10-K 1 k123113.htm FORM 10-K YEAR ENDED DECEMBER 31, 2013 k123113.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, 2013
   
¨
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, 2013, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $162,334,000.

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 12, 2014, FX Energy had 53,912,277 shares of its common stock, par value $0.001, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE.  Portions of FX Energy’s definitive Proxy Statement in connection with the 2014 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, 2013
 


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
24
2
 
Properties
24
3
 
Legal Proceedings
41
4
 
Mine Safety Disclosures
41
       
   
Part II
 
5
 
Market for Registrant’s Common Equity, Related Stockholder Matters
 
   
and Issuer Purchases of Equity Securities
41
6
 
Selected Financial Data
42
7
 
Management’s Discussion and Analysis of Financial Condition and Results of Operation
43
7A
 
Quantitative and Qualitative Disclosures about Market Risk
57
8
 
Financial Statements and Supplementary Data
57
9
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
57
9A
 
Controls and Procedures
58
9B
 
Other Information
59
       
   
Part III
 
10
 
Directors, Executive Officers and Corporate Governance
60
11
 
Executive Compensation
60
12
 
Security Ownership of Certain Beneficial Owners and Management and Related
 
   
Stockholder Matters
60
13
 
Certain Relationships and Related Transactions, and Director Independence
60
14
 
Principal Accountant Fees and Services
60
       
   
Part IV
 
15
 
Exhibits and Financial Statement Schedules
61
--
 
Signatures
66
--
 
Report of Independent Registered Public Accounting Firm
F-1

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 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 consistent with our initial estimate of an exploration target area’s gross unrisked potential;

●  
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, development, 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 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 related to the future determination of exploitation fees, royalty rates, and other matters governing our oil and gas interests;

●  
uncertainties, restrictions, and increased costs resulting from the current public interest and regulatory focus on hydraulic fracturing, which we intend to use in Poland;

●  
price and market changes that may result from the development of an open Polish gas market to replace government-set pricing tariffs;

●  
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.  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 2013, independent reserve engineers estimated our worldwide proved oil and gas reserves to be 42.0 billion cubic feet, or Bcf, of natural gas and 0.5 million barrels of oil, or Bbl, or a combined total of 44.8 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 44.8 Bcfe, 94% was in Poland and 6% was in the United States.  The SMOG Value of our proved reserves is approximately $152 million, based on reserve calculations of independent engineers.

Our 2013 oil and gas production was 4.4 Bcfe (12.2 million cubic feet equivalent per day, or MMcfed), which was down 7% from 2012 production.  Of our 2013 production, 4.1 Bcfe (11.4 MMcfed) of our production was in Poland and 0.3 Bcfe (0.8 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 2013 were $33.3 million, which is a decrease of 3% compared to revenues for the preceding fiscal year.  We currently expect that our 2014 production will rise from our 2013 production rates with the start of production at our Lisewo-2 and Komorze-3K wells, coupled with a full year of production from our Lisewo-1 and Winna Gora wells, which we believe will be greater than the natural declines in production from our currently producing wells.  We expect our 2014 first quarter production to average approximately 13.6 MMcfed.  Production began at our Winna Gora well in late January of 2013 and at our Lisewo-1 well in December of 2013.  Production facilities were completed and gas began flowing at our Komorze-3K well in February of 2014.  We expect production to begin at our Lisewo-2 well in the second half of 2014.

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.  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 2.5 million gross acres (1.8 million net acres) in Poland and continually review additional acreage acquisition opportunities.

During 2013 in Poland, we drilled one well that we plan to place into production in 2014, one well that we plan to place into production in 2015, two wells with gas shows that have been temporarily abandoned pending further evaluation and/or drilling, and one dry hole.

As of December 31, 2013, we had approximately 53.7 million shares of common stock outstanding, and our market capitalization was approximately $196 million (approximately $211 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 2014, our average daily trading volume has been approximately 285,000 shares.  Our total assets as of December 31, 2013, were $100.7 million, and our working capital was $11.3 million.  Total net debt per thousand cubic feet equivalent, or Mcfe, of proved reserves was $0.75 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 11 conventional gas discoveries in our core Fences concession in Poland are 12.7 Bcf.  The average initial gross production rate for these 11 wells is approximately 4.5 million cubic feet per day, or 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, which has a methane content of 80%, is approximately 80% higher than 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.

