10-K 1 k123112.htm FORM 10-K YEAR ENDED DECEMBER 31, 2012 k123112.htm
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, 2012
   
¨
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, 2012, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $299,202,000.

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 8, 2013, FX Energy had outstanding 53,409,022 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 2013 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, 2012
 


TABLE OF CONTENTS


Item
   
Page
   
Part I
 
--
 
Special Note on Forward-Looking Statements
   3
1
 
Business
   5
1A
 
Risk Factors
 12
1B
 
Unresolved Staff Comments
 25
2
 
Properties
 26
3
 
Legal Proceedings
 43
4
 
Mine Safety Disclosures
 43
       
   
Part II
 
5
 
Market for Registrant’s Common Equity, Related Stockholder Matters
 
   
and Issuer Purchases of Equity Securities
 44
6
 
Selected Financial Data
 45
7
 
Management’s Discussion and Analysis of Financial Condition and Results of Operation
 47
7A
 
Quantitative and Qualitative Disclosures about Market Risk
 61
8
 
Financial Statements and Supplementary Data
 61
9
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 62
9A
 
Controls and Procedures
 62
9B
 
Other Information
 62
       
   
Part III
 
10
 
Directors, Executive Officers and Corporate Governance
 63
11
 
Executive Compensation
 63
12
 
Security Ownership of Certain Beneficial Owners and Management and Related
 
   
Stockholder Matters
 63
13
 
Certain Relationships and Related Transactions, and Director Independence
 63
14
 
Principal Accountant Fees and Services
 63
       
   
Part IV
 
15
 
Exhibits and Financial Statement Schedules
 64
--
 
Signatures
 69
--
 
Management’s Report on Internal Control over Financial Reporting
F-1
--
 
Report of Independent Registered Public Accounting Firm
F-2

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 or produced;

·  
the rates at which our resources will be produced, particularly from properties for which we are not the operator;

·  
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 Polskie Górnictwo Naftowe i Gazownictwo, 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;
 
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·  
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;

·  
the effect of future changes in reservoir pressure, prices, reservoir mapping, production rates, and other factors on reserve quantities;

·  
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 Poland and which we have used in our Montana oil 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 and changes in applicable royalty rates;

·  
environmental hazards, such as uncontrollable flows of crude oil, brine, well fluids, hydraulic fracturing fluids, or other pollutants by us or third-party service providers;

·  
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.
 
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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 and oilfield service activities in the United States, where we have conducted limited exploration during 2012.  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 2012, independent reserve engineers estimated our worldwide proved oil and gas reserves to be 44.1 billion cubic feet, or Bcf, of natural gas and 0.6 million barrels of oil, or Bbl, or a combined total of 47.7 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).  Of this 47.7 Bcfe, 93% was in Poland and 7% was in the United States.  The independent engineers estimated the PV-10 Value of our proved reserves to be approximately $158 million.

At year-end 2012, independent reserve engineers estimated our worldwide proved plus probable, or P50, oil and gas reserves to be a combined total of 79.4 Bcfe.  The independent engineers estimated the PV-10 Value of our P50 reserves to be approximately $208 million.

Our 2012 oil and gas production was 4.8 Bcfe (13.1 million cubic feet equivalent per day, or MMcfed), which was up 9% from 2011 production. Of our 2012 production, 4.5 Bcfe (12.2 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.

Our oil and gas revenues for 2012 were $34.5 million, which is an increase of 16% over revenues for the preceding fiscal year.  We currently expect that our 2013 production will rise measurably from our 2012 production rates with the start of production at our Winna Gora, Lisewo-1, and Komorze-3 wells, which we believe will be greater than the natural declines in production from our currently producing wells.  We expect our 2013 first quarter production to average approximately 14.0 MMcfed.  Production began at our Winna Gora well in late January of 2013.  We expect production facilities to be complete and gas to start flowing at our Lisewo-1 and Komorze-3 wells in the second half of 2013.

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 2.7 million gross acres (2.0 million net) in Poland and continually review additional acreage acquisition opportunities.

During 2012 in Poland, we drilled one well that we plan to place into production in 2013, one well with gas shows that has been temporarily abandoned pending further evaluation, and one dry hole.

As of December 31, 2012, we had approximately 53.2 million shares of common stock outstanding, and our market capitalization was approximately $219 million (approximately $214 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 2013, our average daily trading volume has been approximately 278,000 shares.  Our total assets as of December 31, 2012, were $106.0 million, and our working capital was $30.4 million.  Total debt per thousand cubic feet equivalent, or Mcfe, of proved reserves was $0.84 at year end.
 
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Most of our current Polish operations are conducted in partnership with PGNiG, a fully integrated oil and gas company that is largely owned by the Treasury of the Republic of Poland.  PGNiG 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.

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

We believe 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 nine conventional gas discoveries in our core Fences concession in Poland are 14.8 Bcf.  The average initial gross production rate for these nine wells is approximately 5.0 MMcfd of natural gas with a relatively long, flat production profile.

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 more than 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.  Our production volumes in the Fences concession area have increased at a compound annual growth rate of 35% from 2009 through 2012, while our natural gas revenues have increased at a compound annual growth rate of 50% during the same period.  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 majority of our available capital, 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.

Outside our core Fences area, 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 now have means to increase our activities in 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.
 
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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 the long-producing 390 Bcf Radlin field, which was discovered in the 1980s by our joint venture partner PGNiG (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 nine of the 12 wells we have drilled on Rotliegend structural trap targets in our core Fences concession.  In the aggregate, these nine discoveries found gross estimated recoverable proved reserves of approximately 133 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.  We are drilling the Mieczewo-1 well at the date of this report and anticipate drilling three to four additional wells in the Fences area during 2013.  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 part of our Fences concession using vertical drilling and 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.  In the first half of 2013, we plan to fracture three separate intervals in the well and test the potential for commercial production.

We have also identified a number of prospects outside the Fences concession in our other concessions in Poland.  These prospects are generally higher risk, as indicated by two noncommercial tests we drilled in these areas in 2012, but drilling success may open new productive areas with significant resources.  We are drilling the Tuchola-3K well in our Edge concession at the date of this report and anticipate drilling two to three additional wells in 2013 in one or more of our Edge, Block 246, Warsaw South, and Block 229 concessions.  These wells will test various horizons for hydrocarbon potential as part of a planned 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 of employees and consultants experienced with using modern exploration tools and have 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, with a view toward long-term results.

Polish Exploration Rights

As of December 31, 2012, we held oil and gas exploration rights in Poland in a number of separately designated project areas encompassing approximately 2.7 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 2.0 million net acres throughout Poland.
 
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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 Item 2, Properties – “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, 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 133 Bcf gross (59 Bcf net to our interest) in nine 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 area during 2012, we completed the Komorze-3K well.  In 2013 we are drilling the Mieczewo-1 well, anticipate drilling two or three wells in the eastern part of Fences, and plan to fracture and test the Plawce-2 tight sand well previously drilled in the northern part of Fences.  In our other concessions we drilled the Kutno-2 well, a noncommercial deep Rotliegend test in the Kutno concession, the Frankowo-1 well, a noncommercial Zechstein/Rotliegend test in Block 246, and started drilling the Tuchola-3K Ca2/Devonian test in Edge.  In 2013 we expect to finish drilling and test the Tuchola-3K well and drill two or three additional exploration wells in one or more of the Edge, Warsaw South, Block 246, and Block 229 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 12 conventional vertical wells targeting Rotliegend structures through the date of this filing.  Nine of these wells are commercial, with an aggregate estimated ultimate recovery of 133 Bcf over the life of the wells, with remaining proved gas reserves of over 89 Bcf gross (42 Bcf net to our interest) as of December 31, 2012.

We currently produce approximately 13.2 MMcfed net to us from six of these nine wells, one of which started producing in January 2013.  (The oldest of our nine wells had a very small reservoir and was depleted in 2010).  We expect to start production in the second half of 2013 from the remaining two wells.  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 years of test production that is permitted under the exploration concession.

In 2013, subject to our partner’s participation, we plan to drill three to four new wells in the Fences concession: the Mieczewo-1 well currently drilling near our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, production facility and two to three wells near the Lisewo production facility that is currently under construction and is scheduled to begin producing in the second half of 2013.
 
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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 12,000 acres (50 sq. km.).  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 2013 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 the Grabowka-12 well, which has been producing since July 2009, and the Grabowka-6 well, which was connected to the gas plant in December 2012 and is scheduled to begin producing in the first half of 2013.  In addition, we plan to reenter the Grabowka-8 well during the first half of 2013, with a view to further increasing production shortly thereafter.

