FX Energy (FXEN) 10-K 2007 FY Annual report

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, 2007
Commission File Number: 000-25386
FX ENERGY, INC.
(Exact name of registrant as specified in its charter)
Nevada	87-0504461
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
3006 Highland Drive, Suite 206, Salt Lake City, Utah	84106
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code:	Telephone (801) 486-5555
	Facsimile (801) 486-5575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of each exchange on which registered
Common Stock, Par Value $0.001	NASDAQ Global Market
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)

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

Yes o No x

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

Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 29, 2007, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $321,319,000.

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 3, 2008, FX Energy had outstanding 40,296,447 shares of its common stock, par value $0.001.

DOCUMENTS INCORPORATED BY REFERENCE. FX Energy’s definitive Proxy Statement in connection with the 2008 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, 2007

TABLE OF CONTENTS

Item		Page
	Part I
--	Special Note on Forward-Looking Statements	3
1	Business	4
1A	Risk Factors	10
1B	Unresolved Staff Comments	16
2	Properties	17
3	Legal Proceedings	26
4	Submission of Matters to a Vote of Security Holders	27
	Part II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
6	Selected Financial Data	28
7	Management’s Discussion and Analysis of Financial Condition and Results of Operation	29
7A	Quantitative and Qualitative Disclosures about Market Risk	39
8	Financial Statements and Supplementary Data	39
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	39
9A	Controls and Procedures	40
9B	Other Information	40
	Part III
10	Directors, Executive Officers and Corporate Governance	41
11	Executive Compensation	42
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	42
13	Certain Relationships and Related Transactions, and Director Independence	42
14	Principal Accountant Fees and Services	42
	Part IV
15	Exhibits and Financial Statement Schedules	43
--	Signatures	47
--	Management’s Report on Internal Control over Financial Reporting	F-1
--	Report of Independent Registered Public Accounting Firm	F-2

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SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS

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

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

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

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

• whether actual exploration risks will be consistent with our forecasts;

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

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

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

• the ability to economically develop and market discovered reserves;

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

• foreign currency exchange rate fluctuations;

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

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

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

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

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

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

• uncertainties of certain terms to be determined in the future relating to our oil and gas interests, including exploitation fees, royalty rates, and other matters;

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

• other factors that are not listed above.

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

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PART I

ITEM 1. BUSINESS

Introduction

We are an independent oil and gas exploration and production company headquartered in Salt Lake City, Utah. Our principal production, reserves, and exploration activities are in Poland, although we have a modest oil presence in the U.S. We hold 3.7 million gross acres (3.2 million net) in Poland. We believe Poland represents 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 20th Century, the country was closed to exploration by foreign oil and gas companies. Consequently, we think the Polish Permian Basin is underexplored and underexploited.

Independent engineers estimated our total oil and gas reserves at 34.1 billion cubic feet of gas equivalents, or “Bcfe.” Our total oil and gas reserves increased approximately 50% from year end 2006 to 2007. Our production more than doubled from 2006 to 2007. In both cases, the increase was virtually all attributable to our exploration in Poland. See Item 7, Management’s Discussion and Analysis, for further information.

References to us in this report include FX Energy, Inc., our subsidiaries, and the entities or enterprises organized under Polish law in which we have an interest and through which we conduct our activities in that country. See “Oil and Gas Terms” at the end of Item 2, Properties, for definitions of certain industry terms.

Corporate Strategy

We hold substantial acreage in productive fairways or geological trends, primarily in Poland, that we consider underexplored and underdeveloped, where we believe we have the opportunity to find significant gas and oil reserves while mitigating risk through the application of new exploration technology. Our strategy is to:

• increase production and reserves in our core area;

• utilize revenues from our core area to support high potential exploration on our substantial non-core acreage.

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. 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.”

Acting on this thesis, we have accumulated a 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 with modern exploration tools and generated a number of attractive gas prospects. This has already begun to bear fruit with several new discoveries on which to build a production base to support our ongoing exploration program in Poland.

Some of our Polish operations are conducted in partnership with the Polish Oil and Gas Company, or 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.

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Current Activities and Assets in Poland

We focus 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:

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

• In the last 20 years very little exploration focused on the Rotliegend has been conducted in Poland.

We have identified a core area consisting of approximately 852,000 gross acres surrounding the Radlin field. This 390 billion cubic feet, or Bcf, Rotliegend gas field was discovered in the 1980s by our joint venture partner, POGC, which owns and produces gas from it. We have emphasized improved seismic data acquisition and processing in our exploration, using technology developed for Rotliegend exploration in the Southern North Sea. With this approach we have made commercially successful discoveries in four of the five wells we have drilled on Rotliegend structural targets using new two-dimensional, or 2-D, seismic data.

We have made commercial discoveries in the course of our Polish exploration which, at December 31, 2007, were estimated to total 31 Bcf of gas and 14,000 barrels, or Bbls, of light crude oil, net to our interest. Future net revenues, discounted to present value at 10% per annum, or PV-10 value, were estimated at approximately $103 million after taxes. These figures exclude all of our historical Polish production and cash flows through December 31, 2007.

Based on these discoveries and associated technical work, we have identified a subset of our acreage, the Sroda area, as having significant natural gas potential and low drilling risk. Within the Sroda area we have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers. Using this data, we have identified a number of possible structural traps. We believe the 3-D seismic data gives us better definition of the targets and might further reduce our drilling risk. We have scheduled two rigs for the Sroda area to carry out a multi-year exploration, appraisal, and development drilling program. Our operations in the Sroda area focus on the first element of our general strategy–increase production and reserves in our core area.

While maintaining our focus on the Rotliegend structural trap exploration model in our core area, we are also carrying out exploration work on other potential exploration models. These include non-Rotliegend prospects in our core area on various exploration opportunities on our 2.8 million net acres outside our core area. For example, we are currently drilling a well, the Grundy-1, to test a Zechstein carbonate prospect in our core concession. Outside our core concession we are acquiring seismic data on several possible leads in our Northwest concession block. We anticipate continuing exploration work on our non-core acreage and on the secondary exploration targets in our core area. However, the Rotliegend structural trap gas prospects in our core area will continue to receive the greatest portion of our efforts and capital resources.

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, and President of the European Region of AAPG Europe. Mr. Hardman was appointed to our board of directors in October 2003 and is Chairman of our Technical and Advisory Panel.

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            Jerzy Maciolek is a director of the Company and, as Vice President of International Exploration, heads our exploration team. He joined the Company in 1995 specifically to lead it into Poland where he had identified the exploration opportunity that today is the Company’s core asset. Mr. Maciolek has over 25 years’ 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 is fairly mature. It provides a modest amount of cash flow and is not capital intensive. It consists mostly of shallow, oil-producing wells in the Cut Bank oil field of Montana. As of December 31, 2007, our U.S. reserves were estimated at 482,000 barrels of crude oil with a PV-10 value of approximately $11 million.

Exploration, Development and Production Activities

Polish Exploration Rights

As of December 31, 2007, we held oil and gas exploration rights in Poland in the following gross acreage components:

	Operator		Gross	Working
	FX Energy	POGC	Acreage	Interest
Concession Area:
Fences project area		X	852,000	49%(1)
Wilga project area	X		250,000	82%
Northwest project area	X		1,167,000	100%
Kutno project area	X		284,000	100%
Lublin / Warsaw South project area	X		935,000	100%
Block 287 project area	X		213,000	100%
Total gross acreage			3,701,000

_______________

(1) Except for 45,000 acres in which we hold a 24.5% working interest.

As we explore and evaluate our acreage in Poland, we expect to increasingly focus our operational and financial efforts on higher potential areas. 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 six areas: Fences, Northwest, Kutno, Warsaw South, Block 255, and Block 287. Our exploration activities are currently focused primarily on the core Fences area, where the gas-bearing Rotliegend sandstone reservoir rock is a direct analog to the Southern North Sea gas basin offshore the United Kingdom. We are focused on this core area because substantial gas reserves have already been discovered and developed by POGC, we have made five commercial gas discoveries, together with POGC, containing proved gas reserves of approximately 72 Bcf gross (31 Bcf net to our interest), and we have concluded that there is likely to be substantial additional natural gas in the same geologic horizon.

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Fences Area

The Fences concession area is 852,000 gross acres (3,450 sq. km.) in western Poland’s Permian Basin surrounding POGC’s Radlin gas field. The Radlin field and several other POGC gas fields located in the Fences area are “fenced off” or excluded from our exploration acreage. These fields, discovered by POGC between 1974 and 1982, produce from structural traps in the Rotliegend sandstone.

We hold a 49% interest in approximately 807,000 acres and a 24.5% interest in the remaining 45,000 acres in the Fences area.

The Rotliegend is the primary target horizon throughout most of the Fences concession area, at depths from approximately 2,500 to 4,000 meters. There are two types of Rotliegend traps in the region: structural traps and stratigraphic (“pinch-out”) traps. Both of these trap types are known to produce gas in the region. In addition, we have identified what appear to be carbonates in the Zechstein, 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 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 six wells targeting Rotliegend structures. Five of these wells are commercial, with aggregate proved gas reserves of approximately 71 Bcf gross (31 Bcf net to our interest).

In January 2007, we completed the Winna Gora well as a commercial success (with production anticipated to begin at the end of 2009). At year-end, gross proved reserves for the well were estimated at approximately 7.5 Bcf of gas (3.7 Bcf net to our 49% interest). 3-D seismic data in the Winna Gora area will be available during 2008 and should assist us in determining whether to produce the existing vertical well or, alternatively, drill a horizontal well in this structure.

In May 2007, we completed the Roszkow-1 well as a commercial success (with initial production in late 2008 or early 2009). At December 31, 2007, gross proved reserves for the well were estimated at approximately 29.1 Bcf of gas (14.3 Bcf net to our 49% interest).

Three more wells targeting Rotliegend structural traps are scheduled to start drilling in 2008. Each well targets an as-yet undrilled structure in the area of the Sroda-4 and Sroda-5 wells. The structural targets are named: Kromolice-N, Kromolice-S, and Sroda City. These three wells will be located with the help of our recently completed 3-D seismic data.

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 and plan to acquire an additional 200 square kilometers of 3-D seismic data in 2008 in the area where the Sroda-4, Sroda-5, and Winna Gora wells are located and along the trend to the southeast. We also plan to acquire approximately 200 kilometers of 2-D seismic data over a lead, Taczanow, that lies on the trend southeast from the Zaniemysl and Roszkow wells, our two biggest discoveries to date.

Finally, in the northern-most part of our Fences concession and lying within the area covered by our recent 3-D seismic data, we have identified a very large upthrown block, or horst, of Rotliegend sandstone that encompasses approximately 50 square kilometers, or 12,000 acres, within our Fences concession, and continues into the area north of our concession. One well, the 1984 Plawce-1, was drilled on this Rotliegend block within what is now our Fences concession. Five other wells have been drilled in this block north of our concession boundary, all but one of them more than 20 years ago. 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 6 kilometers north of our concession, was drilled in 2007 and reportedly tested gas at rates between 2.5 and 7.5 million cubic feet of natural gas per day, or MMcfD, after hydraulic fracturing.

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            We are currently working with service companies that specialize in production from tight Rotliegend reservoirs in the southern United Kingdom gas basin and in Germany. Over the next few months we will prepare a plan to appraise and develop the gas resource in the Plawce area. We have scheduled additional field work in 2008 that will enhance the quality of our 3-D seismic and appraisal data in the Plawce area.

       Fences Area: Stratigraphic Traps

In the southwestern portion of the Fences concession, outside the area prone to Rotliegend structures, there is potential for stratigraphic trapping, or pinch-outs, in the Rotliegend. Based on data from the Rusocin-1 and the Lugi-1 wells we drilled in 2005, and on the presence of wells that produce from stratigraphic traps further to the west from our concession, we plan to acquire 3-D data in 2009 that will help us determine the next steps in exploring the pinch-out area.

      Fences Area: Carbonate (Reef) Traps

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

Northwest Concession Area

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

During 2007 the Company’s technical team reviewed the existing sparse, 20 year old geological and geophysical data from the area. In an area of 1.6 million acres, there were only about 2,500 kilometers of 2-D seismic data and only three wells drilled to target depths. As a result of this review, we elected to relinquish approximately 500,000 acres from the northeast corner of this concession, retaining approximately 1.1 million acres. In January 2008, we initiated field work to acquire just over 200 kilometers of new 2-D seismic over several of the leads identified the previous year. We plan to seek industry participation 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. The area encompasses a Rotliegend mega-structure (“Kutno”) with projected four-way dip closure. The interpreted gas column is 280 meters over an area of 143 square kilometers. With expected porosity of between 5% and 15%, the structure has a calculated potential gross volume of up to 19 trillion cubic feet. Depth of the structure is estimated at approximately 6,000 meters (19,200 feet). In view of the depth and cost, we are seeking industry participation to drill Kutno.

