencement of production at our Roszkow well, which is currently producing at a rate of 14.5 MMcfd (7.1 MMcfd net to us), a rate that we expect to be constant for at least the next three years;

·	the sixth consecutive year of proved reserves value growth;

·	record fourth quarter 2009 production and year-end production rates;

·	initial progress on the design of our KSK production facilities, which we expect to increase our daily production by approximately 6.9 MMcfd day when production commences, scheduled for late 2010;

·	approvals to begin work on our Winna Gora production facility, scheduled for completion during 2011;

·	the completion of a new 3-D seismic project in our core Fences area;

·	the identification of new drill sites in our core Fences area;

·	the design of a development plan at our Zakowo project in Block 246;

·	a net operating loss of $7.0 million, compared with a net operating loss of $30.1 million for 2008; and

·	net cash used in operations of $5.8 million, compared to $14.2 million for 2008.

We ended the year with total proved reserves of 50.4 Bcfe, compared with 45.9 Bcfe at the end of 2008. See “Proved Reserves” discussion below.

Adapting to Global Economic Conditions

Our business in 2009 was negatively impacted by the recession that began in 2008 and continues to impact world economies, as well as by the changes in the credit markets and ongoing volatile commodity prices. During late 2008 and throughout 2009, we took steps, particularly in areas in which we have some control, to maintain our liquidity in response to the ongoing uncertainty, without diluting our shareholders’ interests. As a result of our actions, some of which are described below, we believe we have weathered much of the economic storm and are poised to achieve significant progress on several fronts in 2010.

Capital and Operating Budgets. Other than for capital projects that were committed and in process at year-end 2008, we 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, which began in September. Increased production and cash flow should allow us to begin new capital projects during 2010.

We took 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 further reduced 2009 cash overhead costs by 8% from budgeted amounts, again by reducing compensation and other controllable costs.

We closely monitor lease operating costs and are working with our partner in Poland to implement efficiencies where possible. We are also continuing to seek reductions in third-party drilling costs and services.

Credit Markets. We have a $25 million Senior Facility Agreement with the Royal Bank of Scotland, or RBS, in London, England. We are in compliance with all of the terms of the facility and are in active discussions to extend and expand the terms and size of the facility. We believe we have reserve volumes and values that would warrant a sizable increase in the facility and have received proposals for a larger new credit facility. We determined to defer refinancing, rather than to press forward during 2009 for the following reasons: (1) interest rates seemed to be abnormally elevated given then-current economic conditions and our reserve position; (2) rates under our existing facility were extremely low compared to then-current and present rates; and (3) we did not have a pressing need for any new debt capacity.

We believe our patience has been rewarded. Current interest rates for a facility of our desired size appear to be significantly lower than they were a few months ago. With the construction of our KSK facilities scheduled for this summer and a need for additional debt financing, we are now engaged in new facility discussions. We are seeking to refinance our existing facility, increase the size of the facility, and extend the maturity dates. In early 2010, we signed a Mandate Letter with RBS, authorizing it to proceed with the expansion of our existing facility to $50 million. As part of the refinance process, RBS reset the date of the first rescheduled principal reduction of our existing facility to May 31, 2011.

Equity Markets. 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 are accessible, we have been unwilling to issue new equity at stock prices that we believe do not adequately reflect our underlying value.

Commodity Prices. Global oil prices continued to be volatile during 2009. Gas prices in the United States decreased significantly for much of 2009. The European gas market operates quite differently than the U.S. 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 2009, the Polish regulator reduced low-methane tariffs by 5% in response to the global recession. 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 oil prices. With the recent volatility in oil prices, 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; however, other major components of the tariff calculation include the cost of gas provided by POGC itself, as well as the necessity for POGC to cover its internal cost structure. 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 Polish gas prices to free-market levels. In addition, Poland was the only country in Europe to record positive GDP growth during 2009, and economists predict another positive year during 2010. These factors may act as cushions against possible declines in prices. As of year-end 2009, 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 2008 to 2009. However, our gas reserves are price-sensitive, and future material reductions in the prices at which we sell our gas in Poland could result in the impairment of reserves.

Property Impairments

During the third quarter of 2009, production ceased at our Wilga well in eastern Poland. Accordingly, we impaired the remaining $1.9 million in capital costs associated with the well at that time. This impairment was a noncash charge and was offset by revisions to our asset retirement obligations.

Foreign Currency Volatility

We enter into various agreements in Poland denominated in the Polish zloty. The exchange rate between the U.S. dollar and the Polish zloty is subject to fluctuations that are beyond our control. During 2009, the zloty fluctuated between a low of 2.71 zlotys per U.S. dollar to a high of 3.90 zlotys per dollar. Variations in exchange rates 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 2010 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our U.S. dollar-denominated revenues compared to 2009.

At the same time, however, our U.S. dollar-denominated costs of conducting business in Poland, which include drilling, geological and geophysical, and overhead costs, will also change as exchange rates fluctuate. 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 and when necessary, transferring dollars to zlotys or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making significant commitments 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.

Effective October 1, 2008, we changed the functional currency of our Polish subsidiary from the U.S. dollar to the Polish zloty. Accounting standards require 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 $3.6 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, 2009 and 2008, the CTA was approximately $10.7 million and $17.1 million, respectively, 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 2009, we recorded foreign currency transaction gains of approximately $7.1 million; in 2008, we recorded foreign currency transaction losses of approximately $24.3 million. These gains or losses are principally attributable to changes 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

Production from our Roszkow well, which began producing at a rate of 15 MMcfd in September 2009, more than offset expected declines at our Wilga well. However, lower average prices for both oil and gas, coupled with a decrease in our drilling services revenues, led to reductions in both oil and gas sales and total revenues. The following table highlights revenues, production volumes, and oil and gas pricing, showing the change from 2008 to 2009:

	2009	2008	Change
	(In thousands)
Revenues:
Oil & Gas Sales	$ 12,772	$ 13,494	-5%
Total Revenues	$ 14,664	$ 17,841	-18%

Production:
Gas Production (Mcf)	1,882	1,251	+50%
Oil Production (Bbls)	64	69	-7%
Total Production (Mcfe)	2,266	1,671	+36%

Pricing:
Average Gas Prices (per Mcf)	$5.01	$5.92	-15%
Average Oil Prices (per Bbl)	$52.03	$88.01	-41%

We expect to see significant increases in both production and oil and gas revenues during 2010 as we record a full year’s production from our Roszkow well, which is projected to average approximately 14.5 MMcfd (7.1 MMcfd net to our interest) for the entire year.

Results of Operations by Business Segment

We operate within two segments of the oil and gas industry: the exploration and production, or E&P, segment in Poland and the United States, and the oilfield services segment in the United States. Direct revenues and costs, including depreciation, depletion and amortization costs, or DD&A, general and administrative costs, or G&A, and other income directly associated with their respective segments are detailed within the following discussion. DD&A, G&A, amortization of deferred compensation, interest income, other income, interest expense, and other costs, which are not allocated to individual operating segments for management or segment reporting purposes, are discussed in their entirety following the segment discussion. The following table summarizes the results of operations by segment for the years ended December 31, 2009, 2008, and 2007 (in thousands):

	Reportable Segments
			Oilfield Services
	Exploration & Production		Oilfield Services
	Poland	U.S.		Non-Segmented	Total
Year ended December 31, 2009:
Revenues	$ 9,459	$ 3,313	$ 1,892	$ --	$ 14,664
Net income (loss)(1)	1,141	1,033	(117)	(2,587)	(530)

Year ended December 31, 2008:
Revenues	$ 7,798	$ 5,695	$ 4,348	$ --	$ 17,841
Net income (loss)(2)	(19,548)	(1,847)	725	(34,034)	(54,704)

Year ended December 31, 2007:
Revenues	$ 10,567	$ 4,336	$ 3,093	$ --	$ 17,996
Net income (loss)(3)	(4,415)	1,102	828	(9,206)	(11,691)

_______________

(1)	Nonsegmented reconciling items for 2009 include $7,257 of G&A costs, $1,693 of noncash stock compensation expense, $7,053 of foreign exchange gains, $600 of other expense, and $90 of corporate DD&A.

(2)	Nonsegmented reconciling items for 2008 include $7,030 of G&A costs, $2,367 of noncash stock compensation expense, $24,279 of foreign exchange losses, $278 of other expense, and $80 of corporate DD&A.

(3)	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.

See note 13 in the notes to the consolidated financial statements for additional detail concerning our segment results.

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $9.4 million during 2009, compared to $7.4 million and $9.1 million in 2008 and 2007, respectively. Our 2009 gas revenues increased from 2008 levels by approximately $3.0 million due to higher production, offset by approximately $1.0 million due to lower year-over-year gas prices. 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.

Two new wells began production during 2009. Production commenced at our Roszkow well in late September at a rate of 15 MMcfd (7.4 MMcfd net to our 49% interest). Gas is being sold to POGC at a contracted rate equal to 95% of the published low-methane tariff. As of December 31, 2009, the net price for gas at the Roszkow well was $6.01 per MMcf.