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 identified an area with potential for Rotliegend sandstone and Zechstein reef reservoirs.  In 2012 we drilled the Frankowo-1 well and encountered good reservoir properties and gas shows or accumulations in these two horizons, but we temporarily abandoned the well pending further evaluation.  In 2013 we plan to acquire 3-D seismic in the prospective area and, in 2014, drill one or two wells to evaluate its potential.

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 Zechstein Main Dolomite reef build-ups on two-dimensional, or 2-D, seismic data in Block 229.  In 2013 we plan to acquire a small amount of additional 2-D seismic data to support a drill-site selection.  We anticipate drilling a well in Block 229 in 2014.  We may seek industry participation in drilling wells in this concession area.

Warsaw South Concession Area

We hold a 51% interest in a total of 463,000 acres (1,875 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.  While not commercial, 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 there are few existing wells and relatively little seismic data.  Nonetheless, we plan to continue our exploration efforts.  In 2012, we elected to drop certain concessions that we deemed less prospective for hydrocarbon potential, while acquiring additional new seismic data on our remaining blocks.  In 2013 we plan to select one or more prospects to drill, depending on the drilling activity in our other concession areas and on our partner’s input.
 
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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 2012 and started drilling the Tuchola-3K well to test both a Ca2 target and a Devonian target.  We are interpreting new seismic data on three of the blocks in the Edge area and may drill in one or two of the concession blocks this year, subject to our drilling plans elsewhere.  We have determined that one of the blocks appears to have much higher exploration risk than the others and will not seek to extend it beyond its 2013 expiration date.  We may seek industry participation in drilling wells in this concession area.

Dropped Concessions

We previously had exploration interests in the Kutno and Northwest concession areas.  We drilled and plugged and abandoned a well in the Kutno concession and intend to let the concession expire.  Because of our evaluations of the exploration potential of the Northwest concession, in the light of related costs and risks, we are relinquishing our interest in that concession.

Additional Concession Acreage

We may apply for more concession blocks in Poland in 2013.  If we acquire more concession blocks, we will allocate modest technical and financial resources to these areas during 2013, 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 principal 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.  Our U.S. operations provide a modest amount of cash flow and are not capital intensive.  They consist mostly of shallow, water flood oil-producing wells in the Southwest Cut Bank Sand Unit, or SWCBSU, of Montana.  As of December 31, 2012, our U.S. reserves (all of which were proved reserves) were estimated at 594,000 Bbls of crude oil with a PV-10 Value of approximately $10.4 million.  At year-end 2012, U.S. reserves were approximately 7% of total proved reserves on a gas equivalent basis.  Our oil wells produce approximately 146 Bbls of oil per day, net to our interest.  We produce oil from approximately 10,732 gross (10,418 net) acres in Montana and 400 gross (128 net) acres in Nevada.
 
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From our field office in Montana, we also provide oilfield services, which provided approximately $2.1 million in revenue during 2012.

Alberta Bakken and Three Forks Shale Exploration

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, 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.

During 2012, 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.  The new joint venture resulted in a one-third working interest in all formations below the Cut Bank in our SWCBSU and a one-sixth working interest in the Americana acreage in all formations below the surface.  Also during 2012, the Somont lease earn-in option expired, and we sold certain of the Americana leases.

We have determined that none of the wells drilled to date in our Albert Bakken project was economic and have suspended further drilling in the area.

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.  We may elect to purchase such insurance on wells drilled in other areas in Poland, which we did for our Tuchola 3-K well of which we own a 100% interest.  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 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 is 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 on wells for which we act as operator.  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.
 
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Our insurance policies may not cover costs and expenses related to government-mandated cleanup of pollution or fines, penalties, or other sanctions resulting from any civil enforcement or criminal proceedings.  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, 2012, we had 50 employees, consisting of nine in Salt Lake City, Utah; 20 in Oilmont, Montana; one in Greenwich, Connecticut; two in Houston, Texas; and 18 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 16,000 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 about 4,900 square feet for approximately 25,000 PLN ($8,000 at December 31, 2012, exchange rate) per month and in Krakow, Poland, located at ul. Smolensk 21/15, where we rent approximately 215 square feet for approximately 1,500 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 Poland and the United States.
 
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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 2013 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 current and hopefully expanded credit facility secured by future production from our reserves, 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, in turn, 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 2013 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our U.S. dollar-denominated revenues in 2013 compared to 2012, with a corresponding increase 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 2013 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.  Similarly, as operator, PGNiG controls the level of production as well as other day-to-day operating details.  Our ability to conduct certain activities may be affected by whether PGNiG classifies such activities as exploratory or development because of different internal budgetary considerations.  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 development activities.  We may undertake this work at our own cost or seek replacement industry participants if this third party fails to pay these costs.
 
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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 or PGNiG develop will provide a useful or effective guide for our exploration or development activities, including selecting exploration prospects and drilling targets.  We continually review and revise or replace these exploration models as a guide to further exploration based on new data, including drilling results, and interpretations.  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, even for development wells.  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 actually 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:

·  
our data regarding 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 royalties and other 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;

·  
market prices and demand for the oil and gas we produce; and
 
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·  
oil and gas quality and impurities that reduce the sales prices we actually received below the posted or contract price.

In accordance with Securities and Exchange Commission’s rules for estimating oil and gas reserves, we use deterministic methods to determine proved reserves, based on 12-month average prices.  Our estimates of probable reserves as of December 31, 2012, 2011, and 2010, are calculated using probabilistic methods.  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.  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 or with different assumptions 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, drill-stem tests, 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 unrisked 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 2013, we have participated in drilling 40 exploratory wells in Poland, including 12 commercial discoveries, 25 noncommercial wells, two wells that were undergoing further evaluation, and one well that was drilling at year-end 2012.  Of our 12 commercial successes in Poland, as of the date of this report we were producing gas at seven wells, including six in our Fences concession and one in our Block 287 concession.  Production from three other commercial discoveries is scheduled to begin in 2013 once requisite permits are obtained and production facilities are constructed.  Two early wells have been fully exploited and no longer produce.
 
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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 in Poland.  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 managing other factors.  Such delays could correspondingly postpone the commencement of cash flow and may require us to increase our reliance on borrowings under our credit line pending commencement of production.  Further, we may design and construct surface and pipeline facilities to accommodate anticipated production from future wells, but we cannot assure that any future wells 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 actual production is smaller than projected, 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 established by and 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, 2012, we have incurred cumulative net losses of approximately $186 million.  Our exploration and production activities may continue to result in net losses through 2013 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.  In addition to our long-term project financing, 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 exploration concessions work commitments that must be satisfied in order to maintain our interest in those concessions.  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.  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.

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 disrupt our activities as we seek a replacement.  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.
 
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Substantially all of our natural gas currently produced in Poland is sold to a single purchaser, PGNiG, or its affiliates.

We currently sell substantially all of the natural 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 diversify our gas purchasers 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, including hedging arrangements, to protect us from price fluctuations and may or may not do so in the future.
 
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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.  We may purchase such insurance on Company-operated wells drilled in other areas in Poland, and currently carry well control insurance for the Tuchola-3-K well, which began drilling in late 2012.  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 negatively 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 may be a defendant in various lawsuits, including claims or civil or criminal proceedings based on environmental claims.  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 decided unfavorably 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.  Adverse litigation decisions or rulings may damage our business reputation.

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.
 
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We have spent $321,000 in oil leak cleanup costs 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, require suspension or cessation of operations in affected areas, and expose us to civil and criminal sanctions or fines, with attendant negative publicity.  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 may use hydraulic fracturing in vertical and horizontal wells in Poland and the United States to enhance oil and natural gas production.  Hydraulic fracturing is a process that involves injecting water, sand, and chemicals into the foundation under high pressure to fracture the surrounding rock to stimulate 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.  The U.S. Environmental Protection Agency, or EPA, requires under the State Water Drinking Act or SWDA, that operators obtain permits when injecting diesel in hydraulic fracturing operations.  The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from the SWDA, prohibits the injection of diesel fuel without a permit.  However, the U.S. Congress is currently considering bills that would eliminate the existing exemption under the SWDA and subject hydraulic fracturing to federal regulation.  Industry groups have challenged the EPA’s determination to require a permit for injecting diesel.  The EPA is studying the potential environmental impacts of hydraulic fracturing, and a U.S. House of Representatives committee is conducting an investigation of hydraulic fracturing practices.  Further, certain members of Congress have called upon: (i) the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (ii) the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and (iii) the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.  Additionally, some states, including Montana, have adopted conditions, restrictions, and regulations that require permits prior to conducting hydraulic fracturing and may in the future 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.
 