Warsaw South Concession Area

In 2007, we acquired a 100% interest in a concession in east central Poland covering approximately 935,000 acres. The Warsaw South concession has several possible exploration opportunities, including carboniferous sands with structural or truncation trapping and Zechstein reefs trapped by overlying evaporates and salt. During 2007, our technical group reviewed the geological and geophysical data from the area. The team identified a dozen carboniferous leads and two possible Zechstein reef targets. We plan to seek industry participation while continuing to carry out early stage exploration work on our own.

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Block 255 Concession Area

The Block 255/Wilga concession area in east central Poland consists of an 82% working interest in approximately 250,000 gross acres. We have one producing well, Wilga-2, in Block 255, the result of an exploration project conducted several years ago by us and Apache Corporation. As of December 31, 2007, the Wilga well had remaining gross proved reserves of approximately 0.55 Bcf of gas and 16,900 barrels of light crude oil (0.45 Bcf and 14,000 barrels, net to our interest). Wilga-2 is currently producing approximately 1 MMcfD of high methane gas and 20 barrels of light crude oil per day from sands in the Carboniferous.

Block 287 Concession Area

The Block 287 concession area is 213,000 acres (863 sq. km.) located approximately 25 miles south of the Fences concession area. We own 100% of the exploration rights. Block 287 was part of a larger concession area which we relinquished in 2007 based on our technical evaluation and on a 2006 dry hole that we drilled.

Within Block 287 there are three Rotliegend gas wells known as the Grabowka wells. Originally drilled by POGC in 1983-85, these three wells tested gas but never produced commercially. In early 2007, we entered into a joint venture agreement with an unrelated party, PL Energia S.A., headquartered in Krzywoploty, Poland, under which all costs of re-entering and completing the three Grabowka wells and building production facilities will be paid by our joint venture partner in exchange for discounted pricing on gas. If our re-entry of these wells is commercial, the project is expected to come on-stream in the second half of 2008. We do not plan to conduct further technical work on Block 287.

Additional Concession Acreage

We have applied for additional concession blocks in Poland that have not yet been issued. We may apply for yet more concession blocks in Poland in 2008. We will allocate modest technical and financial resources to these areas during 2008, 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 2007, we did not drill any wells. We may drill one or two exploratory wells in 2008 on land that is near our existing producing properties in Nevada.

Montana

During 2007, we did not drill any wells in Montana. We may drill one or two exploratory wells in 2008 using our own drilling rig.

Segment Information

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

Available Information

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

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ITEM 1A. RISK FACTORS

Risk Factors

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

Risks Relating to our Business

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

We currently have a limited amount of production in the United States and Poland. While during 2008 we anticipate that we will generate revenues in excess of our general and administrative costs, these revenues are not sufficient to cover all of our exploration and development costs, and we will continue to rely on existing working capital and possibly on funds from external sources to cover these costs. Our exploration programs in Poland are based on interpretations of geological and geophysical data. The factors listed below, most of which are outside our control, may prevent us from establishing additional commercial production or substantial reserves as a result of our exploration, appraisal, and development activities in Poland:

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

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

• whether actual exploration risks will be consistent with our forecasts;

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

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

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

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

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

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

Our partner, POGC, holds the majority interest and is operator of our Fences project area and has a minority interest in our Wilga project area. As a paying partner, we rely to a significant extent on the financial capabilities of POGC. If POGC were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on us. In particular, we have prepared our exploration budget through 2008 and beyond based on the participation of and funding to be provided by POGC. Although we have rights to participate in exploration and development activities on some POGC-controlled acreage, we have limited rights to initiate such activities. Further, we have no direct interest in some of the underlying agreements, licenses, and grants from the Polish agencies governing the exploration, exploitation, development, or production of acreage controlled by POGC. Thus, our program in Poland involving POGC-controlled acreage would be adversely affected if POGC should elect not to pursue activities on such acreage, if the relationship between us and POGC should deteriorate or terminate, or if POGC or the governmental agencies should fail to fulfill the requirements of or elect to terminate such agreements, licenses, or grants.

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

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

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

Notwithstanding the accumulation and study of 2-D and 3-D seismic data, drilling logs, production information from established fields, and other data, we cannot predict accurately the oil or gas potential of individual prospects and drilling targets or the related risks. We sometimes predict the gross potential oil or gas in a particular area as part of our evaluation of the exploration potential and related risks. Our predictions are only rough, preliminary geological estimates of the forecasted volume and characteristics of possible reservoirs and the calculated potential oil or gas that could be contained if present. Such forecasts are not an assurance that our exploration will be successful or we will be able to establish reserves equal to such forecasts. In some cases, our estimates may be based on a review of data from other exploration or producing fields in the area that ultimately may be found not to be similar to our exploration prospects. We may require several test wells and long-term analysis of test data and history of production to determine the oil or gas potential of individual prospects.

We have had limited exploratory success in Poland.

We have participated in drilling 25 exploratory wells in Poland, including six commercial discoveries (the Wilga 2, Kleka 11, Zaniemysl-3, Sroda-4, Winna Gora-1, and Roszkow-1), and nineteen non-commercial wells. Of our six commercial successes in Poland, we were producing gas at our Wilga 2, Zaniemysl-3, and Kleka 11 wells as of December 31, 2007.

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

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

11

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 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, 2007, we have incurred cumulative net losses of approximately $105 million. We expect that our exploration and production activities may continue to result in net losses through 2008 and possibly beyond, depending on whether our activities in Poland and the United States result in sufficient revenues to cover related operating expenses.

Until sufficient cash flow from operations can be obtained, we expect we will need additional capital to fully fund our ongoing planned exploration, appraisal, development, and property acquisition programs in Poland. We may seek required funds from the issuance of additional debt, equity or hybrid securities, project financing, strategic alliances, or other arrangements. Obtaining additional financing may dilute the interest of our existing stockholders or our interest in the specific project being financed. We cannot assure that additional funds could be obtained or, if obtained, would be on terms favorable to us. In addition to planned activities in Poland, we may require additional funds for general corporate purposes.

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

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

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

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

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

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

12

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

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

• the market and price structure in local markets;

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

• market uncertainty;

• political conditions in international oil and gas producing regions;

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

• the level of consumer demand;

• weather conditions affecting production, transportation, and consumption;

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

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

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

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

• other factors beyond our control.

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

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

Our oil and gas drilling and production operations are subject to hazards incidental to the industry. These hazards include blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas, and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. To lessen the effects of these hazards, we maintain insurance of various types to cover our domestic and international operations. We cannot assure that the insurance policies carried by us 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.

13

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, Poland’s laws, policies, and procedures were changed to conform to the requirements that had to be met before Poland was admitted as a full member of the European Union.

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

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

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

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

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

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

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

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Risks Related to an Investment in our Common Stock

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

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

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

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

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

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

Our common stock has traded as low as $4.41 and as high as $10.60 during intraday trading between January 1, 2007, and the date of this report. Some of the factors leading to this volatility include:

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

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

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

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

• actions or announcements by POGC that may affect us;

• prevailing world prices for oil and gas;

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

The Republic of Poland

The Republic of Poland is located in central Europe, has a population of approximately 39 million people, and covers an area comparable in size to New Mexico. During 1989, Poland peacefully asserted its independence and became a parliamentary democracy. Since 1989, Poland has enacted comprehensive economic reform programs and stabilization measures that have enabled it to form a free-market economy and turn its economic ties from the east to the west, with most of its current international trade with the countries of the European Union and the United States. The economy has undergone extensive restructuring in the post-communist era. The Polish government credits foreign investment as a forceful growth factor in successfully creating a stable, free-market economy.

Since its transition to a market economy and a parliamentary democracy, Poland has experienced significant economic growth and political change. Poland has developed and is refining legal, tax, and regulatory systems characteristic of parliamentary democracies with interpretation and procedural safeguards. The Polish government has taken steps to harmonize Polish legislation with that of the European Union, which it joined in May of 2004.

Poland has created an attractive legal framework and fiscal regime for oil and gas exploration by actively encouraging investment by foreign companies to offset its lack of capital to further explore its oil and gas resources. In July 1995, Poland’s Council of Ministers approved a program to restructure and privatize the Polish petroleum sector. So far under this plan, a refinery located in Plock has been privatized as a publicly held company with its stock trading on the London and Warsaw stock exchanges. In September of 2005, POGC sold 15% of its stock in an initial public offering on the Warsaw Stock Exchange, raising a total of 2.7 billion Polish zlotys (approximately US$900 million).

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

Polish Properties

Legal Framework

General Usufruct and Concession Terms

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

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 solvency of POGC as the record owner.

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            The concession authority has granted us oil and gas exploration rights on the Block 287 and Wilga project areas, and has granted POGC oil and gas exploration rights on the Fences project areas. The agreements divide these areas into blocks, generally containing approximately 250,000 acres each. Concessions have been acquired for exploration in all areas that lie within existing usufructs. The exploration period begins after the date of the last concession signed under each respective usufruct. We believe all material concession terms have been satisfied to date.

If commercially viable oil or gas is discovered, the concession owner, during the first two years of production, then applies for an exploitation concession, as provided by the usufructs, generally with a term of 25 to 30 years or as long as commercial production continues. Upon the grant of the exploitation concession, the concession owner may become obligated to pay a fee, to be negotiated, but expected to be less than 1% of the market value of the estimated recoverable reserves in place. The concession owner would also be required to pay a royalty on any production, the amount of which will be set by the Council of Ministers, within a range established by legislation for the mineral being extracted. The royalty rate for high-methane gas is currently less than $0.07 per thousand cubic feet, or Mcf. This rate could be increased or decreased by the Council of Ministers to a rate between $0.02 and $0.10 per Mcf (the current statutory minimum and maximum royalty rates). Local governments will receive 60% of any royalties paid on production. The holder of the exploitation concession must also acquire rights to use the land from the surface owner and could be subject to significant delays in obtaining the consents of local authorities or satisfying other governmental requirements prior to obtaining an exploitation concession.

Existing Project Areas

Fences Project Area

The Fences project area consists of six oil and gas exploration concessions controlled by POGC, including two that were obtained as a result of a public tender in 2007. Three producing fields (Radlin, Kleka, and Kaleje) lie within the concession boundary, but are excluded from the Fences concessions. The original four concessions have expiration dates ranging from July 2008 to September 2012. Remaining work commitments in the aggregate for the four original concessions include acquiring: 200 kilometers of 2-D seismic data, 180 sq. km. of 3-D seismic data, and drilling two wells. POGC has filed an extension for the concession expiring in 2008 which we expect to be granted. The exploration period for the two new concessions will start after they are granted in 2008. The total work commitment for the two concessions is outlined in two phases: Phase I – three years: 260 kilometers of 2-D seismic data; Phase II – three years: drilling two 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 is for a period of six years ending in December 2009. Work commitments included acquiring 100 kilometers of new 2-D seismic data or drilling one well, which was satisfied by the drilling of the Drozdowice-1 well, and analysis and interpretation of existing well data. Beginning in the fourth year, there is a drilling requirement of a second well that will be satisfied by re-entering and producing the Grabowka gas field.

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 2009. The remaining period carries a work commitment of trial production of the Wilga gas-condensate field and 165 kilometers of 2-D seismic data.

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Northwest Project Area

The Northwest project area consists of seven blocks originally awarded in October 2006, and four additional blocks that were awarded as part of a public tender in 2007. The total work commitment for the original seven blocks was outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 960 kilometers of new 2-D seismic data; Phase III – three years: drilling seven wells. As a result of our analysis of existing data during Phase I, we dropped two of the original seven blocks in 2007. In January 2008, we began the acquisition of 220 kilometers of 2-D seismic data in three of the remaining five blocks. For the four new blocks, the exploration period will start after the concessions are granted in 2008. The total work commitment for the four new blocks is outlined in two phases: Phase I – three years: 280 kilometers of 2-D seismic data; Phase II – three years: drilling four wells.

Project areas added in 2007

Lublin/Warsaw South Project Area

This project area is adjacent to Block 255 and consists of five single exploration concessions granted in June, July, and September of 2007 for a period of six years. The total work commitment for the five concessions is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 630 kilometers of new 2-D seismic data; Phase III – three years: drilling five wells.

Kutno Concession

The Kutno concession consists of a single oil and gas exploration concession granted in March 2007 for a period of six years. The total work commitment 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; Phase III – two and one half years: drilling one well.

As of December 31, 2007, all required usufruct/concession payments had been made for each of the above project areas. Usufruct/concession payments on new concessions obtained beginning in 2006 are payable in annual installments over a three-year period.

