FX Energy 10K 2011 Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2011

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

Commission File Number: 000-25386

FX ENERGY, INC.
(Exact name of registrant as specified in its charter)

Nevada		87-0504461
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

3006 Highland Drive, Suite 206, Salt Lake City, Utah		84106
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:		Telephone (801) 486-5555
		Facsimile (801) 486-5575

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of June 30, 2011, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $434,502,000.

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 9, 2012, FX Energy had outstanding 52,926,098 shares of its common stock, par value $0.001.

DOCUMENTS INCORPORATED BY REFERENCE. Portions of FX Energy’s definitive Proxy Statement in connection with the 2012 Annual Meeting of Stockholders are incorporated by reference in response to Part III of this Annual Report.

FX ENERGY, INC.

Form 10-K for the fiscal year ended December 31, 2011

TABLE OF CONTENTS

Item		Page
	Part I
--	Special Note on Forward-Looking Statements	3
1	Business	5
1A	Risk Factors	13
1B	Unresolved Staff Comments	24
2	Properties	24
3	Legal Proceedings	42
4	Mine Safety Disclosures	42

	Part II
5	Market for Registrant’s Common Equity, Related Stockholder Matters
	and Issuer Purchases of Equity Securities	43
6	Selected Financial Data	44
7	Management’s Discussion and Analysis of Financial Condition and Results of Operation	46
7A	Quantitative and Qualitative Disclosures about Market Risk	59
8	Financial Statements and Supplementary Data	60
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
9A	Controls and Procedures	60
9B	Other Information	60

	Part III
10	Directors, Executive Officers and Corporate Governance	61
11	Executive Compensation	61
12	Security Ownership of Certain Beneficial Owners and Management and Related
	Stockholder Matters	61
13	Certain Relationships and Related Transactions, and Director Independence	61
14	Principal Accountant Fees and Services	61

	Part IV
15	Exhibits and Financial Statement Schedules	62
--	Signatures	67
--	Management’s Report on Internal Control over Financial Reporting	F-1
--	Report of Independent Registered Public Accounting Firm	F-2

SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS

This report contains “forward-looking” statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically identified by the use of the words “believe,” “may,” “could,” “should,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “intend,” and similar words and expressions. Statements that describe our future strategic plans, goals, or objectives are also forward-looking statements. We intend that the forward-looking statements will be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

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

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

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

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

·	whether the estimated probable oil and gas reserves will ever be proved;

·	whether we will be able to obtain capital sufficient for our anticipated exploration and other capital expenditures;

·	how our efforts to obtain additional capital will affect the trading market for our securities;

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

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

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

·	foreign currency exchange-rate fluctuations;

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

·	exploration and development priorities and the financial and technical resources of PGNiG, our principal joint venture and strategic partner in Poland, PL Energia S.A., another partner in Poland, or other future partners;

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

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

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

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

·	uncertainties, restrictions, and increased costs resulting from the current public interest and regulatory focus on hydraulic fracturing, which we intend to use in our Montana gas exploration of the Alberta Bakken and Three Forks formations;

·	changes in the regulatory regime for the exploration, development, and production of hydrocarbons in Poland, including changes in the scheme through which prices at which we sell our production may be governmentally established or market influenced;

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

·	the impact on us, our industry partners, our lenders, and others with which we deal of the continuing sovereign debt crises within the European Union, of which Poland is a member; and

·	the factors set forth under the headings “Risk Factors” and “Management’s Discussion and Analysis of Analysis of Financial Condition and Results of Operation” and other factors that are not currently known to us that may emerge from time to time.

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

PART I

ITEM 1. BUSINESS

Introduction

We are an independent oil and gas exploration and production company with production, appraisal, and exploration activities in Poland. We also have modest oil production, oilfield service activities, and a shale acreage position in the United States. Our headquarters are in Salt Lake City, Utah, and our Polish operations are headquartered in Warsaw. Definitions of certain oil and gas industry terms used in this report are provided below under Item 2, Properties – Oil and Gas Terms.

At year-end 2011, independent reserve engineers estimated our worldwide proved oil and gas reserves to be 49.6 billion cubic feet, or Bcf, of natural gas and 0.6 million barrels of oil, or a combined total of 53.5 billion cubic feet of natural gas equivalent, or Bcfe (converting oil to gas at a ratio of one barrel of oil to 6,000 cubic feet of natural gas). This represents an increase from the 2010 year-end reserves of approximately 9.7 Bcfe, or 22%. Of this 53.5 Bcfe, 93% was in Poland and 7% was in the United States. The engineers estimated the PV-10 Value of our proved reserves to be approximately $170 million.

At year-end 2011, independent reserve engineers estimated our worldwide proved plus probable, or P50, oil and gas reserves to be a combined total of 94.5 Bcfe. The engineers estimated the PV-10 Value of our P50 reserves to be approximately $243 million.

Our 2011 oil and gas production was 4.4 Bcfe (12.0 million cubic feet equivalent per day, or MMcfed), which was up 15% from 2010 production; 4.1 Bcfe (11.1 MMcfed) of our production was in Poland and 0.3 Bcfe (0.9 MMcfed) was in the United States. All of our production in Poland consisted of natural gas, while all of our United States production consisted of crude oil.

We currently expect that our 2012 production will rise significantly from our 2011 production rates with the achievement of full production at our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells and the commencement of production at our Winna Gora well. We expect our 2012 first quarter production to average approximately 13.0 MMcfed. We expect full resolution of a pipeline bottleneck in the KSK area during the second quarter of 2012, following which our net daily production should exceed 15.0 MMcfed. We expect production facilities to be complete, and gas to start flowing, at our Winna Gora well in the third quarter of 2012. Production from that well is expected to begin at a rate of approximately 3.9 MMcfd (1.9 MMcfd net to our 49% interest). Thus, even without the benefit of any production from our recent Lisewo-1 well, we expect our 2012 production to significantly exceed our 2011 level.

Substantially all of our growth in reserves and production in recent years has come from our operations in Poland. We expect this will continue, as most of our technical efforts and capital budget are devoted to these operations in Poland. We believe that these operations represent the most favorable opportunities for success that are available to us. See “Corporate Strategy” immediately below. With a view to future growth in reserves and production, we now hold 4.6 million gross acres (3.6 million net) in Poland and continually review additional acquisition opportunities.

As of December 31, 2011, we had approximately 52.8 million shares of common stock outstanding, and our market capitalization was approximately $253 million (approximately $310 million as of the date of this filing). Our shares are listed on the Nasdaq Global Select Market under the symbol “FXEN.” So far during 2012, our average daily trading volume has been approximately 288,000 shares. Our total assets as of December 31, 2011, were $110.2 million, and our net working capital (working capital less long-term debt) was $9.8 million. Total debt per thousand cubic feet equivalent, or Mcfe, of proved reserves was $0.75 at year end.

References to “us,” “we,” and “our” in this report include FX Energy, Inc., and our subsidiaries. In addition to our headquarters in Salt Lake City, Utah, we have operations offices in Warsaw, Poland, and Oilmont, Montana.

Corporate Strategy

Poland is a unique international exploration opportunity. Over the last 50 years or so, Western companies have poured billions of dollars into exploration efforts in the British, Dutch, Norwegian, and German sectors of the offshore and onshore North European Permian Basin (generally the North Sea area). For the industry, these efforts have resulted in the discovery of trillions of cubic feet of gas and more than a billion barrels of oil. However, until the last few years of the twentieth century, Poland was closed to exploration by foreign oil and gas companies. To date, the exploration activities conducted in the Polish onshore portion of the Permian Basin are only a fraction of those conducted in the western part of the basin. Consequently, we believe the Polish Permian Basin is underexplored and underexploited and, therefore, has high potential for discovery of significant amounts of oil and gas relative to the North Sea or other mature oil and gas provinces in the United States and elsewhere. As an example, the estimated gross proved recoverable reserves per well associated with the eight conventional gas discoveries in our core Fences concession in Poland are 17.3 Bcf. The average initial gross production rate for these eight wells is estimated to be approximately 5.7 MMcfd of natural gas with a relatively long, flat production profile. We believe these figures are materially higher than those associated with new discoveries in most mature oil and gas provinces.

Just as important as the reserve and production potential is the fact that Poland is highly dependent upon imported natural gas, which is expensive. There is an attractive and deep market for gas discoveries and production in-country. For example, as of the date of this report the price we receive for natural gas at our Roszkow well, is approximately double the spot price under natural gas contracts traded on the New York Mercantile Exchange, sometimes referred to as the Henry Hub price.

Acting on this combination of facts, we were one of the first independent oil and gas companies to acquire a large land position, to embark on a focused exploration and development program, and as a result, to begin producing hydrocarbons in Poland. After a number of years of effort in Poland, our exploration efforts are showing significant progress. In fact, our proved oil and gas reserve volumes in Poland have increased at a compound annual growth rate of 34% since 2003. Our production volume has increased at a compound annual growth rate of 45% from 2005 through 2011. Though we cannot assert that future results will be similar, this success has encouraged us to continue to focus our efforts in Poland.

More specifically, we have directed the bulk of our available funds, management, and technical resources to our core “Fences” concession area in Poland. We expect to continue concentrating much of our capital budget to this area in an effort to lower drilling risk, shorten the time to first production from successful wells, and optimize opportunities for robust revenue growth.

We currently hold substantial acreage in other areas of Poland that we consider underexplored and underdeveloped and, therefore, subject to greater exploration risk. With the success that we have achieved from our Fences drilling program, we are now exploring our other exploration acreage, through both targeted seismic data acquisition and drilling of higher risk, higher reward exploration wells, where we believe we have the opportunity to find significant oil and gas reserves. To the extent that our overall strategy results in substantial revenue growth, we plan to continue to increase our funding of exploration projects over a wide area in Poland.

Current Activities and Presence in Poland

General

We concentrate our exploration efforts in Poland primarily on the Rotliegend sandstones of the Permian Basin. We have identified a core area consisting of approximately 852,000 gross acres surrounding PGNiG’s long-producing Radlin field. This 390 Bcf Rotliegend gas field was discovered in the 1980s by our joint venture partner, PGNiG, which owns and produces gas from the field (we do not own an interest in this field, but see it as a geologic analog). We have emphasized improved seismic data acquisition and processing in our exploration efforts surrounding this field, using technology developed by others for Rotliegend exploration in the Southern North Sea.

Since 2000, we have made commercially successful discoveries in eight of the 11 wells we have drilled on Rotliegend structural trap targets in our core Fences concession. In the aggregate, these eight discoveries found gross estimated proved reserves of approximately 139 Bcf of gas. We have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers in the Fences concession and plan to acquire 3-D seismic data over more of that concession. Using the data acquired to date, we have identified a number of possible additional structural traps. We believe the 3-D seismic data gives us better definition of the targets and might reduce our drilling risk. However, this is still exploration in an underexplored area. Thus, we expect to drill some wells that do not establish production or reserves, just as we have done in the past. Nonetheless, the extensive production history, well data, and seismic data available for the Fences area have contributed to our success rate there. We plan to continue to direct a significant portion of our available funds to carry out a multiyear exploration, appraisal, and development well drilling program in the Fences concession. These operations are the focus of our strategy to increase production and reserves in our core area.

While maintaining our focus on the Rotliegend structural trap exploration model, we are also working to determine the potential for commercial gas production from tight Rotliegend sandstone in the north of our Fences concession using “unconventional” fracture technology. The Plawce horst was discovered in the 1970s and 1980s; test wells found large gas columns in tight Rotliegend reservoirs. Modern technology now provides better tools to exploit such resources, which have significant potential. In 2011, we drilled a vertical well in the Plawce horst, encountering approximately 480 meters of relatively tight Rotliegend sandstone. Log, core, and test data show gas saturation with no free water. We plan to fracture three separate intervals in the well and test the potential for commercial production in the first half of 2012.

We have also identified a number of prospects outside the Fences concession, in our other concessions in Poland. These prospects are generally higher risk, but drilling success may open new productive areas with significant resources. In 2011, we drilled the Machnatka-2 well, later plugged and abandoned, in our Warsaw South block to test hydrocarbon potential in the Zechstein and Carboniferous horizons. We did encounter a significant amount of good reservoir rock along with good background gas, so we are continuing our exploration efforts in this block. Also in 2011, we started drilling the Kutno-2 exploration well in our Kutno concession in central Poland. The Kutno-2 well targets a very large Rotliegend two-dimensional, or 2-D seismic, defined structure at a depth of approximately 6,500 meters and is anticipated to penetrate this formation later this year. We reduced our financial exposure in both the Warsaw South and Kutno concessions in 2011 by farming out a portion of our 100% interest in return for a partial carry on the named wells.

In 2012, we plan to drill more than one well in one of our Warsaw South, Northwest, Edge, and Block 246 concessions. These wells will test various horizons for hydrocarbon potential as part of a multiyear program of exploration. We have not entered into new farmout arrangements, but do not rule out the possibility of doing so, either before or after initial drilling in order to diversify risk and benefit from the capital and technical resources of others.

We have accumulated a large land position in known productive regions or geologic trends and in selected “rank wildcat” areas in Poland located well away from previous drilling where exploration involves a high degree of risk. We have assembled a sophisticated technical team experienced with using modern exploration tools and generated a number of attractive oil and gas prospects. To the extent that our overall strategy results in substantial revenue growth, we plan to direct more of our own funds toward exploration of these early-stage exploration licenses.

Most of our current Polish operations are conducted in partnership with PGNiG. PGNiG, a fully integrated oil and gas company that is largely owned by the Treasury of the Republic of Poland, is Poland’s principal domestic oil and gas exploration, production, transportation, and distribution entity. Under our existing agreements, PGNiG 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 PGNiG, and we sell almost all of our gas production to PGNiG.

Polish Exploration Rights

As of December 31, 2011, we held oil and gas exploration rights in Poland in a number of separately designated project areas encompassing approximately 4.6 million gross acres. We are currently the operator in all areas, except our 852,000 gross-acre core Fences project area, in which we hold a 49% interest in approximately 807,000 acres and a 24.5% interest in the remaining 45,000 acres. PGNiG is the operator in the Fences project area. We hold interests in approximately 3.6 million net acres throughout Poland.

As we build revenues in our core area and further explore and evaluate our acreage in Poland, we expect to increase the operational and financial efforts we expend outside our core area. 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 several project areas: Fences, Blocks 287, 246, and 229 near the Fences concession, Warsaw South, Kutno, Northwest, and Edge. Our drilling activities have been focused primarily on the core Fences area. We have focused on this core area because substantial gas reserves have already been discovered and developed by PGNiG. We and PGNiG have discovered proved gas reserves of over 139 Bcf gross (60 Bcf net to our interest) in eight commercial wells in the Fences area as of the date of this report. We believe it is likely there remains substantial additional natural gas in the same geologic horizon in this area.

We plan to continue concentrating the majority of our efforts and resources on the Fences concession, but we are also increasing our efforts in our other exploration blocks in Poland. In the Fences during 2011, we completed the Lisewo-1 well as a commercial well and drilled the Plawce-2 well in a tight sand area. Plawce-2 will be fracked and tested in 2012. In our other concessions we drilled the Machnatka-2 well, a noncommercial Zechstein/Carboniferous test, in the Warsaw South concession, and started drilling the Kutno-2 well, a deep Rotliegend test, in the Kutno concession. We anticipate the Kutno-2 well will reach its target depth in the third quarter of 2012. Looking forward, in 2012 we plan to drill four wells in the Fences concession and two to four wells in our other exploration concessions.

Fences Area

The Fences concession area encompasses 852,000 gross acres (3,450 sq. km.) in western Poland’s Permian Basin. PGNiG gas fields located in the Fences area are “fenced off” or excluded from our exploration acreage. These fields, discovered by PGNiG between 1974 and 1985, 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 (406,000 total net acres).

The Rotliegend is the primary target horizon throughout most of the Fences concession area, at depths from approximately 2,500 to 4,000 meters. Both structural traps and stratigraphic (“pinch-out”) traps are known to produce gas from the Rotliegend in the region. In addition, we may have identified carbonates in the Zechstein formation, a third type of trap that is known to produce both oil and gas in the region.

Fences Area: Structural Traps

Based on our drilling experience since 2000 in the Fences area, we have emphasized the use of seismic data 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 using improved seismic data processing and acquisition techniques, we have drilled 11 conventional wells targeting Rotliegend structures through the date of this filing. Eight of these wells are commercial, with an aggregate estimated ultimate recovery of 139 Bcf, with remaining proved gas reserves of over 104 Bcf gross (48 Bcf net to our interest) as of December 31, 2011.

We currently produce from four of these eight wells. (The oldest of our eight wells had a very small reservoir and was depleted in 2010). In 2012, we expect to start production from two more of the eight wells, one in the second quarter and one in the third quarter, at which time we expect to be producing approximately 17 MMcfed net to us. Our eighth Fences well is expected to begin production mid-year 2013. The wells that are currently in production are producing under the required production licenses obtained by PGNiG in its capacity as operator or under the two-year period of test production that is permitted under the exploration concession.

In 2012, we plan to drill four additional wells in the Fences concession: one near our KSK production facility and three near the Lisewo production facility that is currently being permitted for construction and is scheduled to begin production mid-2013.

Finally, in the northernmost part of our Fences concession, we have identified a very large upthrown block, or horst, of Rotliegend sandstone that encompasses approximately 50 square kilometers, or 12,000 acres. In 2011 we drilled a vertical well, Plawce-2, in this horst block, encountering approximately 480 meters of relatively tight Rotliegend sandstone. Log, core, and test data show gas saturation with no free water. In the first half of 2012, we plan to fracture three separate intervals in the well and test the potential for commercial production.

Block 287 Concession Area

The Block 287 concession area is 12,000 acres (50 sq. km.) located approximately 25 miles south of the Fences concession area. We own 100% of the exploration rights. We retained this small portion of Block 287 when we relinquished larger portions in 2007 and 2008.

Within our retained acreage in Block 287, there are three Rotliegend gas wells known as the Grabowka wells. Originally drilled by PGNiG 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 reentering and completing the three Grabowka wells and building production facilities would be paid by our joint venture partner in exchange for discounted pricing on gas. To date, we have reentered only the Grabowka-12 well, which has been producing since July 2009. During 2011, it produced at an average daily rate of approximately 0.2 MMcfd. We plan to recomplete the Grabowka-6 well in the first half of 2012, which should allow us to increase production from this field by early in the third quarter of 2012.

Block 246 Concession Area

In 2008, we acquired a 100% interest in a concession south of our Fences project area covering approximately 241,000 acres (975 sq. km.). We have identified an area with potential for Rotliegend gas and a different area with potential for Ca1 reef build-ups and Carboniferous sands and shales. We are currently acquiring a small amount of 2-D seismic data over two potential drill sites and plan to drill one or more wells this year, subject to drilling plans in our other concession areas.

Block 229 Concession Area

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

Warsaw South Concession Area

We hold a 51% interest in a total of 874,000 acres (3,538 sq. km.) in east-central Poland. During 2011, we entered into a farmout agreement with PGNiG under which it earned a 49% interest in the entire Warsaw South concession in return for paying certain seismic and drilling costs. We subsequently drilled the Machnatka-2 well to test Zechstein and Carboniferous potential in the western part of the concession area. The well encountered a small Zechstein reef, a significant section of reservoir quality Carboniferous, along with good background gas and gas shows. The Warsaw South concession has a number of exploration leads, including carboniferous sands and shales with structural or truncation trapping and possibly Zechstein reefs trapped by overlying evaporites and salt. We believe this area has good potential for gas and condensate production, but data is sparse as there are few existing wells and relatively little seismic data. Nonetheless, we plan to continue our exploration efforts. In 2012, we plan to acquire additional new seismic data and possibly drill one or more wells, depending on the drilling activity in our other concession areas and on our partner’s input.

Kutno Concession Area

We hold a 100% interest in 706,000 acres (2,856 sq. km.) acquired in 2007 and 2008. The area encompasses a very large Rotliegend structure (“Kutno”) with projected four-way dip closure. The exploration model at Kutno is the same as in our core Fences concession, but much deeper. Depth of the structure is estimated at approximately 6,500 meters (21,000 feet). In view of the risk and cost, we entered into an agreement under which PGNiG will earn a 50% interest in the concession area in return for carrying a portion of our drilling costs in the first test well. We started drilling the Kutno-2 well in the third quarter of 2011 and anticipate reaching total depth of 6,500 meters in the third quarter of 2012.

Northwest Concession Area

We hold concessions on 828,000 acres (3,351 sq. km.) in west-central Poland, in Poland’s Permian Basin directly north of PGNiG’s BMB and MLG oil and gas fields. The Northwest concession area has at least two separate exploration models: Rotliegend sands trapping gas in structural closures and Zechstein Ca2 dolomitic sands, reefs, and talus trapping oil and gas.