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 producing wells in the Fences concession area are now providing significant cash flow that we can use to expand our exploration and production efforts throughout the country.  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.
 
6
 
 

 


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 853,000 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 11 of the 15 wells we have drilled on Rotliegend structural trap targets in our core Fences concession.  In the aggregate, these 11 discoveries found gross estimated recoverable proved reserves of approximately 139 Bcf of gas.  We have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers in the Fences concession and plan to acquire 3-D seismic data over more of that concession.  Using the 3-D seismic data acquired to date, we have identified 16 additional structural traps that we plan to drill.  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 anticipate drilling three to four additional wells in the Fences area during 2014.  These operations are the focus of our strategy to increase production and reserves in our core area.

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 recent tests we drilled in these areas that we are continuing to evaluate, but drilling success may open new productive areas with significant resources.  We are drilling the Tuchola-4K well in our Edge concession at the date of this report and anticipate drilling two to three additional wells in 2014 in our Edge and Block 246 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 funds to exploration of these early-stage exploration licenses, with a view toward long-term results.

Polish Exploration Rights

As of December 31, 2013, 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 853,000 gross-acre core Fences project area, in which we hold a 49% interest in approximately 808,000 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 1.8 million net acres throughout Poland.

As we build revenues in our core area and further explore and evaluate our acreage in Poland, we expect to increase the operational and financial efforts we expend outside our core area.  As we do so, we may add new concessions that we believe have high potential and relinquish acreage that we believe has lower potential.  See Item 2, Properties – Wells and Acreage below for further information.
 
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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, Edge, and Warsaw South.  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 there, first by PGNiG and more recently by us.  We and PGNiG have discovered proved gas reserves of over 139 Bcf gross (62 Bcf net to our interest) in 11 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 2013, we completed the Lisewo-2 and Szymanowice-1 wells.  In 2014, we anticipate drilling two or three wells in the eastern part of Fences near these recent discoveries and plan to drill the Karmin-1 well on trend with our Roszkow and Zaniemysl fields.  In our other concessions we drilled the Gorka-Duchowna-1 well, a noncommercial Zechstein/Carboniferous test in Block 246, and drilled the Tuchola-3K Zechstein/Devonian test in Edge.  In 2014, we expect to drill the Tuchola-4K well and two or three additional exploration wells in one or more of the Edge or Block 246 concessions.

Fences Area

The Fences concession area encompasses 853,000 gross acres (3,450 sq. km.) in western Poland’s Permian Basin.  PGNiG gas fields in the Fences area drilled before 2000 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 808,000 acres and a 24.5% interest in the remaining 45,000 acres in the Fences area (407,000 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 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 15 conventional vertical wells targeting Rotliegend structures through the date of this filing.  Eleven of these wells are commercial, with an aggregate estimated ultimate recovery of 139 Bcf over the life of the wells, with remaining proved gas reserves of over 87 Bcf gross (42 Bcf net to our interest) as of December 31, 2013.

We currently produce approximately 14.0 MMcfed net to us from seven of these 11 wells, including the Komorze-3K well, which started producing in February 2014.  We expect to start production in the second half of 2014 from the Lisewo-2 well and in the first half of 2015 from the Szymanowice-1 well.  The Zaniemysl-3 well stopped production during mid-2013 due to an influx of water and is scheduled to be sidetracked during 2014, targeting additional gas reserves that are higher on the Zaniemsyl structure than the existing well.  The oldest of our 11 wells had a very small reservoir and was depleted in 2010.  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 2014, subject to our partner’s participation, we plan to drill three to four new wells in the Fences concession: the Karmin-1 well, which is on trend with our Roszkow and Zaniemsyl fields, and two to three wells near our Lisewo production facility, where production began in December 2013.
 
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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 and are producing from all three of the wells.