Production, Transportation and Marketing

The following table sets forth our net daily gas and oil production, average sales price, and average production costs associated with our Polish production during 2007, 2006, and 2005:

		2007		2006		2005
Average daily net gas production (Mcf)(1)		5,039		837		--
Average sales price per Mcf	$	4.95	$	3.88	$	--
Average daily net oil production (Bbls)(1)		69		106		--
Average sales price per Bbl	$	58.68	$	56.58	$	--
Average daily net Mcfe production(1)		5,453		1,473		--
Average production costs per Mcfe(2)	$	0.58	$	0.56	$	--

_______________

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

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

Poland has a network of gas pipelines and crude oil pipelines traversing the country serving major metropolitan, commercial, industrial, and gas production areas, including significant portions of our acreage. Poland has a well-developed infrastructure of hard-surfaced roads and railways over which oil and/or light crude 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 oil or gas we produce, we will be required to obtain prior governmental approval.

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

United States Properties

Producing Properties

In the United States, we currently produce oil in Montana and Nevada. All of our producing properties, except for the Rattlers Butte field (an exploratory discovery during 1997), were purchased during 1994. A summary of our average daily production, average working interest, and net revenue interest for our United States producing properties during 2007 follows:

	Average Daily Production (Bbls)		Average Working	Average Net Revenue
	Gross	Net	Interest	Interest
United States producing properties:
Montana:
Cut Bank	201	173	99.6%	86.4%
Bears Den	7	5	98.0	78.3
Rattlers Butte	6	0	6.3	5.1
Total	214	178
Nevada:
Trap Springs	6	1	21.6	18.9
Munson Ranch	29	9	36.0	34.0
Bacon Flat	23	4	16.9	12.5
Total	58	14
Total United States producing properties	272	192

In Montana, we operate the Cut Bank and Bears Den fields and have an interest in the Rattlers Butte field, which is operated by an industry partner. Production in the Cut Bank field, producing since the 1940s from an average depth of approximately 2,900 feet, is from a waterflood program with 120 producing oil wells, 29 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, discovered during 1997, 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 2007, 2006, and 2005:

	Years Ended December 31,
	2007	2006	2005
United States producing property data:
Average daily net oil production (Bbls)	192	209	217
Average sales price per Bbl	$61.75	$56.07	$48.09
Average production costs per Bbl(1)	$34.12	$27.65	$26.79

_______________

(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.

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            We sell oil at posted field prices to one of several purchasers in each of our production areas. We sell all of our Montana production, which represents over 94% of our total oil sales, to CENEX, a regional refiner and marketer. Posted prices are generally competitive among crude oil purchasers. Our crude oil sales contracts may be terminated by either party upon 30 days’ notice.

Oilfield Services – Drilling Rig and Well-Servicing Equipment

In Montana, we perform, through our drilling subsidiary, FX Drilling Company, Inc., a variety of third-party contract oilfield services, including drilling, workovers, location work, cementing, and acidizing. We currently have a drilling rig capable of drilling to a vertical depth of 6,000 feet, a workover rig, two service rigs, cementing equipment, acidizing equipment, and other associated oilfield servicing equipment.

Proved Reserves

Proved reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. Our proved oil and gas reserve quantities and values are based on estimates prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission, or SEC. Operating costs, production taxes, and development costs were deducted in determining the quantity and value information. Such costs were estimated based on current costs and were not adjusted to anticipate increases due to inflation or other factors. No price escalations were assumed, and no amounts were deducted for general overhead, depreciation, depletion and amortization, and interest expense. The proved reserve quantity and value information is based on the weighted average price on December 31, 2007, of $93.68 per Bbl of oil and $5.61 per Mcf of gas in Poland and $81.07 per Bbl for oil in the United States. The determination of oil and gas reserves is based on estimates and is highly complex and interpretive, as there are numerous uncertainties inherent in estimating quantities and values of proved reserves, projecting future rates of production, and the timing and amount of development expenditures. The estimated present value, discounted at 10% per annum, of the future net cash flows, the Standardized Measure of Future Net Cash Flows (“SMOG”), or PV-10 Value, was determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosure About Oil and Gas Activities,” and SEC guidelines. Our proved reserve estimates are subject to continuing revisions as additional information becomes available or assumptions change.

Estimates of our proved United States oil reserves were prepared by Larry Krause Consulting, an independent engineering firm in Billings, Montana. Estimates of our proved Polish gas reserves were prepared by RPS Energy, an independent engineering firm in the United Kingdom. No estimates of our proved reserves were filed with or included in any report to any other federal agency during 2007.

The following summary of proved reserve information as of December 31, 2007, represents discounted, after tax estimates net to us only, and should not be construed as exact:

	Poland			United States		Total
	Oil	Gas	PV-10 Value	Oil	PV-10 Value	PV-10 Value
	(MBbls)	(MMcf)	(In thousands)	(MBbls)	(In thousands)	(In thousands)
Proved reserves	14	31,116	$91,501	482	$11,467	$102,968

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Drilling Activities

The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2007, 2006, and 2005:

	Years Ended December 31,
	2007		2006		2005
	Gross	Net	Gross	Net	Gross	Net
Exploratory productive wells:
Poland	2.0	1.0	--	--	2.0	0.7
United States	--	--	--	--	--	--
Total	2.0	1.0	--	--	2.0	0.7
Exploratory dry holes:
Poland	--	--	1.0	1.0	2.0	1.0
United States	--	--	2.0	1.5	4.0	2.0
Total	--	--	3.0	2.5	6.0	3.0
Total wells drilled	2.0	1.0	3.0	2.5	8.0	3.7

Wells and Acreage

As of December 31, 2007, our producing gross and net well count consisted of the following:

	Number of Wells
	Gross	Net
Well count:
Poland	3.0	1.6
United States(1)	133.0	127.0
Total	136.0	128.6

_______________

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

The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2007:

	Developed		Undeveloped
	Gross	Net	Gross	Net
Poland:(1)
Fences project area	225	110	852,000	406,000
Block 287	--	--	213,000	213,000
Wilga project area	543	441	250,000	205,000
Kutno project area	--	--	284,000	284,000
Lublin / Warsaw South project area			935,000	935,000
Northwest project area	--	--	1,167,000	1,167,000
Total Polish acreage	768	551	3,701,000	3,210,000
United States:
Montana	10,732	10,418	4,510	4,417
Nevada	400	128	9,332	6,351
Total	11,132	10,546	13,482	10,768
Total Acreage	11,900	11,097	3,714,482	3,220,768

_______________

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

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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 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.

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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.

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            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, 2007, we had 40 employees, consisting of nine in Salt Lake City, Utah; 20 in Oilmont, Montana; one in Greenwich, Connecticut; three in Houston, Texas; and seven in Poland. Our employees are not represented by a collective bargaining organization. We consider our relationship with our employees to be satisfactory. We also regularly engage technical consultants to provide specific geological, geophysical, and other professional services. Our executive officers and other management employees regularly travel to Poland to supervise activities conducted by our staff and others under contract on our behalf.

Offices and Facilities

Our corporate offices, located at 3006 Highland Drive, Salt Lake City, Utah, contain approximately 3,500 square feet and are rented at $3,400 per month under a month-to-month agreement. In Montana, we own a 16,160 square foot building located at the corner of Central and Main in Oilmont. We also have an office in Warsaw, Poland, located at Ul. Chalubinskiego 8, which we rent for approximately $4,300 per month.

Oil and Gas Terms

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

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

“Bbl” means oilfield barrel.

“Bcf” means billion cubic feet of natural gas.

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

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

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

“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic conditions.

“Gross” acres and “gross” wells mean the total number of acres or wells, as the case may be, in which an interest is owned, either directly or through a subsidiary or other Polish enterprise in which we have an interest.

“Horizon” means an underground geological formation that is the portion of the larger formation that has sufficient porosity and permeability to constitute a reservoir.

“LCO” means light crude oil.

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“MBbls” means thousand oilfield barrels.

“Mcf” means thousand cubic feet of natural gas.

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

“MMcf” means million cubic feet of natural gas.

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

“Net” means, when referring to wells or acres, the fractional ownership working interests held by us, either directly or through a subsidiary or other Polish enterprise in which we have an interest, multiplied by the gross wells or acres.

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

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

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

“Tcf” means trillion cubic feet of natural gas.

“Usufruct” means the Polish equivalent of a U.S. 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:

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

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of our security holders during the fourth quarter of the fiscal year ended December 31, 2007.

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
2008:
First Quarter (through March 3, 2008)	$ 4.50	$ 5.94
2007:
Fourth Quarter	5.68	8.19
Third Quarter	6.03	9.29
Second Quarter	7.79	10.39
First Quarter	5.83	7.88
2006:
Fourth Quarter	4.72	7.00
Third Quarter	4.19	5.48
Second Quarter	3.98	5.71
First Quarter	4.04	8.37

We have never paid cash dividends on our common stock and do not anticipate that we will pay dividends in the foreseeable future. We intend to reinvest any future earnings to further expand our business. We estimate that, as of March 2, 2008, we had approximately 10,000 stockholders.

Equity Compensation Plans

The information from the definitive proxy statement for the 2008 annual meeting of stockholders under the caption “Equity Compensation Plans” is incorporated herein by reference.

Recent Sales of Unregistered Securities

None.

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ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for the five years ended December 31, 2007, 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,
	2007	2006	2005	2004		2003
	(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales	$ 14,903	$ 6,533	$ 3,805		$ 3,096		$ 2,230
Oilfield services	3,093	1,696	2,132		710		98
Total revenues	17,996	8,229	5,937		3,806		2,328
Operating costs and expenses:
Lease operating expenses (1)	3,538	2,647	2,462		1,946		1,546
Exploration costs (2)	10,624	5,608	8,369		3,013		523
Recovery of previously expensed
Input VAT	--	--	(2,121)		--		--
Impairment of oil and gas properties (3)	2,299	3,583	--		--		161
Oilfield services costs	1,998	1,245	1,689		551		190
Depreciation, depletion and
amortization	2,064	1,290	903		636		599
Accretion expense	78	53	45		41		37
Amortization of deferred
compensation (G&A)	2,604	2,759	125		--		--
Stock compensation (G&A) (4)	--	--	76		5,859		--
General and administrative (G&A)	6,915	5,606	6,592		4,909		3,253
Total operating costs and expenses	30,120	22,791	18,140		16,955		6,309
Operating loss	(12,124)	(14,562)	(12,203)		(13,149)		(3,981)
Other income (expense):
Interest and other income	818	795	780		529		36
Interest expense	(385)	--	--		--		(788)
Total other income (expense)	433	795	780		529		(752)
Loss before cumulative effect of
change in accounting principle	(11,691)	(13,767)	(11,423)		(12,620)		(4,733)
Cumulative effect of change in
accounting principle	--	--	--		--		1,800
Net loss	$ (11,691)	$ (13,767)	$ (11,423)		$ (12,620)		$ (2,933)

– Continued –

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	Years Ended December 31,
	2007	2006		2005		2004	2003
	(In thousands)
Basic and diluted net loss per share:
Basic and diluted loss per common share before
cumulative effect of change in accounting
principle	$ (0.32)		$ (0.39)		$ (0.33)	$ (0.41)		$ (0.41)
Cumulative effect of change in
accounting principle	--		--		--	--		0.09
Basic and diluted net loss per common share	$ (0.32)		$ (0.39)		$ (0.33)	$ (0.41)		$ (0.32)
Basic and diluted weighted average
shares outstanding	36,694		35,163		34,733	30,691		19,885
Cash Flow Statement Data:
Net cash used in operating activities	$(1,581)		$(5,303)		$(10,105)	$ (5,886)		$ (5,561)
Net cash provided by (used in) investing activities	(13,152)		8,135		4,656	(41,492)		(1,446)
Net cash (used in) provided by financing activities	14,351		(578)		4,055	33,791		23,673
Balance Sheet Data:
Working capital	$ 15,374		$ 11,967		$ 27,715	$ 33,777		$ 16,032
Total assets	46,369		39,167		48,271	52,962		23,769
Long-term debt	--		--		--	--		--
Stockholders’ equity	37,542		31,965		42,280	48,556		21,459

_______________

(1) Includes lease operating expenses and production taxes.

(2) Includes geophysical and geological costs, exploratory dry hole costs, and nonproducing leasehold impairments.

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

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

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

The following discussion of our historical financial condition and results of operations should be read in conjunction with Item 6, Selected Consolidated Financial Data, our consolidated financial statements and related notes contained in this report.

Introduction

As a result of the very different characteristics of our two major operating areas (Poland and U.S.), our financial results show a distinct dichotomy. Our Polish operations are early in their initial development and growth phase, while our U.S. operations are relatively mature. Thus, in late 2006, our results began to show substantial changes and improvement. See “Results of Operations by Business Segment” below.

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

Our 2007 operations reflect a major shift for us, as our exploration efforts in Poland led to our first meaningful production there commencing in late 2006. At that time, we began producing and selling gas from two more of our six commercial discoveries, the Wilga and Zaniemysl wells. Revenues from our Polish properties became the primary component of our revenue in 2007, and will increase further when three more of our commercial wells begin production in 2009 and 2010.