Production also began during the third quarter of 2009 at our Grabowka well. PL Energia, a gas distribution company in Poland, is the purchaser of the gas from the Grabowka field. Under a three well re-entry program, gas is sold at a fixed rate of approximately $1.62 per MMcf (approximately $2.70 per million BTUs based on 60% methane content). This price, which is lower than the current market price, was agreed upon in order to compensate the buyer for bearing all of the cost and risk of re-entering and completing the wells and paying for construction of the production facilities. Gas is being compressed and transported by truck. The combination of the purchaser-provided financing of all development costs and the lower than normal gas price effectively creates economic outcome and risk similar to a royalty interest for us.

We ceased production at our Wilga well in eastern Poland, despite repeated workover attempts during the third quarter of 2009. We have impaired the remaining capitalized costs at Wilga and are planning to plug the well and dismantle the production facility.

Although the Polish low-methane tariff averaged about 9% higher during 2009 compared to 2008, average U.S. dollar-denominated gas prices related to our Poland production decreased 15% from 2008 to 2009. The average exchange rate during 2008 was 2.41 zlotys per U.S. dollar, compared with 3.12 zlotys per U.S. dollar during 2009, a change of 30%.

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, 2009, 2008, and 2007, is set forth in the following table:

	For the year ended December 31,
	2009	2008	2007
Revenues	$9,430,000	$7,404,000	$9,098,000
Percent change versus prior year	+27%	-19%	+408%
Average price (per Mcf )	$5.01	$5.92	$4.95
Percent change versus prior year	-15%	+20%	+28%
Production volumes (Mcf)	1,882,000	1,251,000	1,840,000
Percent change versus prior year	+50%	-32%	+299%
Lifting costs per Mcf (1)	$0.48	$0.65	$0.63
Percent change versus prior year	-26%	+3%	+17%

_______________

(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 $3.3 million, $6.1 million, and $5.8 million for the years ended December 31, 2009, 2008, and 2007, respectively. Significantly lower average oil prices in 2009 compared to 2008 was the primary cause for the decline in revenues. Our average oil price during 2009 was $52.03 per barrel, a 41% decrease compared to $88.01 per barrel received during 2008. In addition, oil production at Wilga declined, as expected, by 100% from 2008 to 2009. Production from our U.S. properties declined by 3% due to normal production declines.

Included in oil revenues were approximately $29,000, $394,000, and $1.5 million related to the sale of oil at the Wilga well for the years ended December 31, 2009, 2008, and 2007, respectively. All other oil revenues during the three years were derived from our producing properties in the United States. U.S. oil revenues in 2009 decreased from 2008 levels by approximately $2.2 million due to lower oil prices, in addition to approximately $150,000 related to production declines. 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.

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, 2009, 2008, and 2007, is set forth in the following table (in thousands, except for prices and percentages):

	For the year ended December 31,
	2009	2008	2007
Revenues	$3,342,000	$6,090,000	$5,804,000
Percent change versus prior year	-45%	+5%	+22%
Average price (per Bbl )	$52.03	$88.01	$60.86
Percent change versus prior year	-41%	+45%	+8%
Production volumes (Bbl)	64,226	69,192	95,242
Percent change versus prior year	-7%	-27%	+13%
Lifting costs per Bbl (1)	$40.08	$38.07	$27.04
Percent change versus prior year	+5%	+41%	+7%

_______________

(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 oil and gas. Lifting costs include production taxes incurred in the United States.

Lease Operating Costs. Lease operating costs were $3.5 million in 2009, $3.4 million in 2008, and $3.5 million in 2007. Operating costs increased slightly in 2009 with the commencement of production at our Roszkow well. Operating costs decreased slightly in 2008 from 2007 as we negotiated lower indirect costs at our non-operated properties in Poland.

Exploration Costs. Exploration expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes. Exploration costs were $4.8 million, $15.4 million, and $10.6 million for the years ended December 31, 2009, 2008, and 2007, respectively.

Geological and geophysical costs, or G&G costs, were $4.7 million, $15.0 million, and $10.6 million for the years ended December 31, 2009, 2008, and 2007, 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 area in Poland.

Exploratory dry-hole costs were $0.2 million, $0.4 million, and $0 for the years ended December 31, 2009, 2008, and 2007, respectively. During 2009, we drilled one dry hole in Nevada. 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.

Impairment Costs. Impairments of oil and gas properties were $1.9 million, $14.7 million, and $2.3 million for the years ended December 31, 2009, 2008, and 2007, respectively. As discussed previously, production at our Wilga well ceased during 2009, and we impaired its remaining capital costs and offset the impairment by $0.5 million related to revisions of our asset retirement obligations. 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 due to negative reserve revisions that resulted in lower estimated future net revenues. See note 1 in the notes to the consolidated financial statements for more information about our 2008 and 2007 impairments.

DD&A Expense - Producing Operations. DD&A expense for producing properties was $0.9 million, $1.2 million, and $1.7 million for the years ended December 31, 2009, 2008, and 2007, respectively. The 25% decrease from 2008 to 2009 arose primarily because we impaired the bulk of capital costs associated with our domestic oil properties during 2008, which reduced the depletion base for 2009. 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.

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 $1.9 million, $4.3 million, and $3.1 million for the years ended December 31, 2009, 2008, and 2007, respectively. We drilled 25 wells for third parties during 2009, along with additional well service work, compared to 23 wells during 2008. However, all but two of the wells drilled in 2009 were shallow wells that can be drilled in two to three days and generate less revenue per well. We drilled 19 wells for third parties during 2007. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors. We cannot accurately predict future oilfield services revenues.

Oilfield Services Costs. Oilfield services costs were $1.4 million, $2.8 million, and $2.0 million for the years ended December 31, 2009, 2008, and 2007, respectively, or 75%, 63%, and 65% of oilfield-servicing revenues, respectively. The year-to-year decrease from 2008 to 2009 was primarily due to the nature of our drilling activity discussed above. The increase in costs from 2007 to 2008 was primarily due to increased drilling activity. In general, oilfield-servicing costs are closely 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 $597,000, $411,000, and $267,000 for the years ended December 31, 2009, 2008, and 2007, respectively. We spent $925,000, $1,008,000, and $911,000 on upgrading our oilfield-servicing equipment during 2009, 2008, and 2007 respectively. These capital additions resulted in higher DD&A expenses for this segment during 2008 and 2009.

Bad Debt Expense – Oilfield Services. Bad debt expense was $0, $460,000, and $0 for the years ended December 31, 2009, 2008, and 2007, 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 incurred no bad debt charges in 2009, and do not expect to incur further bad debt charges in the future.

Nonsegmented Items

G&A Costs - Corporate. G&A costs were $7.3 million, $7.0 million, and $7.1 million for the years ended December 31, 2009, 2008, and 2007, respectively. Our 2009 G&A costs rose from 2008 levels primarily due to higher accounting and insurance costs.

Stock Compensation. Stock compensation expense recorded for 2009 represents $1.7 million of amortization related to restricted stock granted in 2009, 2008, and 2007. 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.

Interest and Other Income (Expense) - - Corporate. Interest and other income (expense) was ($600,000), ($278,000), and $433,000 for the years ended December 31, 2009, 2008, and 2007, respectively. During 2009, we amortized $239,000 related to fees incurred in securing our Senior Credit Facility. We also paid $415,000 in interest on outstanding borrowings. These interest-related costs were offset by interest income of $54,000. 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.

Foreign Exchange. As discussed previously, we incurred foreign exchange gains of $7.1 million and foreign exchange losses of $24.3 million and gains of $146,000 for the years ended December 31, 2009, 2008, and 2007, respectively. Included in the 2009 gain and 2008 loss were $1.2 million and $0.9 million, respectively, related to mark-to-market and settlement adjustments to Polish zloty forward contracts.

Income Taxes. We incurred net losses of $0.5 million, $54.7 million, and $11.7 million for the years ended December 31, 2009, 2008, and 2007, respectively. Accounting standards require 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.

Proved Reserves

We have historically added reserves through our exploration and development activities (See Items 1 and 2, Business and Properties). Changes in proved reserves were as follows:

	2009	2008	2007
(MMcfe)
Proved Reserves Beginning of Year	45,864	34,092	22,768
Extensions, Discoveries, and Other Additions	6,333	11,295	17,939
Revisions of Previous Estimates	515	2,148	(4,205)
Production	(2,266)	(1,671)	(2,410)
Proved Reserves End of Year	50,446	45,864	34,092

Extensions, Discoveries, and Other Additions. These are additions to proved reserves that result from the discovery of new fields with proved reserves.

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions at year-end 2009 included positive oil revisions due to higher crude oil prices, offset by negative gas revisions due to the cessation of production at our Wilga well. At year-end 2008, positive gas revisions in Poland were attributable to our Sroda-4 and Zaniemysl-3 wells due to additional technical data acquired during 2008, while negative oil revisions were due to lower year-end oil prices in the United States. At year-end 2007, negative oil and gas revisions in Poland were attributable to our Wilga-4 well due to water encroachment, while positive oil revisions due to higher year-end oil prices in the United States.

Production. See “Gas Revenues” and “Oil Revenues” above.

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. In addition, cash flow from our production operations has been providing a portion of our capital expenditures for the past three years.

We have a history of operating losses. From our inception in January 1989 through December 31, 2009, we have incurred cumulative net losses of approximately $161 million. We expect that our exploration and production activities may continue to result in net losses through 2010 and possibly beyond, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses. While revenues from our operations exceed our fixed operating and overhead costs, we have reported negative cash flow from operating activities in each of the past three years.