Based on our review of reprocessed old and newly acquired 2-D seismic data, we drilled the Ostrowiec well in the Northwest concession in 2009 to test a Ca2 target at a depth of 3,800 meters and a Rotliegend target at a depth of 4,100 meters. The well did not encounter commercial hydrocarbons in the Ca2 target before reaching target depth for the Rotliegend. The well was operated and owned 51% by us. PGNiG earned a 49% interest in 211,000 acres in return for paying certain drilling costs associated with the Ostrowiec well.

The Rotliegend potential extends into the area where we hold 100% interest. In that area, we have identified a series of large potential Rotliegend structures. In 2012, we plan to acquire a small amount of 2-D seismic data on a proposed drill site. Based on the results of this new data we may drill a well to test Rotliegend gas potential, subject to our drilling plans on our other concession blocks. We may seek industry participation in connection with the proposed well.

Edge Concession Area

In 2008, we acquired a 100% interest in four concessions in north-central Poland covering approximately 881,000 acres (3,567 sq. km.). Having reprocessed existing 2-D seismic data, we identified a number of leads, including several Permian age Ca2 reefs and Devonian structures. We acquired additional 2-D seismic data in 2011 and plan to acquire more in 2012. We also plan to drill a well in one of the concession blocks this year, subject to our drilling plans elsewhere. We may seek industry participation in the drilling of wells in this concession area.

Additional Concession Acreage

We may apply for more concession blocks in Poland in 2012. If we acquire more concession blocks, we will allocate modest technical and financial resources to these areas during 2012, primarily in the form of data collection and seismic reprocessing, with a view to ascertaining relative hydrocarbon potential and exploration risk.

Key Personnel for Poland

Jerzy Maciolek is a director of the Company and heads our exploration team as Vice President of International Exploration. He joined the Company in 1995 specifically to lead us into Poland, where he had identified the exploration opportunity that today is our core asset. Before joining us, Mr. Maciolek had over 25 years of experience as a geophysicist with PGNiG and 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 PGNiG’s Upstream Exploration and Production Division. During his 20-year career with PGNiG, he rose through the ranks as a production engineer and was serving as Vice Chairman of PGNiG at the time of his retirement. Mr. Tatys has unique qualifications to lead us through our transition from a pure exploration company to a natural gas and oil producer in Poland.

Our 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 50 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 as Vice President of Exploration, he was responsible for key Amerada Hess North Sea and international discoveries, including the Valhall, Scott, and South Arne fields. Mr. Hardman was made Commander of the British Empire in the New Year Honours, 1998, and has served as the Chairman of the Petroleum Society of Great Britain, President of the Geological Society of London, and President of the European Region of American Association of Petroleum Geologists Europe.

Our U.S. Activities and Presence

Unlike our position in Poland, our U.S. operations have not been a focus of our exploration efforts until recently. Our U.S. operations provide a modest amount of cash flow and are not capital intensive. They consist mostly of shallow, oil-producing wells in the Southwest Cut Bank Sand Unit, or SWCBSU, of Montana. As of December 31, 2011, our U.S. reserves (all of which were proved reserves) were estimated at 639,000 barrels of crude oil with a PV-10 Value of approximately $12.3 million. At year-end 2011, U.S. reserves were approximately 7% of total proved reserves on a gas equivalent basis. Our oil wells produce approximately 155 barrels of oil per day, net to our interest. From our field office in Montana, we also provide oilfield services, which provided approximately $5.6 million in revenue during 2011. We produce oil from approximately 10,732 gross (10,418 net) acres in Montana and 400 gross (128 net) acres in Nevada.

Alberta Bakken and Three Forks Shale Exploration

Recently, U.S. and Canadian oil and gas operators have been drilling for oil in the Bakken and Three Forks shale formations in the Williston Basin in North Dakota and Montana and in the Alberta Basin in Montana and Canada. The Bakken (also known in Canada as the Exshaw) and related formations are the focus of a growing trend of testing oil potential with multistage fracturing of horizontal wells. Newfield Exploration Co. (NFX) and Rosetta Resources, Inc. (ROSE), are two of the more active companies among a number operating near SWCBSU in northern Montana. In 2011, we initiated our own exploration effort.

In 2011, we entered into a joint venture with two other companies, American Eagle Energy, Inc., and Big Sky Operating LLC, in which we pooled our approximately 10,000 net acres in our SWCBSU with their approximately 65,000 net acres, the Americana leases, along with a farmout agreement that provides the group with an ability to earn an interest in an additional 7,000 acres covered by the Somont leases. Under the joint venture, the three parties have equal interests only in the Alberta Bakken formation group and share exploration costs equally. We maintain our original interest only in the mineral rights above the Alberta Bakken and related formations in the SWCBSU, from which we are currently producing oil. During 2011, we drilled three vertical wells on joint venture acreage to obtain log and core data. We also drilled a 3,600-foot lateral from one of these three wells, the Anderson 14-29, and carried out a multistage fracture. We are currently testing oil potential in the Anderson 14-29 well.

Subsequent to year-end 2011, we entered into a new joint venture, wherein the existing partners contributed half of their interest in all formations above the base of the Alberta Bakken group in only the Americana leases in exchange for a like interest in the Americana leases in all formations below the Alberta Bakken group, including the Nisku and others that have regionally demonstrated the potential for oil production. We now have a one-third working interest in all formations below the Cut Bank in our SWCBSU, the ability to earn a one-third interest in all formations below the top of the Alberta Bakken group in the Somont acreage, and a one-sixth working interest in the Americana acreage in all formations below the surface. We currently plan to drill two more vertical wells and drill a lateral from one of the vertical wells drilled in 2011. We may continue drilling wells throughout 2012 as part of the overall program of evaluating the Bakken group in our acreage to determine whether all or any part of our acreage might support commercial oil production from this horizon.

We, either directly or through our joint venture partners, contracted with industry-standard third-party specialists for both the horizontal drilling and completion phases of the well we hydraulically fractured. To date, there have not been any environmental or safety incidents, citations, or suits related to the hydraulic fracturing operations used as part of the completion of the Anderson 14-29 well.

Insurance

We carry third-party liability and property and casualty insurance for our activities and facilities in Poland, but we do not plan to purchase control of well 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, except at our Kutno project, for which we have purchased control of well coverage. We rely on the control of well coverage and financial responsibility of PGNiG as operator of the wells in which we jointly participate in the Fences project area. We cannot assure that the insurance policies carried by us or by PGNiG, as operator of the Fences area, can continue to be obtained on reasonable terms or that such policies will protect against all risks of loss.

In the United States, we maintain insurance coverage against potential losses that we believe is customary in the industry in the United States. We currently maintain general liability insurance with limits of $1,000,000 per event with a $2,000,000 annual aggregate limit. In addition, we carry an Umbrella Excess Liability policy with a $10,000,000 per event limit with a $10,000,000 general total limit. There is a $1,000 per claim deductible for only our property damage liability and a $10,000 retention for our commercial umbrella liability insurance. Our general liability insurance covers us for, among other things, legal and contractual liabilities arising out of property damage and bodily injury, but not for pollution liability. Our commercial umbrella liability insurance is in addition to our general liability insurance policy and triggered if the general liability insurance policy limits are exceeded. In addition, we maintain control of well insurance with per occurrence limits of $5 million and retentions of $100,000 for any one occurrence. Our control of well policy insures us for blowout risks associated with drilling, completing, and operating our wells, including aboveground pollution, but not for groundwater damage due to hydraulic fracturing.

Our insurance policies may not cover fines, penalties, or costs and expenses related to government-mandated cleanup of pollution. In addition, these policies do not provide coverage for all liabilities, and in particular, do not provide coverage for losses arising out of our hydraulic fracturing operations. We cannot assure that our insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Employees and Consultants

As of December 31, 2011, we had 48 employees, consisting of nine in Salt Lake City, Utah; 19 in Oilmont, Montana; one in Greenwich, Connecticut; two in Houston, Texas; and 17 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 3,700 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, where we rent 404 square meters for approximately 22,000 PLN per month and in Krakow, Poland, located at ul. Smolensk 21/15, where we rent approximately 15 square meters for approximately 1,100 PLN per month.

Segment Information

Further information concerning our financial and geographic segments can be found in the notes to the consolidated financial statements included in this report.

Available Information

We make available, free of charge, on our website (www.fxenergy.com), 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 after we file such material with, or furnish it to, the Securities and Exchange Commission. We also make these materials available, free of charge, by contacting our main office in Salt Lake City, Utah at (801) 486-5555. Information on our website is not incorporated by reference in this report.

ITEM 1A. RISK FACTORS

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

Risks Relating to our Business

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

We anticipate that our production will increase in 2012 as previously drilled wells are placed into production and that we will generate revenues in excess of direct lease operating costs as well as anticipated general and administrative costs. However, these revenues will not be sufficient to cover all of our planned exploration and development costs. Accordingly, we will continue to rely on existing working capital, borrowings under our credit facility, additional funds obtained from the sale of equity securities and other external sources, and industry partners to cover these costs. If we are unable to obtain the funds that we seek from these sources for our exploration and development plans, we may be required to reduce our capital expenditures.

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

The prices at which we sell gas in Poland to PGNiG are determined pursuant to published tariffs for gas sold to wholesale consumers. Such tariffs are determined, in part, by reference to the cost of Russian imported gas, the price of which is based, in part, on trailing, historical oil prices. The trailing impact of lower oil prices may have a depressing effect on such tariffs, and so may reduce the price that we receive for our gas from PGNiG. Conversely, because the tariffs are determined, in part, by trailing prices, increases in oil prices may result in higher tariffs for the gas we sell in Poland. Changes in the mechanism for determining the applicable tariff may also result in lower prices for gas that we may sell.

We may incur additional losses due to exchange-rate fluctuations.

Continuing fluctuations in the rates at which U.S. dollars are exchanged into Polish zlotys may result in ongoing noncash exchange-rate losses. We are subject to exchange-rate fluctuations as we transfer dollar-denominated funds from the United States to Poland for exploration and development and receive payment for the gas we sell in Poland in zlotys. As the U.S. dollar strengthens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys declines; conversely, when the U.S. dollar weakens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys increases. Should exchange rates in effect during early 2012 continue throughout the year, we expect the exchange rates to have a slightly negative impact on our U.S. dollar-denominated revenues in 2012 compared to 2011, with a corresponding reduction in the U.S. dollar cost of our capital expenditures in Poland. Applicable exchange rates may be adversely affected by the continuing European debt and financial crises.

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

Our partner, PGNiG, holds the majority interest and is operator of our Fences project area, where our principal production and reserves are located. As a paying partner, we rely to a significant extent on the financial capabilities of PGNiG. If PGNiG were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on our business, financial condition, results of operations, and cash flows. In particular, we have prepared our exploration budget through 2012 and beyond based on the participation of, and funding to be provided by, PGNiG. Although we have rights to participate in exploration and development activities on some PGNiG-controlled acreage, we have limited rights to initiate such activities, which might slow the pace at which we might like to advance our exploration and development efforts if we had full funding. Similarly, as operator, PGNiG controls the level of production as well as other day-to-day operating details. Our program in Poland involving PGNiG-controlled acreage would be adversely affected if PGNiG should elect not to pursue activities on such acreage, if the relationship between us and PGNiG should deteriorate or terminate, or if PGNiG or the governmental agencies should fail to fulfill the requirements of, or elect to terminate, such agreements, licenses, or grants. In our Block 287 area, we are dependent on the financial ability of a different industry participant to pay the costs of agreed exploration activities. We may undertake this work at our own cost or seek replacement industry participants if this third party fails to pay these costs.

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

We cannot assure the exploration models we and PGNiG develop will provide a useful or effective guide for selecting exploration prospects and drilling targets. We continually review and revise or replace these exploration models as a guide to further exploration based on ongoing drilling results. These exploration models are typically based on incomplete or unconfirmed data and theories that have not been fully tested. The seismic data, other technologies, and the study of producing fields in the area do not enable us to know conclusively prior to drilling that gas or oil will be present in commercial quantities. The fact that some prospects may appear to have similar geological or geophysical subsurface features or may be located near previous wells cannot assure that such prospects are in fact similar or that drilling results will be comparable. Every prospect is unique and must be evaluated individually. We cannot assure that the analogies that we draw from available data from other wells, fully explored prospects, or producing fields will be applicable to our drilling prospects or will enable us to forecast accurately drilling results.

Our statements respecting the quantities of potential gas or oil accumulation that we estimate for management purposes should not be converted into reserves.

For purposes of management decisions and risk analysis, we use a variety of geological, engineering, and geophysical techniques to estimate probable or possible reserves and gross, unrisked resource potential. These various methods are important in making many kinds of management decisions during the exploration, development, and production process, but the quantities and values estimated through these methods are not comparable and should not be compared. We cannot assure that any gas or oil quantities or values that we estimate through alternative methods will ever be converted through additional exploration and production into reserves.

Our estimates of proved and probable oil and gas reserves and future net revenues are subject to various risks and uncertainties.

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

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

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

·	the assumed effects of regulatory requirements and government payments;

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

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

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

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

In accordance with Securities and Exchange Commission’s revisions to the rules for estimating oil and gas reserves that we adopted effective December 31, 2009, our reserve estimates are based on 12-month average prices, rather than year-end prices. The application of these rules resulted in the use of lower prices for estimating reserves than under the previous rules. Furthermore, as permitted by the revised rules, our estimates of probable reserves as of December 31, 2011, 2010, and 2009, are calculated using probabilistic, as distinguished from deterministic, methods used in estimating proved reserves. The larger quantity of proved plus probable reserves, as compared to proved reserves only, is attributable largely to using a less certain interpretation of reservoir size and a higher recovery factor in estimating probable reserves that reduces the likelihood of the actual recovery of probable reserves. For example, probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. Such uncertainties preclude the reserves at issue from being classified as proved.

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

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

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

We may continue to have exploration failures in Poland.

Since 1995 and through early 2012, we have participated in drilling 30 exploratory wells in Poland, including nine commercial discoveries (Wilga 2, Kleka 11, Zaniemysl-3, Sroda-4, Winna Gora-1, Roszkow-1, Kromolice-1, Kromolice-2, and Lisewo-1), 21 noncommercial wells, and two wells that were either drilling or waiting on further testing at year-end 2011. Of our nine commercial successes in Poland, as of the date of this report we were producing gas at our Roszkow-1, Zaniemysl-3, Kromolice-1, and Sroda-4 wells. Our Wilga 2 and Kleka 11 wells have been fully exploited and no longer produce. Production from the three other commercial discoveries will not commence until requisite permits are obtained and production facilities are constructed.

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

We currently estimate that it may take approximately two years or more to place a completed gas well on line so that we can commence production and sell gas from such well. We may encounter delays in commencing the production and sale of gas in Poland, including our recent gas discoveries and other possible future discoveries. We may face delays in obtaining rights-of-way to connect to the PGNiG pipeline system, construction permits, and materials and contractors; signing gas or oil purchase/sales contracts; receiving commitments for required capital expenditures by PGNiG; and other factors. Such delays could correspondingly postpone the commencement of cash flow and may require us to obtain additional short-term financing pending commencement of production. Further, we may design and construct surface and pipeline facilities to accommodate anticipated production from additional drilling, but we cannot assure that additional drilling will establish additional reserves or production that will provide an economic return for expenditures for those 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. Further, producing wells for which PGNiG acts as the operator generally are produced at levels that are acceptable to it, which may be lower as compared to the productive capacity of similar wells in the United States.

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

From our inception in January 1989 through December 31, 2011, we have incurred cumulative net losses of approximately $190 million. Our exploration and production activities may continue to result in net losses through 2012 and possibly beyond, depending on whether our activities in Poland and the United States are successful and result in sufficient revenues to cover related operating expenses.

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

We may not fulfill our work commitments on the exploration rights we hold in Poland.

We are subject to certain work commitments respecting various exploration concessions that must be satisfied in order to maintain our interest in those concessions. We cannot assure that we will be granted any requested changes to usufruct and concession agreements that either modify the obligations to reduce our commitments or extend the terms of those agreements. Our exploration budget and related activities may not be focused specifically or primarily on meeting these work commitments. We may not be able to retain any concession rights on areas for which we do not timely complete required work commitments.

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

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

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

We currently sell substantially all of the oil and gas we produce in Poland to PGNiG or one of its affiliates. If PGNiG were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on us. The market for the sale of gas in Poland is open to competition, but there are not yet many market participants. While our contracts provide us with the ability to market gas to other purchasers, including those outside of Poland, we do not expect to have the opportunity to diversify our gas markets in the foreseeable future.

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

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

·	the market and price structure in local markets;

·	changes in the mechanism for determining the applicable tariff for pricing gas;

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

·	market uncertainty;

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

·	political conditions in international oil and gas producing regions;

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

·	the level of consumer demand;

·	weather conditions affecting production, transportation, and consumption;

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

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

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

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

·	other factors beyond our control.

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

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

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

Our operations are subject to potential litigation that could have an adverse effect on our business.

From time to time we are a defendant in various lawsuits. The nature of our operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be adversely decided against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition.

We face competition from larger oil and gas companies, which could result in adverse effects on our business.

The exploration and production business is highly competitive. Many of our competitors have substantially larger financial resources, staffs, and facilities. Our competitors in Poland and the United States include numerous major oil and gas exploration and production companies.

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

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

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

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

We spent $321,000 in oil leak cleanup costs in 2011 and may incur additional significant costs related to this or other environmental matters.

Following a June 2011 oil leak at our Southwest Cut Bank Sand Unit (SWCBSU) in Montana, we spent approximately $321,000 in completing cleanup, mitigation, and restoration pursuant to an approved plan in cooperation with the Blackfeet Tribe and the United States Environmental Protection Agency, commonly referred to as the EPA. We cannot assure that the satisfactory completion of the cleanup according to the specifications provided by the Blackfeet Tribe and the EPA will not result in additional costs or sanctions. As an owner or lessee and operator of oil and gas properties in the United States and Poland, we are subject to various federal, tribal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations, subject the lessee to liability for pollution damages, and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in a significant adverse effect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

Our United States operations are subject to governmental risks that may impact our operations.

Our United States operations have been, and at times in the future may be, affected by political developments and by federal, state, tribal, and local laws and regulations such as restrictions on production, changes in taxes, royalties, and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations. New political developments, laws, and regulations may adversely impact our results on operations.

United States federal, state, and Polish legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to explore and produce from our properties.

We have initiated a program to test the oil potential of the Bakken, Three Forks, and related shale formations underlying our SWCBSU with multistage hydraulic fracturing of horizontal wells. In addition, we intend to hydraulically fracture the Plawce well in Poland, which may lead to additional wells in the Plawce area that we may treat similarly. Hydraulic fracturing is a practice used to enhance oil and natural gas production. The process of hydraulic fracturing has typically been regulated by state oil and natural gas regulators but has not been subject to federal oversight or regulation. However, the United States Congress is currently considering bills that would eliminate an existing exemption under the Safe Drinking Water Act and subject hydraulic fracturing to federal regulation. Moreover, the EPA has begun a study of the potential environmental impacts of hydraulic fracturing, and a committee of the U.S. House of Representatives is also conducting a study of the chemicals used in the fracturing process. Additionally, some states have adopted, and Montana might consider adopting, conditions, restrictions, and regulations that could prohibit hydraulic fracturing under certain circumstances. If enacted, such a provision could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping requirements, and meet plugging and abandonment requirements.

Other measures propose to add a federal requirement that natural gas drillers disclose the chemicals that are pumped into the ground as part of the hydraulic fracturing process, which may broaden public awareness of long-standing industry practice. Certain states and other agencies have adopted or are considering similar disclosure legislation, moratoria, or enforcement initiatives relating to hydraulic fracturing.

In Poland, the requirement that we provide an environmental impact assessment and seek specific regulatory authority before hydraulically fracturing wells in the Plawce area might result in delays, increase costs, and require us to alter planned activities.

Adoption of legislation or implementation of regulations placing restrictions on, or imposing reporting and disclosure obligations regarding, hydraulic fracturing activities could impose operational delays, increase operating costs, and add regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced and booked as reserves in the future, delayed exploration and development, and increased costs of compliance and doing business. Such consequences could limit the potential upside of any activities we undertake with respect to shale plays in Montana or the Plawce area in Poland.

The demand for hydraulic fracturing expertise and equipment may make it difficult for us to complete our planned hydraulic fracturing.

Many oil and gas exploration firms in both Poland and the United States have expanded their use of hydraulic fracturing, and the resulting demand on the availability of third parties with fracturing expertise and equipment, particularly in Poland, may make it difficult for us to complete planned fracturing activities within estimated schedules or budgets.

Risks Relating to Conducting Business in Poland

A substantial amount of our revenues is attributable to our operations in Poland.

Any disruption in production, development, or our ability to produce and sell oil in Poland would have a material adverse effect on our results of operations or reduce future revenues.

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 our partners and us or the oil and gas industry in Poland in general;

·	the potential adoption of an entirely new regulatory regime for the exploration, development, extraction, and taxation of all natural resources, including oil and gas;

·	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, PGNiG’s and our 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.