Most of our exploration costs during the past several years have been attributable to our efforts in Poland. We expect our Polish operations will continue to represent the bulk of our exploration costs, reflecting the nature of our exploration efforts there.

Following is a brief discussion concerning certain significant operational and capital events that occurred during 2007 and the first quarter of 2008.

Recent Operational Events

As a result of our ongoing drilling and production successes in Poland, 2007 was a record year for the Company in terms of revenues, oil and gas production, and year-end proved reserve volumes and values.

	2007	2006	Change
Revenues:	(In thousands)
Oil & Gas Sales	$ 14,903	$6,533	+128%
Total Revenues	$ 17,996	$8,229	+119%
Production:
Gas Production (Mcf)	1,840	461	+299%
Oil Production (Bbls)	95	85	+12%
Total Production (Mcfe)	2,412	968	+149%
Proved Reserve Volumes:
Gas Reserves (Mcf)	31,116	19,264	+62%
Oil Reserves (Bbls)	496	584	-15%
Total Reserves (Mcfe)	34,092	22,768	+50%
Proved Reserve Values:
Gas Reserves Value	$102,968	$63,757	+62%

In addition to these new benchmarks, we also saw significant improvement in the areas of cash used in operating activities, liquidity (cash and working capital), finding and development costs, and per unit operating costs. All of these improvements are directly tied to the commencement of production in Poland in late 2006, as well as the successful completion of two new commercial wells in Poland in 2007.

While we expect most 2008 results will remain well above those of 2006 and prior periods, we expect to see a decline in oil and gas production and revenues from 2007 to 2008. This is attributable to our Wilga well. (See Property Impairments for additional information). However, we expect to see another upward trend in early 2009 as we anticipate bringing additional wells in Poland into production.

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Recent Capital Events

2007 Common Stock Offering. In July 2007, we sold 1,500,000 shares of common stock to certain long-term institutional shareholders at a price of $8.63 per share in a registered direct offering. After offering costs, the proceeds to us were approximately $12.4 million. This funding provided the critical resources for us to accelerate and expand our 3-D seismic program in our core Fences area in Poland, allowing us to begin a 155 square kilometer extension of the Sroda 3-D project. This 3-D seismic will cover our 2007 Winna Gora new field discovery, as well as a number of additional Rotliegend sandstone structures previously identified on 2-D seismic. Field work on the survey began in late 2007.

2008 Warrant Exercises. In February 2008, warrant holders exercised a total of 1,990,000 outstanding warrants at a price of $3.60 per share, resulting in proceeds to us of $7.2 million. The warrants were issued in a 2003 offering of common stock and warrants and expired as of March 1, 2008.

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

The Facility is significant to us on a number of levels. First, and foremost, we view the Facility as a validation by a respected international financial institution of the value of our reserves, production, and land in Poland. Second, it provides us with the ability to leverage our balance sheet and finance the development of our gas projects in Poland at a reasonable cost. Third, it provides us with a potentially important initial relationship in the financial community. See Note 5 to the consolidated financial statements for additional information on our Facility.

Property Impairments

Wilga. Our Wilga well in eastern Poland is unique, with no comparable wells to model. It produces both gas and light crude oil, or LCO, or condensate, from three productive zones. The well began to experience significant water encroachment from one of the productive zones in late 2007, and our production engineering data suggest that we may see a sharp decline in oil and gas production over the course of the next 12-18 months as a result. We are currently evaluating alternative methods of sustaining production or slowing the anticipated decline; however, we expect oil and gas revenues in 2008 to be adversely impacted from 20% to 30% by lower Wilga production than that recorded in 2007. As a consequence of the water encroachment, the proved reserves at Wilga have been reduced accordingly, resulting in an impairment of capitalized costs in the amount of $2.3 million in 2007.

Rusocin. During the second half of 2004, we and POGC drilled the Rusocin-1 well, the first well intentionally focused on a stratigraphic trap in the Rotliegend. We believe the well may have discovered commercial quantities of natural gas. However, our exploration and production focus primarily in the Sroda and other areas is to continue in the near term. Therefore, during the fourth quarter of 2006, we determined to delay steps to place the Rusocin well into production as we focus our exploration efforts on the Sroda area. In accordance with the provisions of FASB Staff Position 19-1, “Accounting for Suspended Well Costs,” the capitalized costs associated with this well of $3.4 million were charged to expense in the fourth quarter of 2006.

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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, 2007, 2006, and 2005 (in thousands). See Footnote 12 to the consolidated financial statements for additional detail concerning our segment results.

	Reportable Segments
			Oilfield Services
	Exploration & Production
	Poland	U.S.		Non-Segmented	Total
Year ended December 31, 2007:
Revenues	$ 10,567	$ 4,336	$ 3,093	$         --	$ 17,996
Net income (loss)(1)	(4,415)	1,102	828	(9,206)	(11,691)
Year ended December 31, 2006:
Revenues	$ 2,273	$ 4,260	$ 1,696	$         --	$ 8,229
Net income (loss)(2)	(6,779)	463	296	(7,747)	(13,767)
Year ended December 31, 2005:
Revenues	$       --	$ 3,805	$ 2,132	$          --	$ 5,937
Net income (loss)(3)	(6,238)	(84)	78	(5,179)	(11,423)

_______________

(1) Nonsegmented reconciling items for 2007 include $6,915 of general and administrative costs, $2,604 of noncash stock compensation expense, $433 of other income, and $120 of corporate DD&A.

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

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

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

Exploration and Production Segment

Gas Revenues. As discussed previously, we began gas production in Poland during late 2006, and the related gas revenues rapidly became the primary component of our revenue. Revenues from gas sales were $9.1 million during 2007, compared to $1.8 million and $0 in 2006 and 2005, respectively. Gas production from our Wilga well contributed approximately 42% of our 2007 production volumes and approximately 57% of our 2007 gas revenues.

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            A summary of the amount and percentage change, as compared to their respective prior-year period, for gas revenues, average gas prices, gas production volumes, and lifting costs per Mcf for the years ended December 31, 2007, 2006, and 2005, is set forth in the following table:

	For the year ended December 31,
	2007	2006	2005
Revenues	$9,098,000	$1,790,000	$--
Percent change versus prior year	+408%	NA	--
Average price (per Mcf )	$4.95	$3.88	$--
Percent change versus prior year	+28%	NA	--
Production volumes (Mcf)	1,839,504	461,303	--
Percent change versus prior year	+299%	NA	--
Lifting costs per Mcf (1)	$0.63	$0.54	$--
Percent change versus prior year	+17%	NA	--

_______________

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

With the anticipated decline in production discussed earlier at our Wilga well, we expect gas revenues in 2008 to be lower than those for 2007, but still above those of 2006 and earlier. However, we expect to bring our Roszkow well, and possibly other Polish wells, into production in 2009 and later. These wells are expected to have a substantial positive impact on future production and revenues.

Oil Revenues. Oil revenues were $5.8 million, $4.7 million, and $3.8 million for the years ended December 31, 2007, 2006, and 2005, respectively. Included in 2007 and 2006 revenues were approximately $1.5 million and $483,000, respectively, related to the sale of LCO in Poland at our Wilga well. With the anticipated decline in production discussed earlier at our Wilga well, we expect LCO revenues in 2008 to be significantly reduced. All other oil revenues during the three years were derived from our producing properties in the United States. During these three years, oil revenues fluctuated primarily due to volatile oil prices and changing production rates that are a function of normal production declines. U.S. oil revenues in 2007 increased from 2006 levels by approximately $398,000 due to higher oil prices, offset by approximately $322,000 related to production declines. Oil revenues in 2006 increased from 2005 levels by approximately $607,000 due to higher oil prices, offset by approximately $151,000 related to production declines.

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, 2007, 2006, and 2005, is set forth in the following table:

	For the year ended December 31,
	2007	2006	2005
Revenues	$5,804,000	$4,744,000	$3,805,000
Percent change versus prior year	+22%	+25%	+23%
Average price (per Bbl )	$60.86	$56.13	$48.45
Percent change versus prior year	+8%	+16%	+33%
Production volumes (Bbl)	95,242	84,520	78,534
Percent change versus prior year	+13%	+78%	-7%
Lifting costs per Bbl (1)	$27.04	$25.23	$26.79
Percent change versus prior year	+7%	-6%	+42%

_______________

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

Depending largely upon future oil prices, we expect that 2008 and future oil revenues will be fairly stable compared to the future changes expected for gas revenues. We do not expect major oil production changes similar to those for future gas production.

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Lease Operating Costs. Lease operating costs were $3.5 million in 2007, $2.6 million in 2006, and $2.5 million in 2005. The higher costs in 2007 are reflective of a full year’s production in Poland. Poland operating costs rose from $289,000 in 2006 to $1.1 million in 2007. Operating costs rose slightly from 2005 to 2006 as we commenced gas and LCO production at our Wilga well in Poland. Lease operating costs at our Kleka and Zaniemysl wells were not significant in 2006. We also recompleted nine producing wells in Montana during 2006.

Exploration Costs. Our exploration efforts are focused in Poland, and the expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes. Exploration costs were $10.6 million, $5.6 million, and $8.4 million for the years ended December 31, 2007, 2006, and 2005, respectively.

Geological and geophysical costs, or G&G costs, were $10.6 million, $4.2 million, and $3.3 million for the years ended December 31, 2007, 2006, and 2005, respectively. During all three years, most of our G&G costs were spent on acquiring, processing, and interpreting new seismic data on the Fences I and II areas, including our new 3-D seismic survey in the Sroda area which began shooting in late 2006, and on which we spent a total of $6.7 million in 2007.

Exploratory dry-hole costs were $0, $1.6 million, and $5.1 million for the years ended December 31, 2007, 2006, and 2005, respectively. During 2007, both of the wells we drilled in Poland were determined to be commercial, and were completed for future production. Our 2006 exploration costs included approximately $800,000 associated with the Drozdowice-1 well in our Fences III prospect in Poland, along with additional amounts for two dry holes in Montana and Nevada. During 2005, we plugged and abandoned two wells in Poland, the Sroda-5 and Lugi 1 wells, for a total cost of approximately $4.6 million. In addition, we plugged and abandoned four exploratory wells in Nevada for a total cost of approximately $713,000.

Since different types of future exploration costs may either be capitalized and depleted, or written off altogether, depending upon future exploration results, it is not possible to provide especially meaningful forward-looking thoughts on these expenses. However, the 2008 capital budget is substantially above that of 2007, which would indicate exploration costs might well be higher in the future.

Impairment Costs. Impairments of oil and gas properties were $2.3 million, $3.6 million, and $0 for the years ended December 31, 2007, 2006, and 2005, respectively. As discussed previously, during 2007 we impaired $2.3 million related to our Wilga well, and in 2006 we impaired the entire amount of capitalized costs associated with our Rusocin-1 well. There were no similar impairments during 2005.

DD&A Expense - Producing Operations. DD&A expense for producing properties was $1.7 million, $957,000, and $511,000 for the years ended December 31, 2007, 2006, and 2005, respectively. The 78% increase from 2006 to 2007 was a reflection of a full-year’s worth of production in Poland, discussed earlier. DD&A expense in Poland was $935,000 in 2007. The increase from 2005 to 2006 was due primarily to the commencement of production at our properties in Poland, which accounted for $304,000 of the $446,000 increase. The remaining increase is due to capital cost additions in 2006 at our Montana producing properties.

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 $3.1 million, $1.7 million, and $2.1 million for the years ended December 31, 2007, 2006, and 2005, respectively. Activity in the contract drilling industry where we operate increased significantly during 2005, slowed somewhat in 2006, and increased again in 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.

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Oilfield Services Costs. Oilfield services costs were $2.0 million, $1.2 million, and $1.7 million for the years ended December 31, 2007, 2006, and 2005, respectively, or 65%, 73%, and 79% of oilfield servicing revenues, respectively. In general, oilfield servicing costs are directly associated with oilfield services revenues. As such, oilfield services costs will continue to fluctuate period to period based on the number of wells drilled, revenues generated, weather, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.

DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $267,000, $155,000, and $243,000 for the years ended December 31, 2007, 2006, and 2005, respectively. We spent $911,000, $295,000, and $264,000 on upgrading our oilfield servicing equipment during 2007, 2006, and 2005 respectively.

Nonsegmented Items

G&A Costs - Corporate. G&A costs were $6.9 million, $5.6 million, and $6.6 million for the years ended December 31, 2007, 2006, and 2005, respectively. Higher employee compensation costs in 2007, associated in part with an expansion of our Poland operations office, coupled with higher legal, insurance, and software maintenance costs, resulted in an increase in 2007 G&A of $1.3 million. During 2006, we significantly reduced from 2005 levels legal and consulting fees, reducing our G&A by approximately $612,000. Decreases in other G&A areas were offset to some extent by higher employee costs, as we increased headcount in our Poland office. During 2005, we opened a new office in Warsaw, Poland, hiring five experienced individuals to assist in our expanding exploration and production efforts.