With the establishment of proved reserves in Poland, in November 2006, we established a $25 million Senior Credit Facility with the Royal Bank of Scotland to fund infrastructure and development costs in Poland. As of December 31, 2009, we had drawn down the full $25 million available under this facility. At December 31, 2009, we had working capital of approximately $3.5 million. In early 2010, we signed a Mandate Letter with RBS, authorizing it to proceed with the expansion of our existing facility to $50 million. As part of the refinance process, RBS reset the date of the first rescheduled principal reduction of our existing facility to May 31, 2011.

While we did not experience significant impacts from the economic crisis during 2009, the global economy continues to be unsteady. However, the strengthening of the Polish zloty against the U.S. dollar over the past few months will, if it continues, have a positive impact on our U.S. dollar-denominated future revenues and net operating profit; conversely, any U.S. dollar-denominated capital, exploration, and operating costs in Poland will increase at the same rate. Based on current conditions, we presently expect our exploration and development programs will continue in spite of the economic downturn; however, in recognition of the downturn, we plan to continue, as we did throughout 2009, matching capital spending with our discretionary cash flow, plus increased debt capacity when it becomes available. As of December 31, 2009, we had no firm commitments for future capital and exploration costs. We have the ability to control the timing and amount of all of our future capital and exploration costs. Despite the fact that we have no firm commitments, we are moving ahead with production facilities for our KSK wells. We expect the facilities to be complete and ready for production to begin in late 2010. Absent additional debt capacity, which we expect to finalize during the second quarter of 2010, we will pay for the facilities from our projected cash flow in Poland.

We cannot assure that our efforts to increase borrowings will be successful; however, should we be unable to finalize the credit expansion, our existing cash balances, coupled with expected cash flow in Poland, will provide adequate funding to make the repayment and still fund the KSK production facilities.

We may seek to obtain additional funds for future capital investments from the sale of additional securities, project financing to help finance the completion of successful wells, sale of partial property interests, or other arrangements, all of which may dilute the interest of our existing stockholders or our interest in the specific project financed.

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

Working Capital (current assets less current liabilities). Our working capital was $3.5 million as of December 31, 2009, a decrease of $10.5 million from December 31, 2008.

Operating Activities. We used net cash of $5.8 million, $14.2 million, and $1.6 million in our operating activities during 2009, 2008, and 2007, respectively, primarily as a result of the net losses, excluding noncash charges, incurred in those years. Lower exploration costs in 2009, which were reduced intentionally as we matched our spending with our cash flow, helped reduce the cash used during 2009. Our current assets at year-end 2009 included approximately $2.9 million in accrued oil and gas sales from both the United States and Poland and $0.9 million in receivables related to our oilfield services segment. Our current liabilities at year-end included approximately $1.6 million in costs related to our exploration activities in Poland that were paid in early 2010, as well as $0.6 million in VAT (value added tax) payables that were also satisfied in early 2010.

Investing Activities. We used net cash in investing activities of $4.0 million, $11.8 million, and $13.1 million in 2009, 2008 and 2007, respectively. In 2009, we received $4.7 million from the maturities of marketable securities and invested $11,000 in marketable securities. We spent $7.7 million for oil and gas property additions, $7.2 million of which was related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $83,000 upgrading our office equipment and $0.9 million adding to our oilfield services equipment.

In 2008, we received $11.3 million from the maturities of marketable securities and invested $186,000 in marketable securities. We spent $21.8 million for oil and gas 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 and invested $9.6 million in marketable securities. We spent $7.5 million for oil and gas 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.

Financing Activities. We used net cash in financing activities of $2.7 million during 2009. We received net cash from financing activities of $40.1 million and $14.4 million in 2008 and 2007, respectively. During 2009, we paid $2.8 million towards a loan related to auction-rate securities. In addition, 55,000 options and warrants were exercised during the year, resulting in proceeds to us of $132,000.

During 2008, we borrowed $25 million under our Senior Credit Facility with RBS and $3.4 million as a loan 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.

Contractual Obligations and Contingent Liabilities and Commitments

Contractual Obligations. At December 31, 2009, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:

	Total	2010	2011	2012	2013	2014
	(In thousands)
Senior credit facility	$25,000	--	$15,000	$10,000	$ --	$ --
Interest payments on long-term debt	771	370	290	111	--	--

We had no other significant contractual obligations or commitments as of December 31, 2009. We are subject to certain work commitments respecting our 100%-owned 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 oil and gas drilling and production operations are subject to hazards incidental to the industry that can cause severe damage to and destruction of property and equipment, pollution or environmental damage, suspension of operations, personal injury, and loss of life. To lessen the effects of these hazards, we maintain insurance of various types to cover our United States and Poland operations and also rely on the insurance or financial capabilities of our exploration partners in Poland. These measures do not cover risks related to violations of environmental laws or all other risks involved in oil and gas exploration, drilling, and production. We would be adversely affected by a significant 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 have liabilities of $1.5 million related to asset retirement obligations on our Consolidated Balance Sheet at December 31, 2009, 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

Recent Securities and Exchange Commission Rule-Making Activity

·	Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used, rather than a year-end price.

·	Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

·	Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

·	Third-Party Reserves Preparation – If a company represents that its estimates of reserves are prepared or audited by a third party, the company must file a report of the third party as an exhibit to the relevant registration statement or report.

·	Use of Probabilistic Methods – Reserves may be estimated using probabilistic methods in which there is at least a 90% probability of recovery of “proved” reserves, at least a 50% probability of recovery of “probable” reserves, and at least a 10% probability of recovery of “possible” reserves.

·	Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total oil and gas proved reserves.

We adopted the rules effective December 31, 2009. See Supplemental Oil and Gas Information (Unaudited) for impact of adoption on oil and gas reserves.

In addition, in January 2010, the Financial Accounting Standards Board (FASB) issued new standards to provide consistency with the new Securities and Exchange Commission rules. The new standards align the reserves calculation and disclosure requirements under U.S. generally accepted accounting principles with the requirements in the Securities and Exchange Commission rules. We adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. See, also, Supplemental Oil and Gas Information (Unaudited).

On January 1, 2009, we adopted a new accounting standard regarding derivative instruments and hedging activities. The new standard requires enhanced disclosure about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

In April 2009, the FASB issued three amendments to the accounting and disclosure requirements regarding fair value measurements and impairments of securities. These amendments provide guidelines for making fair value measurements more consistent with the principles presented in prior pronouncements, enhance consistency in financial reporting by increasing the frequency of fair value disclosures, and provide additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. We adopted these for the period ended June 30, 2009.

In June 2009, the FASB issued the FASB Accounting Standards Codification (Codification). The Codification will become the single source for all authoritative GAAP recognized by the FASB to be applied for financial statements issued for periods ending after September 15, 2009. The adoption of the Codification does not change GAAP.

In May 2009, the FASB issued new standards that establish the accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued. In particular, the new standards set forth:

·	the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued);

·	the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and

·	the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.

We adopted the new standards as of June 30, 2009. We have evaluated subsequent events after the balance sheet date of December 31, 2009, through the time of filing with the Securities and Exchange Commission.

In October 2008, the FASB issued an amendment to the accounting and disclosure requirements regarding the determination of the fair value of a financial asset when the market for that asset is not active. This amendment was effective October 10, 2008.

In all cases referenced above, the adoption of the new rules or standards did not have a material impact on our results of operations and financial condition. We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position, and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.

Critical Accounting Policies

Oil and Gas Activities

We follow the successful efforts method of accounting for our oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, these costs plus the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that net capitalized costs of unproved properties, on a property-by-property basis, are not considered to be realizable. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net cash flows determined on a property-by-property basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value, determined on a property-by-property basis. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as a recovery of costs and any resulting gain or loss is recorded as other income. 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. As a result of the foregoing, our results of operations for any particular period may not be indicative of the results that could be expected over longer periods.

Oil and Gas Reserves

All of the reserves data in this Form 10-K are estimates. Estimates of our crude oil and natural gas reserves are prepared by our engineers in accordance with guidelines established by the Securities and Exchange Commission, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements, which we adopted effective December 31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserves estimate. We based our December 31, 2009, reserves estimates on a 12-month average commodity price, unless contractual arrangements designate the price to be used, in accordance with Securities and Exchange Commission rules. However, oil and gas prices are volatile and, as a result, our reserves estimates will change in the future.

Estimates of proved crude oil and natural gas reserves significantly affect our DD&A expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of crude oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. See Item 8, Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).

Stock-based Compensation

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.

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 affiliates 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.

We currently do not engage in any hedging activities to protect ourselves against market risks associated with oil and gas price fluctuations, although we may elect to do 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. During 2009, the zloty fluctuated between a low of 2.71 zlotys per U.S. dollar to a high of 3.90 zlotys per dollar. Variations in exchange rates 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 2010 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our U.S. dollar-denominated revenues compared to 2009.

At the same time, however, our U.S. dollar-denominated costs of conducting business in Poland, which includes drilling, geological and geophysical, and overhead costs, will also change as exchange rates fluctuate. 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.