Our operations are concentrated in Poland such that any impediment to these operations would have a material adverse effect on our business, financial condition, and results of operations.

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

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

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

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

Neither our partners nor we can 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.

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

Our activities in Poland have benefited from our relationship with PGNiG, which has provided us with exploration acreage, seismic data, and production data under our agreements. The Polish government commenced the privatization of PGNiG by selling PGNiG’s refining assets in the mid-90s and by successfully completing an initial public offering of approximately 15% of its stock. Complete privatization or a re-nationalization of PGNiG 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 PGNiG in the future.

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

The amounts in our agreements relating to our activities in Poland are sometimes expressed and payable in U.S. dollars and sometimes in Polish zlotys. In the future, our financial results and cash flows in Poland may be affected by fluctuations in exchange rates between the Polish zloty and the U.S. dollar. Currencies used by us may not be convertible at satisfactory rates. In addition, the official conversion rates between United States and Polish currencies may not accurately reflect the relative value of goods and services available or required in Poland. Further, inflation may lead to the devaluation of the Polish zloty.

The ongoing European sovereign debt crises and collateral financial issues may adversely affect our ability to borrow money.

Under our Senior Secured Credit Facility with three European banks, we have drawn $40 million in financing and have access to an additional $15 million when we attain certain production benchmarks. Although all three lending banks successfully passed the required European bank stress tests, our access to the remaining $15 million under our credit facility, when it becomes available, may be adversely affected in view of the continuing unresolved sovereign debt conditions in Europe, the unsettled circumstances surrounding the secondary credit crisis in Europe, and the uncertain success of efforts to resolve the Euro crisis. Such factors may adversely impact the capital stability of our lenders as well as other lenders from which we might seek additional or replacement financing.

The Polish Ministry of the Environment has the authority to terminate the mining usufruct agreements with immediate effect and may impose a contractual penalty in the amount of 25% of the fee due under the mining agreement if we do not comply with the terms and obligations indicated in such agreements.

Pursuant to the Polish Geological and Mining Law, a mining usufruct is the right to carry out work connected with the prospecting and exploration for or the extraction of oil and gas. A mining usufruct is established based on an agreement concluded with the Polish State Treasury, in that case represented by the Polish Ministry of the Environment. The Polish Ministry of the Environment has the authority to terminate a mining usufruct agreement with immediate effect and may impose on us a contractual penalty in the amount of 25% of the fee due under the mining usufruct agreement if we fail to comply with the terms and obligations indicated in such agreement, in particular with the obligation to pay the fee due under the agreement. We cannot ensure that we have complied and will comply in the future with all the terms and obligations imposed on us under the mining usufruct agreements. The loss of the usufruct rights under the mining usufruct agreements would have a material adverse effect on our business, financial condition, and results of operations.

Our operations in Poland require our compliance with the Foreign Corrupt Practices Act.

We must conduct our activities in or related to Poland in compliance with the United States Foreign Corrupt Practices Act, or FCPA, and similar anti-bribery laws that generally prohibit companies and their intermediaries from making improper payments to foreign government officials for the purpose of obtaining or retaining business. Enforcement officials interpret the FCPA’s prohibition on improper payments to government officials to apply to officials of state-owned enterprises such as PGNiG, our principal partner in Poland. While our employees and agents are required to acknowledge and comply with these laws, we cannot assure that our internal policies and procedures will always protect us from violations of these laws, despite our commitment to legal compliance and corporate ethics. The occurrence or allegation of these types of risks may adversely affect our business, performance, prospects, value, financial condition, reputation, and results of operations.

Risks Related to 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:

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

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

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

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

Our common stock has traded as low as $3.67 and as high as $12.20 during intraday trading between January 1, 2011, 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 and the United States;

·	the potential sale by us of newly issued common stock to raise capital;

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

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

·	actions or announcements by our partners that may affect us;

·	announced drilling or other exploration results by others in or near the areas of our activities;

·	turmoil in the financial sector that may impact our revolving credit facility;

·	prevailing world prices for oil and gas;

·	changes in regulatory environments may adversely affect the trading prices for our common stock;

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

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

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

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

Our current rating by third-party corporate governance consultants advising institutional stockholders may result in recommendations that incumbent directors not be reelected or the approval of other matters in accordance with management’s recommendations.

Various corporate governance consultants advising institutional investors and others provide scores or ratings of our governance measures, nominees for election as directors, and other matters that may be submitted to the stockholders for consideration. Although the full details of such scores or ratings by consultants are not available to us, we expect that certain nominees or matters that we propose for approval from time to time may not merit a favorable score or rating or may result in a negative score or rating or recommendation that the nominee or matter be rejected. We believe that approximately 40% of our stock may be held by institutions that may be advised by such consultants. Accordingly, unfavorable scores or ratings by such consultants could adversely affect our ability to obtain reelection of incumbent directors or the approval of other matters in accordance with management’s recommendations. We have reviewed certain governance measures, such as our classified board and stockholder rights plan, that we believe contribute to our low scores and ratings and have determined that such governance provisions are in the best interests of our stockholders notwithstanding the adverse effect of such provisions on such scores or ratings.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Proved Reserves Disclosures

Securities and Exchange Commission Modernization of Oil and Gas Reserves Reporting

On December 31, 2009, we adopted the Securities and Exchange Commission’s rule revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

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

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

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

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

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

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

Additional disclosure as provided below was also required by the Securities and Exchange Commission revisions.

Effect of Adoption

Use of 12-month average pricing at December 31, 2009, as required by the current rules, resulted in a decrease in proved developed oil reserves of approximately 1.0 MMcfe in 2009. We did not calculate the impact of the current rules on our 2010 or 2011 reserves. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.

Internal Controls over Reserves Estimates

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

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

Proved and Probable Reserves

Proved reserves are estimated quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward and recoverable in future years from known reservoirs and under existing economic conditions, operating methods, and governmental regulations, prior to the expiration of the contracts providing the right to operate, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited: (i) to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances; and (ii) to other undrilled locations if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

We emphasize that the volume of reserves are estimates that by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. These reserve revisions result primarily from increases or decreases in performance from a variety of sources such as an addition to or a reduction in recoveries below or above previously established lowest known hydrocarbon levels, improvements or deteriorations in drainage from natural drive mechanisms, and increases or decreases to drainage areas. If the estimates of proved reserves were to decline, the rate at which we record depletion expense would increase.

Proved Undeveloped Reserves

As of December 31, 2011, our proved undeveloped reserves totaled 17.6 Bcf of natural gas. All of our proved undeveloped reserves are located in Poland, and all are associated with wells that have been drilled, tested, and completed for production. We do not have any proved undeveloped reserves attributable to undrilled locations. These reserves are classified as proved undeveloped because relatively major expenditures are required for the completion of production facilities, which includes the construction of pipelines to connect the wells to the existing pipeline in order to fully develop the reserves and commence production. The development of such undeveloped reserves is not dependent on additional drilling on undrilled acreage. All development activities will be completed within five years of reserve bookings.

Changes in Proved Undeveloped Reserves

No reserves were converted from undeveloped reserves at December 31, 2010, to developed reserves at December 31, 2011.

Development Costs

Costs incurred relating to the development of proved undeveloped reserves were approximately $3.0 million in 2011, almost all of which were attributable to the construction of production facilities at our KSK wells.

Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $6.0 million in 2012. The estimated development costs are for the cost of facilities construction at our Winna Gora and Lisewo production facilities and not for the drilling of development wells.

For more information, see the following:

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

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

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

Other Reserves Information

Since January 1, 2011, no crude oil or natural gas reserves information has been filed with, or included in any report to, any other federal authority or agency.

Reserve Volumes and Values

The following table sets forth our estimated proved developed, proved undeveloped, and probable reserves volumes as of December 31, 2011:

	United States	Poland	Total
	MBbls	MMcf	MMcfe
Proved developed reserves	639	31,987	35,821
Proved undeveloped reserves	--	17,649	17,649
Total proved reserves	639	49,636	53,470
Probable reserves	--	41,035	41,035
Total proved plus probable reserves	639	90,671	94,505

The following table sets forth the estimated PV-10 Value of our proved plus probable reserves as of December 31, 2011:

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

Proved	53,470	$169,567
Probable	41,035	73,740
Total Proved and Probable	94,505	$243,307

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

Economic producibility of reserves and discounted cash flows are based on the use of unweighted, 12-month first day of the month historical average prices adjusted for basis and quality differentials, rather than year-end prices. In Poland, average gas prices used in calculating reserve values also take into consideration exchange rates between the U.S. dollar and Polish zloty in effect on the first day of each month. The average prices used to calculate year-end reserve values were $6.44 and $5.66 per Mcf and $84.61 and $68.12 per barrel for 2011 and 2010, respectively.

Drilling Activities

The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2011, 2010, and 2009:

	Year Ended December 31,
	2011		2010		2009
	Gross	Net	Gross	Net	Gross	Net
Exploratory productive wells:
Poland	1.0	0.5	--	--	1.0	0.5
United States	--	--	--	--	--	--
Total	1.0	0.5	--	--	1.0	0.5

Exploratory dry holes:
Poland	1.0	0.5	--	--	--	--
United States	--	--	--	--	1.0	0.5
Total	1.0	0.5	--	--	1.0	0.5

Total wells drilled	2.0	1.0	--	--	2.0	1.0

The productive exploratory well drilled in 2011 was our Lisewo-1 well, which had net proved reserves of 12.2 Bcf of natural gas at year-end 2011. The exploratory dry hole in Poland drilled in 2011 was our Machnatka-2 well. The foregoing does not include the Plawce-1 and Kutno-2 wells being drilled or evaluated in Poland at 2011 year end. It also does not include two vertical and one horizontal Alberta Bakken shale wells drilled in the United States that were being evaluated at year-end 2011. We did not drill any development wells in 2011, 2010, or 2009.

Wells and Acreage

As of December 31, 2011, our gross and net producing wells consisted of the following:

	Number of Wells
	Gas		Oil
	Gross	Net	Gross	Net
Well count:
Poland(1)	4.0	2.2	--	--
United States	--	--	122.0	105.0
Total	4.0	2.2	122.0	105.0

_______________

(1)	In addition to the wells producing at year-end 2011, an additional well resumed production in early January 2011. As of December 31, 2011, we had two wells in Poland awaiting the construction of production facilities.

The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2011. All of our gas production is in Poland and all of our oil production is in the United States:

	Developed		Undeveloped
	Gross	Net	Gross	Net
Poland:(1)
Fences project area	3,215	1,416	850,000	406,000
Northwest project area	--	--	828,000	724,000
Kutno project area(2)	--	--	706,000	706,000
Warsaw South project area	--	--	874,000	446,000
Block 287 project area	410	410	12,000	12,000
Edge project area	--	--	881,000	881,000
Block 246 project area	--	--	241,000	241,000
Block 229 project area	--	--	233,000	233,000
Total Polish acreage	3,625	1,826	4,625,000	3,649,000

United States:
Montana(3)	10,732	10,418	83,742	30,563
Nevada	400	128	9,332	6,351
Total	11,132	10,546	93,074	36,914

Total Acreage	14,757	12,372	4,718,074	3,685,914

_______________

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

(2)	PGNiG will earn a 50% interest in our Kutno acreage upon completion of drilling at the Kutno-1 well.

(3)

The figures shown for Montana developed acreage represent the gross and net working interests in the Cut Bank formation in our SWCBSU. In 2011, we entered into a joint venture to explore various formations, including the Alberta Bakken and Three Forks shale formations, which lie below the Cut Bank formation. As part of the joint venture, we contributed our rights to the deeper formation to a project that encompassed a total of approximately 75,000 gross acres, in which we own 33%. The incremental acreage that is subject to the joint venture arrangement at year-end 2011, approximately 79,000 gross and 26,000 net acres, is included in the total gross and net undeveloped acres in Montana.

Polish Properties

Producing Properties

A summary of our average daily production, average interest, and net revenue interest for our Poland producing properties during 2011 follows:

	Average Daily			Average
	Production (Mcfe)		Average	Net Revenue
	Gross	Net	Interest	Interest
Fences project area	26,693	10,890	41%	41%
Grabowka	233	233	100%	100%
Total	26,926	11,123

Production, Transportation and Marketing

During 2011, our Roszkow and Zaniemysl wells produced steadily throughout the year. Production from our Sroda-4, Kromolice-1, and Kromolice-2 wells was intermittent, as we dealt with restricted pipeline capacity due to a bottleneck in the gas production system in the KSK area. In September of 2011, the Kromolice-1 well began steady production at a rate agreed upon with PGNiG. In early 2012, the Sroda-4 well, which our independent reservoir engineers believe is part of the same producing field as Kromolice-1, began continous production at its agreed-upon rate. We expect the pipeline bottleneck to be resolved in the second quarter of 2012, at which time the Kromolice-2 well will begin steady production.

The following table sets forth, by well, our net daily oil and gas production and volume weighted average sales prices and production costs associated with our Polish production during 2011, 2010, and 2009:

			Average
	Production		Production Cost	Average Sales Price
	Gas	Oil	per Mcfe(1)	Gas	Oil
	(Mcf)	(Bbls)		(Per Mcf)	(Per Bbl)
2011
Roszkow	2,279,000	-	$0.20	$6.68	$ -
Zaniemysl	799,000	-	0.22	5.11	-
Sroda/Kromolice-1	759,000	-	0.13	6.33	-
Kromolice-2(2)	138,000	-	0.94	6.25	-
Other wells(3)	85,000	-	1.52	1.61	-
Total	4,060,000	-	0.24	6.19	-

2010
Roszkow	2,443,000	-	$0.20	$5.93	$ -
Zaniemysl	848,000	-	0.21	4.54	-
Other wells(3)	182,000	-	2.27	2.38	-
Total	3,473,000	-	0.29	5.39	-

2009
Roszkow	753,000	-	$0.07	$6.08	$ -
Zaniemysl	867,000	-	0.18	4.33	-
Other wells(3)	262,000	530	2.77	4.20	54.96
Total	1,882,000	530	0.50	5.01	54.96

_______________

(1)

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.

(2)	Kromolice-2 production costs include the cost of a workover performed in early 2011.

(3)	Production costs at other wells include the costs of maintaining the production facilities at our Wilga and Kleka wells, neither of which is currently in production.

Poland has a network of gas pipelines and crude oil pipelines traversing the country serving major metropolitan, commercial, industrial, and gas production areas, including significant portions of our acreage. Poland has a well-developed infrastructure of hard-surfaced roads and railways over which oil produced can be transported for sale. There are refineries in Gdansk and Plock in Poland and one in Germany near the western Polish border that we believe could process crude oil produced in Poland. Should we choose to export any gas or oil we produce, we will be required to obtain prior governmental approval.

We are currently selling substantially all of our oil and gas production in Poland to PGNiG or one of its affiliates. We are dependent on PGNiG for the sale of gas in Poland, since there are few other competitive purchasers. Gas is sold pursuant to long-term sales contracts, typically for the life of each well, which obligate PGNiG to purchase all gas produced.

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, and average working and net revenue interests, based on the number of producing wells, for our United States producing properties during 2011 follows:

	Average Daily			Average
	Production (Bbls)		Average	Net Revenue
	Gross	Net	Interest	Interest
Montana	191	146	99%	85%
Nevada	39	9	39%	30%
Total United States producing properties	230	155

In Montana, we operate the Southwest Cut Bank Sand Unit (SWCBSU) and Bears Den fields and have an interest in the Rattlers Butte field, which is operated by an industry partner. Production in the SWCBSU, producing since the 1940s from an average depth of approximately 2,900 feet, is from a waterflood program with 103 producing oil wells, 24 active injection wells, and one active water supply well. The Bears Den field, under waterflood since 1990, is producing oil from five wells at a depth of approximately 2,430 feet, with one active water injection well. In the Rattlers Butte field, we own a 0.683% 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 prices, and production costs associated with our United States oil production during 2011, 2010, and 2009:

	Year Ended December 31,
	2011	2010	2009
United States producing property data:
Average daily net oil production (Bbls)	155	168	175
Average sales price per Bbl	$83.02	$68.09	$51.92
Average production costs per Bbl(1)	$50.41	$39.84	$39.62

_______________

(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. Costs in 2011 include approximately $321,000 associated with the cleanup of a minor oil leak. Excluding the cleanup costs, lifting costs per barrel in 2011 would have equaled approximately $44.73 per barrel.

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 95% of our total oil sales, to Cenex, a regional refiner and marketer. Posted prices are generally competitive among crude oil purchasers. Our crude oil sales contracts may be terminated by either party upon 30 days’ notice.

Oilfield Services – Drilling Rig and Well-Servicing Equipment

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

The Republic of Poland

The Republic of Poland is located in north-central Europe, has a population of approximately 38 million people, and covers an area comparable to New Mexico. During 1989, Poland peacefully asserted its independence and became a parliamentary democracy. Since 1989, Poland has enacted comprehensive economic reform programs and stabilization measures that have enabled it to form a free-market economy and turn its economic ties from the east to the west, with most of its current international trade with the countries of the European Union and the United States. The economy has undergone extensive restructuring in the post-communist era. The Polish government credits foreign investment as a forceful growth factor in successfully creating a stable, free-market economy.

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

Poland has created an attractive legal framework and fiscal regime for oil and gas exploration by actively encouraging investment by foreign companies. In July 1995, Poland’s Council of Ministers approved a program to restructure and privatize the Polish petroleum sector. So far under this plan, a refinery located in Plock has been privatized as a publicly held company with its stock trading on the London and Warsaw stock exchanges. In September of 2005, PGNiG 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.

Legal Framework

General Usufruct and Concession Terms

All of our rights in Poland have been awarded to us or to PGNiG 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. We can request changes to usufruct and concession agreements that either modify the obligations or extend the terms of those agreements.

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

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

If commercially viable gas or oil is discovered, the concession owner may be able to produce such gas or oil for test purposes for a period of two years based on the exploration concession. During such two-year period, the concession owner typically applies for an exploitation concession, which generally will have a term of 25 to 30 years or as long as commercial production continues. Upon the grant of the exploitation concession, the concession owner may become obligated to pay a fee, to be negotiated, but expected to be less than 1% of the market value of the estimated recoverable reserves in place. The concession owner would also be required to pay a royalty on any production, the amount of which will be set by the Council of Ministers, within a range established by legislation for the mineral being extracted. The royalty rate for low-methane gas such as we produce is currently set for 2012 at approximately $0.04 per Mcf. Local governments will receive 60% of any royalties paid on production. The holder of the exploitation concession must also acquire rights to use the land from the surface owner and could be subject to significant delays in obtaining the consents of local authorities or satisfying other governmental requirements prior to obtaining an exploitation concession.

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

Existing Project Areas

Fences Project Area

The Fences project area consists of four oil and gas exploration concessions controlled by PGNiG. Three producing fields (Radlin, Kleka, and Kaleje) lie within the concession boundaries, but are excluded from the Fences area in which we participate. The Fences concessions have expiration dates ranging from August 2012 to July 2015. The total joint remaining work commitment, which must be satisfied by us and PGNiG according to our respective interests, includes: acquiring 50 kilometers of 2-D seismic data, acquiring 180 square kilometers of 3-D seismic data, and drilling two wells.

Wilga/Block 255 Project Area

The Wilga project area consists of a single oil and gas exploration concession held by us that expires in August 2012. The remaining period carries a work commitment of 65 kilometers of 2-D seismic data and optional drilling of up to three wells. We currently plan to shoot the required seismic data and apply for an extension before the expiration date of the concession.

Warsaw South Project Area

This project area is adjacent to Block 255 and consists of four exploration concessions with expiration dates ranging from September 2012 to July 2013. We currently plan to meet all concession requirements and apply for extensions as needed before the various expiration dates or relinquish certain parts of this Project area. The total work commitment for the four concessions is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 450 kilometers of new 2-D seismic data, 325 kilometers of which have already been completed; Phase III – three years: drilling four wells one of which has been completed.

Block 287 Project Area

The Block 287 project area consists of a single oil and gas exploration concession held by us. The concession expires in December 2012. Work commitment includes reentering and producing the Grabowka gas field; recompletion of one out of three wells was completed and production began in 2009. As of the date of this report, we were in the process of preparing to recomplete a second well and have plans to recomplete the third well before year-end 2012.

Northwest Project Area

The Northwest project area consists of four oil and gas exploration concessions granted at various times in 2006, 2007, and 2008, with expiration dates ranging from October 2012 through September 2014. The total work commitment for the four concessions is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – three years: acquiring 620 kilometers of new 2-D seismic data; Phase III – two years: drilling four wells. Presently, 400 kilometers of new 2-D seismic data have been completed and part of the drilling commitment was satisfied during 2009 by drilling the Ostrowiec well. Prior to October 2012, we will either satisfy the remaining commitments or relinquish certain parts of this concession.