Stock Compensation (G&A). Stock compensation expense recorded in 2005 represents the amortization of stock and options issued to consultants prior to the adoption of SFAS No. 123R.

Amortization of Deferred Compensation (G&A). As discussed above, we adopted the provisions of SFAS No. 123R on January 1, 2006, using the modified prospective method. Under this method, prior periods are not revised for comparative purposes. Stock-based awards that were granted prior to the effective date continue to be accounted for in accordance with SFAS No. 123, except that stock option expense for unvested options must be recognized in the consolidated statement of operations. Stock compensation expense recorded for 2007 represents $1.8 million of amortization related to restricted stock granted in 2007, 2006, and 2005 and $842,000 of amortization of unvested stock options granted prior to 2005, using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123. Stock compensation expense recorded for 2006 represents $1.1 million of amortization related to restricted stock granted in 2006 and 2005 and $1.7 million of amortization of unvested stock options granted prior to 2005, using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123.

Interest and Other Income (Expense) - Corporate. Interest and other income (expense) was $433,000, $795,000, and $780,000 for the years ended December 31, 2007, 2006, and 2005, respectively. During 2007, we began to amortize the fees incurred in securing our Senior Credit Facility to interest expense as well as the semi-annual commitment fees for the facility, totaling $386,000 in interest-related charges. These charges offset interest income of $818,000, an increase over 2006 levels due to higher cash balances available for investment. The increase in interest income for 2005 to 2006 was also due to higher cash balances generally available for investment over the prior year, coupled with rising interest rates.

Income Taxes. We incurred net losses of $11.7 million, $13.8 million, and $11.4 million for the years ended December 31, 2007, 2006, and 2005, respectively. SFAS No. 109, “Accounting for Income Taxes,” requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our consolidated statement of operations for these years.

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Liquidity and Capital Resources

To date, we have financed our operations principally through the sale of equity securities, issuance of debt securities, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. We believe our cash resources and marketable securities at December 31, 2007, together with anticipated revenues in 2008 and availability under our $25 million Senior Facility Agreement, are sufficient to cover our planned exploration program and ongoing operations in the United States and Poland for the next 12 months.

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

Working Capital (current assets less current liabilities). Our working capital was $15.3 million as of December 31, 2007, an increase of $3.4 million from December 31, 2006. The increase is due primarily to the proceeds of an equity financing during 2007, offset by costs associated with our drilling and seismic activities during 2007. The exercise of warrants in early 2008 as discussed above has further improved working capital.

Operating Activities. We used net cash of $1.6 million, $5.3 million, and $10.1 million in our operating activities during 2007, 2006, and 2005, respectively, primarily as a result of the net losses, excluding noncash charges, incurred in those years. Revenues from oil and gas sales in Poland, which commenced in late 2006, helped us reduce the amount of cash used in operations in both 2006 and 2007. Our current assets at year-end included approximately $1.9 million in accrued oil and gas sales from both the United States and Poland, and $446,000 in refundable Input VAT that we expect to receive during the first six months of 2008. Our current liabilities at year-end included approximately $376,000 in costs related to our exploration activities in Poland that were paid in early 2008.

Investing Activities. We used net cash in investing activities of $13.1 million in 2007 and received net cash from investing activities of $8.1 million and $4.7 million in 2006 and 2005, respectively. In 2007 we received $4.9 million from the maturities of marketable securities. We invested $9.6 million in marketable securities. We spent $7.5 million for 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.

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

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

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Financing Activities. We received net cash from financing activities of $14.4 million in 2007, used net cash in financing activities of $578,000 in 2006, and received net cash of $4.1 million from our financing activities during 2005. During 2007, we sold 1.5 million shares of stock in a registered direct offering, resulting in net proceeds to us of $12.4 million. In addition, 672,165 options and warrants were exercised during the year, resulting in proceeds to us of an additional $1.9 million. All the cash used in financing activities in 2006 was used to pay the loan origination fees and associated legal costs related to our $25 million Senior Credit Facility. All of the proceeds in 2005 were from the exercise of stock options and warrants. In 2004 we received a total of $20.7 million in net proceeds from the sale of securities. In addition, the exercise of warrants and options provided additional proceeds of $13.1 million.

Contractual Obligations and Contingent Liabilities and Commitments

We had no significant contractual obligations or commitments as of December 31, 2007. We are subject to certain work commitments with respect to our exploration concessions that must be satisfied in order to maintain our interest in those concessions. These work commitments are, however, optional on our part.

Our oil and gas drilling and production operations are subject to hazards incidental to the industry that can cause severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations, personal injury, and loss of life. To lessen the effects of these hazards, we maintain insurance of various types to cover our United States and Poland operations and also rely on the insurance or financial capabilities of our exploration partners in Poland. These measures do not cover risks related to violations of environmental laws or all other risks involved in oil and gas exploration, drilling, and production. We would be adversely affected by a significant adverse event that is not fully covered by insurance or by our inability to maintain adequate insurance in the future at rates we consider reasonable.

New Accounting Pronouncements

Effective January 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation Number 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. The adoption of this pronouncement did not have any effect on our financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial assets and liabilities for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157.” FSP 157-2 delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities that are not re-measured at fair value on a recurring basis until fiscal years beginning after November 15, 2008. Any amounts recognized upon adoption of this rule as a cumulative effect adjustment will be recorded to the opening balance of retained earnings in the year of adoption. We have evaluated SFAS No. 157 and have determined that it will not have a material impact on our consolidated financial statements.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (“SFAS No. 159”), which permits an entity to choose to measure eligible items at fair value at specified election dates. An entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective for fiscal years that begin after November 15, 2007. We have evaluated SFAS No. 159 and have determined that it will not have a material impact on our consolidated financial statements and we have not early adopted.

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

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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

Engineering estimates of our oil and gas reserves are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. There are authoritative guidelines regarding the engineering criteria that have to be met before estimated oil and gas reserves can be designated as “proved.” Proved reserve estimates are updated at least annually and take into account recent production and technical information about each field. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. This change is considered a change in estimate for accounting purposes and is reflected on a prospective basis in related depreciation, depletion and amortization (“DD&A”) rates.

Despite the inherent imprecision in these engineering estimates, these estimates are used in determining DD&A expense and impairment expense and in disclosing the supplemental standardized measure of discounted future net cash flows relating to proved oil and gas properties. DD&A rates are determined based on estimated proved reserve quantities (the denominator) and capitalized costs of producing properties (the numerator). Producing properties’ capitalized costs are amortized based on the units of oil or gas produced. Therefore, assuming all other variables are held constant, an increase in estimated proved reserves decreases our DD&A expense. Also, estimated reserves are used to calculate future cash flows from our oil and gas operations, which serve as an indicator of fair value in determining whether a property is impaired or not. The larger the estimated reserves, the less likely the property is impaired.

Stock-based Compensation

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

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

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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.

Our gas in Poland is sold to POGC or its subsidiaries under contracts that extend for the life of each field. Prices are determined contractually and, in the case of our Wilga and Zaniemysl wells, are tied to published tariffs. Gas sold at Kleka is sold at a fixed price without regard to any published tariff or index. The currently limited volumes and sources of our gas production mean we cannot assure uninterruptible production or production in amounts that would be meaningful to industrial users, which may depress the price we may be able to obtain by limiting our market for potential customers. POGC is the primary purchaser of domestic gas in Poland. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in a more competitive setting and may be lower than prevailing western European prices, at least until a fully competitive market develops in Poland.

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

Foreign Currency Risk

We have entered into various agreements in Poland denominated in the Polish zloty. The Polish zloty is subject to exchange rate fluctuations that are beyond our control. We do not currently engage in hedging transactions to protect ourselves against foreign currency risks, nor do we intend to do so in the immediate future; our policy is to use zloty-based revenues generated in Poland to pay for all zloty-based invoices, supplemented as needed by transferring U.S. dollars to Poland to cover invoices that exceed the generated revenues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

During the year ended December 31, 2007, we have not disagreed with our independent registered public accounting firm on any items of accounting treatment or financial disclosure.

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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, 2007, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2007, 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 2008 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.

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ITEM 11. EXECUTIVE COMPENSATION

The information from the definitive proxy statement for the 2008 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 2008 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 2008 annual meeting of stockholders under the captions “Certain Relationships and Related Transactions” and “Director Independence” is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information from the definitive proxy statement for the 2008 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS AND 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, 2007 and 2006	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005	F-6
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2007, 2006 and 2005	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	F-8
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2007, 2006 and 2005	F-9
Notes to the Consolidated Financial Statements	F-10

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

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

Exhibit Number*	Title of Document	Location
Item 3	Articles of Incorporation and Bylaws
3.01	Restated and Amended Articles of Incorporation	Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended September 30, 2000, filed November 7, 2000.
3.02	Bylaws, as amended January 2, 2008	This filing.
3.03	Articles of Amendment to the Restated Articles of Incorporation of FX Energy, Inc.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2005, filed March 14, 2006.
3.04	Amendment to Articles of Incorporation Revising and Restating Designation of Rights, Privileges, and Preferences of Series A Preferred Stock	Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.

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Item 4	Instruments Defining the Rights of Security Holders
4.01	Specimen Stock Certificate	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
4.04	Rights Agreement dated as of April 4, 2007, between FX Energy, Inc. and Fidelity Transfer Corp.	Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.
Item 10	Material Contracts
10.26	Frontier Oil Exploration Company 1995 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.27	FX Energy, Inc. 1996 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.28	FX Energy, Inc. 1997 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.29	FX Energy, Inc. 1998 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.52	Form of Indemnification Agreement between FX Energy, Inc. and certain directors, with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.53	Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to Fences I project area	Incorporated by reference from the current report on Form 8-K filed May 2, 2000.
10.59	Sales / Purchase Agreement Special Provisions between Plains Marketing Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.60	Form of Non-Qualified Stock Option awarded August 14, 2002, with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.62	Agreement Regarding Cooperation within the Poznan Area (Fences II) entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.

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10.63	Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.64	Farmout Agreement Entered into by and between FX Energy Poland Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. Covering the “Fences Area” in the Foresudetic Monocline made as of January 9, 2003	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.67	FX Energy, Inc. 1999 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.68	FX Energy, Inc. 2000 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.69	FX Energy, Inc. 2001 Stock Option and Award Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.70	FX Energy, Inc. 2003 Long-Term Incentive Plan	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.74	Greater Zaniemysl Area Agreement made as of March 12, 2004, among FX Energy Poland Sp. z o.o. and CalEnergy Resources Poland Sp. z o.o.	Incorporated by reference from the quarterly report on Form 10-Q for the period ended March 31, 2004, filed May 11, 2004.
10.75	Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.76	Supplemental Indemnification Agreement between FX Energy, Inc. and Dennis B. Goldstein**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2004, filed March 15, 2005.
10.77	Description of compensation arrangement with executive officers and directors**	This filing.
10.78	Form of Employment Agreement with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.

44

10.79	Change in Control Compensation Agreement with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.81	FX Energy, Inc. 2004 Long-Term Incentive Plan**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2004, filed March 15, 2005.
10.82	Letter of Engagement, H. Allen Turner, dated February 14, 2007	Incorporated by reference from the current report on Form 8-K filed February 20, 2007.
10.83	US$25,000,000 Senior Facility Agreement among FX Poland Sp. z o.o., FX Energy, Inc., FX Energy Netherlands Partnership CV., FX Energy Netherlands BV., and The Royal Bank of Scotland PLC, dated November 17, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.84	Common Stock Purchase Warrant dated November 17, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.85	Agreement for Pledges over Shares in FX Energy Poland Sp. z o.o., dated December 18, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.86	Subordination Deed dated December 21, 2006	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.87	Restated FX Energy, Inc. 401(k) Stock Bonus Plan dated January 25, 2007**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.88	Agreement for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Mazowiecka 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.
Item 21	Subsidiaries of the Registrant
21.01	Schedule of Subsidiaries	This filing.

45

Item 23	Consents of Experts and Counsel
23.01	Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm	This filing.
23.02	Consent of Larry D. Krause, Petroleum Engineer	This filing.
23.03	Consent of RPS Energy, Petroleum Engineers	This filing.
Item 31	Rule 13a-14(a)/15d-14(a) Certifications
31.01	Certification of Chief Executive Officer Pursuant to Rule 13a-14	This filing.
31.02	Certification of Chief Financial Officer Pursuant to Rule 13a-14	This filing.
Item 32	Section 1350 Certifications
32.01	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	This filing.
32.02	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	This filing.