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 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 2008, 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 matured March 31, 2009. In connection with these outstanding contracts, we recorded a 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. During 2009, we recorded additional losses of $1.4 million related to these contracts.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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, 2009, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2009, 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.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information from the definitive proxy statement for the 2010 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 2010 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 2010 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 2010 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 2010 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.

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, 2009 and 2008	F-4
Consolidated Statements of Operations for the Years Ended
December 31, 2009, 2008 and 2007	F-6
Consolidated Statements of Comprehensive Loss for the Years Ended
December 31, 2009, 2008 and 2007	F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2009, 2008 and 2007	F-8
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years
Ended December 31, 2009, 2008 and 2007	F-9
Notes to the Consolidated Financial Statements	F-10

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

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

Exhibit Number*	Title of Document	Location

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

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.
10.53	Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to Fences I project area	Incorporated by reference from the current report on Form 8-K filed May 2, 2000.
10.59	Sales / Purchase Agreement Special Provisions between Plains Marketing Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.60	Form of Non-Qualified Stock Option awarded August 14, 2002, with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.62	Agreement Regarding Cooperation within the Poznan Area (Fences II) entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.63	Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

Exhibit Number*	Title of Document	Location

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**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2008, filed March 16, 2009.

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.
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.

Exhibit Number*	Title of Document	Location
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 Spółka 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.
10.92	Exhibit 10.92, Amendment and Reconfirmation of 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, 2008, filed March 16, 2009.
10.93	Agreement No. for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe I Gazownictwo S.A., dated June 19, 2009	This filing.

10.94	Executive Incentive Royalty Plan and related schedule**	This filing.


Exhibit Number*	Title of Document	Location

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 Hohn Engineering PLLC, Petroleum Engineers	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 Principal Executive Officer Pursuant to Rule 13a-14	This filing.
31.02	Certification of Principal 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.

Item 99	Additional Exhibits

99.01	Report of Hohn Engineering PLLC, Petroleum Engineers	To be filed by amendment.

99.02	Report of RPS Energy, Petroleum Engineers	To be filed by amendment.

_____________

All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601, and the number following the decimal indicating the sequence of the particular document. Omitted numbers in the sequence refer to documents previously filed as an exhibit, but no longer required.

**	Identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit, as required by Item 15(a)(3) of Form 10-K.

SIGNATURES

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

		FX ENERGY, INC. (Registrant)



Dated:	March 16, 2010	By:	/s/ David N. Pierce
			David N. Pierce
			President and Chief Executive Officer



Dated:	March 16, 2010	By:	/s/ Clay Newton
			Clay Newton
			Principal Financial Officer

	/s/ Thomas B. Lovejoy
Dated: March 16, 2010	Thomas B. Lovejoy, Director

	/s/ David N. Pierce
Dated: March 16, 2010	David N. Pierce, Director, President,
	and Principal Executive Officer

	/s/ Dennis B. Goldstein
Dated: March 16, 2010	Dennis B. Goldstein, Director

	/s/ Arnold S. Grundvig, Jr.
Dated: March 16, 2010	Arnold S. Grundvig, Jr., Director

	/s/ Jerzy B. Maciolek
Dated: March 16, 2010	Jerzy B. Maciolek, Director

	/s/ Richard Hardman
Dated: March 16, 2010	Richard Hardman, Director

	/s/ H. Allen Turner
Dated: March 16, 2010	H. Allen Turner, Director

	/s/ Clay Newton
Dated: March 16, 2010	Clay Newton, Principal Financial and
	Accounting Officer

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 2009 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, 2009, 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, 2009, 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, 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 16, 2010

F-3

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

As of December 31, 2009 and 2008

(in thousands)

	2009		2008
ASSETS

Current assets:
Cash and cash equivalents	$	4,225	$	16,588
Marketable securities		--		4,105
Receivables:
Accrued oil and gas sales		2,875		1,093
Other receivables		918		1,720
VAT receivable		--		2,514
Inventory		232		211
Other current assets		394		450
Total current assets		8,644		26,681

Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		32,700		28,600
Unproved		3,403		2,770
Other property and equipment		7,654		6,667
Gross property and equipment		43,757		38,037
Less accumulated depreciation, depletion and amortization		(11,466)		(11,164)
Net property and equipment		32,291		26,873

Other assets:
Certificates of deposit		406		406
Loan fees		729		842
Total other assets		1,135		1,248

Total assets	$	42,070	$	54,802

-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, 2009 and 2008

(in thousands, except share data)

-Continued-

	2009		2008
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	3,569	$	7,779
VAT payable		575		--
Accrued liabilities		1,048		4,937
Total current liabilities		5,192		12,716

Long-term liabilities:
Notes payable		25,000		25,000
Asset retirement obligation		1,133		1,932
Total long-term liabilities		26,133		26,932

Total liabilities		31,325		39,648

Commitments and Contingencies (Note 6)

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
December 31, 2009 and 2008; no shares outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized as of
December 31, 2009 and 2008; 43,037,540 and 42,202,878 shares issued
and outstanding as of December 31, 2009 and 2008, respectively		43		42
Additional paid in capital		160,594		158,075
Cumulative translation adjustment		10,738		17,137
Accumulated deficit		(160,630)		(160,100)
Total stockholders’ equity		10,745		15,154

Total liabilities and stockholders’ equity	$	42,070	$	54,802

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, 2009, 2008 and 2007

(in thousands, except per share amounts)

	2009		2008		2007

Revenues:
Oil and gas sales	$	12,772	$	13,494	$	14,903
Oilfield services		1,892		4,347		3,093
Total revenues		14,664		17,841		17,996
Operating costs and expenses:
Lease operating expenses		3,478		3,441		3,538
Exploration costs		4,829		15,389		10,624
Impairment of oil and gas properties		1,335		14,746		2,299
Oilfield services costs		1,412		2,751		1,998
Depreciation, depletion and amortization (DD&A)		1,602		1,720		2,064
Accretion expense		41		84		78
Stock compensation		1,693		2,367		2,604
Bad debt expense		--		460		--
General and administrative costs (G&A)		7,257		7,030		7,061
Total operating costs and expenses		21,647		47,988		30,266
Operating loss		(6,983)		(30,147)		(12,270)

Other income (loss):
Interest income (net of interest expense) and
other income (expense)		(600)		(278)		433
Foreign exchange gain (loss)		7,053		(24,279)		146
Total other income (expense)		6,453		(24,557)		579

Net loss	$	(530)	$	(54,704)	$	(11,691)

Basic and diluted net loss per common share	$	(0.01)	$	(1.35)	$	(0.32)

Basic and diluted weighted average number
of shares outstanding		42,529		40,420		36,694

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, 2009, 2008 and 2007

(in thousands)

		2009		2008	2007

Net loss	$	(530)	$	(54,704)	$	(11,691)

Other comprehensive income (loss)
Foreign currency translation adjustment		(6,399)		13,584		--
Increase (decrease) in market value of marketable securities		--		1		71

Comprehensive loss	$	(6,929)	$	(41,119)	$	(11,620)

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, 2009, 2008 and 2007

(in thousands)

		2009		2008		2007
Cash flows from operating activities:
Net loss	$	(530)	$	(54,704)	$	(11,691)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization		1,602		1,720		2,064
Impairment of oil and gas properties		1,864		14,746		2,299
Accretion expense		41		84		78
(Gain) loss on property dispositions		--		(5)		--
Stock compensation (G&A)		1,693		2,367		2,604
Foreign exchange (gains) losses		(8,296)		22,306		--
Common stock issued for services (G&A)		694		498		242
Loan fee amortization		242		210		183
Increase (decrease) from changes in working capital items:
Receivables		1,682		(3,056)		(583)
Inventory		(21)		(33)		28
Other current assets		58		(85)		(43)
Other assets		(128)		(136)		(239)
Accounts payable and accrued liabilities		(4,025)		1,840		3,479
Asset retirement obligation		(705)		--		(2)
Net cash used in operating activities		(5,829)		(14,248)		(1,581)

Cash flows from investing activities:
Additions to oil and gas properties		(7,666)		(21,808)		(7,517)
Additions to other property and equipment		(983)		(1,077)		(966)
Additions to marketable securities		(11)		(186)		(9,610)
Proceeds from maturities of marketable securities		4,661		11,284		4,941
Proceeds from sale of assets		--		15		--
Net cash used in investing activities		(3,999)		(11,772)		(13,152)

Cash flows from financing activities:
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		(2,808)		(546)		--
Proceeds from notes payable		--		25,000		--
Proceeds from exercise of stock options and warrants		132		12,313		1,915
Net cash provided by (used in) financing activities		(2,676)		40,121		14,351

Effect of exchange rate changes on cash		141		(1,775)		--

Net increase (decrease) in cash		(12,363)		12,326		(382)
Cash and cash equivalents at beginning of year		16,588		4,262		4,644

Cash and cash equivalents at end of year	$	4,225	$	16,588	$	4,262

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, 2009, 2008 and 2007

(in thousands)

		Common Stock					Accumulated
			$0.001		Additional		Other				Total
	Preferred	Shares	Par		Paid in		Comprehensive		Accumulated		Stockholders’
	Stock	Issued	Value		Capital		Income (Loss)		Deficit		Equity (Deficit)

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	--	--		--		--		7 1		--		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	--	--		--		--		3,553		--		3,553
change in functional currency
at October 1, 2008
Other comprehensive 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
Common stock issued for services and other	--	610		1		694		--		--		695
Exercise of stock options and warrants	--	225		--		132		--		--		132
Stock compensation	--	--		--		1,693		--		--		1,693
Other comprehensive income	--	--		--		--		(6,399)		--		(6,399)
Net loss for year	--	--		--		--		--		(530)		(530)
Balance as of December 31, 2009	--	43,038	$	43	$	160,594	$	10,738	$	(160,630)	$	10,745

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 “us,” “we,” “our,” or “the Company”), is an independent oil and gas exploration and production company with principal production, reserves, and exploration in Poland and oil production and oilfield service activities in the United States. In Poland, we have 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 our own account. In the United States, we explore for and produce oil from fields in Montana and Nevada, and we have 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 its undivided interests in Poland. All significant intercompany accounts and transactions have been eliminated in consolidation. At December 31, 2009, we owned 100% of the voting common stock or other equity securities of our subsidiaries.