19
 
 

 

 
In 2012, we 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.  Following uneconomic well results, we have placed that program on hold indefinitely and have no current plans for future hydraulic fracturing in the United States.

In Poland, we intend to hydraulically fracture the Plawce well, which may lead to additional wells in the Plawce area that we may treat similarly.  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 respecting 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.

Our activities may be directly or indirectly adversely affected by unauthorized invasion of our data processing and communications systems.

We are dependent on a number of computerized data storage and processing and communications systems to operate our business and interconnect our activities in Poland and Montana with our principal executive offices.  We use these systems to gather and store raw exploration, development, and production data; interpret geophysical and geological data as part of our exploration and development activities; model the resource potential and reserves or project areas; forecast production; administer contracts with third parties; gather and report financial and other data to our stockholders and regulatory authorities; and other complete critical functions throughout the company.  Our vendors and suppliers also rely on similar systems in conducting their own businesses.  Our reliance, like others in the industry, on these technologies makes us increasingly vulnerable to risks of technological failures resulting from others gaining unauthorized access, intentional and unintentional cyber incidents, network failures, breaches of security, and similar events that could result in the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information, including the release of such information to competitors, or other damaging disruption of our activities.  We cannot assure that the measures we implement to protect against these kinds of cyber risks will be successful or that our operations will not be adversely affected by cyber events.  We expect that the financial and managerial resources that we devote to protective measures or to remediate breaches will increase.

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:
 
20
 
 

 


·  
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.  Further, since the history and practice of industry regulation is sparse, our activities may be particularly vulnerable to the decisions and positions of individuals, who may change, be subject to external pressures, or administer policies inconsistently.  Internal bureaucratic politics may have unpredictable and negative consequences.
 
21
 
 

 


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.  Recently, PGNiG has announced plans to privatize its service affiliates, including the geophysical and drilling companies that we regularly engage.  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.

We are dependent on PGNiG to accurately account for expenditures on our behalf and for which we are responsible.

Many of our activities in Poland are undertaken in collaboration with PGNiG, which frequently owns a majority of the interest in the project and acts as operator under our agreements.  As operator, PGNiG incurs costs for agreed activities, such as gathering seismic data, drilling and completing wells, constructing production facilities, and other costs, and we are obligated to advance or reimburse our share of such costs.  We have limited rights to audit or otherwise examine the records of expenditures on our behalf that we reimburse.  The limitation on such rights and our inability to undertake audits to determine compliance with our agreements may expose us to overcharges or other irregularities.

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.
 
22
 
 

 


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 until June 30, 2013, at which time our borrowing base is scheduled to be reduced to $44 million.  Although all three lending banks in our credit facility recently successfully passed required European bank stress tests, there is no guarantee that they will maintain their required capital and other ratios, and our access to the remaining available funds 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.

We cannot assure that we will be able to renew or expand our current credit facility or establish a new credit facility to provide required capital for our exploration and development activities in Poland.

We are seeking renewal and expansion of our existing $55 million credit facility to finance our expanding development activities in Poland.  We have been advised that the Royal Bank of Scotland, which is the lead for the three banks that currently provide our credit facility, will not participate in a renewed or expanded facility due to new internal lending policies.  We cannot assure that the remaining lenders will be willing to renew and expand the credit facility or that other banks will be willing to participate.  Both our existing banks and prospective new banks may have new restrictive lending policies or propose lending covenants or restrictions that we might be unwilling or unable to meet.  We cannot assure that we will be able to establish a new credit facility or that we will meet criteria they may impose to increase our borrowing ability.  Our inability to enter into a renewed and expanded credit facility may slow or limit the development and production of oil and gas discoveries in Poland.

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, if we fail to comply with the terms and obligations indicated in the mining usufruct agreement, in particular with the obligation to pay the fee due under the agreement, 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 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.
 
23
 
 

 


Proposed changes to Poland’s hydrocarbon legislation will have an adverse impact on our operations if approved as they are currently defined.

In late 2012, the Polish government approved guidelines for new hydrocarbon legislation, including, among other things, higher royalties on hydrocarbons produced, a new cash flow tax based on the positive cumulative cash flow of exploration and development projects, as well as changes to how usufruct fees are determined and how concessions are awarded.  The Minister of Environment has been directed to prepare a draft law, which was published in early 2013.  Comments from the industry/general public will be invited, then taken into account or not in preparing a revised draft by the Minister.  The revised draft will be subject to review by various governmental committees and agencies, and then a final draft will be subject to approval by the government, before it is sent to the Parliament.

The new legislation is meant to increase governmental revenue from the oil and gas industry, with the stated intention for the total royalty and tax burden of an energy company to approach 40% of taxable income, which is approximately double that of the current fiscal regime.  The new law, once approved by Parliament, would become effective January 1, 2015, at the earliest, but in any event not prior to the first commercial production of shale gas in the country.

Although the draft law was recently published, we are unable to estimate the impact of the law on our financial results or operations.  However, any increase in royalties or income taxes to which we may be subject would have an adverse impact.

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 closed as low as $3.36 and as high as $8.52 between January 1, 2012, 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;
 
24
 
 

 


·  
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 against 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 lowering our 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.
 
25
 
 

 



 
ITEM 2. PROPERTIES
 

Proved Reserves Disclosures

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 to: (i) 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) 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.
 
26
 
 

 


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 due to a variety of factors 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, 2012, our proved undeveloped reserves totaled 20.4 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.  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.  We do not have any proved undeveloped reserves attributable to undrilled locations, so 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, 2011, to developed reserves at December 31, 2012.

Development Costs

Costs incurred relating to the development of proved undeveloped reserves were approximately $2.3 million in 2012, almost all of which were attributable to the construction of production facilities at our Winna Gora and Lisewo wells.

Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $13.0 million in 2013.  The estimated development costs are for the cost of facilities construction at our Lisewo and Komorze production facilities and for drilling the Lisewo-2 well.

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, 2012, no crude oil or natural gas reserves information has been filed with, or included in any report to, any other federal authority or agency.
 
27
 
 

 


Reserve Volumes and Values

The following table sets forth our estimated proved developed, proved undeveloped, and probable reserves volumes as of December 31, 2012:

 
United States
 
Poland
 
Total
 
MBbls
 
MMcf
 
MMcfe
Proved developed reserves
594
 
23,759
 
27,323
Proved undeveloped reserves
--
 
20,362
 
20,362
Total proved reserves
594
 
44,121
 
47,685
Probable reserves
--
 
31,724
 
31,724
Total proved plus probable reserves
594
 
75,845
 
79,409

The following table sets forth the estimated PV-10 Value of our proved plus probable reserves as of December 31, 2012:

 
Total Net
 
PV-10
 
Reserves
 
Value
 
(MMcfe)
 
(In thousands)
Proved
47,685
 
$157,603
Probable
31,724
 
50,718
Total Proved and Probable
79,409
 
$208,321

Our proved reserves were calculated using deterministic methods.  Our probable reserves were calculated using probabilistic methods and represent a 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 $6.60 and $6.44 per Mcf and $78.14 and $84.61 per barrel for 2012 and 2011, respectively.

Drilling Activities

The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2012, 2011, and 2010:

 
Year Ended December 31,
 
2012
 
2011
 
2010
 
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
 
1.0
 
0.5
 
--
 
--
United States
4.0
 
1.6
 
--     
 
--     
 
--
 
--
Total
5.0
 
2.1
 
1.0
 
0.5
 
--
 
--
                       
Total wells drilled
6.0
 
2.6
 
2.0
 
1.0
 
--
 
--

 
28
 
 

 


The productive exploratory well drilled in 2012 was our Komorze 3-K well, which had gross proved reserves of 4.7 Bcf of natural gas at year-end 2012.  The exploratory dry holes in 2012 include the Kutno-2 well in Poland and four Alberta Bakken wells drilled in Montana.  Of these wells, three were drilled in 2011, but all were determined to be noncommercial during 2012.  The productive exploratory well drilled in 2011 was our Lisewo-1 well, which had gross proved reserves of 26.5 Bcf of natural gas at year-end 2012.  The exploratory dry hole in Poland drilled in 2011 was our Machnatka-2 well.  The foregoing does not include the Plawce-1 and Frankowo-1 wells being evaluated in Poland at 2012 year end.  We did not drill any development wells in 2012, 2011, or 2010.