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

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

46

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 7, 2008 By: /s/ David N. Pierce

David N. Pierce

President and Chief Executive Officer

Dated: March 7, 2008 By: /s/ Clay Newton

Clay Newton

Principal Financial Officer

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

	/s/ Thomas B. Lovejoy
Dated: March 7, 2008	Thomas B. Lovejoy, Director
	/s/ David N. Pierce
Dated: March 7, 2008	David N. Pierce, Director
	/s/ Dennis B. Goldstein
Dated: March 7, 2008	Dennis B. Goldstein, Director
	/s/ David L. Worrell
Dated: March 7, 2008	David L. Worrell, Director
	/s/ Arnold S. Grundvig, Jr.
Dated: March 7, 2008	Arnold S. Grundvig, Jr., Director
	/s/ Jerzy B. Maciolek
Dated: March 7, 2008	Jerzy B. Maciolek, Director
	/s/ Richard Hardman
Dated: March 7, 2008	Richard Hardman, Director
	/s/ H. Allen Turner
Dated: March 7, 2008	H. Allen Turner, Director

47

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 2007 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, 2007, 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, 2007, 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2007in 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, 2007, 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.

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

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 7, 2008

F-3

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

As of December 31, 2007 and 2006

(in thousands)

	2007		2006
ASSETS
Current assets:
Cash and cash equivalents	$	4,262	$	4,644
Marketable securities, available for sale		15,202		10,462
Receivables:
Accrued oil and gas sales		1,906		1,615
Joint interest and other receivables		805		249
Input VAT receivable		446		710
Inventory		178		206
Other current assets		365		322
Total current assets		23,164		18,208
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		23,491		19,293
Unproved		2,001		2,912
Other property and equipment		5,590		4,624
Gross property and equipment		31,082		26,829
Less accumulated depreciation, depletion and amortization		(9,197)		(7,134)
Net property and equipment		21,885		19,695
Other assets:
Certificates of deposit		406		382
Loan fees		914		882
Total other assets		1,320		1,264
Total assets	$	46,369	$	39,167

-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, 2007 and 2006

(in thousands, except share data)

-Continued-

	2007		2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	4,432	$	5,234
Accrued liabilities		3,358		1,007
Total current liabilities		7,790		6,241
Asset retirement obligation		1,037		961
Total liabilities		8,827		7,202
Commitments and Contingencies (Note 6)
Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of December 31, 2007 and 2006; no shares outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized as of December 31, 2007 and 2006; 38,196,357 and 35,560,744 shares issued and outstanding as of December 31, 2007 and 2006, respectively		38		36
Additional paid in capital		142,901		125,706
Accumulated other comprehensive loss		(1)		(72)
Accumulated deficit		(105,396)		(93,705)
Total stockholders’ equity		37,542		31,965
Total liabilities and stockholders’ equity	$	46,369	$	39,167

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, 2007, 2006 and 2005

(in thousands, except per share amounts)

	2007		2006		2005
Revenues:
Oil and gas sales	$	14,903	$	6,533	$	3,805
Oilfield services		3,093		1,696		2,132
Total revenues		17,996		8,229		5,937
Operating costs and expenses:
Lease operating expenses		3,538		2,647		2,462
Exploration costs		10,624		5,608		8,369
Recovery of previously expensed Input VAT		--		--		(2,121)
Impairment of oil and gas properties		2,299		3,583		--
Oilfield services costs		1,998		1,245		1,689
Depreciation, depletion and amortization (DD&A)		2,064		1,290		903
Accretion expense		78		53		45
Stock compensation (G&A)		--		--		76
Amortization of deferred compensation (G&A)		2,604		2,759		125
General and administrative costs (G&A)		6,915		5,606		6,592
Total operating costs and expenses		30,120		22,791		18,140
Operating loss		(12,124)		(14,562)		(12,203)
Other income:
Interest and other income		433		795		780
Total other income		433		795		780
Net loss	$	(11,691)	$	(13,767)	$	(11,423)
Basic and diluted net loss per common share	$	(0.32)	$	(0.39)	$	(0.33)
Basic and diluted weighted average number of shares outstanding		36,694		35,163		34,733

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, 2007, 2006 and 2005

(in thousands)

		2007		2006	2005
Net loss	$	(11,691)	$	(13,767)	$	(11,423)
Other comprehensive income (loss)
Increase (decrease) in market value of available for sale marketable securities		71		(14)		281
Comprehensive loss	$	(11,620)	$	(13,781)	$	(11,142)

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, 2007, 2006 and 2005

(in thousands)

		2007		2006		2005
Cash flows from operating activities:
Net loss	$	(11,691)	$	(13,767)	$	(11,423)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		2,064		1,290		903
Impairment of oil and gas properties		2,299		3,583		--
Property abandonment		--		--		242
Accretion expense		78		53		45
(Gain) loss on property dispositions		--		--		(18)
Stock compensation (G&A)		--		--		76
Amortization of deferred compensation (G&A)		2,604		2,759		125
Common stock issued for services (G&A)		242		517		610
Increase (decrease) from changes in working capital items:
Receivables		(583)		1,451		(2,438)
Inventory		28		(110)		(4)
Other current assets		(43)		(52)		(46)
Other assets		(56)		(25)		3
Accounts payable and accrued liabilities		3,479		(995)		1,848
Asset retirement obligation		(2)		(7)		(28)
Net cash used in operating activities		(1,581)		(5,303)		(10,105)
Cash flows from investing activities:
Additions to oil and gas properties		(7,517)		(7,521)		(2,989)
Additions to other property and equipment		(966)		(362)		(422)
Recovery of previously capitalized VAT		--		--		1,921
Additions to marketable securities		(9,610)		(782)		(627)
Proceeds from maturities of marketable securities		4,941		16,800		6,750
Proceeds from sale of assets		--		--		23
Net cash provided by (used in) investing activities		(13,152)		8,135		4,656
Cash flows from financing activities:
Payment of loan fees		--		(578)		--
Proceeds from issuance of common stock , net of offering costs		12,436		--		--
Proceeds from exercise of stock options and warrants		1,915		--		4,055
Net cash provided by (used in) financing activities		14,351		(578)		4,055
Net increase (decrease) in cash		(382)		2,254		(1,394)
Cash and cash equivalents at beginning of year		4,644		2,390		3,784
Cash and cash equivalents at end of year	$	4,262	$	4,644	$	2,390

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, 2007, 2006 and 2005

(in thousands)

		Common Stock								Accumulated
				Par Value				Additional		Other				Total
	Preferred	Shares		$0.001 Per		Deferred		Paid in		Comprehensive		Accumulated		Stockholders’
	Stock	Issued		Share		Compensation		Capital		Income (Loss)		Deficit		Equity (Deficit)
Balance as of December 31, 2004	--	34,398	$	34	$	--	$	117,376	$	(339)	$	(68,515)	$	48,556
Common stock issued for services and other	--	58		--		--		610		--		--		610
Exercise of stock options	--	593		1		--		3,874		--		--		3,875
Stock compensation	--	--		--		--		76		--		--		76
Deferred compensation	--	--		--		(3,100)		3,100		--		--		--
Amortization of deferred compensation	--	--		--		125		--		--		--		125
Exercise of warrants	--	48		--		--		180		--		--		180
Other comprehensive income	--	--		--		--		--		281		--		281
Net loss for year	--	--		--		--		--		--		(11,423)		(11,423)
Balance as of December 31, 2005	--	35,097	$	35	$	(2,975)	$	125,216	$	(58)	$	(79,938)	$	42,280
Common stock issued for services and other	--	464		1		--		706		--		--		707
Elimination of deferred compensation upon adoption of SFAS No. 123R	--	--		--		2,975		(2,975)		--		--		--
Amortization of deferred compensation	--	--		--		--		2,759		--		--		2,759
Other comprehensive loss	--	--		--		--		--		(14)		--		(14)
Net loss for year	--	--		--		--		--		--		(13,767)		(13,767)
Balance as of December 31, 2006	--	35,561	$	36	$	--	$	125,706	$	(72)	$	(93,705)	$	31,965
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
Amortization of deferred compensation	--	--		--		--		2,604		--		--		2,604
Other comprehensive income	--	--		--		--		--		71		--		71
Net loss for year	--	--		--		--		--		--		(11,691)		(11,691)
Balance as of December 31, 2007	--	38,196	$	38	$	--	$	142,901	$	(1)	$	(105,396)	$	37,542

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

F-9

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 1: Summary of Significant Accounting Policies

Organization

FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively referred to hereinafter as the “Company”), is an independent energy company with activities concentrated within the upstream oil and gas industry. In Poland, the Company has projects involving the exploration and exploitation of oil and gas prospects in partnership with the Polish Oil and Gas Company (“POGC”), other industry partners and for its own account. In the United States, the Company explores for and produces oil from fields in Montana and Nevada and has an oilfield services company in northern Montana that performs contract drilling and well servicing operations.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and the Company’s undivided interests in Poland. All significant inter-company accounts and transactions have been eliminated in consolidation. At December 31, 2007, the Company owned 100% of the voting common stock or other equity securities of its subsidiaries.

Cash and Cash Equivalents

The Company considers all highly-liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Concentration of Credit Risk

Excluding the receivable for Input VAT, which is due from the State Treasury Office of Poland, the majority of the Company’s receivables are within the oil and gas industry, primarily from the purchasers of its oil and gas, fees generated from oilfield services and its industry partners. Substantially all of the Company’s domestic receivables are with Cenex, a regional refiner and marketer, and substantially all of the Company’s Polish receivables are with the Polish Oil and Gas Company or one of its affiliates. The receivables are not collateralized. To date, the Company has experienced minimal bad debts, and has no allowance for doubtful accounts at December 31, 2007 and 2006. The majority of the Company’s cash and cash equivalents are held by four financial institutions in Utah, Montana, New York and Poland. The Company’s marketable securities are held by two financial institutions in Utah and New York.

Inventory

Inventory consists primarily of tubular goods and production related equipment and is valued at the lower of average cost or market.

F-10

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether an individual well has found proved reserves. If it is determined that an exploratory well has not found proved reserves, or if the determination that proved reserves have been found cannot be made within one year, or if the Company is not making sufficient progress assessing the reserves and the economic and operating viability of the project, the costs of the well are expensed. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are not considered to be realizable. Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is provided on a field-by-field basis using the units-of-production method. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net revenues determined on a field-by-field basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value determined on a property-by-property basis. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as a recovery of costs and any resulting gain or loss is recorded as other income.

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 suggests that the well may experience a decline in oil and gas production over the course of the next 12-18 months as a result. As a consequence of the water encroachment, the proved reserves at Wilga have been reduced. According to the provision of Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”), Accounting for the Impairment and Disposal of Long-Lived Assets, the Company recorded an impairment of capitalized costs in the amount of $2,299,534 in 2007. The impairment amount was calculated by reducing the net capitalized costs of the well to its fair value at year-end. The fair value of the well was equal to its remaining estimated  discounted future net cash flows.

The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves, during 2007, 2006 and 2005.

	December 31,
	2007		2006		2005
				(In thousands)
Beginning balance at January 1	$	2,386	$	3,435	$	8,779
Additions to capitalized exploratory well costs pending the determination of proved reserves		669		2,386		313
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(2,386)		--		(5,559)
Capitalized exploratory well costs charged to expense		--		(3,435)		(98)
Ending balance at December 31	$	669	$	2,386	$	3,435

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

The 2005 balance included only the costs associated with the Rusocin well in Poland, which was under evaluation at year-end 2005.

F-11

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Other Property and Equipment

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

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

						Estimated
	December 31,					Useful Life
	2007		2006			(in years)
	(In thousands)
Other property and equipment:
Drilling rigs	$	4,180	$		3,317	6
Other vehicles		320			290	5
Building		108			108	40
Office equipment and furniture		982			909	3 to 6
Total cost		5,590		4,624
Accumulated depreciation		(4,250)		(3,863)
Net other property and equipment	$	1,340	$		761

Supplemental Disclosure of Cash Flow Information

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

			Year Ended December 31,
		2007			2006		2005
			(In thousands)
Noncash investing transactions:
Additions to properties included in current liabilities	$	428		$	2,359	$	798
Recovery of previously capitalized VAT included in Input VAT receivable		--			--		254

Supplemental disclosure of cash paid for interest and income taxes:

			Year Ended December 31,
		2007			2006		2005
			(In thousands)
Supplemental disclosure:
Cash paid during the year for interest	$	125		$	--	$	--
Cash paid during the year for income taxes		--			--		--

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

F-12

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Revenue Recognition

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

Investments

The cost and estimated market value of marketable securities at December 31, 2007, are as follows (in thousands):

				Gross		Estimated
				Unrealized		Market
		Cost		Losses		Value
Marketable securities	$	15,203	$	(1)	$	15,202

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

				Gross		Estimated
				Unrealized		Market
		Cost		Losses		Value
Marketable securities	$	10,534	$	(72)	$	10,462

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

Stock-Based Compensation

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

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

F-13

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

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

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

The fair value of each option granted to employees and consultants during 2005 was estimated on the date of grant using the Black-Scholes option pricing model. The following weighted-average assumptions were utilized for the Black-Scholes valuation: (1) expected volatility of 60% for 2005; (2) expected life of three years; (3) risk-free interest rates at the date of grant ranging from 2.21% to 4.39%; and, (4) dividend yield of zero for each year.