Cash and Cash Equivalents and Marketable Securities

We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. We determine the appropriate classification of our investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluate such designation at each balance sheet date.

Fair Value of Financial Instruments

The carrying amounts of our 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 2008 receivable for Input VAT, which was due from the State Treasury Office of Poland, the majority of our receivables are within the oil and gas industry, primarily from the purchasers of our oil and gas, and fees generated from oilfield services and our industry partners. Substantially all of our domestic receivables are with Cenex, a regional refiner and marketer, and substantially all of our Polish receivables are with POGC or one of its affiliates. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts at December 31, 2009 and 2008. The majority of our cash and cash equivalents are held by four financial institutions in Utah, Montana, and Poland.

Derivative Instruments

Accounting standards require 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, 2009 and 2008, we 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

We follow the successful-efforts method of accounting for our 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, if the determination that proved reserves have been found cannot be made within one year, or if we are 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 charge 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.

During 2009, production ceased at our Wilga well in eastern Poland. We impaired the remaining capitalized costs of the well in the amount of $1,864,000. This impairment was offset by $529,000 related to changes in the estimates of our asset retirement obligation.

Low year-end oil prices resulted in a negative revision to our 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 our domestic oil properties was greater than their estimated future net revenues at December 31, 2008. In accordance with accounting standards, we recorded an impairment of capitalized costs in the amount of $3,774,000 in 2008. The impairment amount was calculated by reducing the net capitalized costs of the U.S. oil properties to their year-end fair value, which was equal to their remaining estimated discounted future net cash flows.

During 2008, we impaired the costs of the Grundy-1 and Sroda-6 wells. Accounting standards require capitalized costs of exploratory wells to be expensed if the enterprise is not making sufficient progress assessing the reserves and economic viability of the project. Under then-current economic conditions, we did not have firm plans to further develop these two wells. Accordingly, we recorded an impairment charge of $7,220,000 associated with the Grundy-1 well and $3,752,000 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. We recorded an impairment of capitalized costs in the amount of $2,299,000 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 2009, 2008, and 2007.

	December 31,
	2009		2008		2007
				(In thousands)

Beginning balance at January 1	$	2,390	$	669	$	2,386
Additions to capitalized exploratory well costs
pending the determination of proved reserves		1,766		2,390		669
Reclassifications to wells, facilities and equipment
based on the determination of proved reserves		(4,156)		--		(2,386)
Capitalized exploratory well costs charged to expense		--		(669)		--
Ending balance at December 31	$	--	$	2,390	$	669

The 2009 and 2008 activity includes costs associated with the Kromolice-2 well, which was drilling at year-end 2008. During 2009, the well was completed for production, and the determination of proved reserves was made. The 2007 balance includes equipment costs incurred for the Grundy well in Poland, which began drilling in early 2008. Accounting standards 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.

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 three 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
	2009		2008			(in years)
	(In thousands)

Other property and equipment:
Drilling rigs	$	5,980	$		5,101	6
Other vehicles		355			309	5
Building		110			108	40
Office equipment and furniture		1,209			1,149	3 to 6
Total cost		7,654		6,667
Accumulated depreciation		(5,355)		(4,663)
Net other property and equipment	$	2,299	$		2,004

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:

Cash paid for interest in 2008 includes $188,715 in commitment fees on our Senior Facility Agreement. Cash paid for interest in 2007 includes $119,040 in commitment fees paid on our 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 other purchaser, and are net of royalties. Oilfield service revenues are recognized when the related service is performed.

Stock-Based Compensation

We maintain several share-based incentive plans. Under these plans, we 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. Accounting standards require share-based compensation costs to be measured at the grant date, based on the estimated fair value of the award, and are recognized as expense over the employee’s requisite service period.

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.

We did not have any unrecognized tax benefits at December 31, 2009. We are subject to audit in the United States by the Internal Revenue Service and various states for the prior three years and in Poland by Polish tax authorities for the prior five years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months. Our policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. No tax-related interest expense was recognized during the year ended December 31, 2009.

F-13

New Accounting Standards

Recent SEC Rule-Making Activity

·	Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used, rather than a year-end price.

·	Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

·	Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

·	Third-Party Reserves Preparation – If a company represents that its estimates of reserves are prepared or audited by a third party, the company must file a report of the third party as an exhibit to the relevant registration statement or report.

·	Use of Probabilistic Methods – Reserves may be estimated using probabilistic methods in which there is at least a 90% probability of recovery of “proved” reserves, at least a 50% probability of recovery of “probable” reserves, and at least a 10% probability of recovery of “possible” reserves.

·	Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total oil and gas proved reserves.

We adopted the rules effective December 31, 2009. See Supplemental Oil and Gas Information (Unaudited) for the impact of adoption on oil and gas reserves.

In addition, in January 2010, the FASB issued new standards to provide consistency with the new Securities and Exchange Commission rules. The principal revisions under the new authoritative guidance include changing the manner in which oil and gas reserves are estimated. We adopted the new standards effective December 31, 2009. This change in accounting has been applied prospectively and treated in these financial statements as a change in accounting principle that is inseparable from a change in accounting estimate. See also Supplemental Oil and Gas Information (Unaudited).

In June 2009, the FASB issued the FASB Accounting Standards Codification (Codification). The Codification will become the single source for all authoritative GAAP recognized by the FASB to be applied to financial statements issued for periods ending after September 15, 2009. The adoption of the Codification does not change GAAP.

F-14

·	the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued);

·	the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and

·	the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.

In all cases referenced above, the adoption of the new rules or standards did not have a material impact on our results of operations and financial condition. We have reviewed all other recently issued, but not yet adopted or applicable, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position, and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings, financial condition, or operations.

Foreign Operations

Effective October 1, 2008, we changed the functional currency of our Polish subsidiary from the U.S. dollar to the Polish zloty. The change in functional currency for the Polish subsidiary affects the amounts reported for Polish assets, liabilities, revenues, and expenses from those that would be reported had the U.S. dollar been maintained as the functional currency. The differences depend on changes in period-average and period-end exchange rates. Translation adjustments result from the process of translating the Polish subsidiary’s financial statements into the U.S. dollar reporting currency. Translation adjustments are not included in determining net income but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities of FX Energy Poland 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 $3.6 million. At December 31, 2008, the CTA had increased to approximately $17.1 million, and it decreased to $10.7 million at December 31, 2009. Because of the fluctuation in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.

During 2009, we recorded foreign currency transaction gains of approximately $7.1 million. We recorded a gain of approximately $8.3 million attributable to decreases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. There was a corresponding debit to other comprehensive income for the gains attributable to the intercompany loans and unpaid interest, which was then offset by translation adjustments of approximately $1.9 million related to our other balance sheet accounts as discussed above. The remaining $1.2 million loss was primarily attributable to the settlement of outstanding zloty forward-purchase contracts and the translation of period-end cash balances.

F-15

The following table provides a summary of changes in CTA (in thousands) for the years ended December 31, 2009 and 2008:

		Year Ended		Year Ended
		December 31, 2009		December 31, 2008
Beginning balance	$	17,137	$	--
Cumulative translation adjustment due to change
in functional currency		--		3,553
Increase (decrease) related to losses (gains)
on intercompany loans		(8,297)		22,373
Increase (decrease) related to translation adjustments		1,898		(8,789)
Ending balance	$	10,738	$	17,137

Future transaction gains or losses may be significant given the amount of intercompany loans and the volatility of the exchange rate. Future translation adjustments will also vary in concert with changes in exchange rates. These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.

We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. 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. We do not use derivative financial instruments for trading or speculative purposes. We have used forward-purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense are recognized in the consolidated financial statements. As of December 31, 2009, there were no outstanding zloty forward-purchase contracts.

The change in functional currency will have no impact on our 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, 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. We evaluate our estimates and assumptions on a regular basis. We base our 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 our 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 is computed by dividing the net loss applicable to common shares by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing the net loss by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options, warrants, unvested restricted stock, and convertible preferred stock or debt.