Kutno Project Area

The Kutno project area consists of three oil and gas exploration concessions. The first concession was granted in 2007 for a period of six years, and two new concessions were added in 2008 for a period of three years. The obligatory work commitment for the initial concession has been satisfied based on the work program in two phases: Phase I – two years: reprocessing and reinterpretation of existing data; Phase II – four and a half years: drilling one well, which is currently underway. The work commitments for the 2008 concessions are outlined in two phases: Phase 1 – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 200 kilometers of 2-D seismic data. We relinquished one of the 2008 concessions during 2011 and have an extension application pending for the second concession. We are evaluating the remaining 2008 concession, as it may be peripheral to the gas play in the main Kutno block.

Edge Project Area

The Edge project area consists of four oil and gas exploration concessions granted for the period of five years (2008-2013). The obligatory work commitment is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 350 kilometers of 2-D seismic data; Phase III – two years: drilling four wells. Currently, 300 kilometers of new 2-D seismic data and 50 square kilometers of 3-D have been completed. We hope to begin drilling the first of these four wells later this year.

Block 246 Project Area

The Block 246 project area is adjacent to the Fences project area in the southwest and consists of a single concession granted for six years (2008-2014). The work commitment is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 120 kilometers of 2-D seismic data; Phase III – three years: drilling one well. We currently plan to acquire 125 kilometers of 2-D seismic data later this year.

Block 229 Project Area

The Block 229 project area is adjacent to the Fences project area in the east and consists of two explorations concessions granted for the period of six years (2008-2014). The total work commitment is outlined in three phases: Phase I – one year: reprocessing and reinterpretation of existing data; Phase II – two years: acquiring 300 kilometers of 2-D seismic data; Phase III – three years: drilling two wells.

As of December 31, 2011, all required usufruct/concession payments had been made for each of the above project areas.

Government Regulation

Poland

Our activities in Poland are subject to political, economic, and other uncertainties, including the adoption of new laws, regulations, or administrative policies that may adversely affect us or the terms of our exploration or production rights; political instability and changes in government or public or administrative policies; export and transportation tariffs and local and national taxes; foreign exchange and currency restrictions and fluctuations; repatriation limitations; inflation; environmental regulations; and other matters. These operations in Poland are subject to the Geological and Mining Law dated as of February 4, 1994 (as amended), and the Environment Protection Law dated as of April 27, 2001 (as amended), which are the current primary statutes governing environmental protection. Agreements with the government of Poland respecting our exploration and production areas create certain standards to be met regarding environmental protection. Participants in oil and gas exploration, development, and production activities generally are required to: (1) adhere to good international petroleum industry practices, including practices relating to the protection of the environment; and (2) prepare and submit geological work plans, with specific attention to environmental matters, to the appropriate agency of state geological administration for its approval prior to engaging in field operations such as seismic data acquisition, exploratory drilling, and field-wide development. Poland’s regulatory framework respecting environmental protection is not as fully developed and detailed as that which exists in the United States. We intend to conduct our operations in Poland in accordance with good international petroleum industry practices and, as they continue to develop, Polish requirements.

There appears to be some political and administrative interest in Poland in reviewing and potentially altering the current natural resources regulatory scheme that has been in place for some years. Such interest appears to focus on governmental policies respecting granting hydrocarbon exploration and production rights, determining hydrocarbon sales prices, taxing production, and other matters. New policies, if adopted, may result in a more openly competitive process for obtaining exploration concessions and retaining rights to discovered hydrocarbons, increased production taxes, requiring governmental concessions for transporting and marketing gas, mandating governmental equity participation in hydrocarbon firms, more market-based hydrocarbon pricing, releasing exploration data and similar matters, all or any one of which could increase our costs and reduce our expansion opportunities.

United States

State and Local Regulation of Drilling and Production

Our U.S. exploration and production operations are subject to various types of federal, state, and local regulation. 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

Our operations are subject to stringent federal, state, and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. These laws and regulations require the acquisition of a permit by operators before drilling commences; mandate the use of specific procedures and facilities in handling specific substances and 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 increase the costs of drilling and operating wells.

Numerous governmental agencies, such as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil, and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

Environmental regulatory programs typically regulate the permitting, construction, and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can issue a cease-and-desist order to terminate operations. New programs and changes in existing programs are routinely proposed, considered, and in some cases adopted, which both complicate compliance and potentially make it more expensive. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition, results of operations, and cash flows.

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose 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. In addition, companies that incur liability frequently confront additional claims because 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 Solid Waste Disposal Act, as amended by 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. However, these wastes may be regulated by the EPA or state agencies as nonhazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, wastes generated in connection with our exploration and production activities may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA.

Our operations are also subject to the federal Clean Water Act and analogous state laws. The Clean Water Act regulates discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of spill prevention, control, and countermeasure plans in connection with on-site storage of significant quantities of oil. In June 2011, an oil leak occurred at our Southwest Cut Bank Sand Unit (SWCBSU) in Montana. We spent approximately $321,000 in completing cleanup, mitigation, and restoration pursuant to an approved plan in cooperation with the Blackfeet Tribe and the EPA. Although we believe that we have satisfactorily completed the cleanup according to the specifications provided by the Blackfeet Tribe and the EPA, we cannot assure that the leak will not result in additional costs or sanctions.

The federal Safe Drinking Water Act (SWDA), the Underground Injection Control (UIC) program promulgated under the SWDA, and state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. See discussion of hydraulic fracturing below.

The federal Clean Air Act and comparable state laws regulate air emissions of various pollutants through permitting programs and other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for noncompliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, in certain circumstances and locations, may be subject to permits and restrictions under these statutes for emissions of air pollutants. In addition, the EPA has indicated that in 2012 it may revise its national emissions standards for hazardous air pollutants for crude oil and natural gas production and gas transmission and storage, as well as its new source performance standards for oil and gas production.

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current and proposed exploration and production activities on federal lands, including activities of our joint venture to explore the Alberta Bakken and Three Forks shale formations in Montana, require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act, and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where the taking of, harm, or damage to a species, wetlands, habitat, or natural resources occurs or may occur, governmental entities or at times private parties may act to prevent oil and gas exploration activities or seek damages, and in some cases criminal penalties, for harm to a species, wetlands, habitat, or natural resources resulting from drilling, construction, or releases of oil, wastes, hazardous substances, or other regulated materials.

We are subject to federal and state hazard communications and community right-to-know statutes and regulations. These regulations govern recordkeeping and reporting of the use and release of hazardous substances, including the federal Emergency Planning and Community Right-to-Know Act.

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 cleanup 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.

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.

Federal and Indian Leases

A substantial part of our producing properties in Montana as well as the areas in which our joint venture is exploring the Alberta Bakken and Three Forks shale formations consist of oil and gas leases issued by the Bureau of Land Management or by the Blackfeet Tribe under the supervision of the Bureau of Indian Affairs. 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

In all of our field activities, particularly our oilfield services segment, we are subject to the requirements of the federal Occupational Safety and Health Act, commonly referred to as OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public. 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.

Hydraulic Fracturing

During 2012, we plan to hydraulically fracture three separate intervals encountering approximately 480 meters of relatively tight Rotliegend sandstone in the Plawce well in Poland as well as a lateral extension in one of two wells we drilled in 2011 in Montana. Hydraulic fracturing is a process in the completion or reworking of certain oil and natural gas wells whereby water, sand, and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production.

If our hydraulic fracturing tests warrant, we expect that additional wells in the Plawce area in Poland as well as substantially all of the Montana horizontal wells that we participate in will be completed using hydraulic fracturing techniques. Although detailed plans for the possible fracturing have not been finalized, we expect to use industry-standard, long-established third-party service providers with specialized experience and equipment in hydraulic fracturing. Prior to initiating a lateral to an existing well or drilling a new well that might result in a lateral extension, we will include in the planning and budgetary process all costs associated with the fracture treatment. The costs of a well vary based on the depth to which it will be drilled, its horizontal length, and the completion technique to be used, which will include the added expenditure for the fracture treatment, as well as anticipated environmental and safety considerations.

Because we contract with industry-standard, long-established third-party service providers for all drilling, casing, and cementing services, we depend upon their industry expertise, safety processes, and best practices for conducting those operations. Our joint venture partners, advisers, and third-party service providers have significant, long-term experience with the engineering required to determine where and how a well should be drilled and whether the well should be hydraulically fractured as part of the completion process. Accordingly, we believe that we will be able to determine whether our third-party service providers are using proper drilling and completion techniques. Nevertheless, we will rely on them, in the case of fracturing services, to:

·	instantaneously monitor in real-time the rate and pressure of the fracturing treatment for any abrupt change in rate or pressure;

·	evaluate the environmental impact of additives to the hydraulic fracturing fluid;

·	minimize the use of water during the fracturing process; and

·	dispose of any produced water in a manner that avoids any impact on other resources and is in full compliance with all federal, state, and local governmental regulations.

We and our joint venture partners will rely fully on our third-party service providers to establish and carry out procedures to cope with any negative environmental impact that could occur in the event of a spill or leak in connection with their hydraulic fracturing services. The third-party service providers are typically responsible for costs arising out of any surface spillage, mishandling of fluids, or leakage from their equipment, including chemical additives. We may engage third-party contractors to provide hydraulic fracturing services pursuant to service orders on a job-by-job basis. Some such service orders limit the liability of these contractors. Hydraulic fracturing operations can result in surface spillage or, in rare cases, the underground migration of fracturing fluids. Any such spillage or migration could result in litigation, government fines and penalties, or remediation or restoration obligations. Our current insurance policies provide some coverage for losses arising out of our hydraulic fracturing operations. However, these policies may not cover fines, penalties, or costs and expenses related to government-mandated cleanup activities, and total losses related to a spill or migration could exceed our per occurrence or aggregate policy limits. Any losses due to hydraulic fracturing that are not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash flows.

The specific chemical composition of the fluids used by the third-party service providers in hydraulic fracturing operations is expected to vary by project and by provider; however, we expect that the chemical composition of such fluids will meet industry standards and will be used in a manner that conforms to all relevant federal, state, and local rules and regulations. As discussed below, our future hydraulic fracturing operations in Montana will be subject to new laws enacted during 2011 requiring specific permitting for proposed hydraulic fracturing, including the disclosure of treatment procedures and the chemical and other additives to be used.

In order to prevent the underground migration of fracture fluids, we, and we expect our joint venture partners and third-party service providers to, follow industry-standard practices in respect of casing, cementing, and testing to ensure good physical isolation of the fractured interval from other sections of the well. We will attempt to ensure that well construction processes and procedures conform to all relevant federal, state, and local rules and regulations. We believe that the large thickness of rock formations between the fractured interval and any potable water sources will minimize the risk of underground migration of fracture fluids. In addition, we expect that surface casing will be set below the deepest known depth of all subsurface potable water, which is the depth sufficient to protect fresh water zones as determined by regulatory agencies, and the well casing will be cemented to create a permanent isolating barrier between the casing pipe and surrounding geological formations. We believe these aspects of well design will practicably eliminate a pathway for underground migration of the fracturing fluid to contact any fresh or potable water aquifers during the hydraulic fracturing operations. We expect that third-party fracturing contractor employees will be trained in the safe handling of all fracturing fluids, chemical additives, and materials and will be required to wear appropriate protective clothing and eye and foot wear. Other protective measures may include safety briefings prior to conducting fracturing operations, testing of pumping equipment and surface lines to pressures exceeding expected maximum fracture treating pressures prior to conducting fracturing operations, detailed fracture treating process checklists used by our fracturing contractors, and guidelines for the disposal of excess fracturing fluids.

Applicable laws typically impose responsibility on owners and operators for any costs resulting from underground migration of fracture fluids, and we are not fully insured against this risk. The occurrence of a significant event resulting from the underground migration of fracture fluids or surface spillage, mishandling, or leakage of fracture fluids could have a materially adverse effect on our financial condition and results of operations. To date, there have been no such incidents, and the members of our management team have not encountered such an incident in their long-term experience in this industry.

In 2010, the EPA announced that it would be conducting a study on the environmental effects of hydraulic fracturing. The study is expected to be completed in 2012. Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.

In 2011, Montana enacted regulations that require operators to disclose information about hydraulic fracturing fluid on a well-by-well basis. Each well permit application is required to include the estimated volume of treatment to be used, the principal components or chemicals to be used, the estimated amount or volume of the principal components to be used, the estimated weight or volume of inert substances such as proppants, and the maximum anticipated treating pressure or the well specifications demonstrating that the well is appropriately constructed for the proposed stimulation. The requirement to disclose this information in the drilling permit application does not apply for wildcat or exploratory wells or when the operator is unable to determine that it will need to conduct hydraulic fracturing as part of well completion. For those wells to be fractured, the operator must provide the same information in a notice of intent to fracture that is provided at least 48 hours in advance of the fracturing operation. Additional details of the fracturing treatment must be reported after the treatment is completed.

In Poland, regulatory authorities have announced that if an exploration concession does not specifically cover horizontal drilling and fracturing, the operator must obtain a concession amendment before proceeding with such operations. Such an amendment must be preceded by an environmental impact assessment, the scope of which is largely dependent upon the discretion of the relevant environmental authority, typically at the municipality level, with participation of regional environmental authorities. This process would likely require disclosure of the pressure and volumes of treatment fluids as well as the chemicals and other treatment components used.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “Risk Factors—Risks Related to Our Business—Federal, state, and Polish legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to explore and produce from our properties.”

Title to Properties

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

Nearly all of our United States 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 our activities on such properties. Further, we believe the economic effects of such burdens have been appropriately reflected in our carrying 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.

Oil and Gas Terms

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

“Bbl” means oilfield barrel.

“Bcf” means billion cubic feet of natural gas.

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

“BTU” means British thermal unit.

“Ca1” and “Ca2” refers to specific calcium-rich geological formations, typically a dolomitic reef.

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

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

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

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

“Fracturing” or “Fracking” means injecting fluids or slurry under sufficient pressure and rate to fracture the formation, leaving proppants that keep the fractures open to serve as a pathway for gas or oil to flow to the well bore.

“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 enterprise in which we have an interest.

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

“MBbls” means thousand oilfield barrels.

“Mcf” means thousand cubic feet of natural gas.

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

“MMcf” means million cubic feet of natural gas.

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

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

“MMcfed” means million cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas per day.

“Net” means, when referring to wells or acres, the fractional ownership 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.

“P50 reserves” means proved reserves plus probable reserves.

“Play” means the activities associated with oil and gas exploration, typically in its early stages, in an area generally believed to contain common reservoir, seal, source, or trapping features.

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

“Probable reserves” means those reserves determined by probabilistic methods that are less certain than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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

“PV-10 Value” means the estimated future net revenue to be generated from the production of proved or probable reserves discounted to present value using an annual discount rate of 10%, 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 determined using guidelines established by the SEC, without escalation and without giving effect to non-property-related expenses, such general and administrative costs, debt service, and depreciation, depletion, and amortization.

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

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

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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 Select Market, or its predecessor, Nasdaq National Market:

	Low	High
2012:
First Quarter (through March 9, 2012)	$4.70	$6.71

2011:
Fourth Quarter	3.75	6.38
Third Quarter	4.13	10.10
Second Quarter	6.80	9.24
First Quarter	6.20	11.76

2010:
Fourth Quarter	4.12	6.74
Third Quarter	3.02	4.14
Second Quarter	3.40	4.88
First Quarter	2.85	3.55

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. As of March 9, 2012, we had approximately 9,000 stockholders.

Recent Sales of Unregistered Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for the five years ended December 31, 2011, 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:

	Year Ended December 31,
	2011		2010		2009		2008		2007
		(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	29,807	$	22,914	$	12,772	$	13,494	$	14,903
Oilfield services		5,631		2,099		1,892		4,347		3,093
Total revenues		35,438		25,013		14,664		17,841		17,996
Operating costs and expenses:
Lease operating expenses (1)		3,834		3,473		3,478		3,441		3,538
Exploration costs (2)		16,618		3,038		4,829		15,389		10,624
Impairment of oil and gas properties(3)		72		564		1,864		14,746		2,299
Asset retirement obligation gain		(52)		(264)		(529)		--		--
Oilfield services costs		4,458		1,550		1,412		2,751		1,998
Depreciation, depletion and
amortization		3,397		2,626		1,602		1,720		2,064
Accretion expense		68		92		41		84		78
Stock compensation		1,744		1,379		1,693		2,367		2,604
Bad debt expense		--		--		--		460		--
General and administrative costs (G&A)		8,396		7,973		7,257		7,030		7,061
Total operating costs and expenses		38,535		20,431		21,647		47,988		30,266

Operating income (loss)		(3,097)		4,582		(6,983)		(30,147)		(12,270)

Other income (expense):
Interest expense		(2,167)		(1,936)		(654)		(672)		(385)
Interest and other income		188		829		54		394		818
Foreign exchange (loss) gain		(23,448)		(4,233)		7,053		(24,279)		146
Total other (expense) income		(25,427)		(5,340)		6,453		(24,557)		579

Net loss	$	(28,524)	$	(758)	$	(530)	$	(54,704)	$	(11,691)

– Continued –

	Year Ended December 31,
	2011		2010		2009		2008		2007
		(In thousands, except per share amounts)
Basic and diluted net loss
per common share	$	(0.57)	$	(0.02)	$	(0.01)	$	(1.35)	$	(0.32)

Basic and diluted weighted average
shares outstanding		50,262		43,387		42,529		40,420		36,694

Cash Flow Statement Data:
Net cash provided by (used in) operating
activities	$	(120)	$	7,249	$	(5,829)	$	(14,248)	$	(1,581)
Net cash (used in) provided by
investing activities		(18,486)		(7,814)		(3,999)		(11,772)		(13,152)
Net cash provided by (used in)
financing activities		50,842		16,092		(2,676)		40,121		14,351

Balance Sheet Data:
Working capital(4)	$	49,787	$	18,212	$	3,452	$	13,965	$	15,374
Total assets		110,224		66,604		42,070		54,802		46,369
Notes payable		40,000		35,000		25,000		25,000		--
Total stockholders’ equity		58,627		23,837		10,745		15,154		37,542

_______________

(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)	Working capital represents current assets minus current liabilities.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

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

Overview

As discussed in Item 1, Business above, the majority of our operations are in Poland, and we have devoted most of our technical talent and capital expenditures in the last several years to our operations in that country. The decision to devote most of our available capital to this area drives our operating results and the changes to our balance sheet and liquidity. Our operations in Poland, which are a combination of existing production and substantial exploration, have grown considerably. Oil and gas production, oil and gas revenues, cash flow, earnings, oil and gas reserves, and oil and gas expenditures in this area have grown significantly over the last three years.

Our U.S. operations also have an impact. Our U.S. operations are smaller than those in Poland and do not present the same level of opportunities for expansion; however, our U.S. operations are a relatively stable source of cash flow. This, too, is reflected in our operating results.

Highlights over the past three years include:

·	Oil and gas revenues have increased more than 120% to $29.8 million in 2011, a compound annual growth rate of 30% per year since 2008.

·	Total revenues have likewise increased, with a compound annual growth rate of 26% per year during the same period.

·	Oil and gas production has jumped 164% to 4.4 Bcfe in 2011.

·	Proved reserve volumes have increased 17% to a record 53.4 Bcfe at year-end 2011.

·	The PV-10 Value of our proved oil and gas reserves increased 44% to $170 million at year-end 2011.

·	Our total liquidity and financial flexibility have improved substantially with our higher revenues along with the proceeds from an equity offering concluded in early 2011.

Notwithstanding our positive results, we continue to face challenges operating in a foreign country, economic system, and culture, including:

·	delays associated with the commencement of production from our KSK wells, which prevented higher revenue gains during 2011;

·	the pace at which PGNiG, our operating partner in the Fences concession, wishes to proceed or the extent to which PGNiG wishes to participate as a non-operating partner in other concessions;

·	operating practices that differ from customary practices in the United States, which generally result in higher capital costs in Poland, longer lead times to first production, and lower initial production rates;

·	relatively less success in our exploration efforts outside of our core Fences area; and

·	volatile noncash adjustments for foreign currency fluctuations continuing to affect our net income in an unpredictable fashion.

There are two other factors that affect our results of operations that, though not unique to us, are a bit different from factors United States investors typically see in comparison with most domestic, small-capitalization independent producers:

·	the different pricing model for our Polish gas production; and

·	the functional currency for our largest subsidiary, FX Energy Poland, which is the Polish zloty, not the U.S. dollar.

Commodity Prices

Global oil prices continued to be volatile in 2011. Gas prices in the United States remained at depressed levels, which have persisted since 2009. However, the Polish gas market operates quite differently than the U.S. domestic market. In Poland, substantially all of our gas production is sold to PGNiG and is tied to published tariffs (wholesale prices) set from time to time by the public utility regulator for gas sold to wholesale consumers. During 2009, the Polish regulator reduced the low-methane tariff, which is the basis for all of our gas contracts in Poland, by 5% in response to the global recession; however, the regulator increased the same tariff twice in 2010, the first by 6.8% and the second by 6.4%. In 2011, prices were further increased by 12.5% in August, and PGNiG had a price increase request pending with the regulator in early 2012.