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.

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

F-14

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

New Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” ("SFAS No. 157") which defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial assets and liabilities for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157.” FSP 157-2 delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities that are not re-measured at fair value on a recurring basis until fiscal years beginning after November 15, 2008. Any amounts recognized upon adoption of this rule as a cumulative effect adjustment will be recorded to the opening balance of retained earnings in the year of adoption. The Company has evaluated SFAS No. 157 and has determined that it will not have a material impact on its Consolidated Financial Statements.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” ("SFAS No. 159") which permits an entity to choose to measure eligible items at fair value at specified election dates. An entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective for fiscal years that begin after November 15, 2007. The Company has evaluated SFAS No. 159 and has determined that it will not have a material impact on its Consolidated Financial Statements and the Company has not early adopted.

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

Foreign Operations

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

Use of Estimates

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

Net Loss per Share

Basic earnings per share are computed by dividing the net loss applicable to common shares by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing the net loss by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options, warrants, unvested restricted stock, and convertible preferred stock or debt.

F-15

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Outstanding options, warrants and unvested restricted stock as of December 31, 2007, 2006 and 2005, were as follows:

	Options, Warrants and Unvested Restricted Stock	Price Range
Balance sheet date:
December 31, 2007	6,320,602	$0.00 - $10.65
December 31, 2006	6,859,106	$0.00 - $10.65
December 31, 2005	6,997,656	$0.00 - $10.65

The Company had a net loss in 2007, 2006 and 2005. The above options, warrants and unvested restricted stock were not included in the computation of diluted earnings per share for the years presented because the effect would have been antidilutive.

Note 2: Asset Retirement Obligation

The Company accounts for future site restoration costs according to Statement No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). Under SFAS No. 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. The Company uses an expected cash flow approach to estimate its asset retirement obligations under SFAS No. 143. The Company recorded accretion expense of $78,087, $53,038 and $44,565 in 2007, 2006 and 2005, respectively. At December 31, 2007, 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, 2007 and 2006:

	December 31,
	2007		2006
	(In thousands)
Asset retirement obligations:
Beginning balance	$	961	$	431
Current year additions		--		484
Liabilities settled		(2)		(7)
Accretion expense		78		53
Ending balance	$	1,037	$	961

Note 3: Other Assets

As of December 31, 2007 and 2006, the Company had a replacement bond with a federal agency in the amount of $463,000, which was collateralized by certificates of deposit totaling $231,500. In addition, there are certificates of deposit totaling $175,000 covering performance bonds in other states.

F-16

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Note 4: Accrued Liabilities

The Company’s accrued liabilities as of December 31, 2007 and 2006, were comprised of the following:

	December 31,
	2007		2006
	(In thousands)
Accrued liabilities:
Credit facility commitment fees	$	78	$	--
Partner share of oil & gas revenue		1,737		439
Compensation-related costs		1,543		568
Total	$	3,358	$	1,007

Note 5: Notes Payable

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

Under the terms of the Facility, the current commitment is for approximately $18.6 million. The terms of the Facility call for interest payments only through the end of 2010. The principal amount of the Facility will begin to be reduced at that time, terminating at the end of 2012, unless the Company has been successful in adding additional properties and/or reserves to its borrowing base. Interest will be accrued at LIBOR plus an applicable margin, which is currently 1.25%.

In consideration for the Facility, the Company paid a 1% origination fee and issued warrants to purchase 110,000 shares of common stock, valid for 2 years at an exercise price of $6.00 per share. The Black-Scholes value of these warrants (approximately $305,000), along with the loan origination fee and associated legal fees, have been capitalized as deferred financing costs, and are being amortized over the 6 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.

Note 6: Commitments and Contingencies

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

F-17

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Note 7: Value Added Tax Refund

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

During 2004, Poland joined the European Union. This event caused changes to several tax laws, including the law that precluded the Company from obtaining refunds of Input VAT. In April 2005, the Company filed a refund application for approximately 13.7 million Polish zlotys, representing all Input VAT paid since the Company’s inception in Poland through March of 2005. The Polish taxing authorities refunded the entire amount, which was approximately $4.2 million at then-current exchange rates, in October 2005.

A portion of the past Input VAT was related to capital costs, with the remainder attributed to 2005 and prior years’ geological and geophysical costs, along with overhead and other expenses. Accordingly, for the $4.2 million refund received in 2005, the Company reduced its capital costs by approximately $1.9 million, 2005 expenses by $0.1 million, with the remaining $2.1 million related to prior years’ expenses shown as a Recovery of Previously Expensed Input VAT in the Consolidated Statements of Operations. In addition, the Company recorded an Input VAT receivable at December 31, 2005 of approximately $2.0 million, representing Input VAT paid since April 2005. This amount was collected in 2006. The Company expects to remain Input VAT neutral. The input VAT receivable at December 31, 2007 and December 31, 2006 was $445,974 and $709,858 respectively.

Note 8: Income Taxes

The Company recognized no income tax benefit from the losses generated during 2007, 2006 and 2005. The components of the net deferred tax asset as of December 31, 2007 and 2006 are as follows:

	December 31,
	2007		2006
	(In thousands)
Deferred tax liability:
Property and equipment basis differences	$	(2,388)	$	(3,637)
Deferred tax asset:
Net operating loss carryforwards:
United States		25,615		23,309
Poland		9,252		9,379
Oil and gas properties		2,713		1,855
Options issued for services		1,359		946
Asset retirement obligation		387		176
Valuation allowance		(36,938)		(32,028)
Total	$	--	$	--

F-18

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

The change in the valuation allowance during 2007, 2006 and 2005 is as follows:

		Year Ended December 31,
		2007		2006		2005
		(In thousands)
Valuation allowance:
Balance, beginning of year	$	(32,028)	$	(24,887)	$	(23,209)
Change in property and equipment basis differences		(1,249)		2,511		(93)
Increase due to net operating loss		(2,179)		(8,875)		(1,538)
Other		(1,482)		(777)		(47)
Total	$	(36,938)	$	(32,028)	$	(24,887)

SFAS No. 109, “Accounting for Income Taxes,” requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. The Company’s ability to realize the benefit of its deferred tax asset will depend on the generation of future taxable income through profitable operations and expansion of the Company’s oil and gas producing activities. The risks associated with that growth requirement are considerable, resulting in the Company’s conclusion that a full valuation allowance be provided at December 31, 2007 and 2006.

United States NOL

At December 31, 2007, the Company had net operating loss (“NOL”) carryforwards in the United States of approximately $68,671,000 available to offset future taxable income. The carryforwards begin to expire in 2008 and will fully expire in 2022. 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 $20,531,000 relating to tax deductions resulting from the exercise of stock options. The tax benefit from adjusting the valuation allowance related to this portion of the NOL carryforward will be credited to additional paid-in capital.

Polish NOL

As of December 31, 2007, the Company had NOL carryforwards in Poland totaling approximately $48,697,000. During 2006 the Company received a favorable ruling from the Polish tax authorities which allows for a ten year carryover of prior years’ NOLs. This ruling allowed for the reinstatement of approximately $24 million of NOLs which had previously expired under the normal carryover rules. The NOLs will begin to expire in 2008 and will fully expire in 2016. The ruling allows a ten year carryover period for losses incurred from 1997 to 2007. The normal carryforward period in Poland is five years. However, no more than 50% of the NOL carryforward for any given year may be applied against Polish income in succeeding years.

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

			Year Ended December 31,
		2007			2006		2005
			(In thousands)
Domestic	$	(6,078)		$	(6,764)	$	(5,199)
Foreign		(5,613)			(7,003)		(6,224)
Total	$	(11,691)		$	(13,767)	$	(11,423)

F-19

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Note 9: Stockholders’ Equity

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

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

Note 10: Stock Options, Warrants and Restricted Stock

Equity Compensation Plans

The Company’s equity compensation consists of annual stock option and award plans that are each subject to approval by the board of directors and are subsequently presented for approval by the stockholders at the Company’s annual meetings.

The following table summarizes information regarding the Company’s stock option and award plans as of December 31, 2007:

	Number of Shares Authorized Under Plan	Weighted Average Exercise Price of Outstanding Options	Number of Options Available for Future Issuance
Equity compensation plans approved by stockholders:
1995 Stock Option and Award Plan	500,000	$7.49	--
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	545
1999 Stock Option and Award Plan	500,000	2.78	--
2000 Stock Option and Award Plan	600,000	2.51	17
2001 Stock Option and Award Plan	600,000	3.22	999
2003 Long Term Incentive Plan	800,000	6.64	--
2004 Long Term Incentive Plan	1,000,000	7.79	314,525
Total	5,500,000	$5.19	316,086

The above table excludes 25,000 options that have been granted outside of stockholder approved option plans.

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

F-20

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

The following table summarizes option activity for 2007, 2006 and 2005:

	2007		2006		2005
	Number of Options	Weighted Average Exercise Price	Number of Options	Weighted Average Exercise Price	Number of Options	Weighted Average Exercise Price
Options outstanding:
Beginning of year	2,836,833	$5.08	3,193,333	$5.16	3,851,733	$5.47
Granted	--	.00	--	.00	35,000	9.89
Exercised	(466,726)	4.13	--	.00	(620,066)	6.95
Cancelled	(54,666)	8.42	--	5.82	(73,334)	8.27
Expired	--	--	(356,500)	--	--	--
End of year	2,315,441	$5.19	2,836,833	$5.08	3,193,333	$5.16
Exercisable at year-end	2,303,776	$5.16	2,497,177	$4.61	2,270,685	$4.33

The weighted average fair value per share of options granted during 2005 was $9.72.

In 2007, the Company recognized $842,273 in expense related to unvested stock options granted prior to the adoption of FAS 123R. Total unamortized expense at December 31, 2007 related to unvested options was $15,508.

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

In December of 2006, the Company issued 318,400 shares of restricted stock resulting in deferred compensation of $2,053,680 which will be amortized ratably over the three year vesting period. Expense recognized for these shares during 2007 and 2006 totaled $684,557 and $18,756 respectively.

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

The following table summarizes information about stock options outstanding as of December 31, 2007:

	Outstanding			Exercisable
Exercise Price Range	Number of Options Outstanding	Weighted Average Remaining Contractual Life (in years)	Weighted Average Exercise Price	Number of Options Exercisable	Weighted Average Exercise Price
$2.40 - $2.40	435,000	1.62	2.40	435,000	2.40
$2.44 - $3.20	386,000	1.11	2.54	386,000	2.54
$3.98 - $3.98	587,109	2.82	3.98	587,109	3.98
$6.06 - $6.06	4,167	3.07	6.06	4,167	6.06
$8.37 - $8.37	843,165	3.67	8.37	843,165	8.37
$9.00 - $10.65	60,000	3.86	9.52	48,335	9.43
Total	2,315,441	2.64	$5.19	2,303,776	$5.16

The aggregate intrinsic value of outstanding stock options at December 31, 2007 was $3,632,921. The aggregate intrinsic value of unvested restricted stock at December 31, 2007 was $3,861,196. The aggregate intrinsic value represents the total pretax intrinsic value, based on the Company’s stock price of $5.68 as of December 31, 2007, which would have been received by the restricted stock award and stock option holders had all in-the-money restricted stock awards and options been exercised as of that date.

F-21

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Warrants

The following table summarizes warrant activity during 2007, 2006 and 2005:

	2007			2006		2005
		Number of Shares	Price Range	Number of Shares	Price Range	Number of Shares	Price Range
Warrants outstanding and exercisable:
Beginning of year		3,615,373	$3.60--$6.00	3,505,373	$3.60--$3.75	3,553,373	$3.60--$3.75
Issued		--	--	110,000	$6.00	--	--
Exercised		(290,000)	$3.60	--	--	(48,000)	$3.75
End of year		3,325,373	$3.60--$6.00	3,615,373	$3.60--$6.00	3,505,373	$3.60--$3.75

Restricted Stock

The following table summarizes restricted stock activity during 2007, 2006 and 2005:

	2007	2006	2005
	Number of Shares	Number of Shares	Number of Shares
Unvested restricted stock outstanding:
Beginning of year	516,900	298,950	--
Issued	370,925	318,400	298,950
Forfeited	(4,020)	(1,200)	--
Vested	(204,017)	(99,250)	--
End of year	679,788	516,900	298,950

Note 11: Quarterly Financial Data (Unaudited)

Summary quarterly information for 2007 and 2006 is as follows:

		Quarter Ended
		December 31		September 30		June 30		March 31
		(In thousands, except per share amounts)
2007:
Revenues	$	4,064	$	5,243	$	4,511	$	4,178
Net operating loss		(6,728)		(53)		(2,711)		(2,632)
Net income (loss)		(6,550)		166		(2,682)		(2,625)
Basic and diluted net loss per common share	$	(0.17)	$	(0.00)	$	(0.08)	$	(0.07)
2006:
Revenues	$	3,165	$	1,842	$	2,137	$	1,085
Net operating loss		(6,037)		(1,919)		(2,227)		(4,379)
Net loss		(5,795)		(1,728)		(2,054)		(4,190)
Basic and diluted net loss per common share	$	(0.16)	$	(0.05)	$	(0.06)	$	(0.12)

The net operating loss for the fourth quarter of 2007 includes $2.3 million of impairment loss associated with the Wilga well in Poland. The net operating loss for the fourth quarter of 2006 includes $3.4 million of impairment loss associated with the Rusocin well in Poland.