Wells and Acreage

As of December 31, 2012, our gross and net producing wells consisted of the following:

 
Number of Wells
 
Gas
 
Oil
 
Gross
 
Net
 
Gross
 
Net
Well count:
             
Poland(1)
6.0
 
3.2
 
-- 
 
-- 
United States
--     
 
--     
 
131.0
 
112.0
Total
6.0
 
3.2
 
131.0
 
112.0
_______________
 
(1)
In addition to the wells producing at year-end 2012, a seventh well began production in January 2013, and an eighth well was being readied for production about the end of the first quarter.  We also had two additional 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, 2012.  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
Warsaw South project area
--
 
--
 
463,000
 
236,000
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
 
2,680,000
 
2,009,000
               
United States:
             
Montana(2)
10,732
 
10,418
 
12,765
 
11,131
Nevada
400
 
128
 
9,332
 
6,351
Total
11,132
 
10,546
 
22,097
 
17,482
               
Total Acreage
14,757
 
12,372
 
2,702,097
 
2,026,482
_______________
 
(1)
All gross and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.
(2)
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.  The incremental acreage that remains subject to the joint venture arrangement at year-end 2012 is included in the total gross and net undeveloped acres in Montana.
 
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Polish Properties

Producing Properties

A summary of our average daily production, weighted average interest, and weighted average net revenue interest for our Poland producing properties during 2012 follows:

 
Average Daily
     
Average
 
Production (Mcfe)
 
Average
 
Net Revenue
 
Gross
 
Net
 
Interest
 
Interest
Fences project area
27,099
 
11,934
 
  44%
 
  44%
Grabowka
243
 
243
 
100%
 
100%
Total
27,343
 
12,178
       

Production, Transportation and Marketing

During 2012, we resolved a pipeline bottleneck issue that was constraining production at our KSK wells due to restricted pipeline capacity.  We began full production from all three KSK wells in late June of 2012.  We do not expect to encounter any such production restraints during the foreseeable future.

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 2012, 2011, and 2010:
 
     
Average
   
 
Production
 
Production Cost
 
Average Sales Price
 
Gas
 
Oil
 
per Mcfe(1)
 
Gas
 
Oil
 
(Mcf)
 
(Bbls)
     
(Per Mcf)
 
(Per Bbl)
2012
                 
Roszkow
2,169,000
 
-
 
$0.18   
 
$7.27   
 
$    -      
Zaniemysl
492,000
 
-
 
0.36
 
5.44
 
-
Sroda/Kromolice-1
1,027,000
 
-
 
0.24
 
6.90
 
-
Kromolice-2
680,000
 
-
 
0.27
 
6.89
 
-
Other wells(3)
89,000
 
-
 
2.54
 
1.59
 
-
Total
4,457,000
 
-
 
0.28
 
6.81
 
-
                   
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
 
-

_______________
 
(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 DD&A; 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 ongoing costs of maintaining the production facilities at our Wilga and Kleka wells, neither of which is currently in production.
 
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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 2012 follows:
 
Average Daily
     
Average
 
Production (Bbls)
 
Average
 
Net Revenue
 
Gross
 
Net
 
Interest
 
Interest
Montana
181
 
138
 
97%
 
83%
Nevada
34
 
8
 
39%
 
29%
Total United States producing properties
215
 
146
       

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, 21 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 2012, 2011, and 2010:

 
Year Ended December 31,
 
2012
 
2011
 
2010
United States producing property data:
         
Average daily net oil production (Bbls)
146
 
155
 
168
Average sales price per Bbl
$76.87
 
$83.02
 
$68.09
Average production costs per Bbl(1)
$45.00
 
$50.41
 
$39.84
_______________
 
(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.
 
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We sell oil at posted field prices to one of several purchasers in each of our production areas.  We sell all of our Montana production, which represents over 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 reforms 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.

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 2012.  Economists predict another positive year during 2013, as it also builds foundations for sustainable future growth.  Poland’s economy remains one of the more attractive and safer debt markets in Europe.
 
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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, or the former Geological and Mining Law of February 4, 1994 (as amended), 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 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.  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 2013 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 July 2014 to Sept 2017.  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 210 square kilometers of 3-D seismic data, and drilling two wells.
 
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Warsaw South/Wilga Project Area

The Wilga project area consists of a single oil and gas exploration and production concession covering Block 255 held by us.  Following a full completion of the previous work commitment, a concession extension is in progress and should be completed in 2013.  Adjacent to Block 255, we hold two exploration concessions expiring in July 2013 covering Blocks 234 and 254.  We currently plan to seek an extension of the Block 254 concession.

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 2015.  Work commitment includes reentering and producing the Grabowka gas field; recompletion of one out of three wells was completed and production began in 2009.  The second well was recompleted in late 2012, and production is scheduled to begin in the first quarter of 2013.  We plan to recomplete the third well in 2013.

Edge Project Area

The Edge project area consists of four oil and gas exploration concessions granted for 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, besides reprocessing and reinterpretation of existing data, the acquisition of 600 kilometers of new 2-D seismic data and 50 square kilometers of 3-D have been completed, and the drilling of the first of these four wells began in December 2012.  We currently plan to seek an extension of three out of four of these concessions expiring in September 2013.

Block 246 Project Area

The Block 246 project area is adjacent to the Fences project area in the southwest and consists of a single concession granted for six years (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.  Currently, besides reprocessing and reinterpretation of existing data, the acquisition of 40 kilometers of 2-D seismic data and 26 square kilometers of 3-D seismic data have been completed, as well as the drilling of one well.

Block 229 Project Area

The Block 229 project area is adjacent to the Fences project area in the east and consists of two exploration concessions granted for 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.  Currently, besides reprocessing and reinterpretation of existing data, the acquisition of 50 kilometers of 2-D seismic data has been completed.

As of December 31, 2012, all required usufruct/concession payments had been made for each of the above project areas.
 
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Government Regulation

Poland

Our activities in Poland are subject to political, economic, and other uncertainties, including the adoption of new laws, regulations, or administrative policies that may adversely affect us or the terms of our exploration or production rights; political instability and changes in government or public or administrative policies; export and transportation tariffs and local and national taxes; foreign exchange and currency restrictions and fluctuations; repatriation limitations; inflation; environmental regulations; and other matters.  These operations in Poland are subject to the Geological and Mining Law dated as of June 9, 2011 (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.

Proposed Changes to the Polish Hydrocarbon Industry Tax Regime

As a result of the political and administrative interest discussed above, in late 2012, the Polish government approved guidelines for new hydrocarbon legislation, including, among other things, higher royalties on hydrocarbons produced, a new cash flow tax based on the positive cumulate cash flow of exploration and development projects, as well as changes to how usufruct fees are determined and how concessions are awarded.  The Minister of Environment was directed to prepare a draft law, which was published in early 2013.

The recent draft new law addresses the concession system and environmental regulation and forms a basis for appointing a National Energy Minerals Operator, or NOKE.  Principal proposals for consideration include the replacement of the current three types of concessions with one 10 to 30 year concession for exploration and production; new requirements for prequalification for applicants for concessions, including the applicant’s proposed royalty or similar payment to NOKE; a mechanism by which NOKE may participate in up to 5% of the costs and a percentage of revenue as proposed by the concession applicant; and increases of revenues to local authorities from oil and gas production.  A Future Generation Fund would be created to invest profits obtained by NOKE toward promotion of economic development.  Administrative changes would be aimed at improving concession administration.

Comments from the industry/general public will be invited and either taken into account or not in preparing a revised draft by the Minister.  The revised draft will be subject to review by various governmental committees and agencies, and then a final draft will be subject to approval by the government, before it is sent to the Parliament.  It is impossible to predict whether any new proposals will be adopted or the substance of any changes that might be effected.
 
35
 
 

 


The new legislation is meant to increase governmental revenue from the oil and gas industry, with the stated intention for the total royalty and tax burden of an energy company to approach 40% of taxable income, which is approximately double that of the current fiscal regime.  The new law, once approved by Parliament, would become effective January 1, 2015, at the earliest, but in any event not prior to the first commercial production of shale gas in the country.  The new royalty and tax structure would be applicable to all production, without regard to when the well was drilled or the relevant concession granted.

Although the draft law was recently published, we are unable to estimate the impact of the law on our financial results or operations.  However, any increase in royalties or income taxes to which we may be subject would have an adverse impact.

While these draft proposals are being reviewed and considered, we may encounter delays or policy changes respecting the approval by the Minister of Environment of changes to provisions of our concessions, such as our requests for extensions of work commitments or other modifications.

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.
 
36
 
 

 


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 2011 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, sanctions, or penalties arising from civil or criminal actions and attendant negative publicity.

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.
 