A major component of the tariff calculation is the cost of Russian imported gas, which is priced based predominantly on trailing oil prices. Thus, world oil prices can have a significant impact on Polish gas prices. Other major components of the tariff calculation include the cost of gas provided by PGNiG itself, as well as the necessity for PGNiG to cover its internal cost structure. Natural gas prices in Poland are, and for years have been, below European Union average prices for both households and industry, because the prices have been subsidized by the government. European Union rules require Poland to gradually abandon market subsidies and bring Polish gas prices to free-market levels.

Poland continues to enjoy the strongest economy in the European Union, and was the only country in Europe to record positive GDP growth every year from 2008 through 2011. Economists predict another positive year during 2012. These factors may act as cushions against possible declines in prices. As of year-end 2011, gas prices in Poland remained firm and were significantly higher than those of an equivalent BTU content in the United States. For example, as of the date of this report the price we receive for natural gas at our Roszkow well, which has a methane content of 80%, is approximately double the spot price under natural gas contracts for 100% methane gas traded on the New York Mercantile Exchange, sometimes referred to as the Henry Hub price. The volumes of our gas reserves in Poland from 2008 through 2011 were not impacted by changing prices. However, all of our oil and gas reserves can be price-sensitive, and future material reductions in the prices at which we sell our oil and gas could result in the impairment of reserves.

Functional Currency and Exchange Rates

The functional currency of our Polish subsidiary is the Polish zloty. Accounting standards require the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Because FX Energy Poland’s functional currency is the Polish zloty, translation adjustments result from the process of translating its financial statements into the U.S. dollar reporting currency. Translation adjustments are not included in determining net income, but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities affected by the change is adjusted to reflect the difference between the exchange rate when the asset or liability was first recorded and the exchange rate on the date of the change.

The difference in functional currency also affects the amounts we report for our Polish assets, liabilities, revenues, and expenses from those that would be reported were the U.S. dollar the functional currency for our Polish operations. The differences will depend on changes in period-average and period-end exchange rates. Transaction gains or losses may be significant given the volatility of the exchange rate.

We enter into various agreements in Poland denominated in the Polish zloty. The exchange rate between the U.S. dollar and the Polish zloty is subject to fluctuations that are beyond our control. During 2011, the zloty fluctuated between a low of 2.65 zlotys per U.S. dollar to a high of 3.51 zlotys per U.S. dollar, a fluctuation of 33%. Variations in exchange rates affect the U.S. dollar-denominated amount of revenue we report, compared to what we receive in Polish zlotys. As the U.S. dollar strengthens relative to the zloty, our U.S. dollar-denominated revenue actually received in Polish zlotys declines; conversely, when the U.S. dollar weakens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys increases. Likewise, a weak U.S. dollar leads to lower U.S. dollar-denominated drilling, capital, and exploration costs, while a strong U.S. dollar has the opposite effect for the cost structure of our Polish operations. Should exchange rates in effect during early 2012 continue throughout the year, we expect the exchange rates to have a slightly negative impact on our U.S. dollar-denominated revenues compared to 2011.

In addition, the change in the exchange rate from the end of each reporting period to the next has an impact on foreign exchange gains and losses. At the end of 2010, the exchange rate was 2.96 zlotys per U.S. dollar compared to 3.42 zlotys per U.S. dollar at the end of 2011. This 16% year-end to year-end devaluation of the zloty represents an increase in the amount of Polish currency required to satisfy outstanding U.S. dollar-denominated intercompany and other loans of FX Energy Poland as of December 31, 2011, and creates the foreign exchange loss recorded on our consolidated statements of operations.

More information concerning the impact of foreign currency transactions can be found in the discussion that follows, as well as in note 1 in the notes to the consolidated financial statements included in this report.

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 fully following the segment discussion. The following table summarizes the results of operations by segment for the years ended December 31, 2011, 2010, and 2009 (in thousands):

	Reportable Segments
	Exploration & Production				Oilfield Services
	Poland		U.S.				Non-Segmented		Total
Year ended December 31, 2011:
Revenues	$	25,120	$	4,687	$	5,631	$	--	$	35,438
Net income (loss)(1)		5,250		1,668		189		(35,631)		(28,524)

Year ended December 31, 2010:
Revenues	$	18,730	$	4,184	$	2,099	$	--	$	25,013
Net income (loss)(2)		12,389		1,818		(194)		(14,771)		(758)

Year ended December 31, 2009:
Revenues	$	9,459	$	3,313	$	1,892	$	--	$	14,664
Net income (loss)(3)		1,141		1,033		(117)		(2,587)		(530)

_______________

(1)	Nonsegmented reconciling items for 2011 include $8,396 of G&A costs, $1,744 of noncash stock compensation expense, $23,448 of noncash foreign exchange losses, $1,979 of interest expense (net of other income), and $64 of corporate DD&A.

(2)	Nonsegmented reconciling items for 2010 include $7,973 of G&A costs, $1,379 of noncash stock compensation expense, $4,233 of noncash foreign exchange losses, $1,107 of other expense, and $79 of corporate DD&A.

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

See note 11 in the notes to the consolidated financial statements for additional detail concerning our segment results.

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $25.1 million during 2011, compared to $18.7 million and $9.4 million in 2010 and 2009, respectively. Gas revenues in 2011 increased from 2010 levels by approximately $2.8 million due to higher gas prices, coupled with approximately $3.6 million related to higher annual production. Our 2010 gas revenues increased from 2009 levels by approximately $0.7 million due to higher gas prices, coupled with approximately $8.6 million related to higher annual production.

Company-wide net gas production increased from a daily rate in 2010 of approximately 9.5 MMcfd to a record rate of approximately 11.1 MMcfd in 2011. In early January 2012, gas was flowing in Poland at an average rate of 13.3 MMcfd, net to our interest.

In addition to our increased production, three factors resulted in higher gas revenues during 2011. First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, averaged 10% higher during the full year of 2011 compared to 2010. The increase was a function of a 12.5% increase that became effective for us on August 1, 2011. Second, period-to-period strength in the Polish zloty against the U.S. dollar increased our U.S. dollar-denominated gas prices. The average exchange rate during 2011 was 2.96 zlotys per U.S. dollar. The average exchange rate during 2010 was 3.02 zlotys per U.S. dollar, a change of approximately 2%. Third, with the addition of production from our KSK wells, where we receive approximately 86% of the low-methane tariff, our weighted average price per thousand cubic feet of natural gas increased slightly. We negotiate a separate gas sales agreement for each new field.

The primary driver of our increased production in 2011 was the commencement, in December 2010, of production at our KSK wells. While we experienced significant delays in the commencement of full production from these three wells due to an unresolved pipeline bottleneck, our KSK wells still produced a combined total of 897,000 MMcf net to our interest, resulting in incremental revenues during 2011 of approximately $5.7 million.

We expect production from our KSK wells to generate significant increases in both revenues and net production during 2012. We expect full resolution of the pipeline bottleneck during the second quarter of 2012, following which the following which the KSK wells are expected to be producing at a combined rate of 12.5 MMcfd (6.1 MMcfd net to our 49% interest). We receive 86% of the low-methane tariff, adjusted for energy content, for our KSK production.

Gas production at our Roszkow well averaged 12.7 MMcfd during 2011, taking into consideration a two week production cessation for annual maintenance. At year-end, the well was producing at a rate of 13.0 MMcfd. Gas at Roszkow is being sold to PGNiG at a contracted rate equal to 95% of the published low-methane tariff.

Gas production at our Zaniemysl well averaged 8.9 MMcfd during 2011, taking into consideration a two week production cessation for annual maintenance. At year-end, the well was producing at a rate of 9.3 MMcfd. Gas at Zaniemysl is being sold to PGNiG at a contracted rate equal to 70% of the published low-methane tariff.

We expect production facilities to be complete, and gas to start flowing, at our Winna Gora well early in the third quarter of 2012. Production from that well is expected to begin at a rate of approximately 3.9 MMcfd (1.9 MMcfd net to our 49% interest).

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, 2011, 2010, and 2009, is set forth in the following table:

	Year Ended December 31,
	2011	2010	2009
Revenues	$25,120,000	$18,730,000	$9,430,000
Percent change versus prior year	+34%	+99%	+27%
Average price (per Mcf)	$6.19	$5.39	$5.01
Percent change versus prior year	+15%	+8%	-15%
Production volumes (Mcf)	4,060,000	3,473,000	1,882,000
Percent change versus prior year	+17%	+85%	+50%
Lifting costs per Mcf (1)	$0.23	$0.29	$0.48
Percent change versus prior year	-21%	-40%	-26%

_______________

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

Oil Revenues. Oil revenues were $4.7 million, $4.2 million, and $3.3 million for the years ended December 31, 2011, 2010, and 2009, respectively. Higher average oil prices in 2011 compared to 2010 was the cause for the increase in revenues. Our average oil price during 2011 was $83.02 per barrel, a 22% increase compared to $68.09 per barrel received during 2010. Production from our U.S. properties declined by 8% due to normal production declines.

Included in oil revenues were approximately $29,000 related to the sale of oil at our Wilga well in Poland for the year ended December 31, 2009. All other oil revenues during the three years were derived from our producing properties in the United States. U.S. oil revenues in 2011 increased from 2010 levels by approximately $0.8 million due to higher oil prices, offset by approximately $0.3 million related to production declines. U.S. oil revenues in 2010 increased from 2009 levels by approximately $1.0 million due to higher oil prices, offset by approximately $0.1 million 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, 2011, 2010, and 2009, is set forth in the following table:

	Year Ended December 31,
	2011	2010	2009
Revenues	$4,688,000	$4,184,000	$3,342,000
Percent change versus prior year	+12%	+25%	-45%
Average price (per Bbl)	$83.02	$68.09	$52.03
Percent change versus prior year	+22%	+31%	-41%
Production volumes (Bbl)	56,462	61,463	64,226
Percent change versus prior year	-8%	-4%	-7%
Lifting costs per Bbl (1)	$50.41	$39.84	$40.08
Percent change versus prior year	+27%	-1%	+5%

_______________

(1)

Lifting costs per barrel are computed by dividing the related lease operating expenses by the total barrels of oil produced. Light crude oil lifting costs in Poland are based on an allocation of total costs based on relative revenues between oil and gas. Lifting costs include production taxes incurred in the United States. Costs in 2011 include approximately $0.3 million associated with the cleanup of a minor oil leak. Excluding the cleanup costs, lifting costs per barrel in 2011 would have equaled approximately $44.73 per barrel.

Lease Operating Costs. Lease operating costs were $3.8 million in 2011, $3.5 million in 2010, and $3.5 million in 2009. Operating costs in the United States increased in 2011 by approximately $0.4 million over 2010 costs, due to $0.3 million spent to remediate a small oil leak in Montana along with higher workover costs on our existing producing wells. Operating costs in Poland decreased slightly in 2011 from 2010 levels. Most operating costs in Poland arise from fixed costs at our production facilities; variations in production do not usually result in cost variations. The decrease in 2011 resulted from a reduction in costs associated with our Wilga and Kleka wells, neither of which produced in 2011.

Exploration Costs. Exploration expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes. Exploration costs were $16.6 million, $3.0 million, and $4.8 million for the years ended December 31, 2011, 2010, and 2009, respectively. The increase in 2011 was a function of increased funds available for exploration activities following our equity offering in March.

Geological and geophysical costs, or G&G costs, were $15.3 million, $2.0 million, and $4.7 million for the years ended December 31, 2011, 2010, and 2009, respectively. During all three years, most of our G&G costs were spent on acquiring, processing, and interpreting new 3-D and 2-D seismic data in the Fences area and in our other concession areas in Poland.

Exploratory dry-hole costs were $1.3 million, $1.0 million, and $0.2 million for the years ended December 31, 2011, 2010, and 2009, respectively. Our 2011 dry-hole costs were associated with our Machnatka well. Under the terms of a joint operating agreement, our partner agreed to pay 100% of the costs of the well to a depth of 3,558 meters. After reaching that depth, the partners agreed to continue drilling to a depth of approximately 4,500 meters. Our share of the dry-hole costs is equal to 51% of the incremental drilling costs incurred drilling the additional 952 meters. During 2010, recompletion attempts failed to establish commercial production at our Zakowo project in Poland. During 2009, we drilled one dry hole in Nevada.

Impairment Costs. Impairments of oil and gas properties were $72,000, $0.6 million, and $1.9 million for the years ended December 31, 2011, 2010, and 2009, respectively. During 2011, we dropped a small amount of non-prospective acreage near our Kutno project and impaired the associated undeveloped leasehold costs. As discussed previously, production at our Kleka and Wilga wells ceased during 2010 and 2009, respectively, and we impaired their remaining capital costs.

Asset Retirement Obligation. We recorded gains associated with future asset retirement obligations of $52,000, $0.3 million, and $0.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. When the present value of a future asset retirement obligation changes due to the increase or decrease of the estimated plugging costs of that asset, we adjust the related asset retirement cost. During all three years, the economic lives of our United States oil wells were increased, as higher oil prices resulted in more economic barrels. This change resulted in a decrease in the net present value of the retirement obligations, which in turn resulted in gains associated with those obligations, as the related asset retirement costs had been previously written off due to property impairments.

DD&A Expense - Producing Operations. DD&A expense for producing properties was $2.3 million, $1.8 million, and $0.9 million for the years ended December 31, 2011, 2010, and 2009, respectively. The 28% increase from 2010 to 2011 was primarily a function of our increased production in Poland. The 100% increase from 2009 to 2010 is primarily related to a downward reserve revision at our Roszkow well, which is discussed below.

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 and changes in reserve volumes.

Accretion Expense. Accretion expense was $68,000, $92,000, and $41,000 for the years ended December 31, 2011, 2010 and 2009, respectively. Accretion expense is related entirely to our asset retirement obligation associated with expected future plugging and abandonment costs.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $5.6 million, $2.1 million, and $1.9 million for the years ended December 31, 2011, 2010, and 2009, respectively. We drilled eight wells for third parties, including those drilled for our Alberta Bakken joint venture, during 2011, along with additional well service work. We drilled 25 wells for third parties during 2010; however, most of these were shallow wells, which can be drilled in only two to three days and generate less revenue per well than deeper wells. We also drilled 25 similar wells for third parties during 2009, along with additional well service work. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors. We cannot accurately predict future oilfield services revenues.

Oilfield Services Costs. Oilfield services costs were $4.5 million, $1.6 million, and $1.4 million for the years ended December 31, 2011, 2010, and 2009, respectively, or 79%, 74%, and 75% of oilfield-servicing revenues, respectively. The increases from 2009 to 2010 and again from 2010 to 2011 were primarily due to the nature of our drilling activity discussed above. In general, oilfield-servicing costs are closely associated with oilfield services revenues. As such, oilfield services costs will continue to fluctuate period to period based on the number of wells drilled, revenues generated, weather, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.

DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $1.0 million, $0.7 million, and $0.6 million for the years ended December 31, 2011, 2010, and 2009, respectively. We spent $1.2 million, $1.1 million, and $0.9 million on upgrading our oilfield-servicing equipment during 2011, 2010, and 2009, respectively. These capital additions resulted in higher DD&A expenses for this segment during 2011 and 2010.

Nonsegmented Items

G&A Costs - Corporate. G&A costs were $8.4 million, $8.0 million, and $7.3 million for the years ended December 31, 2011, 2010, and 2009, respectively. Our 2011 G&A costs rose from 2010 levels primarily due to higher legal and investor relations-related costs. Our 2010 G&A costs rose from 2009 levels primarily due to higher compensation and consulting costs.

Stock Compensation. Stock compensation expense recorded for 2011 represents $1.7 million of amortization related to restricted stock and stock options granted to employees in 2011, 2010, 2009, and 2008. Stock compensation expense recorded for 2010 represents $1.4 million of amortization related to restricted stock granted in 2010, 2009, 2008, and 2007. Stock compensation expense recorded for 2009 represents $1.7 million of amortization related to restricted stock granted in 2009, 2008, 2007, and 2006.

Interest and Other (Income) Expense - Corporate. Interest and other (income) expense was $2.0 million, $1.1 million, and $0.6 million for the years ended December 31, 2011, 2010, and 2009, respectively. During 2011, we incurred $2.2 million in interest expense, which included $0.6 million of amortization of loan fees and $0.9 million in unused commitment fees. Interest and other income was $0.2 million during 2011. Included in the 2011 amount was interest income of approximately $238,000, offset by a charge of approximately $50,000 associated with the impairment of some obsolete inventory in the United States.

During 2010, we incurred $1.9 million in interest expense, which included $0.6 million of previously unamortized loan fees associated with our prior credit facility, $0.4 million of amortization of loan fees and $0.2 million in unused commitment fees. Interest and other income was $829,000 during 2010. Included in the 2010 amount was a gain of approximately $0.8 million attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008. During 2009, we amortized $0.2 million related to fees incurred in securing our 2008 senior credit facility which was charged to interest expense. We also paid $0.4 million in interest on outstanding borrowings. These interest-related costs were offset by interest income of $0.1 million.

Foreign Exchange. We incurred foreign exchange losses of $23.4 million, $4.2 million, and gains of $7.1 million for the years ended December 31, 2011, 2010, and 2009, respectively. Included in 2009 were $1.2 million related to mark-to-market and settlement adjustments to Polish zloty forward contracts. There were no such contracts in 2011 and 2010.

Income Taxes. We incurred net losses of $28.5 million, $0.8 million, and $0.5 million for the years ended December 31, 2011, 2010, and 2009, respectively. Accounting standards require that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our consolidated statement of operations for these years.

Proved Reserves

Oil and Gas Reserves

Reserve volumes increased year-end 2011 due primarily to the addition of the Lisewo-1 well, which was completed early in the year. Positive reserve revisions, due to higher oil prices in the United States and to more favorable technical data in Poland, partially offset our record 2011 gas production. Higher average oil and gas prices used to calculate year-end reserve values increased our estimated PV-10 values.

The following table highlights year-end reserve volumes and values and shows the change from 2010 to 2011:

	2011	2010	Change
	(In thousands)
Proved Reserve Volumes:
Gas Reserves (Mcf)	49,636	39,959	+24%
Oil Reserves (Bbls)	639	639	--
Total Reserves (Mcfe)	53,470	43,793	+22%

Proved Reserve Values:
Reserves PV-10 Value	$169,567	$127,337	+33%

Changes in proved reserves were as follows:

	2011	2010	2009
(MMcfe)
Proved Reserves Beginning of Year	43,793	50,446	45,864
Extensions, Discoveries, and Other Additions	12,245	--	6,333
Revisions of Previous Estimates	1,828	(2,814)	515
Production	(4,396)	(3,839)	(2,266)
Proved Reserves End of Year	53,470	43,793	50,446

Extensions, Discoveries, and Other Additions. All of the 2011 additions to proved reserves that result from the discovery of new fields are associated with our Lisewo well, which was completed for production during early 2011.

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Apart from a reduction due to annual production, we recorded upward reserve revisions at our Roszkow and Winna Gora wells, which were offset by small downward revisions at our Zaniemysl and KSK wells. At Roszkow, new pressure data indicates that the initial gas-in-place may be more than estimated at year-end 2010. We also recorded upward revisions of approximately 56,000 barrels of oil in the United States, primarily due to higher oil prices resulting in more economically recoverable barrels. Revisions at year-end 2010 included downward revisions in Poland due to interpretations of reservoir pressure data at our Roszkow well, while upward revisions occurred in the United States due to higher oil prices. Revisions at year-end 2009 included upward oil revisions due to higher crude oil prices, offset by downward gas revisions due to the cessation of production at our Wilga well. We have historically added reserves through our exploration and development activities (see Items 1 and 2, Business and Properties).

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

2012 Operational Trends

We currently expect that our 2012 production will rise significantly from our 2011 production rates with the achievement of full production at our three KSK wells and the commencement of production at our Winna Gora well. We expect full resolution of the pipeline bottleneck during the second quarter of 2012, at which time the KSKwells are expected to be producing at a rate of 12.5 MMcfd (6.1 MMcfd net to our 49% interest). We will receive 86% of the published low-methane tariff, adjusted for energy content, for our KSK production.

We expect production facilities to be complete, and gas to start flowing, at our Winna Gora well in the third quarter of 2012. Production from that well is expected to begin at a rate of approximately 3.9 MMcfd (1.9 MMcfd net to our 49% interest). As of early 2012, we had not yet concluded a gas sales agreement for our Winna Gora well, but we expect the price we receive to be approximately equal to that of our KSK wells. The amount of revenue from this increased production will depend on applicable gas sales prices and prevailing currency exchange rates.

Future oil revenues from our domestic production will depend on the impact of prices we receive as we continue to experience normal production declines. We cannot accurately predict future oilfield services revenues and related costs, which will continue to fluctuate based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the nature and extent of any equipment upgrading, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.