F-22

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Note 12: Business Segments

The Company operates within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. The Company’s revenues associated with its E&P activities are comprised of oil sales from its producing properties in the United States and oil and gas sales from its producing properties in Poland. Over 90% of the Company’s oil sales in the United States were to Cenex during 2007, 2006 and 2005. During 2007 and 2006 all sales of oil and gas in Poland were made to POGC or its affiliated companies. There were no oil and gas sales in Poland during 2005 and 2004. The Company believes the purchasers of its oil production in the United States could be replaced, if necessary, without a loss in revenue. Gas sales in Poland are sold pursuant to long term sales contracts which obligate the buyer to purchase all gas produced. Individual oil sales are negotiated with POGC affiliated entities and are not subject to sales contracts.

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

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

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

F-23

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

Information on the Company’s operations by business segment for 2007, 2006 and 2005 is summarized as follows:

	2007
						Oilfield Services	Total (In thousands)
	Exploration & Production
	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

	2006
						Oilfield Services	Total (In thousands)
	Exploration & Production
	U.S.		Poland
Operations summary:
Revenues	$	4,260	$	2,273	$	1,696	$	8,229
Lease operating expense		(2,358)		(289)		--		(2,647)
Oilfield services costs		--		--		(1,245)		(1,245)
Exploration expense		(739)		(4,869)		--		(5,608)
Impairment expense		--		(3,583)		--		(3,583)
Accretion expense		(46)		(7)		--		(53)
DD&A expense		(654)		(304)		(155)		(1,113)
Operating income (loss)	$	463	$	(6,779)	$	296	$	(6,020)
Identifiable net property and equipment:
Unproved properties	$	--	$	2,912	$	--	$	2,912
Proved properties		3,124		12,898		--		16,022
Equipment and other		--		22		534		556
Total	$	3,124	$	15,832	$	534	$	19,490
Net Capital Expenditures:
Property and equipment	$	613	$	9,008	$	295	$	9,916
Total	$	613	$	9,008	$	295	$	9,916

F-24

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

- Continued -

		2005
						Oilfield Services		Total (In thousands)
		Exploration & Production
		U.S.		Poland
Operations summary:
Revenues	$		3,805	$	--	$	2,132	$	5,937
Lease operating expense			(2,462)		--		--		(2,462)
Oilfield services costs			--		--		(1,689)		(1,689)
Exploration expense			(486)		(5,762)		--		(6,248)
Accretion expense			(45)		--		--		(45)
DD&A expense			(511)		--		(243)		(754)
Operating income (loss)	$		301	$	(5,762)	$	200	$	(5,261)
Identifiable net property and equipment:
Unproved properties	$		143	$	161	$	--	$	304
Proved properties			3,139		10,465		--		13,604
Equipment and other			--		24		372		396
Total	$		3,282	$	10,650	$	372	$	14,304
Net Capital Expenditures:
Property and equipment	$		505	$	3,783	$	264	$	4,552
Total	$		505	$	3,783	$	264	$	4,552

A reconciliation of the segment information to the consolidated totals for 2007, 2006 and 2005 follows:

	2007		2006		2005
	(In thousands)
Revenues:
Reportable segments	$	17,996	$	8,229	$	5,937
Non-reportable segments		--		--		--
Total revenues	$	17,996	$	8,229	$	5,937
Net loss:
Operating loss, reportable segments	$	(2,485)	$	(6,020)	$	(5,261)
Expense or (revenue) adjustments:
Corporate DD&A expense		(120)		(177)		(149)
General and administrative costs (G&A)		(6,915)		(5,606)		(6,592)
Amortization of deferred compensation (G&A)		(2,604)		(2,759)		(125)
Stock compensation (G&A)		--		--		(76)
Total net operating loss		(12,124)		(14,562)		(12,203)
Non-operating income		433		795		780
Net loss	$	(11,691)	$	(13,767)	$	(11,423)
Net property and equipment:
Reportable segments	$	21,723	$	19,490	$	14,304
Corporate assets		162		205		336
Net property and equipment	$	21,885	$	19,695	$	14,640
Property and equipment capital expenditures:
Reportable segments	$	6,479	$	9,916	$	4,552
Corporate assets		73		59		158
Total property and equipment capital expenditures	$	6,552	$	9,975	$	4,710

F-25

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

Note 13: Subsequent Event

In February 2008, warrant holders exercised a total of 1,960,000 outstanding warrants at a price of $3.60 per share and 30,000 outstanding warrants at a price of $3.75 per share, resulting in proceeds to the Company of $7,168,500. The warrants were issued in a 2003 offering of common stock and warrants with an expiration date of March 1, 2008.

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, 2007 and 2006, are summarized as follows:

		United States		Poland		Total
				(In thousands)
December 31, 2007:
Proved properties	$	5,986	$	17,505	$	23,491
Unproved properties		61		1,940		2,001
Total gross properties		6,047		19,445		25,492
Less accumulated depreciation, depletion and amortization		(2,819)		(2,128)		(4,947)
	$	3,228	$	17,317	$	20,545
December 31, 2006:
Proved properties	$	5,552	$	13,741	$	19,293
Unproved properties		--		2,912		2,912
Total gross properties		5,552		16,653		22,205
Less accumulated depreciation, depletion and amortization		(2,428)		(843)		(3,271)
	$	3,124	$	15,810	$	18,934

Results of Operations

Results of operations are reflected in Note 12, Business Segments. There is no tax provision as the Company is not likely to pay, nor has it received any benefit from, any federal or local income taxes due to its operating losses. Total production costs (in thousands) for 2007, 2006 and 2005 were $3,538, $2,647 and $2,462, respectively.

Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities during 2007, 2006 and 2005, whether capitalized or expensed, are summarized as follows:

		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
Year ended December 31, 2006:
Acquisition of unproved properties	$	4	$	366	$	370
Exploration costs		932		11,159		12,091
Development costs		580		5,762		6,342
Total	$	1,516	$	17,287	$	18,803

F-26

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

		United States		Poland		Total
				(In thousands)
Year ended December 31, 2005:
Acquisition of unproved properties	$	95	$	30	$	125
Exploration costs		683		9,809		10,492
Development costs		366		520		886
Total	$	1,144	$	10,359	$	11,503

Impairment of Oil and Gas Properties

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

	2007	2006	2005
Impairment of properties	$2,299	$3,583	$  --

Exploratory dry hole costs

There were no dry holes drilled in 2007. During 2006, the Company plugged and abandoned the Drozdowice well in Poland, the Teton River well in Montana and the West Bacon Flat well in Nevada, incurring total dry hole costs of $1,572,749. During 2005, the Company plugged and abandoned the Lugi, Sroda 5 and four wells in the Inselberg and Radio prospects in Nevada, incurring total dry hole costs of $5,065,586.

Summary Oil and Gas Reserve Data (Unaudited)

Estimated Quantities of Proved Reserves

Proved reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. The Company’s proved oil and gas reserve quantities and values are based on estimates prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission. Operating costs, production taxes and development costs were deducted in determining the quantity and value information. Such costs were estimated based on current costs and were not adjusted to anticipate increases due to inflation or other factors. No price escalations were assumed and no amounts were deducted for general overhead, depreciation, depletion and amortization, and interest expense. The proved reserve quantity and value information is based on the weighted average price on December 31, 2007, of $81.07 per bbl for oil in the United States and $93.68 per bbl of oil and $5.61 per Mcf of gas in Poland. The determination of oil and gas reserves is based on estimates and is highly complex and interpretive, as there are numerous uncertainties inherent in estimating quantities and values of proved reserves, projecting future rates of production and timing of development expenditures. The estimates are subject to continuing revisions as additional information becomes available or assumptions change.

F-27

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

Estimates of the Company’s proved domestic reserves were prepared by Larry Krause Consulting, an independent engineering firm in Billings, Montana. Estimates of the Company’s proved Polish reserves were prepared by RPS Energy, an independent engineering firm in the United Kingdom.

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, 2007	482	14	--	5,288
December 31, 2006	382	202	--	11,382
December 31, 2005	408	--	--	974

Total Proved Reserves:

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

	Crude Oil		Natural Gas
	United States	Poland	United States	Poland
	(In thousand barrels of oil)		(In millions of cubic feet)
December 31, 2007:
Beginning of year	382	202	--	19,264
Extensions or discoveries	--	--	--	17,939
Revisions of previous estimates	170	(163)	--	(4,247)
Production	(70)	(25)	--	(1,840)
End of year	482	14	--	31,116
December 31, 2006:
Beginning of year	408	209	--	19,788
Revisions of previous estimates	50	2	--	(63)
Production	(76)	(9)	--	(461)
End of year	382	202	--	19,264
December 31, 2005:
Beginning of year	809	111	--	10,198
Extensions or discoveries	--	--	--	7,882
Acquisition of minerals in place	--	98	--	2,199
Revisions of previous estimates	(322)	--	--	(491)
Production	(79)	--	--	--
End of year	408	209	--	19,788

See Note 1. Summary of Significant Accounting Policies, Oil and Gas Properties, for further information concerning the Company’s Poland gas revisions.

F-28

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

Standardized Measure of Discounted Future Net Cash Flows (“SMOG”) and Changes Therein Relating to Proved Oil Reserves

Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, “Disclosures about Oil and Gas Activities.” Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute the proved reserve valuation do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rates also could result directly or indirectly from factors outside the Company’s control, such as unintentional delays in development, environmental concerns and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating expenditures to be incurred in developing and producing the proved oil reserves at the end of the period, based on period-end costs and assuming continuation of existing economic conditions. A discount rate of 10.0% per year was used to reflect the timing of the future net cash flows. The future net cash flows for the Company’s Polish reserves are based on a gas and condensate sales contract the Company has with POGC.

The components of SMOG are detailed below:

		United States		Poland		Total
				(In thousands)
December 31, 2007:
Future cash flows	$	39,056	$	179,698	$	218,754
Future production costs		(22,459)		(15,051)		(37,510)
Future development costs		--		(10,029)		(10,029)
Future income tax expense		--		(16,835)		(16,835)
Future net cash flows		16,597		137,783		154,380
10% annual discount for estimated timing of cash flows		(5,130)		(46,282)		(51,412)
Discounted net future cash flows	$	11,467	$	91,501	$	102,968
December 31, 2006:
Future cash flows	$	19,719	$	103,903	$	123,622
Future production costs		(13,511)		(12,046)		(25,557)
Future development costs		--		(2,502)		(2,502)
Future income tax expense		--		(4,595)		(4,595)
Future net cash flows		6,208		84,760		90,968
10% annual discount for estimated timing of cash flows		(1,643)		(25,568)		(27,211)
Discounted net future cash flows	$	4,565	$	59,192	$	63,757
December 31, 2005:
Future cash flows	$	20,833	$	73,114	$	93,947
Future production costs		(12,808)		(2,504)		(15,312)
Future development costs		--		(7,658)		(7,658)
Future income tax expense		--		(7,742)		(7,742)
Future net cash flows		8,025		55,210		63,235
10% annual discount for estimated timing of cash flows		(2,189)		(19,131)		(21,320)
Discounted net future cash flows	$	5,836	$	36,079	$	41,915

F-29

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

The principal sources of changes in SMOG are detailed below:

		Year Ended December 31,
		2007			2006			2005
					(In thousands)
SMOG sources:
	Balance, beginning of year	$	63,757	$		41,915	$		18,225
	Sale of oil and gas produced, net of production costs		(11,364)			(3,886)			(1,343)
	Net changes in prices and production costs		7,866			16,111			14,423
	Acquisition of minerals in place		--			--			4,391
	Extensions and discoveries, net of future costs		62,343			--			16,243
	Changes in estimated future development costs		(5,022)			3,953			(3,232)
	Previously estimated development costs incurred during the year		420			580			886
	Revisions in previous quantity estimates		(13,561)			(169)			(4,384)
	Accretion of discount		6,376			4,192			1,823
	Net change in income taxes		(8,008)			1,911			(5,131)
	Changes in rates of production and other		161			(850)			14
	Balance, end of year	$	102,968	$		63,757	$		41,915

F-30