37
 
 

 


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, in December 2012, the EPA released its study on the environmental effects of hydraulic fracturing and reported the methodologies and focus of this ongoing study, with a draft initial report to be released in late 2014.

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 and the use of tribal contractors.  We believe we are currently in full compliance with all material provisions of such regulations.
 
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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.

Resource Extraction Reporting

Under 2012 regulations adopted by the SEC under the Dodd-Frank Wall Street Reform and Consumer Protection Act, in 2014 we will be required to begin reporting annually to the SEC the payments we make to governmental entities to further commercial development of oil and gas.  We will tag the information filed in the same XBRL format that we use for our financial statements that we file with the SEC.  We expect to incur new accounting and administrative costs in implementing this reporting system.  The reports we file will be publicly available and may be accessed by governmental agencies, competitors, and others.

Hydraulic Fracturing

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 and rates sufficient to crack rock in the target formation to extend the cracks and leave behind a propping agent sufficient to keep the cracks open after pressurization ceases.  The purpose of this treatment is to provide a pathway that allows the hydrocarbons to migrate from the rock to the well bore, thus stimulating natural gas and oil production.

We plan to hydraulically fracture three separate intervals encountering approximately 480 meters of relatively tight Rotliegend sandstone in the Plawce well in Poland.  We have no current plans for future hydraulic fracturing in the United States.

If the results of our initial hydraulic fracturing tests in the Plawce well in Poland warrant, we expect that additional wells in the Plawce area in Poland may be completed using hydraulic fracturing techniques.  In addition, if subsequent evaluation of the results from our 2012 hydraulic fracturing of horizontal wells in shale formations underlying our SWCBSU in Montana warrant, we expect that we may use hydraulic fracturing in the future in Montana.  We expect to use industry-standard, long-established third-party service providers with specialized experience and equipment in hydraulic fracturing.  Prior to initiating a horizontal lateral to an existing well or drilling a new well that might result in a horizontal 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;
 
 
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·  
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 respecting 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 December 2012, the EPA released its study on the environmental effects of hydraulic fracturing.  Also, the EPA reported the methodologies and focus of this ongoing study and announced that it expects to release a draft initial report in late 2014.  Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.
 
40
 
 

 


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 fracturing 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.
 
41
 
 

 


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

“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.
 
42
 
 

 


“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.
 
43
 
 

 


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 trading 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
2013:
     
First Quarter (through March 9, 2013)
$3.36  
 
$ 4.40  
       
2012:
     
Fourth Quarter
3.87
 
7.58
Third Quarter
5.84
 
8.78
Second Quarter
4.60
 
6.11
First Quarter
4.56
 
6.82
       
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  

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 8, 2013, we had approximately 9,500 stockholders.

Recent Sales of Unregistered Securities

None.
 
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ITEM 6. SELECTED FINANCIAL DATA
 

The following selected financial data for the five years ended December 31, 2012, 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,
   2012    2011    2010    2009    2008
   (In thousands, except per share amounts)
Statement of Operations Data:  
Revenues:
                 
Oil and gas sales
$ 34,461 
  
$ 29,807 
 
$ 22,914 
 
$ 12,772 
 
$ 13,494 
Oilfield services
2,137 
 
5,631 
 
2,099 
 
1,892 
 
4,347 
Total revenues
36,598 
 
35,438 
 
25,013 
 
14,664 
 
17,841 
Operating costs and expenses:
                 
Lease operating expenses(1)
3,631 
 
3,834 
 
3,473 
 
3,478 
 
3,441 
Exploration costs(2)
23,795 
 
16,618 
 
3,038 
 
4,829 
 
15,389 
Impairment of oil and gas properties(3)
2,562 
 
72 
 
564 
 
1,864 
 
14,746 
Asset retirement obligation gain
-- 
 
(52)
 
(264)
 
(529)
 
-- 
Oilfield services costs
1,610 
 
4,458 
 
1,550 
 
1,412 
 
2,751 
Depreciation, depletion and amortization
4,239 
 
3,397 
 
2,626 
 
1,602 
 
1,720 
Accretion expense
63 
 
68 
 
92 
 
41 
 
84 
Loss on sale of asset
49 
 
-- 
 
-- 
 
-- 
 
-- 
Stock compensation
2,325 
 
1,744 
 
1,379 
 
1,693 
 
2,367 
Bad debt expense
-- 
 
-- 
 
-- 
 
-- 
 
460 
General and administrative costs (G&A)
8,369 
 
8,396 
 
7,973 
 
7,257 
 
7,030 
Total operating costs and expenses
46,643 
 
38,535 
 
20,431 
 
21,647 
 
47,988 
                   
Operating income (loss)
(10,045)
 
(3,097)
 
4,582 
 
(6,983)
 
(30,147)
                   
Other income (expense):
                 
Interest expense
(2,485)
 
(2,167)
 
(1,936)
 
(654)
 
(672)
Interest and other income
356 
 
188 
 
829 
 
54 
 
394 
Foreign exchange (loss) gain
16,292 
 
(23,448)
 
(4,233)
 
7,053 
 
(24,279)
Total other (expense) income
14,163 
 
(25,427)
 
(5,340)
 
6,453 
 
(24,557)
                   
Net income (loss)
$   4,118 
 
$(28,524)
 
$      (758)
 
$    (530)
 
$(54,704)
 

– Continued –
 
45
 
 

 
 
 
  Year Ended December 31,
   2012    2011    2010    2009    2008
   (In thousands, except per share amounts)
Basic and diluted net income (loss)
                 
per common share
$     0.08 
 
$    (0.57)
 
$   (0.02)
 
$   (0.01)
 
$    (1.35)
                   
Basic and diluted weighted average
                 
shares outstanding
52,274 
 
50,262 
 
43,387 
 
42,529 
 
40,420 
                   
Cash Flow Statement Data:
                 
Net cash provided by (used in) operating
                 
activities
$  (1,233)
 
$     (120)
 
$  7,249 
 
$ (5,829)
 
$(14,248)
Net cash (used in) provided by
                 
investing activities
(16,350)
 
(18,486)
 
(7,814)
 
(3,999)
 
(11,772)
Net cash provided by (used in)
                 
financing activities
-- 
 
50,842 
 
16,092 
 
(2,676)
 
40,121 
                   
Balance Sheet Data:
                 
Working capital(4)
$ 30,395 
 
$ 49,787 
 
$18,212 
 
$  3,452 
 
$ 13,965 
Total assets
105,954 
 
110,224 
 
66,604 
 
42,070 
 
54,802 
Notes payable
40,000 
 
40,000 
 
35,000 
 
25,000 
 
25,000 
Total stockholders’ equity
54,799 
 
58,627 
 
23,837 
 
10,745 
 
15,154 
 
_______________
 
(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.
 
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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, 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 almost tripled since 2009 to $34.5 million in 2012, a compound annual growth rate of 39% per year.

·  
Total revenues have likewise increased, with a compound annual growth rate of 36% per year during the same period.

·  
Oil and gas production has more than doubled since 2009 to 4.8 Bcfe in 2012, a compound annual growth rate of 30%.

·  
Natural gas prices in Poland continue to show strength in the face of economic uncertainty.  At the time of this report, the low-methane tariff in Poland was 40% higher than at year-end 2009.

·  
The average gas price we received in 2012, taking into account currency fluctuations throughout the year, was 36% higher than the amount we received in 2009.

·  
We continue to diversify our production risk profile.  At the time of this report, we were producing gas from seven wells in Poland, with three additional wells scheduled to begin production during 2013.  At the end of 2009, we were producing gas from only three wells in Poland.

·  
Our exploration and development spending continues to increase.  The amounts we reported for exploration costs and capital additions for 2012, which represent a record level of activity for us, were triple our 2009 spending.

·  
Since 2009, we have been designated to act as the operator for the permitting, designing, and construction of all new production facilities in Poland.
 
47
 
 

 


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

·  
a new hydrocarbon law, which, if enacted as proposed, would increase the royalties and taxes we pay in Poland;

·  
delays such as those associated with the commencement of production from our Winna Gora and KSK wells, which prevented higher production and revenue gains during 2012 and 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 drilling, first production, and lower initial production rates;

·  
obtaining better success ratios in our exploration efforts outside of our core Fences area; and

·  
volatile noncash adjustments for foreign currency fluctuations that continue 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 different from what United States investors typically see when comparing us 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 2012.  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.  At the time of this report, the low-methane tariff, which is the basis for all of our gas contracts in Poland, is 40% higher than it was at the end of 2009.