Costs that vary in concert with production, such as lease operating expenses and DD&A costs, will trend up or down with production increases or decreases. Our 2012 plans for capital expenditures are detailed in the following section, “Liquidity and Capital Resources – Our Capital Resources and Future Expenditures.”

Our U.S. dollar-denominated financial results will continue to be impacted by exchange-rate fluctuations, which cannot be predicted.

Liquidity and Capital Resources

For much of our history, we have financed our operations principally through the sale of equity securities, bank borrowings, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. However, as our oil and gas production has increased in Poland in the last several years and as higher oil prices have improved the profitability of our U.S. production, our internally generated cash flow has become a significant source of operations financing.

2011 Liquidity and Capital

Working Capital (current assets less current liabilities). Our working capital was $49.8 million as of December 31, 2011, an increase of $31.6 million from December 31, 2010. Our current assets at year-end 2011 included approximately $50.9 million in cash and cash equivalents, $3.4 million in accrued oil and gas sales from both the United States and Poland, and $4.8 million in receivables from our joint interest partners in both the United States and Poland that were collected in early 2012. In Poland, approximately $3.8 million was due at year end from PGNiG primarily related to the drilling of our Kutno well, where we act at the operator. Our joint interest receivables in the United States are primarily related to our Alberta Bakken project. Our current liabilities at year-end included approximately $7.2 million payable by FX Poland for Kutno drilling and other costs associated with our operations in Poland that were paid in early 2012.

Operating Activities. Net cash used in operations during 2011 was $0.1 million. Net cash provided by operating activities during 2010 was $7.2 million. We used net cash of $5.8 million in our operating activities during 2009. A $13.6 million increase in exploration costs in 2011 offset higher revenues, leading to a decline in cash provided from operating activities in 2011.

Investing Activities. We used net cash in investing activities of $18.5 million, $7.8 million, and $4.0 million in 2011, 2010, and 2009, respectively. In 2011, we spent $17.3 million for oil and gas property additions, $14.8 million of which were related to our Polish drilling activities, with the remainder being spent on our domestic properties. We spent $1.2 million adding to our oilfield services equipment. We also benefited from approximately $12.0 million spent in the Warsaw South project area by PGNiG for seismic and drilling costs in 2011 in order to earn a 49% interest in the concession. In 2010, we spent $6.5 million for oil and gas property additions, $6.0 million of which were related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $1.3 million adding to our oilfield services equipment.

In 2009, we received $4.7 million from the maturities of marketable securities and invested $11,000 in marketable securities. We spent $7.7 million for oil and gas property additions, $7.2 million of which were related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $83,000 upgrading our office equipment and $0.9 million adding to our oilfield services equipment.

Financing Activities. Our cash flow from financing activities was $50.8 and $16.1 million, during 2011 and 2010, respectively. We used net cash in financing activities of $2.7 million during 2009. During 2011, we issued 6.9 million shares of common stock in a registered public offering, which resulted in net proceeds to us, after offering costs, of approximately $45.0 million. We used $35.0 million of those proceeds to repay amounts outstanding under our credit facility at the time of the offering. We borrowed $40 million under our credit facility in the fourth quarter of 2011. We also received proceeds of $800,000 from the exercise of stock options.

During 2010, we borrowed $35 million under our expanded credit facility, using $25 million to repay our 2008 credit facility and $2.5 million in fees associated with the expanded credit facility. In addition, we sold 1.5 million shares of stock in a registered direct offering, resulting in net proceeds to us of $8.4 million. Option holders exercised options to purchase 152,892 shares of common stock, resulting in proceeds to us of an additional $0.2 million.

During 2009, we paid $2.8 million towards a loan related to auction-rate securities. In addition, options and warrants to purchase 55,000 shares of common stock were exercised during the year, resulting in proceeds to us of $132,000.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2012 include our working capital of $49.7 million at year-end 2011, available credit of $15 million under our expanded credit facility when we meet the benchmarks discussed below, and cash available from our operations.

In August 2010, we refinanced our existing credit facility by executing an expanded credit facility with The Royal Bank of Scotland Plc, ING Bank N.V., and KBC Bank NV. The expanded credit facility calls for a periodic interest rate of LIBOR plus 4.0% and has a term of five years, with semiannual borrowing base reductions of $11 million each beginning on June 30, 2013. The expanded credit facility is an interest-only facility until June 2013. We have access to $40 million under the expanded credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been on simultaneous production for 30 days, at which time the full $55 million becomes available.

In late 2011, we drew $40 million under this facility. Although all three banks that participate in our credit facility successfully passed the required European bank stress tests, in view of the unsettled circumstances surrounding the secondary credit crisis in Europe, signs of deteriorating sovereign debt conditions in Europe, and the uncertain success of efforts to resolve the Euro crisis, we felt it prudent to access these funds to ensure their availability to finance our future capital programs. Our access to the remaining $15 million under our credit facility, when it becomes available, may be adversely affected by the capital stability of our lenders and European credit and economic conditions generally.

Production remains stable at our Roszkow, Zaniemysl, and Kromolice-1 wells in Poland. As discussed earlier, production resumed at our Sroda-4 well in early 2012, and we expect production to commence from our Kromolice-2 well during the second quarter of 2012. Further, production should begin in the third quarter at our Winna Gora well. Along with our oil production in the United States, we expect to see another increase in oil and gas revenues in 2012.

We have an effective universal shelf registration statement under the Securities Act under which we may sell up to $200 million of equity or debt securities of various kinds. In December 2010, we entered into an agreement to possibly sell up to $50 million in common stock during the next two years in at-the-market transactions. Through the date of this filing, we have not sold any stock under that agreement. In March 2011, we sold 6.9 million shares of stock for $48.3 million, which resulted in net proceeds to us of approximately $45.0 million. Assuming all $50 million of common stock covered by the at-the-market facility were sold, the remaining $92.7 million balance of securities available for sale under the registration statement is available for sale at any time, subject to market conditions and our ability to access the capital markets, to further finance our exploration and development plans in Poland and for other corporate purposes.

At year-end 2011, we were in the process of drilling the Kutno-2 well, having incurred a total cost of $4.4 million during the year. Our total costs for this well once drilling is completed are expected to be in the $10 million range. We have agreed with PGNiG to conduct a fracture stimulation test at the Plawce-2 well early in the second quarter of 2012. We were also in the process of building production facilities at our Winna Gora well. We had no other firm commitments for future capital and exploration costs at 2011 year end.

We expect our primary use of cash for 2012 will be for our exploration and development activities in Poland and the United States. We expect the cost of these activities to range from $60 million to $70 million for 2-D and 3-D seismic data acquisition and analysis, production facilities for existing discoveries, and additional exploration and development drilling. The actual amount of our expenditures will depend on ongoing exploration results; the pace at which PGNiG, our operating partner in the Fences project area, wishes to proceed or the extent it wishes to continue to participate with us in concessions we operate; the availability of drilling and other exploration resources; and the amount of capital we obtain from the various sources discussed above. Our various sources of liquidity and capital outlined above should more than enable us to meet our capital needs in Poland and the United States for the next 12 months. We have the ability to control the timing and amount of most of our future capital and exploration costs.

We may continue to incur operating losses in future periods, and we continue to fund substantial exploration and development in Poland. We have a history of operating losses. From our inception in January 1989 through December 31, 2011, we have incurred cumulative net losses of approximately $190 million. Despite our recent and expected future increases in production and revenues, our exploration and production activities may continue to result in net losses in future years, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses.

We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements such as those recently negotiated for our Kutno and Warsaw South project areas in which industry participants are bearing the initial exploration costs to earn an interest in the project 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.

Contractual Obligations and Contingent Liabilities and Commitments

Contractual Obligations. At December 31, 2011, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:

	Total		2012		2013		2014		2015		2016
		(In thousands)
Credit facility	$	40,000	$	--	$	7,000	$	22,000	$	11,000	$	--
Interest payments on long-term debt		4,420		1,700		1,551		935		234		--
Total	$	44,420	$	1,700	$	8,551	$	22,935	$	11,234	$	--

Under the terms of our $55 million credit facility, the amount of credit available is reduced by $11 million each six months, beginning on June 30, 2013. As of December 31, 2011, we had borrowed $40 million under the facility, and the reduction of that amount is illustrated in the table above.

During the ordinary course of business in Poland, we enter into agreements for the drilling of wells, the construction of production facilities, and for seismic projects. These are typically short-term agreements and are completed in less than one year. We are subject to certain work commitments respecting our 100%-owned exploration concessions that must be satisfied in order to maintain our interest in those concessions. These work commitments are optional on our part; however, they must be satisfied in order to maintain our interest in those concessions. We can request changes to usufruct and concession agreements that either modify the obligations to reduce our commitments or extend the terms of those agreements. In addition, we routinely relinquish acreage that we believe has lower potential rather than continue to be subject to the related work commitment. Our exploration budget and related activities are focused on exploration and long-term exploitation of our most promising exploration opportunities and are not specifically or primarily focused on meeting these work commitments.

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

Asset Retirement Obligation. We have liabilities of $1.2 million related to asset retirement obligations on our Consolidated Balance Sheet at December 31, 2011, excluded from the table above. Due to the nature of these obligations, we cannot determine precisely when the payments will be made to settle these obligations.

New Accounting Pronouncements

Recent Securities and Exchange Commission Rule-Making Activity

In June 2011, the Financial Accounting Standards Board (“FASB”) issued amended standards that eliminated the option to report other comprehensive income in the statement of stockholders’ equity and require companies to present the components of net income and other comprehensive income as either one continuous statement of comprehensive income or two separate but consecutive statements. The amended standards do not affect the reported amounts of comprehensive income. In December 31, 2011, the FASB deferred the requirement to present components of reclassifications of other comprehensive income on the face of the income statement that had previously been included in the June 2011 amended standard. These amended standards are to be applied retrospectively for interim and annual periods beginning after December 15, 2011. We adopted these standards on January 1, 2012.

In May 2011, the FASB issued amended standards to achieve common fair value measurements and disclosures between GAAP and International Financial Reporting Standards. The standards include amendments that clarify the intent behind the application of existing fair value measurements and disclosures and other amendments that change principles or requirements for fair value measurements or disclosures. The amended standards are to be applied prospectively for interim and annual periods beginning after December 15, 2011. We adopted these standards on January 1, 2012.

In January 2010, the FASB issued new standards intended to improve disclosures about fair value measurements. The new standards require details of transfers in and out of Level 1 and Level 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. We adopted these new rules effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward, which we adopted December 31, 2010.

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

Critical Accounting Policies

Oil and Gas Activities

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

Oil and Gas Reserves

All of the reserves data in this Form 10-K are estimates. Estimates of our crude oil and natural gas reserves are prepared by our engineers in accordance with guidelines established by the Securities and Exchange Commission, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements, which we adopted effective December 31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserves estimate. We based our December 31, 2011, reserves estimates on a 12-month average commodity price, unless contractual arrangements designated the price to be used, in accordance with Securities and Exchange Commission rules. However, oil and gas prices are volatile and, as a result, our reserves estimates will change in the future.

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

Stock-based Compensation

Share-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period.

ITEM 7A. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

Price Risk

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

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

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

Foreign Currency Risk

We enter into various agreements in Poland denominated in the Polish zloty. The exchange rate between the U.S. dollar and the Polish zloty is subject to fluctuations that are beyond our control. During 2011, the zloty fluctuated between a low of 2.65 zlotys per U.S. dollar to a high of 3.51 zlotys per U.S. dollar, a fluctuation of 33%. Variations in exchange rates affect the U.S. dollar-denominated amount of revenue we receive in Polish zlotys. As the U.S. dollar strengthens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys declines; conversely, when the U.S. dollar weakens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys increases. Conversely, a weak U.S. dollar leads to lower U.S. dollar-denominated drilling, capital, and exploration costs, while a strong U.S. dollar has the opposite effect for the cost structure of our Polish operations. Should exchange rates in effect during early 2012 continue throughout the year, we expect the exchange rates to have a slightly negative impact on our U.S. dollar-denominated revenues compared to 2011. We are also generating revenues in Poland in Polish zlotys, and we keep those zlotys in Poland and use them to pay zloty-based invoices.

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

During October 2008, we drew down the remaining $14 million available under our then-existing senior credit facility to ensure that we had the necessary capital on hand to meet existing commitments. At the same time, we purchased approximately $13.9 million in Polish zloty forward contracts. These contracts matured at the end of each month, beginning in October 2008 and concluding in March 2009. During 2009, we recorded losses of $1.4 million related to these contracts. We did not enter into any currency hedging arrangements during 2010 or 2011.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the periods specified by the Securities and Exchange Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2011, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2011, 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 our definitive proxy statement for our 2012 annual meeting of stockholders under the captions “Corporate Governance,” “Proposal 1. Election of Directors,” and “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information from our definitive proxy statement for our 2012 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 our definitive proxy statement for our 2012 annual meeting of stockholders under the captions “Principal Stockholders” and “Equity Compensation Plans” is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

AND DIRECTOR INDEPENDENCE

The information from our definitive proxy statement for our 2012 annual meeting of stockholders under the captions “Certain Relationships and Related-Party Transactions” and “Director Independence” is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information from our definitive proxy statement for our 2012 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

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

	Page
Management’s Report on Internal Control over Financial Reporting	F-1
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2011 and 2010	F-4
Consolidated Statements of Operations for the Years Ended
December 31, 2011, 2010, and 2009	F-6
Consolidated Statements of Comprehensive Loss for the Years Ended
December 31, 2011, 2010, and 2009	F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2011, 2010, and 2009	F-8
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years
Ended December 31, 2011, 2010, and 2009	F-9
Notes to the Consolidated Financial Statements	F-10

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

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

Exhibit Number*	Title of Document	Location

Item 1	Underwriting Agreement
1.01	At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC	See Exhibit 10.99

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.

3.03	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.

3.05	Bylaws of FX Energy, Inc., as amended May 24, 2010	Incorporated by reference from the current report on Form 8-K filed June 8, 2010.

Exhibit Number*	Title of Document	Location

Item 4	Instruments Defining the Rights of Security Holders
4.01	Specimen Stock Certificate	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.

4.04	Rights Agreement dated as of April 4, 2007, between FX Energy, Inc. and Fidelity Transfer Company	Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.

4.05	Amendment to Rights Agreement dated as of March 7, 2011	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2010, filed March 7, 2011.

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.

10.53	Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Gazownictwo S.A. [POGC-PGNiG] 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.

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

10.63	Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG] 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.

10.74	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.

Exhibit Number*	Title of Document	Location

10.75	Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2008, filed March 16, 2009.

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

10.78	Form of Employment Agreement with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.

10.79	Change in Control Compensation Agreement with related schedule**	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.

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

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

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.

10.89	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. [POGC-PGNiG], dated December 8, 2005 [Zaniemysl]	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 [Grabowka]	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.

10.92	Amendment and Reconfirmation of Supplemental Indemnification Agreement between FX Energy, Inc. and Dennis B. Goldstein	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2008, filed March 16, 2009.

10.93	Agreement No. for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG], dated June 19, 2009 [Roszkow]	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2009, filed March 17, 2010.

10.95	USD 55,000,000 Senior Reserve Base Lending Facility Agreement among FX Energy Poland Sp. z o.o., FX Energy, Inc., FX Energy Netherlands Partnership C.V., FX Energy Netherlands B.V., The Royal Bank of Scotland Plc, ING Bank N.V., and KBC Bank NV dated August 5, 2010	Incorporated by reference from the current report on Form 8-K filed August 11, 2010

Exhibit Number*	Title of Document	Location

10.96	Intercreditor Deed among FX Energy Poland Sp. z o.o., The Royal Bank Of Scotland Plc, and the subordinated lenders dated August 5, 2010	Incorporated by reference from the current report on Form 8-K filed August 11, 2010

10.97	Deed of Pledge of Registered Shares among Frontier Exploration Company and FX Drilling Company, Inc., in their capacity of general partners of FX Energy Netherlands Partnership C.V.; The Royal Bank of Scotland Plc; and FX Energy Netherlands B.V., dated August 6, 2010	Incorporated by reference from the current report on Form 8-K filed August 11, 2010

10.99	At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC	Incorporated by reference from the current report on Form 8-K filed December 23, 2010.

10.100	Form of Relinquishment Agreement dated August 9, 2011, with schedule of signatories	Incorporated by reference from the current report on Form 8-K filed August 10, 2011.

10.101	FX Energy, Inc., 2011 Incentive Plan	Incorporated by reference from the definitive Proxy Statement on Schedule 14A filed August 8, 2011.

10.102	Participation Agreement among American Eagle Energy Inc., Big Sky Operating LLC, and FX Producing Company, Inc. [Alberta Bakken]	This filing.

10.103	Cenex Contract Number 3000748 Amendment No. 1 between Cenex Harvest States Cooperatives and FX Drilling Company, Inc.	This filing.

10.104	Agreement no 10/K/Z/2010 for the Sale of Natural Gas concluded between FX Energy Poland Sp. z o.o. and Polish Oil and Gas S.A. [KSK]	This filing.

10.105	Joint Operating Agreement between Polskie Górnictwo Naftowe i Gazownictwo S.A. [PGNiG] and FX Energy Poland Sp. z o.o. [Warsaw South]	This filing.

Item 21	Subsidiaries of the Registrant
21.01	Schedule of Subsidiaries	Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2007, filed March 10, 2008.

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

23.02	Consent of Hohn Engineering PLLC, Petroleum Engineers	This filing.

23.03	Consent of RPS Energy, Petroleum Engineers	This filing.

Exhibit Number*	Title of Document	Location

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

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

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

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

Item 99	Additional Exhibits
99.01	Evaluation of Polish Gas Assets of RPS Energy, Petroleum Engineers	This filing.

99.02	Appraisal of Certain Properties of Hohn Engineering PLLC, Petroleum Engineers	This filing.

Item 101	Interactive Data
101	Interactive Data files	This filing.