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 drilled the Gorka-Duchowna well, which we are currently evaluating for commercial potential.  We are currently interpreting 3-D seismic data that we shot in 2013 and, pending that interpretation, plan to drill one or two wells in 2014.

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.  We have determined to postpone drilling a well in Block 229 for the present.

Warsaw South Concession Area

We hold a 51% interest in a total of 395,000 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 shows.  The Warsaw South concession has a number of exploration leads, including carboniferous sands and shale 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 and in 2014, we elected to drop certain concessions that we deemed less prospective for hydrocarbon potential, while acquiring additional new seismic data on our remaining block.  We are continuing to evaluate this concession area.

Edge Concession Area

In 2008, we acquired a 100% interest in four concessions in north-central Poland covering approximately 726,000 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 and 3-D seismic data in 2011 and 2012 and drilled the Tuchola-3K well to test both a Zechstein target and a Devonian target.  We are shooting and interpreting new seismic data in the Edge area, are currently drilling the Tuchola-4K well, and may drill additional wells in the concession blocks this year, subject to our drilling plans elsewhere.
 
 
 

 
Additional Concession Acreage

We may apply for more concession blocks in Poland in 2014.  If we acquire more concession blocks, we will allocate modest technical and financial resources to these areas during 2014, 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 MS 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, waterflood oil-producing wells in the Southwest Cut Bank Sand Unit of Montana.  As of December 31, 2013, our U.S. reserves (all of which were proved reserves) were estimated at 461,000 Bbls of crude oil with a SMOG Value of approximately $8.2 million.  At year-end 2013, U.S. reserves were approximately 6% of total proved reserves on a gas equivalent basis.  Our oil wells produce approximately 133 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.

From our field office in Montana, we also provide oilfield services, which provided approximately $1.2 million in revenue during 2013.

Alberta Bakken and Three Forks Shale Exploration

In 2011, we entered into a joint venture with two other companies to jointly explore the Alberta Bakken and Three Forks Shale formations in northwestern Montana.  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 and carried out a multistage fracture.  In 2012, we determined that none of the wells drilled in our Albert Bakken project was economic and suspended further drilling in the area.
 
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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 100%-owned Tuchola-3K well.  We rely on the financial responsibility of PGNiG as operator of the wells in which we jointly participate in the Fences project area as they have control-of-well coverage for those wells.  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 $1.0 million per event with a $2.0 million annual aggregate limit.  In addition, we carry an umbrella/excess liability policy with a $10.0 million per event limit with a $10.0 million 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 $5.0 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.

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, 2013, we had 56 employees, consisting of nine in Salt Lake City, Utah; 24 in Oilmont, Montana; one in Greenwich, Connecticut; two in Houston, Texas; and 20 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 5,200 square feet for approximately 25,000 PLN ($8,800 at December 31, 2013, 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 ($528) 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.
 
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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.

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 2014 from 2013 levels 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 credit facility secured by future production from our reserves, additional funds obtained from the sale of equity securities, 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.

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 in zlotys for the gas we sell in Poland.  As the dollar strengthens relative to the zloty, our dollar-denominated revenue received in zlotys declines; conversely, when the dollar weakens relative to the zloty, our dollar-denominated revenue received in zlotys increases.  Should exchange rates in effect during early 2014 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our dollar-denominated revenues in 2014 compared to 2013, with a corresponding increase in the 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, which bears a share of the costs of many projects as a joint owner.  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 2014 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 would 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 our relationship with 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 oil and gas reserves and future net revenues are subject to various risks and uncertainties.

Our estimates of oil and gas reserves, calculated by independent, third-party engineering firms, 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 reserves, projecting future sales of production, and the timing and amount of development expenditures.  Many of these factors are beyond our control.  Our proved 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, characteristics, and recoverability of underground accumulations of oil and gas that cannot be measured exactly.  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;
 
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●  
the effect of certain terms that could be changed in the future, including gas and oil exploitation fees, royalty rates, pricing discounts or adjustments, and similar items;

●  
market prices and demand for the oil and gas we produce; and

●  
oil and gas quality and impurities that reduce the sales prices we actually receive 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.  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 may be unable to meet the reserve and future cash flow criteria to support the borrowing base of our credit facility.