A major component of the gas 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 Western Europe 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 2012.  While the economy is expected to slow somewhat, economists are still predicting positive growth during 2013.  These factors may act as cushions against possible declines in prices.  As of year-end 2012, 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 2009 through 2012 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.
 
48
 
 

 



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 parent company’s 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 2012, the zloty fluctuated between a low of 3.07 zlotys per U.S. dollar to a high of 3.58 zlotys per U.S. dollar, a fluctuation of 17%.  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 2013 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our U.S. dollar-denominated revenues, and a slightly negative impact on our dollar-denominated costs, compared to 2012.

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 2012, the exchange rate was 3.10 zlotys per U.S. dollar compared to 3.42 zlotys per U.S. dollar at the end of 2011.  This 9% year-end to year-end appreciation of the zloty represents a decrease 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, 2012, and creates the noncash foreign exchange gain 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 of the notes to the consolidated financial statements included in this report.

Proposed Changes to Poland’s Hydrocarbon Legislation

In late 2012, the Polish government approved guidelines for new hydrocarbon legislation, including, among other things, higher royalties on hydrocarbons produced, a new cash flow tax based on the positive cumulative cash flow from exploration and development projects, as well as changes to how usufruct fees are determined and how concessions are awarded.  The Minister of Environment has been directed to prepare a draft law, which was published in early 2013.  Comments from the industry/general public will be invited, and either taken into account or not in preparing a revised draft by the Minister.  The revised draft will be subject to review by various governmental committees and agencies, and then a final draft will be subject to approval by the government, before it is sent to the Parliament.

The new legislation is meant to increase governmental revenue from the oil and gas industry, with the stated intention for the total royalty and tax burden of an energy company to approach 40% of taxable income, which is approximately double that of the current fiscal regime.  The new law, once approved by Parliament, would become effective January 1, 2015, at the earliest, but in any event not prior to the first commercial production of shale gas in the country.  The new royalty and tax structure would be applicable to all production, without regard to when the well was drilled or the relevant concession granted.
 
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Although the draft law was recently published, we are unable to estimate the impact of the law on our financial results or operations.  However, any increase in royalties or income taxes to which we may be subject would have an adverse impact.

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, 2012, 2011, and 2010 (in thousands):
 
 
Reportable Segments
   
   
Oilfield Services
   
 
Exploration & Production
   
 
Poland
U.S.
 
Non-Segmented
Total
           
Year ended December 31, 2012:
         
Revenues
$  30,344
$ 4,117
$2,137
$              --
$   36,598
Net income (loss)(1)
2,031
(770)
(582)
3,439
4,118
           
Year ended December 31, 2011:
         
Revenues
$  25,120
$ 4,687
$5,631
$              --
$   35,438
Net income (loss)(2)
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)(3)
12,389
1,818
(194)
(14,771)
   (758)
 
_______________
 
(1)
Nonsegmented reconciling items for 2012 include $8,369 of G&A costs, $2,325 of noncash stock compensation expense, $16,292 of noncash foreign exchange gains, $2,129 of interest expense (net of other income), and $30 of corporate DD&A.
(2)
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.
(3)
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.

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 $30.3 million during 2012, compared to $25.1 million and $18.7 million in 2011 and 2010, respectively.  Our 2012 gas revenues increased $5.2 million from 2011 levels by approximately $2.5 million due to higher gas prices, coupled with approximately $2.7 million related to higher annual production.  Gas revenues in 2011 increased $6.4 million from 2010 levels by approximately $2.8 million due to higher gas prices, coupled with approximately $3.6 million related to higher annual production.

Company-wide net gas production increased from a daily rate in 2011 of approximately 11.1 MMcfd to a record rate of approximately 12.2 MMcfd in 2012, an increase of 10%.  In early February 2013, gas was flowing in Poland at an average rate of 13.6 MMcfd, net to our interest.
 
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In addition to our increased production, higher gas prices, which were partially offset by negative currency changes, resulted in higher gas revenues during 2012.  The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, averaged 21% higher during the full year of 2012 compared to 2011.  The increase was primarily a function of a 16.9% increase that became effective for us on April 1, 2012.  This increase was preceded by a 12.5% increase that became effective for us on August 1, 2011.  However, the increase in prices was partially offset by the effect of currency changes from year to year.  Strength in the U.S. dollar against the Polish zloty decreased our U.S. dollar-denominated gas prices.  The average exchange rate during 2012 was 3.24 zlotys per U.S. dollar.  The average exchange rate during 2011 was 2.96 zlotys per U.S. dollar, a change of approximately 9%.

The primary driver of our increased production in 2012 was the full resolution of a pipeline bottleneck during the second quarter of 2012, following which the KSK wells were placed on full production.  Gas production at our three KSK wells averaged 9.5 MMcfd during 2012, compared to 5.0 MMcfd during 2011.  At year-end, the wells were producing at a combined rate of 12.7 MMcfd.  Gas at KSK is being sold to PGNiG at a contracted rate equal to 86% of the published low-methane tariff.  We have a 49% interest in the KSK wells.

Gas production at our Roszkow well averaged 12.1 MMcfd during 2012, compared to 12.7 MMcfd during 2011.  At year-end, the well was producing at a rate of 11.7 MMcfd.  Gas at Roszkow is being sold to PGNiG at a contracted rate equal to 95% of the published low-methane tariff.  We have a 49% interest in the Roszkow well.

Gas production at our Zaniemysl well averaged 5.5 MMcfd during 2012, compared to 8.9 MMcfd during 2011.  At year-end, the well was producing at a rate of 2.7 MMcfd.  Gas at Zaniemysl is being sold to PGNiG at a contracted rate equal to 70% of the published low-methane tariff.  We have a 24.5% interest in the Zaniemysl well.

Gas production began at our Winna Gora well in January of 2013.  At the time of this report, the well was producing approximately 1.6 MMcfd (0.8 MMcfd net to our 49% interest).  Gas at Winna Gora is being sold to PGNiG at a contracted rate equal to 86% of the published low-methane tariff.

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, 2012, 2011, and 2010, is set forth in the following table:

 
Year Ended December 31,
 
2012
 
2011
 
2010
Revenues
$30,344,000
 
$25,120,000
 
$18,730,000
Percent change versus prior year
+21%
 
+34%
 
+99%
Average price (per Mcf)
$6.81
 
$6.19
 
$5.39
Percent change versus prior year
+10%
 
+15%
 
+8%
Production volumes (Mcf)
4,457,000
 
4,060,000
 
3,473,000
Percent change versus prior year
+10%
 
+17%
 
+85%
Lifting costs per Mcf(1)
$0.28
 
$0.23
 
$0.29
Percent change versus prior year
+22%
 
-21%
 
-40%
_______________
 
(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 $4.1 million, $4.7 million, and $4.2 million for the years ended December 31, 2012, 2011, and 2010, respectively.  Lower average oil prices in 2012 compared to 2011 combined with lower production to cause the decrease in revenues.  Our average oil price during 2012 was $76.87 per barrel, a 7% decrease compared to $83.02 per barrel received during 2011.  Production from our U.S. properties declined by 5% due to normal production declines.

U.S. oil revenues in 2012 decreased from 2011 levels by approximately $.3 million due to lower oil prices, combined with approximately $0.3 million related to production declines.  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.
 
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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, 2012, 2011, and 2010, is set forth in the following table:

 
Year Ended December 31,
 
2012
 
2011
 
2010
Revenues
$4,117,000
 
$4,688,000
 
$4,184,000
Percent change versus prior year
-12%
 
+12%
 
+25%
Average price (per Bbl)
$76.87
 
$83.02
 
$68.09
Percent change versus prior year
-7%
 
+22%
 
+31%
Production volumes (Bbl)
53,553
 
56,462
 
61,463
Percent change versus prior year
-5%
 
-8%
 
-4%
Lifting costs per Bbl(1)
$44.80
 
$50.41
 
$39.84
Percent change versus prior year
-11%
 
+27%
 
-1%
_______________
 
(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 $3.6 million in 2012, $3.8 million in 2011, and $3.5 million in 2010.  Operating costs in the United States decreased in 2012 by approximately $0.4 million over 2011 costs, due to $0.3 million spent during 2011 to remediate a small oil leak in Montana along with higher workover costs incurred on our existing producing wells during that year.  Operating costs in Poland increased 24% in 2012 from 2011 levels.  Most operating costs in Poland arise from fixed costs at our production facilities; fees paid to the operator of our production facilities increased year over year.

Exploration Costs.  Exploration expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes.  Exploration costs were $23.8 million, $16.6 million, and $3.0 million for the years ended December 31, 2012, 2011, and 2010, respectively.  The increase in 2012 was a function of increased dry-hole costs, offset by lower geological and geophysical costs.