___________________

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

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

SIGNATURES

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

	FX ENERGY, INC. (Registrant)



Dated: March 12, 2012	By:	/s/ David N. Pierce
		David N. Pierce
		President and Chief Executive Officer

	/s/ Thomas B. Lovejoy
Dated: March 12, 2012	Thomas B. Lovejoy, Director

	/s/ David N. Pierce
Dated: March 12, 2012	David N. Pierce, Director, President,
	and Principal Executive Officer

	/s/ Dennis B. Goldstein
Dated: March 12, 2012	Dennis B. Goldstein, Director

	/s/ Arnold S. Grundvig, Jr.
Dated: March 12, 2012	Arnold S. Grundvig, Jr., Director

	/s/ Jerzy B. Maciolek
Dated: March 12, 2012	Jerzy B. Maciolek, Director

	/s/ Richard Hardman
Dated: March 12, 2012	Richard Hardman, Director

	/s/ H. Allen Turner
Dated: March 12, 2012	H. Allen Turner, Director

	/s/ Clay Newton
Dated: March 12, 2012	Clay Newton, Principal Financial and
	Accounting Officer

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

As of the end of the Company’s 2011 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, 2011, 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, 2011, 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 income (loss), of cash flows and of stockholders’ equity present fairly, in all material respects, the financial position of FX Energy, Inc. and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

F-2

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

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 12, 2012

F-3

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Balance Sheets

As of December 31, 2011 and 2010

(in thousands)

	2011		2010
ASSETS

Current assets:
Cash and cash equivalents	$	50,859	$	19,740
Receivables:
Accrued oil and gas sales		3,446		2,617
Joint interest and other receivables		4,768		2,013
Value-added tax receivable		389		392
Inventory		196		242
Other current assets		542		293
Total current assets		60,200		25,297

Property and equipment, at cost:
Oil and gas properties (successful-efforts method):
Proved		49,388		38,528
Unproved		3,482		3,320
Other property and equipment		9,968		8,853
Gross property and equipment		62,838		50,701
Less accumulated depreciation, depletion and amortization		(14,942)		(12,327)
Net property and equipment		47,896		38,374

Other assets:
Certificates of deposit		406		406
Loan fees		1,722		2,527
Total other assets		2,128		2,933

Total assets	$	110,224	$	66,604

-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, 2011 and 2010

(in thousands, except share data)

-Continued-

	2011		2010
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	9,736	$	5,742
Accrued liabilities		677		1,343
Total current liabilities		10,413		7,085

Long-term liabilities:
Notes payable		40,000		35,000
Asset retirement obligation		1,184		682
Total long-term liabilities		41,184		35,682

Total liabilities		51,597		42,767

Commitments and Contingencies (Note 6)

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
December 31, 2011 and 2010; no shares outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized as of
December 31, 2011 and 2010; 52,787,350 and 45,284,527 shares issued
and outstanding as of December 31, 2011 and 2010, respectively		53		45
Additional paid-in capital		219,522		171,167
Cumulative translation adjustment		28,964		14,013
Accumulated deficit		(189,912)		(161,388)
Total stockholders’ equity		58,627		23,837

Total liabilities and stockholders’ equity	$	110,224	$	66,604

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, 2011, 2010, and 2009

(in thousands, except per share amounts)

	2011		2010		2009

Revenues:
Oil and gas sales	$	29,807	$	22,914	$	12,772
Oilfield services		5,631		2,099		1,892
Total revenues		35,438		25,013		14,664
Operating costs and expenses:
Lease operating expenses		3,834		3,473		3,478
Exploration costs		16,618		3,038		4,829
Impairment of oil and gas properties		72		564		1,864
Asset retirement obligation gain		(52)		(264)		(529)
Oilfield services costs		4,458		1,550		1,412
Depreciation, depletion and amortization (DD&A)		3,397		2,626		1,602
Accretion expense		68		92		41
Stock compensation		1,744		1,379		1,693
General and administrative costs (G&A)		8,396		7,973		7,257
Total operating costs and expenses		38,535		20,431		21,647
Operating income (loss)		(3,097)		4,582		(6,983)

Other income (expense):
Interest expense		(2,167)		(1,936)		(654)
Interest and other income		188		829		54
Foreign exchange gain (loss)		(23,448)		(4,233)		7,053
Total other income (expense)		(25,427)		(5,340)		6,453

Net loss	$	(28,524)	$	(758)	$	(530)

Basic and diluted net loss per common share	$	(0.57)	$	(0.02)	$	(0.01)

Basic and diluted weighted average number
of shares outstanding		50,262		43,387		42,529

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

F-6

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

For the years ended December 31, 2011, 2010, and 2009

(in thousands)

	2011		2010		2009

Net loss	$	(28,524)	$	(758)	$	(530)

Other comprehensive income (loss)
Foreign currency translation adjustment		14,951		3,275		(6,399)

Comprehensive income (loss)	$	(13,573)	$	2,517	$	(6,929)

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, 2011, 2010, and 2009

(in thousands)

	2011		2010		2009
Cash flows from operating activities:
Net loss	$	(28,524)	$	(758)	$	(530)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization		3,397		2,626		1,602
Impairment of oil and gas properties		72		564		1,864
Accretion expense		68		92		41
(Gain) loss on property dispositions		44		--		--
Stock compensation		1,744		1,379		1,693
Foreign exchange (gains) losses		23,397		4,238		(8,296)
Common stock issued for services (G&A)		777		636		694
Asset retirement obligation gain		(52)		(264)		(529)
Loan fee amortization		554		971		242
Increase (decrease) from changes in working capital items:
Receivables		(5,241)		(1,809)		1,682
Inventory		(3)		(10)		(21)
Other current assets		(253)		101		58
Other assets		--		(143)		(128)
Accounts payable and accrued liabilities		3,950		(289)		(4,025)
Asset retirement obligations settled		(50)		(85)		(176)
Net cash provided by (used in) operating activities		(120)		7,249		(5,829)

Cash flows from investing activities:
Additions to oil and gas properties		(17,300)		(6,475)		(7,666)
Additions to other property and equipment		(1,221)		(1,339)		(983)
Additions to marketable securities		--		--		(11)
Proceeds from maturities of marketable securities		--		--		4,661
Proceeds from sale of assets		35		--		--
Net cash used in investing activities		(18,486)		(7,814)		(3,999)

Cash flows from financing activities:
Proceeds from issuance of common stock, net of offering costs		45,041		8,403		--
Proceeds from notes payable, net of deferred loan fees		40,000		32,532		--
Payments of notes payable		(35,000)		(25,000)		--
Payments on loan related to auction-rate securities		--		--		(2,808)
Proceeds from exercise of stock options and warrants		801		157		132
Net cash provided by (used in) financing activities		50,842		16,092		(2,676)

Effect of exchange rate changes on cash		(1,117)		(12)		141

Net increase (decrease) in cash		31,119		15,515		(12,363)
Cash and cash equivalents at beginning of year		19,740		4,225		16,588

Cash and cash equivalents at end of year	$	50,859	$	19,740	$	4,225

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

F-8

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity

For the years ended December 31, 2011, 2010, and 2009

(in thousands)

		Common Stock					Accumulated
			$0.001		Additional		Other				Total
	Preferred	Shares	Par		Paid-in		Comprehensive		Accumulated		Stockholders’
	Stock	Issued	Value		Capital		Income (Loss)		Deficit		Equity (Deficit)
Balance as of December 31, 2008	--	42,203	$	42	$	158,075	$	17,137	$	(160,100)	$	15,154
Common stock issued for services and other	--	610		1		694		--		--		695
Exercise of stock options and warrants	--	225		--		132		--		--		132
Stock compensation	--	--		--		1,693		--		--		1,693
Other comprehensive income	--	--		--		--		(6,399)		--		(6,399)
Net loss for year	--	--		--		--		--		(530)		(530)
Balance as of December 31, 2009	--	43,038	$	43	$	160,594	$	10,738	$	(160,630)	$	10,745
Issuance of common stock	--	1,500		1		8,402		--		--		8,403
Common stock issued for services and other	--	594		1		635		--		--		636
Exercise of stock options and warrants	--	153		--		157		--		--		157
Stock compensation	--	--		--		1,379		--		--		1,379
Other comprehensive income	--	--		--		--		3,275		--		3,275
Net loss for year	--	--		--		--		--		(758)		(758)
Balance as of December 31, 2010	--	45,285	$	45	$	171,167	$	14,013	$	(161,388)	$	23,837
Issuance of common stock	--	6,900		7		45,034		--		--		45,041
Common stock issued for services and other	--	440		1		776		--		--		777
Exercise of stock options and warrants	--	162		--		801		--		--		801
Stock compensation	--	--		--		1,744		--		--		1,744
Other comprehensive income	--	--		--		--		14,951		--		14,951
Net loss for year	--	--		--		--		--		(28,524)		(28,524)
Balance as of December 31, 2011	--	52,787	$	53	$	219,522	$	28,964	$	(189,912)	$	58,627

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, together with its subsidiaries (collectively referred to hereinafter as “us,” “we,” “our,” or “the Company”), is an independent oil and gas exploration and production company with principal production, reserves, and exploration in Poland and oil production, oilfield service, and exploration activities in the United States. In Poland, we have projects involving the exploration and exploitation of oil and gas prospects in partnership with the Polish Oil and Gas Company (“PGNiG”), other industry partners, and for our own account. In the United States, we explore for and produce oil from fields in Montana and Nevada, and we have an oilfield services company in northern Montana that performs contract drilling and well-servicing operations.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and its undivided interests in Poland. All significant intercompany accounts and transactions have been eliminated in consolidation. At December 31, 2011, we owned 100% of the voting common stock or other equity securities of our subsidiaries.

Cash and Cash Equivalents and Marketable Securities

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

Fair Value of Financial Instruments and Nonfinancial Assets and Liabilities

The carrying amounts of our financial instruments, including cash and cash equivalents, marketable securities, accounts receivable, accounts payable, and accrued liabilities, approximate fair value because of their generally short maturities. The accounting standards for fair value measurements provide for fair value measurements of all nonfinancial assets and nonfinancial liabilities not recognized or disclosed at fair value in the financial statements on a recurring basis.

Concentration of Credit Risk

The majority of our receivables are within the oil and gas industry, primarily from the purchasers of our oil and gas, and fees generated from oilfield services and our industry partners. Substantially all of our domestic receivables are with Cenex, a regional refiner and marketer, and substantially all of our Polish receivables are with PGNiG or one of its affiliates. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts at December 31, 2011 and 2010. The majority of our cash and cash equivalents are held by four financial institutions in Utah, Montana, and Poland.

Derivative Instruments

Accounting standards require derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of derivative instruments depends on their intended use and resulting hedge designation. For derivative instruments designated as hedges, the changes in fair value are recorded in the balance sheet as a component of accumulated other comprehensive income. Changes in the fair value of derivative instruments not designated as hedges are recorded in the consolidated statements of operations, generally as a component of interest and other income (expense). At December 31, 2011 and 2010, we had no derivative instruments designated as hedges.

F-10

Inventory

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

Oil and Gas Properties

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

During 2011, we relinquished certain concessions in Poland. We impaired the remaining capitalized costs of $72,000. During 2010, production ceased at our Kleka well in western Poland. We impaired the remaining capitalized costs of the well of $564,000. During 2009, production ceased at our Wilga well in eastern Poland. We impaired the remaining capitalized costs of the well of $1,864,000.

During 2010, we recorded a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008. The gain is included in interest and other income.

The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves, during 2011, 2010, and 2009:

	December 31,
	2011		2010		2009
			(In thousands)
Beginning balance at January 1	$	3,614	$	--	$	2,390
Additions to capitalized exploratory well costs
pending the determination of proved reserves		9,965		3,614		1,766
Reclassifications to wells, facilities and equipment
based on the determination of proved reserves		(3,614)		--		(4,156)
Capitalized exploratory well costs charged to expense		--		--		--
Ending balance at December 31	$	9,965	$	3,614	$	--

The 2011 activity includes costs associated with the Plawce-1 and Kutno-2 wells in Poland and our first three Alberta Bakken tests in Montana. All five wells were either in progress or being evaluated or tested at the end of the year. The 2010 activity includes costs associated with the Lisewo-1 well, which was drilling at year-end 2010 and was determined to be a commercial well with proved reserves in 2011. Activity during 2009 included costs associated with the Kromolice-2 well, which was drilling at year-end 2008. During 2009, the well was completed for production, and the determination of proved reserves was made.

F-11

Other Property and Equipment

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

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

					Estimated
	December 31,				Useful Life
	2011		2010		(in years)
	(In thousands)
Other property and equipment:
Drilling rigs	$	8,201	$	7,104	6
Other vehicles		408		424	5
Building		137		110	40
Office equipment and furniture		1,222		1,215	3 to 6
Total cost		9,968		8,853
Accumulated depreciation		(6,997)		(6,039)
Net other property and equipment	$	2,971	$	2,814

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,
	2011		2010		2009
		(In thousands)
Noncash investing transactions:
Additions to properties included in current liabilities	$	3,409	$	2,930	$	327
Cash paid for interest:
Cash paid during the year for interest		1,596		801		415

Cash paid for interest in 2011, 2010, and 2009 (in thousands) includes $858, $149, and $189, respectively, in commitment and other fees on our expanded credit facility.

Revenue Recognition

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

Stock-Based Compensation

We maintain several share-based incentive plans. Under these plans, we may issue options or restricted stock awards. Options are granted at an option price equal to the market value of the stock at the date of grant, have terms ranging from five to seven years, and vest in three equal annual installments. Restricted stock awards have similar terms and vesting requirements. Accounting standards require share-based compensation costs to be measured at the grant date, based on the estimated fair value of the award, and recognized as expense over the employee’s requisite service period.

F-12

Income Taxes

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

We did not have any unrecognized tax benefits at December 31, 2011. We are subject to audit in the United States by the Internal Revenue Service and various states for the prior three years and in Poland by Polish tax authorities for the prior five years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months. Our policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. No tax-related interest expense was recognized during the year ended December 31, 2011.

Subsequent Events

We have evaluated subsequent events after the balance sheet date of December 31, 2011, through the time of filing with the Securities and Exchange Commission.

New Accounting Standards

In January 2010, the FASB issued new standards intended to improve disclosures about fair value measurements. The new standards require details of transfers in and out of Level 1 and 2 fair value measurements and the presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. We adopted these new rules effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward, which we adopted December 31, 2010.

F-13

Foreign Operations

The functional currency of our Polish subsidiary is the Polish zloty. The functional currency for the Polish subsidiary affects the amounts reported for Polish assets, liabilities, revenues, and expenses from those that would be reported if we used the U.S. dollar as the functional currency. The differences depend on changes in period-average and period-end exchange rates. Translation adjustments result from the process of translating the Polish subsidiary’s financial statements into the U.S. dollar reporting currency. Translation adjustments are not included in determining net income but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities of FX Energy Poland, our wholly owned subsidiary, is adjusted to reflect the difference between the exchange rate when the asset or liability was first recorded and the exchange rate on the date of the change. We record a cumulative translation adjustment (“CTA”) on our balance sheet to reflect those basis differences. At December 31, 2011 and 2010, the CTA balance was $29.0 million and $14.0 million, respectively. Because of the fluctuation in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.

During 2010, we identified a misclassification between intercompany equity and intercompany debt. This misclassification resulted in an overstatement of foreign exchange loss of $145,000 in 2008 and an overstatement of foreign exchange gain of $29,000 in 2009 with corresponding misstatements in the CTA. This error had no impact on total stockholders’ equity (deficit) or the statement of cash flows. The net impact of correcting this error in the fourth quarter of 2010 resulted in a decrease in the CTA and a decrease in foreign exchange loss and net loss of $116,000 with no impact to earnings per share. We concluded that the impact of the error is immaterial to the financial statements in the periods in which it occurred as well as to the period in which it was corrected.

During 2011, we recorded foreign currency transaction losses of approximately $23.5 million. We recorded a loss of approximately $23.4 million attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc, as well as dollar-denominated notes payable held by FX Energy Poland. There was a corresponding credit to other comprehensive income for the losses attributable to the dollar-denominated loans, notes payable, and unpaid interest, which was then offset by translation adjustments of approximately $8.6 million related to our other balance sheet accounts as discussed above. The total amount of outstanding intercompany loans and accrued interest at December 31, 2011, was approximately $111 million and $43 million, respectively.

During 2010, we recorded foreign currency transaction losses of approximately $4.2 million. We recorded a loss of approximately $4.2 million attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc., as well as dollar-denominated notes payable held by FX Energy Poland. There was a corresponding credit to other comprehensive income for the losses attributable to the dollar-denominated loans, notes payable, and unpaid interest, which was then offset by translation adjustments of approximately $1.0 million related to our other balance sheet accounts as discussed above. The total amount of outstanding intercompany loans and accrued interest at December 31, 2010, was approximately $103 million.

The following table provides a summary of changes in CTA (in thousands) for the years ended December 31, 2011 and 2010:

	Year Ended		Year Ended
	December 31, 2011		December 31, 2010

Beginning balance	$	14,013	$	10,738
Increase (decrease) related to losses (gains)
on dollar-denominated loans and notes payable		23,442		4,238
Increase (decrease) related to translation adjustments		(8,491)		(963)
Ending balance	$	28,964	$	14,013

F-14

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

We enter into various operating agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. Our policy is to reduce currency risk by, under ordinary circumstances, converting dollars to zlotys on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes.

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes, including uncertain tax positions, stock-based compensation, future development and abandonment costs, estimates to certain oil and gas revenues and expenses, and estimates of proved oil and natural gas reserve quantities used to calculate depletion, depreciation, and impairment of proved oil and natural gas properties and equipment.

Net Loss per Share

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

Outstanding options, warrants, and unvested restricted stock as of December 31, 2011, 2010, and 2009, were as follows:

	Options, Warrants, and
	Unvested Restricted Stock	Price Range
Balance sheet date:
December 31, 2011	1,356,041	$0.00 - $10.65
December 31, 2010	1,578,730	$0.00 - $10.65
December 31, 2009	2,209,976	$0.00 - $10.65

We recorded net losses in 2011, 2010, and 2009. 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.

F-15

Note 2: Asset Retirement Obligation

We account for future site restoration costs by recording a liability for the fair value of asset retirement obligations (“ARO”) when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. We use an expected cash flow approach to estimate our asset retirement obligations. We recorded accretion expense of $67,739, $91,624, and $41,296 in 2011, 2010, and 2009, respectively. At December 31, 2011, 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, 2011 and 2010:

	December 31,
	2011		2010
		(In thousands)
Asset retirement obligations:
Beginning balance	$	1,204	$	1,492
Current year additions		218		--
Current year revisions		(189)		(343)
Liabilities settled		(9)		(7)
Foreign exchange adjustments		(108)		(30)
Accretion expense		68		92
Ending balance	$	1,184	$	1,204

When the present value of a future asset retirement obligation changes due to the increase or decrease of the estimated plugging costs of that asset, we adjust the related asset retirement cost. During both 2011 and 2010, the economic lives of our United States oil wells were increased, as higher oil prices resulted in more economic barrels. This change resulted in a decrease in the net present value of the retirement obligations, which in turn resulted in gains associated with those obligations, as the related asset retirement costs had been previously written off.

Note 3: Other Assets

As of December 31, 2011 and 2010, we had reclamation bonds with federal and state agencies with face amounts of $731,500, which were collateralized by certificates of deposit totaling $381,500. In addition, there are certificates of deposit totaling $25,000 covering performance bonds in other states.

Note 4: Accrued Liabilities

Our accrued liabilities as of December 31, 2011 and 2010, were comprised of the following:

	December 31,
	2011		2010
	(In thousands)
Accrued liabilities:
Credit facility commitment fees	$	47	$	79
Compensation-related costs		462		533
Interest expense		100		78
Current portion of asset retirement obligation		--		522
Oilfield equipment installment note		68		131
Total	$	677	$	1,343

F-16

Note 5: Notes Payable

On August 5, 2010, we refinanced our existing facility by executing an expanded credit facility with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The expanded credit facility calls for a borrowing base of $55 million, a periodic interest rate of LIBOR plus an interest margin of 4.0%, and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on June 30, 2013. The expanded credit facility is an interest-only facility until June 2013. Unamortized deferred financing costs of approximately $577,000 associated with our prior credit facility were charged to interest expense during 2010. Payment of the expanded credit facility is secured by our assets in Poland and guaranteed by us. As of December 31, 2011, the total amount drawn under the expanded credit facility was $40 million. The year-end 2011 interest rate was 4.28% per annum.

We have access to $40 million under the expanded credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been on production for 30 days, at which time the full $55 million becomes available. Proceeds from the expanded credit facility are intended to support our development, production, and operating activities in Poland.

In consideration for the expanded credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.5 million. These fees, which were paid by increasing the amount of debt drawn under the expanded credit facility, have been capitalized as deferred financing costs and are being amortized over the five-year term of the loan, beginning in the third quarter of 2010. An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the expanded credit facility. There are no financial covenants associated with the expanded credit facility. The carrying value of the long-term debt at December 31, 2011, approximates its fair value.

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

	Year Ended	Year Ended
	December 31, 2011	December 31, 2010

Beginning balance	$ 35,000	$ 25,000
Payments of notes payable	(35,000)	(25,000)
Proceeds from borrowing	40,000	35,000
Ending balance	$ 40,000	$ 35,000

At December 31, 2011, the aggregate amounts of our contractually obligated principal payment commitments associated with our notes payable for the next five years are as follows:

	Total	2012	2013	2014	2015	2016

Credit facility principal	$40,000	$ --	$7,000	$22,000	$11,000	$ --

The borrowing base is redetermined twice a year, based on reserve volumes and values estimated by independent engineers as of the last day of the prior year. Our last redetermination was completed in December 2011, with no change in the borrowing base amount.

Note 6: Commitments and Contingencies

None.

F-17

Note 7: Fair Value Measurements and Marketable Securities

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

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

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

·	Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no Level 3 assets as of December 31, 2011 or 2010.

Recurring Fair Value

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

Assets measured at fair value on a recurring basis consisted of the following as of December 31, 2011 and 2010 (in thousands):

	December 31,
	2011	Level 1(1)	Level 2(2)	Level 3(3)
Cash equivalents:
Money market funds	$ 2,799	$ 2,799	--	--

	December 31,
	2010	Level 1(1)	Level 2(2)	Level 3(3)
Cash equivalents:
Money market funds	$ 8,290	$ 8,290	--	--

_______________

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

(2)	Significant other observable inputs.

(3)	Significant unobservable inputs.

F-18

Note 8: Income Taxes

We recognized no income tax benefit from the losses generated during 2011, 2010, and 2009. The components of the net deferred tax asset as of December 31, 2011 and 2010, are as follows:

	December 31,
	2011		2010
	(In thousands)
Deferred tax liability:
Property and equipment basis differences	$	(1,383)	$	(977)
Deferred tax asset:
Net operating loss carryforwards:
United States		31,524		31,503
Poland		1,832		3,058
Oil and gas properties		2,765		2,802
Accrued interest expense		8,220		7,078
Foreign exchange translation losses		7,299		3,787
Options issued for services		(2)		423
Asset retirement obligation		291		305
Valuation allowance		(50,546)		(47,979)
Total	$	--	$	--

The change in the valuation allowance during 2011, 2010, and 2009 is as follows:

	Year Ended December 31,
	2011		2010		2009
		(In thousands)
Valuation allowance:
Balance, beginning of year	$	(47,979)	$	(52,809)	$	(50,217)
Change in property and equipment basis differences		443		2,405		2,288
Decrease (increase) due to foreign exchange translation loss		(3,512)		(1,112)		1,376
Change in accrued interest expense		(1,142)		(586)		(2,223)
Decrease (increase) due to net operating loss		1,205		3,246		(4,405)
Other		439		877		372
Total	$	(50,546)	$	(47,979)	$	(52,809)

Accounting standards require that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations through expansion of our oil and gas producing activities. The risks associated with that growth requirement are considerable, resulting in our conclusion that a full valuation allowance be provided at December 31, 2011, 2010, and 2009. Due to the full valuation allowance, our effective income tax rate for all three years was zero percent. The statutory rate was increased by permanent differences relating to changes associated with stock options and that tax treatment of interest income, and reduced by adjustments for net operating losses expiring, exchange rate differences, and changes to deferred taxes related to temporary differences.