We are required to maintain minimum amounts of reserves and estimated future net cash flows in order to maintain our current $65.0 million borrowing base, which is redetermined every six months.  If we fail to maintain such minimums, we would be required to reduce the borrowing base and pay down the principal balance if our outstanding borrowing exceeds the redetermined borrowing base, so that our reserves and cash flows provide adequate security to the lenders.  Further, we will need to increase reserves and estimated future cash flows in order to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism.  We cannot assure that we will be able to maintain existing or increase borrowings from these lenders.

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.  These 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.

From 1995 through early 2014, we have participated in drilling or recompleting 45 exploratory wells in Poland, including 15 commercial discoveries, 27 noncommercial wells, and three wells that were undergoing further evaluation at year-end 2013.  Of our 15 commercial successes in Poland, as of the date of this report we were producing gas at 10 wells, including seven in our Fences concession and three in our Block 287 concession.  Production from two other commercial discoveries is scheduled to begin in 2014 or early 2015 once requisite permits are obtained and production facilities are constructed.  Three 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 from 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; negotiating price and payment details; 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, 2013, we have incurred cumulative net losses of approximately $198 million.  Our exploration and production activities may continue to result in net losses through 2014 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 maintenance and 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 concession 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.  We may lose our rights to exploration acreage if we cannot obtain required changes or extensions.

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 Board 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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The price we receive for gas in Poland is currently determined based on trailing Russian prices.

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 oil prices.  The trailing impact of lower oil prices may have a depressive 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.

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.

The prices at which we sell gas in Poland in the future may be adversely affected by prices established in a developing competitive market in the Polish gas exchange.

Poland has adopted legislation to establish a Polish gas exchange on which an increasing portion of natural gas is to be marketed in an effort to create a competitive gas price market to replace the current government-determined tariff price.  We cannot assure that gas prices in the emerging Polish gas exchange, as it develops over the ensuing months and years, will be as high as those that we might otherwise obtain under tariff prices established under the current system.

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 markets locally and in Russia, on which Polish gas tariffs are based;

●  
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 opening of a new natural gas exchange in Poland;

●  
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;
 
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●  
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.

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-4K well, which began drilling in early 2014.  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.
 
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Concerns regarding global climate change could spur legislation or regulation, globalized through treaties or otherwise, that could diminish global demand for oil and gas products and negatively impact our business.

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

We spent a total of $321,000 in prior years for 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 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.

Compliance with environmental requirements may not be offset by our limited oil production revenue in Montana.

We have limited oil production in Montana, so substantial environmental compliance, mitigation, and reclamation costs may not be offset by revenue from ongoing production from the wells or facilities involved in any incident or even the entire field.  Accordingly, environmental costs expose our entire Montana operations, and the subsidiary through which such operations are conducted, to risk.

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.

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 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.

In Poland, in 2013 we unsuccessfully hydraulically fractured the Plawce-2 well.  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.
 
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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 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 Poland 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 in Utah.  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 complete other 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, 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:

●  
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;
 
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●  
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.

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.
 
20
 
 

 


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 or 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, expertise, 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.

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

Under our Senior Reserve Based Lending Facility with two European banks, we have drawn $45 million in financing and currently have access to an additional $20 million.  Although both 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.
 
21
 
 

 


The Polish Ministry of the Environment has the authority to terminate immediately the mining usufruct agreements 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 prospecting and exploring for, or extracting, 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 immediately a mining usufruct agreement, 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, 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.

Currently unfolding political upheavals in Ukraine, Poland’s neighbor to the southeast, could have unpredictable consequences in Poland and its gas industry.

In recent days there has been a leadership change in Ukraine, along with the possibility of political or military intervention by Russia in the Crimean region of Ukraine, which has ethnic ties with Russia.  At least one gas pipeline enters Poland from Ukraine.  We cannot predict how political events in Ukraine will unfold or whether or how such developments might impact Poland, its gas industry, or our activities there.  We cannot assure that such developments and influences resulting from the conditions in Ukraine will not have an adverse effect on our activities in Poland.