Geological and geophysical costs, or G&G costs, were $11.1 million, $15.3 million, and $2.0 million for the years ended December 31, 2012, 2011, and 2010, 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 $12.7 million, $1.3 million, and $1.0 million for the years ended December 31, 2012, 2011, and 2010, respectively.  Our 2012 dry-hole costs were associated primarily with our Kutno well in Poland.  The Kutno well, which was the deepest well ever drilled in Poland, was found to be noncommercial during the third quarter of 2012.  Under the terms of a farmout agreement, our partner agreed to pay 60% of the costs of the well.  Total costs to us were approximately $12.2 million.  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, we agreed to pay 51% of the costs and continue drilling to a depth of approximately 4,500 meters.  During 2010, recompletion attempts failed to establish commercial production at our Zakowo project in Poland.

Impairment Costs.  Impairments of oil and gas properties were $2.6 million, $72,000, and $0.6 million for the years ended December 31, 2012, 2011, and 2010, respectively.  During 2012, we impaired the cost of certain concessions in Poland, in the amount of $0.8 million, due to our determination that they were not prospective for hydrocarbon accumulation.  Also during 2012, we impaired all capitalized costs associated with our Alberta Bakken project in Montana, which included $1.4 million in drilling costs incurred during 2011 and $0.4 million in leasehold costs.  We have no plans to pursue this project in the near future.  During 2011, we dropped a small amount of non-prospective acreage near our Kutno project and impaired the associated undeveloped leasehold costs.
 
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Asset Retirement Obligation.  We recorded gains associated with future asset retirement obligations of $0, $52,000, and $0.3 million for the years ended December 31, 2012, 2011 and 2010, 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 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 due to property impairments.

DD&A Expense - Producing Operations.  DD&A expense for producing properties was $3.1 million, $2.3 million, and $1.8 million for the years ended December 31, 2012, 2011, and 2010, respectively.  The 35% increase from 2011 to 2012 is a combination of higher DD&A expenses due to increased production at our KSK wells, along with higher DD&A expenses resulting from negative revisions in proved reserves at our KSK and Zaniemysl wells, which are discussed below.  The 28% increase from 2010 to 2011 was primarily a function of our increased production in Poland.

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 $63,000, $68,000, and $92,000 for the years ended December 31, 2012, 2011 and 2010, 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 $2.1 million, $5.6 million, and $2.1 million for the years ended December 31, 2012, 2011, and 2010, respectively.  We drilled five wells for third parties, including one drilled for our Alberta Bakken joint venture, during 2012, along with additional well service work.  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.  Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.  We cannot accurately predict future oilfield services revenues.

Oilfield Services Costs.  Oilfield services costs were $1.6 million, $4.5 million, and $1.6 million for the years ended December 31, 2012, 2011, and 2010, respectively, or 76%, 79%, and 74% of oilfield-servicing revenues, respectively.  The changes in services costs from year to year 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 $1.1 million, $1.0 million, and $0.7 million for the years ended December 31, 2012, 2011, and 2010, respectively.  We spent $0.7 million, $1.2 million, and $1.1 million on upgrading our oilfield-servicing equipment during 2012, 2011, and 2010, respectively.  These capital additions resulted in higher DD&A expenses for this segment during 2012 and 2011.

Nonsegmented Items

G&A Costs - Corporate.  G&A costs were $8.4 million, $8.4 million, and $8.0 million for the years ended December 31, 2012, 2011, and 2010, respectively.  Increased costs in 2012 associated with higher headcount in Poland were offset by lower legal and other fees in the United States.  Our 2011 G&A costs rose from 2010 levels primarily due to higher legal and investor relations-related costs.
 
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Stock Compensation.  Stock compensation expense recorded for 2012 represents $2.3 million of amortization related to restricted stock and stock options granted to employees in 2012, 2011, 2010, and 2009.  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.

Interest and Other (Income) Expense - Corporate.  Interest and other (income) expense was $2.1 million, $2.0 million, and $1.1 million for the years ended December 31, 2012, 2011, and 2010, respectively.  During 2012, we incurred $2.5 million in interest expense, which included $0.5 million of amortization of loan fees and $0.5 million in unused commitment fees.  Interest and other income was $0.4 million during 2012.

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.

Foreign Exchange.  We incurred foreign exchange gains of $16.3 million for the year ended December 31, 2012, and foreign exchange losses of $23.4 million and $4.2 million for the years ended December 31, 2011 and 2010, respectively.

Income Taxes.  We reported net income of $4.1 million for the year ended December 31, 2012, and net losses of $28.5 million and $0.8 million for the years ended December 31, 2011 and 2010, respectively.  No income tax expense was recognized for 2012 due to the reversal of valuation allowances that offset income tax expense for the period. 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 decreased at year-end 2012 due primarily to negative revisions at our KSK and Zaniemysl wells due to declining well head pressures, along with negative revisions in the United States due to lower oil prices.  Positive reserve revisions at our Roszkow, Winna Gora, and Lisewo wells due to more favorable technical data, along with new reserves at our Komorze-3K well (which was completed during the year), partially offset our record 2012 gas production and the negative revisions.
 
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The following table highlights year-end reserve volumes and values and shows the change from 2011 to 2012:
 
 
2012
 
2011
 
Change
 
(In thousands)  
   
Proved Reserve Volumes:          
Gas Reserves (Mcf)
44,121
 
49,636
 
-11%
Oil Reserves (Bbls)
594
 
639
 
-7%
Total Reserves (Mcfe)
47,688
 
53,470
 
-11%
           
Proved Reserve Values:
         
Reserves PV-10 Value
$157,603
 
$169,567
 
-7%
 
Changes in proved reserves were as follows:

 
2012
 
2011
 
2010
(MMcfe)
         
Proved Reserves Beginning of Year
53,470 
 
43,793 
 
50,446 
Extensions, Discoveries, and Other Additions
2,313 
 
12,245 
 
-- 
Revisions of Previous Estimates
(3,317)
 
1,828 
 
(2,814)
Production
(4,778)
 
(4,396)
 
(3,839)
Proved Reserves End of Year
47,688 
 
53,470 
 
43,793 

Extensions, Discoveries, and Other Additions.  All of the 2012 additions to proved reserves that result from the discovery of new fields are associated with our Komorze-3K well, which was completed for production during 2012.

Revisions.  Revisions represent changes in previous reserves estimates, either positive revisions upward or negative revisions 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.  During 2012, excluding the volume reduction due to annual production, we recorded downward revisions at our Zaniemysl and KSK wells due to, respectively, water influx and lower than expected wellhead pressures obtained during the fourth quarter of the year.  These were partially offset by upward reserve revisions at our Roszkow, Lisewo, and Winna Gora wells, where new pressure data indicates that the initial gas-in-place for these wells may be more than estimated at year-end 2011.  We also recorded upward revisions of approximately 9,000 barrels of oil in the United States, primarily due to lower operating costs resulting in more economically recoverable barrels.  During 2011, excluding the 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.  (See Items 1 and 2, Business and Properties).

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

2013 Operational Trends

We currently expect that our 2013 production will be higher than our 2012 production rates with the addition of production at our Winna Gora-1, Lisewo-1, and Komorze 3-K wells.  Production began at Winna Gora-1 in late January of 2013.  Production is expected to begin at Lisewo-1 and at Komorze-3K during the second half of 2013.  We currently expect to receive 86% of the published low-methane tariff, adjusted for energy content, for each of the three new wells.  The amount of revenue from this increased production will depend on applicable gas sales prices and prevailing currency exchange rates.
 
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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 2013 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.

2012 Liquidity and Capital

Working Capital (current assets less current liabilities).  Our working capital was $30.4 million as of December 31, 2012, a decrease of $19.4 million from December 31, 2011.  The primary causes of the decrease are our increased exploration costs in 2012 and the classification of $7.0 million as a current portion of our long-term debt.  At the time of this report, we are in the process of extending and expanding our credit facility.  If we do not complete a new credit facility, we will be required to make a $7.0 million principal payment under the terms of our existing facility on December 31, 2013.

Our current assets at year-end 2012 included approximately $34.0 million in cash and cash equivalents, $4.2 million in accrued oil and gas sales from both the United States and Poland, and $6.8 million in receivables from our joint interest partners in both the United States and Poland that were collected in early 2013.  Almost the entire balance of joint interest receivables at year-end 2012 was due from PGNiG, primarily related to the drilling of our Kutno well, where we act at the operator.  Our current liabilities at year-end included approximately $7.4 million payable by FX Poland for various drilling and development operations in Poland that were paid in early 2013.