F-16

Outstanding options, warrants, and unvested restricted stock as of December 31, 2009, 2008, and 2007, were as follows:

	Options, Warrants and
	Unvested Restricted Stock	Price Range
Balance sheet date:
December 31, 2009	2,209,976	$0.00 - $10.65
December 31, 2008	2,694,862	$0.00 - $10.65
December 31, 2007	6,320,602	$0.00 - $10.65

We recorded net losses in 2009, 2008, and 2007. The above options, warrants, and unvested restricted stock were not included in the computation of diluted earnings per share for the years presented because the effect would have been antidilutive.

Note 2: Asset Retirement Obligation

We account for future site restoration costs by recording a liability for the fair value of asset retirement obligations (“ARO”) 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. We use an expected cash flow approach to estimate our asset retirement obligations. We recorded accretion expense of $41,296, $83,739, and $78,087 in 2009, 2008, and 2007, respectively. At December 31, 2009, 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, 2009 and 2008:

	December 31,
	2009		2008
	(In thousands)
Asset retirement obligations:
Beginning balance	$	1,932	$	1,037
Current year additions		193		--
Current year revisions		(529)		811
Liabilities settled		(169)		--
Foreign exchange adjustments		24		--
Accretion expense		41		84
Ending balance	$	1,294	$	1,932

At year-end 2008, the economic life of our oil reserves in Montana was shortened considerably due to low year-end oil prices. Accordingly, we increased the asset retirement obligation to reflect the shortened period before plugging costs might be incurred. At year-end 2009, the economic life at most of our domestic properties was extended due to higher oil prices.

Note 3: Other Assets

As of December 31, 2009 and 2008, we had reclamation bonds with federal and state agencies with face amounts 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.

F-17

Note 4: Accrued Liabilities

Our accrued liabilities as of December 31, 2009 and 2008, were comprised of the following:

	December 31,
	2009		2008
	(In thousands)
Accrued liabilities:
Credit facility commitment fees	$	--	$	2
Partner share of oil & gas revenue and joint operating costs		127		356
Compensation-related costs		449		841
Interest expense		15		42
Current portion of asset retirement obligation		359		--
Foreign currency derivative contracts		--		888
Oilfield equipment installment note		98		--
Loan related to auction-rate securities (Note 8)		--		2,808
Total	$	1,048	$	4,937

Note 5: Notes Payable

In November of 2006, we 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 us in March 2007, are designated to cover infrastructure and development costs in connection with a variety of our Polish gas projects and are collateralized by our commercial wells and production in Poland. At December 31, 2009, we had drawn the full $25 million available under the Facility.

In consideration for the Facility, we 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.

In early 2010, we signed a Mandate Letter with RBS, authorizing it to proceed with a refinance of our existing Facility. As part of the refinance process, RBS reset the date of the first rescheduled principal reduction of our existing Facility to May 31, 2011. The Facility is an interest-only facility until that date.

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

	For the Year Ended
	December 31, 2009
Balance at January 1, 2009	$25,000
Proceeds from borrowings	--
Balance at December 31, 2009	$25,000

Interest on borrowed funds is accrued at LIBOR plus 1.25%. The average interest rate on the outstanding balance at December 31, 2009, was 1.48% per annum. The carrying value of the long-term debt at December 31, 2009, approximates its fair value.

The borrowing base is redetermined twice a year, based on reserve volumes and values estimated by independent engineers as of the last day of the prior year. Our last redetermination was completed in December 2009, with no change in the borrowing base amount.

F-18

Note 6: Commitments and Contingencies

Note 7: Liquidity

We have a history of operating losses and negative cash flow from operating activities. From our inception in January 1989 through December 31, 2009, we have incurred cumulative net losses of approximately $161 million. We expect that our exploration and production activities may continue to result in net losses through 2010 and possibly beyond, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses. While revenues from our operations exceed our fixed operating and overhead costs, we have reported negative cash flow from operating activities in each of the past three years.

With the establishment of proved reserves in Poland, in November 2006, we established a $25 million Senior Credit Facility with RBS to fund infrastructure and development costs in Poland. As of December 31, 2009, we had drawn down the full $25 million available under this Facility. At December 31, 2009, we had working capital of approximately $3.5 million. In early 2010, we signed a Mandate Letter with RBS, authorizing it to proceed with the expansion of our existing Facility to $50 million. As part of the refinance process, RBS reset the date of the first rescheduled principal reduction under our existing Facility to May 31, 2011. The Facility is an interest-only facility until that date.

While we did not experience significant impacts from the economic crisis during 2009, the global economy continues to be unsteady. Production from our Roszkow well should add significant, incremental revenues and cash flow during 2010. The strengthening of the Polish zloty against the U.S. dollar over the past few months will, if it continues, also have a positive impact on our U.S. dollar-denominated future revenues and operating profit; conversely, any U.S. dollar-denominated capital, exploration, and operating costs in Poland will increase at the same rate. Based on current conditions, we presently expect our exploration and development programs will continue in spite of the economic downturn; however, in recognition of the downturn, we plan to continue, as we did throughout 2009, matching capital spending with our discretionary cash flow, plus increased debt capacity if it becomes available. As of December 31, 2009, we had no firm commitments for future capital and exploration costs. We have the ability to control the timing and amount of all future capital and exploration costs. Despite the fact that we have no firm commitments, we are moving ahead with new production facilities in Poland. We expect the facilities to be complete and ready for production to begin in late 2010. Absent additional debt capacity, we will pay for the facilities from our projected cash flow in Poland.

F-19

Note 8: Fair Value Measurements and Marketable Securities

Fair Value Measurements

On January 1, 2009, we adopted a newly issued accounting standard for fair value measurements of all nonfinancial assets and nonfinancial liabilities not recognized or disclosed at fair value in the financial statements on a recurring basis. The adoption of this accounting standard for those assets and liabilities did not have a material impact on our financial position, results of operations, or liquidity. We did not have any significant nonfinancial assets or nonfinancial liabilities that would be recognized or disclosed at fair value on a recurring basis as of December 31, 2009.

Fair Value Hierarchy

The accounting standard for fair value measurements provides a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. Fair value is defined as the price that would be received for an asset or the exit price that would be paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date. The accounting standard established a fair value hierarchy that requires an entity to maximize the use of observable inputs, where available. The following summarizes the three levels of inputs required as well as the assets and liabilities that we value using those levels of inputs.

·	Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities.

·	Level 2: Observable inputs other than those included in Level 1. For example, quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in inactive markets.

·	Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used 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 2008, certain assets were classified as Level 3 assets. This classification primarily related to investments in auction-rate securities. We had no Level 3 assets as of December 31, 2009.

Recurring Fair Value

The following tables set forth the financial assets and liabilities that we measured at fair value on a recurring basis by level within the fair value hierarchy. We classify assets and liabilities measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of December 31, 2009 (in thousands):

	December 31,
	2009	Level 1(1)	Level 2(2)	Level 3(3)
Cash equivalents:
Money market funds	$ 783	$ 783	--	--
Treasury bills	254	254	--	--

_______________

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

(2)	Significant other observable inputs.

(3)	Significant unobservable inputs.

F-20

The following table provides a summary of changes in fair value of our Level 3 marketable securities (in thousands):

	For the Year Ended
	December 31, 2009
Balance at January 1, 2009	$ 4,650
Purchases, issuances and settlements	(4,650)
Balance at December 31, 2009	$ --

Marketable Securities

Marketable securities on the Consolidated Balance Sheets include investments we hold that are classified as trading securities as defined by accounting pronouncements. Prior to year-end 2008, these investments had historically been accounted for as available for sale. Our marketable securities as of December 31, 2009 and 2008, included $0 and $4,105,000, respectively, of auction-rate securities at their fair market value.

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

As part of the settlement, we also received certain “put” rights, which enabled us to require UBS to purchase, at par value plus accrued interest, all of the auction-rate securities at fixed, future dates. At December 31, 2008, we had certain auction-rate securities with a market value of $2,535,000 that were 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 were eligible to be “put” to UBS on June 30, 2010. Subsequent to December 31, 2008, all auction-rate securities were redeemed at their full par value of $4,650,000. The proceeds from the redemptions were used to satisfy the loan relating to those securities at December 31, 2008, of $2,808,000.

We elected to determine a fair value for the UBS “put” rights at December 31, 2008. We determined the value of the “put” rights to be $545,000, which was the difference between the par value and the fair value of the auction-rate securities. This amount was 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, we also changed the classification of our 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 was recorded as other expense in the statement of operations. There was no cash impact on our balance sheet or statements of operations and cash flow associated with the gain and loss that resulted from these transactions.

Liabilities

At December 31, 2008, we 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 matured March 31, 2009. All contracts were settled on their maturity dates.