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.

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 was directed to prepare a draft law, which was published in early 2013.  Comments from the industry/general public were invited, to be taken into account or not in preparing a revised draft by the Minister.  The revised draft is 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.  As of the date of this report, the proposed legislation remains in draft form, and no vote has yet been scheduled.

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.
 
22
 
 

 


Although the draft law has been 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 $2.56 and as high as $4.90 between January 1, 2013, and the date of this report.  Some of the factors leading to this volatility include:

●  
the outcome of individual wells or the timing of exploration efforts in Poland and the United States;

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

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

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

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

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

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

●  
prevailing world prices for oil and gas;

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

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

●  
changes in stock market analysts’ recommendations regarding us, other oil and gas companies, or the oil and gas industry in general.
 
23
 
 

 


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.


 
ITEM 2. PROPERTIES
 

Proved Reserve Disclosures

Internal Controls over Reserve Estimates

Our policies regarding internal controls over the recording of reserve estimates require such estimates to comply with the Securities and Exchange Commission’s definitions and guidance and prepared in accordance with customary petroleum engineering practices.  Responsibility for compliance in reserve bookings is delegated to our operations and finance staff.  Clay Newton, our principal financial officer, reviews the independence and professional qualifications of the third-party engineering firms we engage.  He also supervises the submission of technical and financial data to third-party engineering firms and reviews the prepared reports to verify that such data has been appropriately reflected in the reports.  Mr. Newton has more than 25 years’ experience in senior financial positions in the oil and gas industry.  He earned a BA in accounting at the University of Utah in 1981 and is a certified public accountant.
 
24
 
 

 
Estimates of our proved Polish reserves were calculated by RPS Energy, an independent engineering firm in the United Kingdom.  Estimates of our proved domestic reserves were calculated by Hohn Engineering, an independent engineering firm in Billings, Montana.  The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  The qualifications of the individuals primarily responsible for the preparation of our reserve reports are included in their respective reports, which are included as exhibits to this filing.  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 Reserves

Proved reserves are estimated quantities of oil and gas calculated using deterministic methods 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 reserve 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.

We emphasize that the reserve volumes are estimates and 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, 2013, our proved undeveloped reserves totaled 0.8 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 gathering lines 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.
 
25
 
 

 


Changes in Proved Undeveloped Reserves

All reserves classified as proved undeveloped reserves at December 31, 2012, were converted to proved developed reserves at December 31, 2013, following successful completion of production facilities and recompletions.

Development Costs

Costs incurred relating to the development of proved undeveloped reserves were approximately $8.9 million in 2013, including the construction costs of production facilities at our Lisewo-1 and Komorze-3K wells, along with the cost to drill our Lisewo-2 well.

Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $0.9 million in 2014.  The estimated development costs represent our share of the cost of the sidetrack project planned for our Zaniemsyl 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 reserve 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 Reserve Information

Since January 1, 2013, no crude oil or natural gas reserve information has been filed with, or included in any report to, any other federal authority or agency.

Reserve Volumes and Values

The following table sets forth our estimated proved developed and proved undeveloped reserve volumes as of December 31, 2013:

 
United States
 
Poland
 
Total
 
MBbls
 
MMcf
 
MMcfe
Proved developed reserves
461
 
41,219
 
43,985
Proved undeveloped reserves
--
 
793
 
793
Total proved reserves
461
 
42,012
 
44,778

The following table sets forth the estimated SMOG Value of our proved reserves as of December 31, 2013:

 
Total Net
 
SMOG
 
Reserves
 
Value
 
(MMcfe)
 
(In thousands)
Proved
44,778
 
$151,802

26
 
 

 


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 $6.82 and $6.60 per thousand cubic feet, or Mcf, of gas and $78.18 and $78.14 per Bbl for 2013 and 2012, respectively.