Operating Activities.  Net cash used in operations during 2012 and 2011 was $1.2 million and $0.1 million, respectively.  Net cash provided by operating activities during 2010 was $7.2 million.  A $7.2 million increase in exploration costs offset higher revenues in 2012, leading to a decline in cash provided from operating activities in 2012.  Likewise, a $13.6 million increase in exploration costs in 2011 offset higher revenues.

Investing Activities.  We used net cash in investing activities of $16.3 million, $18.5 million, and $7.8 million in 2012, 2011, and 2010, respectively.  In 2012, we spent $15.8 million for oil and gas property additions, all of which was related to our Polish drilling activities.  We also spent $0.7 million adding to our oilfield services and office equipment.  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.
 
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Financing Activities.  Our cash flow from financing activities was $50.8 and $16.1 million, during 2011 and 2010, respectively.  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.

There were no financing transactions during 2012.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2013 include our working capital of $30.4 million at year-end 2012, available credit under our expanded credit facility, 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.  As of December 31, 2012, we had $40 million outstanding under the facility, and $15 million of available credit.  Our borrowing base is scheduled to be reduced to $44 million on June 30, 2013.

We currently have increased cash from our operating activities to help fund our exploration and development activities in 2013.  We expect that our 2013 production will be higher than our 2012 production with the addition of production at our Winna Gora-1, Lisewo-1, and Komorze 3-K wells.  Production began at Winna Gora-1 in late January of 2013.  Production is expected to begin at Lisewo-1 and at Komorze-3K during the second half of 2013.  We currently expect to receive 86% of the published low-methane tariff, adjusted for energy content, for each of the three new wells.  The amount of revenue from this increased production will depend on applicable gas sales prices and prevailing currency exchange rates.
 
 
We have an effective Securities Act universal shelf registration statement under which we may sell up to $200 million of equity or debt securities of various kinds.  In June 2012, 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.  Assuming all $50 million of common stock covered by the at-the-market facility were sold, the remaining $150 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 2012, we were in the process of drilling the Tuchola-3 well, having incurred a total cost of $1.5 million during the year.  We began drilling the Mieczewo-2 well in early 2013.  Our total costs for these wells once drilling is completed are expected to be approximately $12 million.  We have agreed with PGNiG to conduct a fracture stimulation test at the Plawce-2 well during the first half of 2013.  We were also in the process of building a pipeline and production facilities at our Lisewo well.  We had no other firm commitments for future capital and exploration costs at 2012 year end.

We expect our primary use of cash for 2013 will be for our exploration and development activities in Poland and the United States.  Our board of directors has approved projects whose cost is expected to range from $60 million to $70 million for production facilities for existing discoveries, exploration and development wells, and 2-D and 3-D seismic data acquisition and analysis, including those items noted above.  All of the approved projects may not be completed during 2013, but we do expect to start work on all of them in the next 12 months.  In 2012, we approved a capital budget of similar size.  Our actual costs in 2012 were $35.7 million, but by early January of 2013, we had started work on projects totaling $56.3 million originally scheduled for 2012.
 
57
 
 

 



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 services; 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, 2012, we have incurred cumulative net losses of approximately $186 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 negotiated in prior years 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, 2012, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:

 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
(In thousands)
Credit facility
$40,000
 
$7,000
 
$22,000
 
$ 11,000
 
$        --
 
$        --
Interest payments on long-term debt
3,318
 
1,885
 
1,146
 
287
 
  --
 
  --
Total
$43,318
 
$8,885
 
$23,146
 
$11,287
 
$       --
 
$       --

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, 2012, 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.
 
58
 
 

 


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 $1.4 million related to asset retirement obligations on our Consolidated Balance Sheet at December 31, 2012, excluded from the table above.  Due to the nature of these obligations, we cannot determine precisely when the payments will be made to settle these obligations.

New Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued new standards that require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  The new standards are effective for annual periods beginning on or after January 1, 2013.  We are currently evaluating the provisions of the new standards and assessing the impact, if any, it may have on our financial position and results of operations.

In June 2011, the 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.
 
59
 
 

 


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.  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, 2012, 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.
 
60
 
 

 


 
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 2012, the zloty fluctuated between a low of 3.07 zlotys per U.S. dollar to a high of 3.58 zlotys per U.S. dollar, a fluctuation of 17%.  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 2013 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our U.S. dollar-denominated revenues compared to 2012.  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.


 
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.
 
61
 
 

 


 
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, 2012, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2012, 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.
 
62
 
 

 


PART III

 
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 

The information from our definitive proxy statement for our 2013 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 2013 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 2013 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 2013 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 2013 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.
 
63
 
 

 


PART IV

 
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 

(a)           The following documents are filed as part of this report or incorporated herein by reference.
 
   1. Financial Statements.  See the following beginning at page F-1:  
     
Page
   
Management’s Report on Internal Control over Financial Reporting
F-1
   
Report of Independent Registered Public Accounting Firm
F-2
   
Consolidated Balance Sheets as of December 31, 2012 and 2011
F-4
   
Consolidated Statements of Operations for the Years Ended
 
   
December 31, 2012, 2011, and 2010
F-6
   
Consolidated Statements of Comprehensive Loss for the Years Ended
 
   
December 31, 2012, 2011, and 2010
F-7
   
Consolidated Statements of Cash Flows for the Years Ended
 
   
December 31, 2012, 2011, and 2010
F-8
   
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years
 
   
Ended December 31, 2012, 2011, and 2010
F-9
   
Notes to the Consolidated Financial Statements
F-10
       
 
2.
Supplemental Schedules.  The supplemental schedules have been omitted because they are not applicable or the required information is otherwise included in the accompanying consolidated financial statements and the notes thereto.
       
 
3.
Exhibits.  The following exhibits are included as part of this report:  
 
Exhibit
Number*
 
Title of Document
 
Location
         
Item 1
 
Underwriting Agreement
   
1.01
 
At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC
 
See Exhibits 10.99 and 10.107
         
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 year 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 quarter 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.
         
 
64
 
 

 
 
 
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 year 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 quarter 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 year 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 year 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 Górnictwo 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 year 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 year 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 year 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 quarter ended March 31, 2004, filed May 11, 2004.
         
10.75
 
Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2008, filed March 16, 2009.
 
 
65
 
 

 
 
 
 
Exhibit
Number*
 
Title of Document
 
Location
         
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 year 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 year 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 year 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 year 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 year 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 year 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 year 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 year 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
         
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
 
 
66
 
 

 
 
 
Exhibit
Number*
 
Title of Document
 
Location
         
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]
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
         
10.103
 
Cenex Contract Number 3000748 Amendment No. 1 between Cenex Harvest States Cooperatives and FX Drilling Company, Inc.
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
         
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]
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
         
10.105
 
Joint Operating Agreement between Polskie Górnictwo Naftowe i Gazownictwo S.A. [PGNiG] and FX Energy Poland Sp. z o.o. [Warsaw South]
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
         
10.106
 
Amendment No. 1 to At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC
 
Incorporated by reference from the current report on Form 8-K filed August 24, 2012.
         
 
10.107
 
 
Agreement no 11/K/Z/2012 for the Sale of Natural Gas concluded between FX Energy Poland Sp. z o.o. and Polish Oil and Gas S.A. [Winna Gora]
 
 
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 year 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.
 
 
 
67
 
 

 
 
 
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.

 
68
 
 

 


 
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 14, 2013
By:
/s/ David N. Pierce
   
David N. Pierce
   
President and Chief Executive Officer


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


 
/s/ Thomas B. Lovejoy
Dated: March 14, 2013
Thomas B. Lovejoy, Director
   
 
/s/ David N. Pierce
Dated: March 14, 2013
David N. Pierce, Director, President,
 
and Principal Executive Officer
   
 
/s/ Dennis B. Goldstein
Dated: March 14, 2013
Dennis B. Goldstein, Director
   
 
/s/ Arnold S. Grundvig, Jr.
Dated: March 14, 2013
Arnold S. Grundvig, Jr., Director
   
 
/s/ Jerzy B. Maciolek
Dated: March 14, 2013
Jerzy B. Maciolek, Director
   
 
/s/ Richard Hardman
Dated: March 14, 2013
Richard Hardman, Director
   
 
/s/ H. Allen Turner
Dated: March 14, 2013
H. Allen Turner, Director
   
 
/s/ Clay Newton
Dated: March 14, 2013
Clay Newton, Principal Financial and
 
Accounting Officer

 
69
 
 

 




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 2012 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, 2012, 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 prin