F-19

United States NOL

At December 31, 2011, we had net operating loss (“NOL”) carryforwards in the United States of approximately $84,515,000 available to offset future taxable income. The carryforwards began to expire in 2012 and will fully expire in 2031. 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 $25,556,000 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, 2011, we had NOL carryforwards in Poland totaling approximately $9,640,000. The NOLs begin to expire in 2013 and will be fully expired in 2013. The normal carryforward period in Poland is five years. However, in any given year, no more than 50% of the NOL carryforward may be applied against Polish income in succeeding years.

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

	United States		Poland
	(In thousands)
Year of NOL expiration:
2012	$	4,995	$	--
2013		6,145		9,640
2014		2,938		--
2015		2,717		--
2016 and thereafter		67,720		--

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

	Year Ended December 31,
	2011		2010		2009
		(In thousands)
Domestic	$	(6,602)	$	(4,433)	$	(8,727)
Foreign		(21,922)		3,675		8,197
Total	$	(28,524)	$	(758)	$	(530)

Note 9: Stockholders’ Equity

During 2011, we sold 6,900,000 shares of common stock in a registered public offering at a price of $7.00 per share, resulting in net proceeds, after offering costs, of $45,041,000. Option holders exercised options with cash to purchase 96,799 shares of common stock in 2011, which resulted in proceeds of approximately $800,000. Option holders exercised options to purchase an additional 485,000 shares of common stock at a price of $8.37 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 65,571 incremental shares.

During 2010, we sold 1,500,000 shares of common stock in a registered-direct offering at a price of $6.00 per share. After offering costs, our net proceeds from the offering were $8,403,000. Also during 2010, option holders exercised outstanding options to purchase a total of 39,507 shares of common stock at a price of $3.98 per share, resulting in proceeds to us of $157,000. Additionally, option holders exercised outstanding options to purchase a total of 598,602 shares of common stock at prices ranging from $3.14 to $3.98 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 152,892 incremental shares.

F-20

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

We issued 106,301, 216,977, and 228,100 shares in 2011, 2010, and 2009, respectively, as contributions to our employee benefit plan. In addition, we issued 9,500, 6,000, and 23,000 shares in 2011, 2010, and 2009, respectively, to consultants for services.

We have a stockholder rights plan, adopted in 2007, that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the stockholder rights plan would cause substantial dilution to a person or group that attempts to acquire us on terms not approved in advance by our board of directors. In addition, our articles of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that our stockholders may consider to be in their best interests.

Note 10: Stock Options, Warrants, and Restricted Stock

Equity Compensation Plans

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

The following table summarizes information regarding our stock option and award plans as of December 31, 2011:

		Weighted	Number
	Number	Average	of Options
	of Shares	Exercise Price	Available
	Authorized	of Outstanding	for Future
	Under Plan	Options	Issuance
Equity compensation plans approved by stockholders:
1995 Stock Option and Award Plan	500,000	$9.76	--
2004 Long Term Incentive Plan	1,000,000	10.65	--
2011 Long Term Incentive Plan	4,447,962	5.06	3,498,271
Total	5,947,962	$5.31	3,498,271

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

Stock Options

The following table summarizes option activity for 2011, 2010, and 2009:

	2011		2010		2009
		Weighted		Weighted		Weighted
		Average		Average		Average
	Number of	Exercise	Number of	Exercise	Number of	Exercise
	Options	Price	Options	Price	Options	Price
Options outstanding:
Beginning of year	832,332	$8.42	1,470,441	$6.47	1,980,441	$5.65
Granted	636,509	5.06	--	--	--	--
Exercised	(581,799)	8.35	(638,109)	3.92	(435,000)	2.40
Cancelled	(3,380)	5.06	--	--	(75,000)	8.58
Expired	(215,533)	8.37	--	--	--	--
End of year	668,129	$5.31	832,332	$8.42	1,470,441	$6.47

Exercisable at year-end	35,000	$9.89	832,332	$8.42	1,470,441	$6.47

F-21

The following table summarizes information about stock options outstanding as of December 31, 2011:

	Outstanding			Exercisable
		Weighted
		Average	Weighted		Weighted
	Number	Remaining	Average	Number	Average
Exercise	of Options	Contractual Life	Exercise	of Options	Exercise
Price Range	Outstanding	(in years)	Price	Exercisable	Price

$5.06 - $5.06	633,129	9.72	5.06	--	--
$9.32 - $9.32	20,000	0.42	9.32	20,000	9.32
$10.65 - $10.65	15,000	0.25	10.65	15,000	10.65
Total	668,129	9.23	$5.31	35,000	$9.89

The aggregate intrinsic value of outstanding stock options at December 31, 2011, was $0.

Restricted Stock

The following table summarizes restricted stock activity during 2011, 2010, and 2009:

	2011	2010	2009
	Number	Number	Number
	of Shares	of Shares	of Shares
Unvested restricted stock outstanding:
Beginning of year	746,398	739,535	714,421
Issued	318,252	373,500	379,500
Forfeited	(7,100)	(2,382)	(18,798)
Vested	(369,638)	(364,255)	(335,588)
End of year	687,912	746,398	739,535

The aggregate intrinsic value of unvested restricted stock at December 31, 2011, was $3,301,978. The aggregate intrinsic value represents the total pretax intrinsic value, based on our stock price of $4.80 as of December 31, 2011, which would have been received by the restricted stock award holders had all in-the-money restricted stock awards been vested as of that date. The weighted average period over which stock compensation expense related to the restricted stock awards will be recognized is 2.13 years.

Stock Compensation Expense

During 2011, we issued 636,509 stock options, resulting in deferred compensation of $1,781,036, which will be amortized ratably over a three-year vesting period. The options were valued at $2.80 per share using a Black-Scholes valuation model, with assumptions of: (i) expected life of four years, (ii) volatility of 75%, (iii) risk-free interest rate of 0.69%, and (iv) expected dividend yield of 0%. Expense recognized during 2011 totaled $173,250.

During 2011, we issued 318,252 shares of restricted stock, resulting in deferred compensation of $1,610,355, which will be amortized ratably over a three-year vesting period. Expense recognized during 2011 totaled $156,647.

During 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2,259,675, which will be amortized ratably over a three-year vesting period. Expense recognized during 2011 and 2010 totaled $748,548 and $26,899, respectively.

F-22

During 2009, we issued 379,500 shares of restricted stock, resulting in deferred compensation of $1,043,625, which is being amortized ratably over a three-year vesting period. Expense recognized during 2011, 2010, and 2009 totaled $345,418, $347,253, and $10,269, respectively.

During 2008, we issued 367,000 shares of restricted stock, resulting in deferred compensation of $1,005,580, which is being amortized ratably over a three-year vesting period. Expense recognized for these shares during 2011, 2010, and 2009 totaled $320,404, $331,330, and $335,214, respectively.

During 2007, we issued 370,925 shares of restricted stock, resulting in deferred compensation of $2,284,991, which is being amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010 and 2009 totaled $673,629 and $761,649, respectively.

In December of 2006, we issued 318,400 shares of restricted stock, resulting in deferred compensation of $2,053,680, which was amortized ratably over a three-year vesting period. Expense recognized for these shares during 2009 totaled $585,398.

Note 11: Business Segments

We operate within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. Revenues associated with our E&P activities are comprised of oil and gas sales from our producing properties in Poland and oil sales from our producing properties in the United States. During the last three years, essentially all sales of oil and gas in Poland were made to PGNiG or its affiliated companies. Over 95% of our oil sales in the United States were to Cenex during 2011, 2010, and 2009. Gas sales in Poland are sold pursuant to long-term sales contracts that obligate the buyer to purchase all gas produced. Individual oil sales are negotiated with PGNiG-affiliated entities and are not subject to sales contracts. We believe the purchasers of our oil production in the United States could be replaced, if necessary, without a loss in revenue.

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

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

DD&A directly associated with a respective business segment is disclosed within that business segment. We do not allocate current assets, corporate DD&A, general and administrative costs, amortization of deferred compensation, interest income, interest expense, other income, or other expense to our operating business segments for management and business segment reporting purposes. All material intercompany transactions between our business segments are eliminated for management and business segment reporting purposes.

F-23

Information on our operations by business segment for 2011, 2010, and 2009 is summarized as follows:

	2011
	(In thousands)
					Oilfield		Total
	Exploration & Production				Services
	U.S.		Poland
Operations summary:
Revenues	$	4,687	$	25,120	$	5,631	$	35,438
Lease operating expense		(2,846)		(988)		--		(3,834)
Oilfield services costs		--		--		(4,458)		(4,458)
Exploration expense		(74)		(16,544)		--		(16,618)
Impairment expense		--		(72)		--		(72)
Accretion expense		(44)		(24)		--		(68)
Asset retirement obligation gain		52		--		--		52
DD&A expense		(107)		(2,242)		(984)		(3,333)
Operating income (loss)	$	1,668	$	5,250	$	189	$	7,107
Identifiable net property and equipment:
Unproved properties	$	628	$	2,854	$	--	$	3,482
Proved properties		2,952		38,490		--		41,442
Equipment and other		--		19		2,926		2,945
Total	$	3,580	$	41,363	$	2,926	$	47,869
Net Capital Expenditures:
Property and equipment	$	2,539	$	13,613	$	1,195	$	17,347
Total	$	2,539	$	13,613	$	1,195	$	17,347

	2010
	(In thousands)
					Oilfield		Total
	Exploration & Production				Services
	U.S.		Poland
Operations summary:
Revenues	$	4,184	$	18,730	$	2,099	$	25,013
Lease operating expense		(2,449)		(1,024)		--		(3,473)
Oilfield services costs		--		--		(1,550)		(1,550)
Exploration expense		(30)		(3,008)		--		(3,038)
Impairment expense		--		(564)		--		(564)
Accretion expense		(70)		(22)		--		(92)
Asset retirement obligation gain		264		--		--		264
DD&A expense		(81)		(1,723)		(743)		(2,547)
Operating income (loss)	$	1,818	$	12,389	$	(194)	$	14,013
Identifiable net property and equipment:
Unproved properties	$	24	$	3,296	$	--	$	3,320
Proved properties		1,124		31,116		--		32,240
Equipment and other		--		20		2,746		2,766
Total	$	1,148	$	34,432	$	2,746	$	38,326
Net Capital Expenditures:
Property and equipment	$	513	$	8,584	$	1,334	$	10,431
Total	$	513	$	8,584	$	1,334	$	10,431

F-24

	2009
	(In thousands)
					Oilfield		Total
	Exploration & Production				Services
	U.S.		Poland

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

A reconciliation of the segment information to the consolidated totals for 2011, 2010, and 2009 follows:

	2011		2010		2009
	(In thousands)

Revenues:
Reportable segments	$	35,438	$	25,013	$	14,664
Non-reportable segments		--		--		--
Total revenues	$	35,438	$	25,013	$	14,664
Net loss:
Operating income (loss), reportable segments	$	7,107	$	14,013	$	2,057
Expense or (revenue) adjustments:
Corporate DD&A expense		(64)		(79)		(90)
General and administrative costs (G&A)		(8,396)		(7,973)		(7,257)
Stock compensation (G&A)		(1,744)		(1,379)		(1,693)
Total net operating income (loss)		(3,097)		4,582		(6,983)
Non-operating income:
Interest income (net of interest expense) and other income		(1,979)		(1,107)		(600)
Foreign exchange gain (loss)		(23,448)		(4,233)		7,053
Net loss	$	(28,524)	$	(758)	$	(530)
Net property and equipment:
Reportable segments	$	47,869	$	38,326	$	32,196
Corporate assets		27		48		95
Net property and equipment	$	47,896	$	38,374	$	32,291
Property and equipment capital expenditures:
Reportable segments	$	17,347	$	10,431	$	7,960
Corporate assets		25		3		27
Total property and equipment capital expenditures	$	17,372	$	10,434	$	7,987

F-25

Note 12: Quarterly Financial Data (Unaudited)

Summary quarterly information for 2011 and 2010 is as follows:

	Quarter Ended
	December 31		September 30		June 30		March 31
		(In thousands, except per share amounts)
2011:
Revenues	$	8,989	$	10,120	$	9,182	$	7,147
Net operating income (loss)		(1,957)		(860)		(567)		287
Net income (loss)		(10,079)		(27,526)		2,547		6,534
Basic and diluted net income (loss) per common share	$	(0.23)	$	(0.53)	$	0.05	$	0.14
2010:
Revenues	$	6,100	$	6,648	$	6,093	$	6,172
Net operating income (loss)		207		2,266		23		2,086
Net income (loss)		(1,756)		22,152		(22,083)		929
Basic and diluted net income (loss) per common share	$	(0.04)	$	0.51	$	(0.51)	$	0.02

F-26

FX ENERGY, INC., AND SUBSIDIARIES

Supplemental Information

Disclosure about Oil and Gas Properties and Producing Activities (Unaudited)

Capitalized Oil and Gas Property Costs

Capitalized costs relating to oil and gas exploration and production activities as of December 31, 2011 and 2010, are summarized as follows:

	United States		Poland		Total
			(In thousands)
December 31, 2011:
Proved properties	$	6,456	$	42,932	$	49,388
Unproved properties		628		2,854		3,482
Total gross properties		7,084		45,786		52,870
Less accumulated depreciation, depletion and amortization		(3,504)		(4,442)		(7,946)
	$	3,580	$	41,344	$	44,924
December 31, 2010:
Proved properties	$	4,520	$	34,008	$	38,528
Unproved properties		24		3,296		3,320
Total gross properties		4,544		37,304		41,848
Less accumulated depreciation, depletion and amortization		(3,396)		(2,892)		(6,288)
	$	1,148	$	34,412	$	35,560

Results of Operations

Results of operations are reflected in Note 12, Business Segments. There is no tax provision because we are not likely to pay, and have not received any benefit from, any federal or local income taxes due to our operating losses. Total production costs (in thousands) for 2011, 2010, and 2009 were $3,834, $3,473, and $3,478, respectively.

Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration, and development activities during 2011, 2010, and 2009, whether capitalized or expensed, are summarized as follows:

	United States		Poland		Total
			(In thousands)
Year ended December 31, 2011:
Acquisition of unproved properties	$	604	$	65	$	669
Exploration costs		1,406		26,844		28,250
Development costs		558		3,059		3,617
Total	$	2,568	$	29,968	$	32,536
Year ended December 31, 2010:
Acquisition of unproved properties	$	3	$	44	$	47
Exploration costs		30		6,622		6,652
Development costs		509		4,937		5,446
Total	$	542	$	11,603	$	12,145

F-27

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

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

Impairment of Oil and Gas Properties

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

	2011	2010	2009
Impairment of properties	$72	$564	$1,864

Exploratory Dry Hole Costs

Total dry hole costs (in thousands) of $1,328 in 2011 were principally related to the Machnatka-1 well drilled in Poland. There were no dry holes drilled in 2010. Total dry hole costs in 2009 of $151 were related to a single dry hole drilled in the United States.

Summary Oil and Gas Reserve Data (Unaudited)

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

Reserves

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

Recent SEC and FASB Rule-Making Activity

In December 2008, the Securities and Exchange Commission announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

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

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

F-28

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

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

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

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

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

We adopted the rules effective December 31, 2009.

Application of the new rules resulted in the use of lower prices at December 31, 2009, for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009, as required by the new rules, resulted in a decrease in proved developed oil reserves of approximately 990,000 cubic feet of natural gas equivalent. We did not calculate the impact of the new rules on our 2010 or 2011 reserves. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.

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

Definitions

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

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

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

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

F-29

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

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

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

Reserves Estimates Preparation

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

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 million cubic feet)

December 31, 2011	639	--	--	31,987
December 31, 2010	639	--	--	31,683
December 31, 2009	463	--	--	20,409

Total Proved Reserves:

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

	Crude Oil		Natural Gas
	United States	Poland	United States	Poland
	(In thousand barrels of oil)		(In million cubic feet)

December 31, 2011:
Beginning of year	639	--	--	39,959
Extensions or discoveries (1)	--	--	--	12,245
Revisions of previous estimates (2)	56	--	--	1,492
Production	(56)	--	--	(4,060)
End of year	639	--	--	49,636

December 31, 2010:
Beginning of year	463	--	--	47,668
Revisions of previous estimates (3)	237	--	--	(4,236)
Production	(61)	--	--	(3,473)
End of year	639	--	--	39,959

F-30

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

	Crude Oil		Natural Gas
	United States	Poland	United States	Poland
	(In thousand barrels of oil)		(In million cubic feet)

December 31, 2009:
Beginning of year	45	47	--	45,312
Extensions or discoveries (4)	--	--	--	6,333
Revisions of previous estimates (5)	482	(47)	--	(2,095)
Production	(64)	--	--	(1,882)
End of year	463	--	--	47,668

_______________

(1)	Volume increase in Poland attributable to new Lisewo-1 well drilled during 2011.

(2)	Upward oil revisions in the United States attributable to higher average oil prices during 2011 compared to average 2010 oil prices. Upward gas revisions in Poland due to the increase of proved reserves calculated at the Roszkow well based on new pressure data.

(3)

Upward oil revisions in the United States attributable to higher average oil prices during 2010 compared to average 2009 oil prices. Downward gas revisions in Poland due to the reduction of proved reserves calculated at the Roszkow well based on new pressure data and cessation of production at the Kleka well.

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

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

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

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. We believe such information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute the proved reserve valuation do not necessarily reflect our expectations of actual revenues to be derived from those reserves or their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rates also could result directly or indirectly from factors outside our control, such as unintentional delays in development, environmental concerns, and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating expenditures to be incurred in developing and producing the proved oil reserves at the end of the period, based on period-end costs and assuming continuation of existing economic conditions. A discount rate of 10% per year was used to reflect the timing of the future net cash flows. The future net cash flows for our Polish reserves are based on gas sales contracts we have with PGNiG. The average prices used to calculate year-end reserve values were $6.44 and $5.66 per Mcf and $84.61 and $68.12 per barrel for 2011 and 2010, respectively.

F-31

FX ENERGY, INC. AND SUBSIDIARIES

Supplemental Information

--continued--

The components of SMOG are detailed below:

	United States		Poland		Total
			(In thousands)
December 31, 2011:
Future cash flows	$	54,036	$	319,840	$	373,876
Future production costs		(32,396)		(22,020)		(54,416)
Future development costs		--		(17,240)		(17,240)
Future income tax expense		--		(40,868)		(40,868)
Future net cash flows		21,640		239,712		261,353
10% annual discount for estimated timing of cash flows		(9,377)		(82,409)		(91,786)
Discounted net future cash flows	$	12,263	$	157,304	$	169,567
December 31, 2010:
Future cash flows	$	43,553	$	226,310	$	269,863
Future production costs		(26,762)		(15,130)		(41,892)
Future development costs		--		(12,580)		(12,580)
Future income tax expense		--		(28,134)		(28,134)
Future net cash flows		16,791		170,466		187,257
10% annual discount for estimated timing of cash flows		(7,122)		(52,798)		(59,920)
Discounted net future cash flows	$	9,669	$	117,668	$	127,337
December 31, 2009:
Future cash flows	$	22,050	$	283,520	$	305,570
Future production costs		(16,334)		(26,750)		(43,084)
Future development costs		--		(17,940)		(17,940)
Future income tax expense		--		(33,411)		(33,411)
Future net cash flows		5,716		205,419		211,135
10% annual discount for estimated timing of cash flows		(2,217)		(63,095)		(65,312)
Discounted net future cash flows	$	3,499	$	142,324	$	145,823

The principal sources of changes in SMOG are detailed below:

	Year Ended December 31,
	2011		2010		2009
				(In thousands)
SMOG sources:
Balance, beginning of year	$	127,337	$	145,823	$	117,568
Sale of oil and gas produced, net of production costs		(25,973)		(19,442)		(9,294)
Net changes in prices and production costs		20,809		200		14,530
Acquisition of minerals in place		--		--		--
Extensions and discoveries, net of future costs		38,210		--		18,200
Changes in estimated future development costs		(4,951)		728		(367)
Previously estimated development costs incurred during the year		3,059		4,670		3,656
Revisions in previous quantity estimates		6,060		(13,839)		(1,671)
Accretion of discount		12,734		14,582		11,757
Net change in income taxes		(7,384)		3,944		(3,906)
Changes in rates of production and other		(334)		(9,329)		(4,650)
Balance, end of year	$	169,567	$	127,337	$	145,823

F-32

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

FX Energy (FXEN) Inactive 10-K2011 FY Annual report

Content analysis