F-21

Note 9: Income Taxes

We recognized no income tax benefit from the losses generated during 2009, 2008, and 2007. The components of the net deferred tax asset as of December 31, 2009 and 2008, are as follows:

	December 31,
	2009		2008
	(In thousands)
Deferred tax liability:
Property and equipment basis differences	$	(577)	$	(288)
Deferred tax asset:
Net operating loss carryforwards:
United States		31,411		27,795
Poland		6,396		5,607
Oil and gas properties		4,807		6,806
Accrued interest expense		6,492		4,269
Foreign exchange translation losses		2,675		4,051
Options issued for services		1,194		1,256
Asset retirement obligation		411		721
Valuation allowance		(52,809)		(50,217)
Total	$	--	$	--

The change in the valuation allowance during 2009, 2008, and 2007 is as follows:

		Year Ended December 31,
		2009		2008		2007
		(In thousands)
Valuation allowance:
Balance, beginning of year	$	(50,217)	$	(36,938)	$	(32,028)
Change in property and equipment basis differences		2,288		(6,193)		(1,249)
Decrease (increase) due to foreign exchange translation loss		1,376		(4,051)		--
Change in accrued interest expense		(2,223)		(4,269)
Decrease (Increase) due to net operating loss		(4,405)		1,465		(2,179)
Other		372		(231)		(1,482)
Total	$	(52,809)	$	(50,217)	$	(36,938)

Accounting standards require 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 through expansion of our oil and gas producing activities. The risks associated with that growth requirement are considerable, resulting in our conclusion that a full valuation allowance be provided at December 31, 2009, 2008, and 2007. Due to the full valuation allowance, our effective income tax rate for all three years was zero percent. The statutory rate was increased by permanent differences relating to changes associated with stock options and that tax treatment of interest income, and reduced by adjustments for net operating losses expiring, exchange rate differences, and changes to deferred taxes related to temporary differences.

United States NOL

At December 31, 2009, we had net operating loss (“NOL”) carryforwards in the United States of approximately $84,213,000 available to offset future taxable income. The carryforwards begin to expire in 2010 and will fully expire in 2029. 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 $20,472,000 relating to tax deductions resulting from the exercise of stock options. The tax benefit from adjusting the valuation allowance related to this portion of the NOL carryforward will be credited to additional paid-in capital.

F-22

Polish NOL

As of December 31, 2009, we had NOL carryforwards in Poland totaling approximately $33,665,000. The NOLs begin to expire in 2010 and will fully expire in 2014. The normal carryforward period in Poland is five years. However, in any given year, no more than 50% of the NOL carryforward may be applied against Polish income in succeeding years.

The following table lists the years of expiration for our net operating losses:

	United States	Poland
	(In thousands)
Year of NOL expiration:
2009	$ 3,565	$ 7,020
2010	8,368	11,027
2011	4,995	--
2012	6,145	11,621
2013 and thereafter	61,140	3,997

The domestic and foreign components of our net loss are as follows:

	Year Ended December 31,
	2009	2008	2007
	(In thousands)
Domestic	$ (8,727)	$ (11,230)	$ (6,078)
Foreign	8,197	(43,474)	(5,613)
Total	$ (530)	$ (54,704)	$ (11,691)

Note 10: Stockholders’ Equity

In 2009, option holders exercised a total of 55,000 outstanding options at a price of $2.40 per share, resulting in proceeds to us of $132,000. Additionally, option holders exercised a total of 380,000 outstanding options at a price of $2.40 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 169,860 incremental shares.

Also during 2009, we issued 228,100 shares for a 2008 contribution to our employee benefit plan. In addition, we issued 21,000 shares to consultants for services. During 2008, we issued 110,090 shares for a 2007 contribution to our employee benefit plan. In addition, we issued 7,000 shares to consultants for services. We received proceeds from the exercise of 3,648,369 stock options and warrants of $12,312,649 during 2008.

We have a stockholder rights plan, adopted in 2007, 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.

Note 11: Stock Options, Warrants and Restricted Stock

Equity Compensation Plans

Our equity compensation consists of annual stock option and award plans that have been adopted by the board of directors and subsequently approved by the stockholders at an annual meeting.

F-23

The following table summarizes information regarding our stock option and award plans as of December 31, 2009:

		Weighted	Number
	Number	Average	of Options
	of Shares	Exercise Price	Available
	Authorized	of Outstanding	for 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	--
2000 Stock Option and Award Plan	600,000	2.61	--
2001 Stock Option and Award Plan	600,000	3.22	--
2003 Long Term Incentive Plan	800,000	6.64	1,627
2004 Long Term Incentive Plan	1,000,000	8.43	124,013
Total	5,500,000	$5.65	125,640

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, 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, we may also issue restricted stock.

The following table summarizes option activity for 2009, 2008, and 2007:

	2009			2008		2007
			Weighted		Weighted		Weighted
			Average		Average		Average
	Number of		Exercise	Number of	Exercise	Number of	Exercise
	Options		Price	Options	Price	Options	Price
Options outstanding:
Beginning of year	1,980,441		$5.65	2,315,441	$5.19	2,836,833	$5.08
Granted	--	��	--	--	--	--	--
Exercised	(435,000)		2.40	(335,000)	2.44	(466,726)	4.13
Cancelled	(75,000)		8.58	--	0.00	(54,666)	8.42
Expired	--		--	--	--	--	--
End of year	1,470,441		$6.47	1,980,441	$5.65	2,315,441	$5.19

Exercisable at year-end	1,470,441		$6.47	1,980,441	$5.65	2,303,776	$5.16

During 2009, we issued 379,500 shares of restricted stock, resulting in deferred compensation of $1,043,625, which will be amortized ratably over the three-year vesting period. Expense recognized during 2009 totaled $10,269.

During 2008, we 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 for these shares during 2009 and 2008 totaled $335,214 and $9,184, respectively.

During 2007, we 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 2009, 2008, and 2007 totaled $761,649, $761,805, and $52,088, respectively.

In December of 2006, we 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 2009, 2008, and 2007 totaled $585,398, $684,608, and $684,557, respectively.

In November of 2005, we 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 and 2007 totaled $895,805 and $1,024,862, respectively.

F-24

In 2009 and 2008, we recognized $0 and $15,508 in expense related to unvested stock options granted prior to the adoption of current accounting standards. There was no unamortized expense related to unvested options at December 31, 2009. All options outstanding at December 31, 2009, are fully vested.

The following table summarizes information about stock options outstanding as of December 31, 2009:

	Outstanding			Exercisable
		Weighted
		Average	Weighted		Weighted
Exercise	Number	Remaining	Average	Number	Average
	of Options	Contractual Life	Exercise	of Options	Exercise
Price Range	Outstanding	(in years)	Price	Exercisable	Price
$3.14 - $3.20	51,000	0.69	$3.19	51,000	$3.19
$3.98 - $3.98	587,109	0.82	3.98	587,109	3.98
$6.06 - $6.06	4,167	1.07	6.06	4,167	6.06
$8.37 - $8.37	793,165	1.67	8.37	793,165	8.37
$9.00 - $10.65	35,000	2.35	9.89	35,000	9.89
Total	1,470,441	1.31	$6.47	1,470,441	$6.47

The aggregate intrinsic value of outstanding stock options at December 31, 2009, was $0.

Restricted Stock

The following table summarizes restricted stock activity during 2009, 2008, and 2007:

	2009	2008	2007
	Number	Number	Number
	of Shares	of Shares	of Shares
Unvested restricted stock outstanding:
Beginning of year	714,421	679,788	516,900
Issued	379,500	367,000	370,925
Forfeited	(18,798)	(8,690)	(4,020)
Vested	(335,588)	(323,677)	(204,017)
End of year	739,535	714,421	679,788

The aggregate intrinsic value of unvested restricted stock at December 31, 2009, was $2,107,675. The aggregate intrinsic value represents the total pretax intrinsic value, based on our stock price of $2.85 as of December 31, 2009, which would have been received by the restricted stock award holders had all in-the-money restricted stock awards and options been vested as of that date.

Warrants

The following table summarizes warrant activity during 2009, 2008, and 2007:

	2008		2007
	Number	Price	Number	Price
	of Shares	Range	of Shares	Range
Warrants outstanding and exercisable:
Beginning of year	3,325,373	$3.60--$6.00	3,615,373	$3.60--$6.00
Issued	--	--	--	--
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

There were no warrants issued and outstanding during 2009.

F-25

Note 12: Business Segments

We operate within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. Revenues associated with our E&P activities are comprised of oil and gas sales from our producing properties in Poland and oil sales from our producing properties in the United States. During the last three years, all sales of oil and gas in Poland were made to POGC or its affiliated companies. Over 90% of our oil sales in the United States were to Cenex during 2009, 2008, and 2007. 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. We believe the purchasers of our oil production in the United States could be replaced, if necessary, without a loss in revenue.

E&P operating costs are comprised of: (1) exploration costs (geological and geophysical costs, exploratory dry holes, and 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 our operations in Poland. The majority of lease operating costs are related to our domestic production.

Revenues associated with our oilfield services segment are comprised of contract drilling and well-servicing fees generated by our oilfield-servicing equipment in Montana. Oilfield-servicing costs are comprised of direct costs associated with our oilfield services.

DD&A directly associated with a respective business segment is disclosed within that business segment. We do 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 our operating business segments for management and business segment reporting purposes. All material intercompany transactions between our business segments are eliminated for management and business segment reporting purposes.

Information on our operations by business segment for 2009, 2008, and 2007 is summarized as follows:

	2009
					Oilfield		Total
	Exploration & Production				Services		(In thousands)
	U.S.		Poland
Operations summary:
Revenues	$	3,313	$	9,459	$	1,892	$	14,664
Lease operating expense		(2,528)		(950)		--		(3,478)
Oilfield services costs		--		--		(1,412)		(1,412)
Exploration expense		(204)		(4,625)		--		(4,829)
Impairment expense / ARO revision		529		(1,864)		--		(1,334)
Accretion expense		(13)		(28)		--		(41)
Asset retirement obligation gain		696		--		--		696
DD&A expense		(64)		(851)		(597)		(1,512)
Operating income (loss)	$	1,033	$	1,141	$	(117)	$	2,057
Identifiable net property and equipment:
Unproved properties	$	20	$	3,383	$	--	$	3,403
Proved properties		695		25,895		--		26,590
Equipment and other		--		101		2,102		2,203
Total	$	715	$	29,379	$	2,102	$	32,196
Net Capital Expenditures:
Property and equipment	$	498	$	6,533	$	929	$	7,960
Total	$	498	$	6,533	$	929	$	7,960

F-26

	2008
					Oilfield		Total
	Exploration & Production				Services		(In thousands)
	U.S.		Poland
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

	2007
					Oilfield		Total
	Exploration & Production				Services		(In thousands)
	U.S.		Poland
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

F-27

A reconciliation of the segment information to the consolidated totals for 2009, 2008, and 2007 follows:

	2009		2008		2007
	(In thousands)
Revenues:
Reportable segments	$	14,664	$	17,841	$	17,996
Non-reportable segments		--		--		--
Total revenues	$	14,664	$	17,841	$	17,996
Net loss:
Operating income (loss), reportable segments	$	2,057	$	(20,670)	$	(2,485)
Expense or (revenue) adjustments:
Corporate DD&A expense		(90)		(80)		(120)
General and administrative costs (G&A)		(7,257)		(7,030)		(7,061)
Amortization of deferred compensation (G&A)		(1,693)		(2,367)		(2,604)
Total net operating loss		(6,983)		(30,147)		(12,270)
Non-operating income:
Interest income (net of interest expense) and other income		(600)		(278)		433
Foreign exchange gain (loss)		7,053		(24,279)		146
Net loss	$	(530)	$	(54,704)	$	(11,691)
Net property and equipment:
Reportable segments	$	32,196	$	26,743	$	21,723
Corporate assets		95		130		162
Net property and equipment	$	32,291	$	26,873	$	21,885
Property and equipment capital expenditures:
Reportable segments	$	7,960	$	25,659	$	6,479
Corporate assets		27		20		73
Total property and equipment capital expenditures	$	7,987	$	25,679	$	6,552

Note 13: Quarterly Financial Data (Unaudited)

Summary quarterly information for 2009 and 2008 is as follows:

	Quarter Ended
	December 31	September 30	June 30	March 31
	(In thousands, except per share amounts)
2009:
Revenues	$ 6,607	$ 3,809	$ 2,466	$ 1,782
Net operating income (loss)	2,028	(2,649)	(2,543)	(3,819)
Net income (loss)	3,336	9,448	11,090	(24,404)
Basic and diluted net income( loss) per common share	$0.08	$ 0.22	$ 0.26	$ (0.57)
2008:
Revenues	$ 3,325	$ 5,096	$ 5,195	$ 4,225
Net operating loss	(20,666)	(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)

The net loss for 2009 includes a foreign exchange gain of $7.1 million primarily related to FX Energy Poland’s intercompany loans from FX Energy, Inc. 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 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.

F-28

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, 2009 and 2008, are summarized as follows:

		United States		Poland	Total
				(In thousands)
December 31, 2009:
Proved properties	$	4,012	$	28,688	$	32,700
Unproved properties		20		3,383		3,403
Total gross properties		4,032		32,071		36,103
Less accumulated depreciation, depletion and amortization		(3,317)		(2,794)		(6,111)
	$	715	$	29,277	$	29,992
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

Results of Operations

Results of operations are reflected in Note 12, Business Segments. There is no tax provision because we are not likely to pay, and have not received any benefit from, any federal or local income taxes due to our operating losses. Total production costs (in thousands) for 2009, 2008, and 2007 were $3,478, $3,441, and $3,538, respectively.

Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration, and development activities during 2009, 2008, and 2007, whether capitalized or expensed, are summarized as follows:

		United States		Poland		Total
				(In thousands)
Year ended December 31, 2009:
Acquisition of unproved properties	$	--	$	525	$	525
Exploration costs		204		6,411		6,615
Development costs		498		3,722		4,220
Total	$	702	$	10,658	$	11,360
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

F-29

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information
-continued-

		United States		Poland		Total
				(In thousands)
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

Impairment of Oil and Gas Properties

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

	2009	2008	2007
Impairment of properties	$1,864	$14,746	$2,299

Exploratory Dry Hole Costs

Total dry hole costs in 2009 of $150,821 were related to a single dry hole drilled in the United States. Dry hole costs for 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.

Summary Oil and Gas Reserve Data (Unaudited)

The following disclosures about our crude oil and natural gas reserves and exploration and production activities are in accordance with accounting principles generally accepted in the United States of America for disclosures about oil and gas producing activities and Securities and Exchange Commission rules for oil and gas reporting disclosures.

Reserves

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.

Recent SEC and FASB Rule-Making Activity

In December 2008, the Securities and Exchange Commission announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 1. Summary of Significant Accounting Policies New Accounting Standards. We adopted the rules effective December 31, 2009, and the rule changes, including those related to pricing, are included in our reserves estimates.

In addition, in January 2010, the FASB issued new standards to provide consistency with the Securities and Exchange Commission’s rules. See Note 1. Summary of Significant Accounting Policies – New Accounting Standards.

F-30

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information
-continued-

Application of the new rules resulted in the use of lower prices at December 31, 2009, for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009, as required by the new rules, resulted in a decrease in proved reserves of approximately 990,000 cubic feet of natural gas equivalents. Prior to 2009, oil and gas reserves were determined using year-end prices. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.

Because we use year-end reserves and add back production to calculate DD&A, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense. We estimate the impact of using 12-month average commodity prices, as required by the new standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $14,000.

Definitions

The following definitions apply to the terms used in this disclosure:

Reserves Estimate—The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.

Proved Oil and Gas Reserves—Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Developed Oil and Gas Reserves—Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.

Undeveloped Oil and Gas Reserves—Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion or production facilities.

For complete definitions of proved natural gas, natural gas liquids, and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).

Reserves Estimates Preparation

Estimates of our proved Polish reserves were prepared by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved domestic reserves were prepared by Hohn Engineering, an independent engineering firm in Billings, Montana. The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both RPS Energy and Hohn Engineering are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

F-31

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, 2009	463	--	--	20,409
December 31, 2008	45	47	--	7,873
December 31, 2007	482	14	--	5,288

Total Proved Reserves:

The following unaudited summary of proved 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, 2009:
Beginning of year	45	47	--	45,312
Extensions or discoveries (1)	--	--	--	6,333
Revisions of previous estimates (2)	482	(47)	--	(2,095)
Production	(64)	--	--	(1,882)
End of year	463	--	--	47,668
December 31, 2008:
Beginning of year	482	14	--	31,116
Extensions or discoveries (3)	--	--	--	11,295
Revisions of previous estimates (4)	(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 (5)	--	--	--	17,939
Revisions of previous estimates (6)	170	(163)	--	(4,247)
Production	(70)	(25)	--	(1,840)
End of year	482	14	--	31,116

_______________

(1)	Volume increase in Poland attributable to new Kromolice-2 and Grabowka wells drilled or recompleted during 2009.

(2)	Positive oil revisions in the United States attributable to higher average oil prices during 2009 compared to year-end 2008 oil prices. Negative gas revisions due to the cessation of production at the Wilga well in Poland.

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

(4)	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.

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

(6)	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-32

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

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. We believe 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 our expectations of actual revenues to be derived from those reserves or 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 our 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 our Polish reserves are based on a gas sales contracts we have with POGC.

The components of SMOG are detailed below:

		United States		Poland		Total
				(In thousands)
December 31, 2009:
Future cash flows	$	22,050	$	283,520	$	305,570
Future production costs		(16,334)		(26,750)		(43,084)
Future development costs		--		(17,940)		(17,940)
Future income tax expense		--		(33,411)		(33,411)
Future net cash flows		5,716		205,419		211,135
10% annual discount for estimated timing of cash flows		(2,217)		(63,095)		(65,312)
Discounted net future cash flows	$	3,499	$	142,324	$	145,823
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

F-33

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information
-continued-

The principal sources of changes in SMOG are detailed below:

	Year Ended December 31,
	2009		2008		2007
				(In thousands)
SMOG sources:
Balance, beginning of year	$	117,568	$	102,968	$	63,757
Sale of oil and gas produced, net of production costs		(9,294)		(10,053)		(11,364)
Net changes in prices and production costs		14,530		(9,220)		7,866
Acquisition of minerals in place				--		--
Extensions and discoveries, net of future costs		18,200		27,000		62,343
Changes in estimated future development costs		(367)		(4,940)		(5,022)
Previously estimated development costs incurred during the year		3,656		--		420
Revisions in previous quantity estimates		(1,671)		10,383		(13,561)
Accretion of discount		11,757		10,297		6,376
Net change in income taxes		(3,906)		(7,941)		(8,008)
Changes in rates of production and other		(4,650)		(926)		161
Balance, end of year	$	145,823	$	117,568	$	102,968

F-34

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

Year Ended December 31,

(In thousands)

Noncash investing transactions:

Additions to properties included in current liabilities