Drilling Activities

The following table sets forth the exploratory wells that we drilled:

 
Year Ended December 31,
 
2013
 
2012
 
2011
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory productive wells:
                     
Poland
2.0
 
1.0
 
1.0
 
0.5
 
1.0
 
0.5
United States
--
 
--
 
--
 
--
 
--
 
--
Total
2.0
 
1.0
 
1.0
 
0.5
 
1.0
 
0.5
                       
Exploratory dry holes:
                     
Poland
1.0
 
0.5
 
1.0
 
0.5
 
1.0
 
0.5
United States
--
 
--
 
4.0
 
1.6
 
--
 
--
Total
1.0
 
0.5
 
5.0
 
2.1
 
1.0
 
0.5
                       
Total wells drilled
3.0
 
1.5
 
6.0
 
2.6
 
2.0
 
1.0

The productive exploratory wells drilled in 2013 were our Lisewo-2 and Szymanowice-1 wells.  The Lisewo-2 well was drilled as a production acceleration well adjacent to the Lisewo-1 well, so no new reserves have been assigned to that well.  The Szymanowice-1 well had gross proved reserves of 8.1 Bcf of natural gas at year-end 2013.  The exploratory dry hole in 2013 was the Mieczeow-1K well in Poland.  The productive exploratory well drilled in 2012 was our Komorze-3K 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 Tuchola-3K, Gorka-Duchowna-1, and Frankowo-1 wells being evaluated in Poland at 2013 year end.  We did not drill any development wells in 2013, 2012, or 2011.

Wells and Acreage

As of December 31, 2013, our gross and net producing wells consisted of the following:

 
Number of Wells
 
Gas
 
Oil
 
Gross
 
Net
 
Gross
 
Net
Well count:
             
Poland(1)
8.0
 
4.9
 
--
 
--
United States
--
 
--
 
136.0
 
116.7
Total
8.0
 
4.9
 
136.0
 
116.7
_______________
 
(1)
In addition to the wells producing at year-end 2013, two wells began production in February 2014.  We also had two additional wells in Poland awaiting the construction of production facilities.
 
27
 
 

 


The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2013.  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
4,600
 
2,085
 
853,000
 
407,000
Warsaw South project area
--
 
--
 
395,000
 
201,000
Block 287 project area
1,430
 
1,430
 
12,000
 
12,000
Edge project area
--
 
--
 
726,000
 
726,000
Block 246 project area
--
 
--
 
241,000
 
241,000
Block 229 project area
--
 
--
 
233,000
 
233,000
Total Polish acreage
6,030
 
3,515
 
2,460,000
 
1,820,000
               
United States:
             
Montana
10,732
 
10,418
 
4,510
 
4,417
Nevada
400
 
128
 
9,332
 
6,351
Total
11,132
 
10,546
 
13,842
 
10,768
               
Total Acreage
17,162
 
14,061
 
2,473,842
 
1,830,768
_______________
 
(1)
All gross and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.

Polish Properties

Producing Properties

A summary of our average daily production, weighted average interest, and weighted average net revenue interest for our Poland producing properties during 2013 follows:

 
Average Daily
     
Average
 
Production (Mcfe)
 
Average
 
Net Revenue
 
Gross
 
Net
 
Interest
 
Interest
Fences project area
23,033
 
11,040
 
48%
 
48%
Grabowka
438
 
438
 
100%
 
100%
Total
23,471
 
11,478
       

Production, Transportation and Marketing

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:

     
Average
   
 
Production
 
Production Cost
 
Average Sales Price
 
Gas
 
Oil
 
per Mcfe(1)
 
Gas
 
Oil
 
(Mcf)
 
(Bbls)
     
(Per Mcf)
 
(Per Bbl)
2013
                 
Roszkow
1,596,000
 
-
 
$0.24
 
$7.63
 
$    -
Zaniemysl-3
90,000
 
-
 
1.50
 
5.84
 
-
Sroda/Kromolice-1
1,190000
 
-
 
0.32
 
7.10
 
-
Kromolice-2
806,000
 
-
 
0.27
 
7.00
 
-
Winna Gora
315,000
 
-
 
0.51
 
6.95
 
-
Other wells(2)
150,000
 
-
 
0.91
 
3.05
 
-
Total
4,147,000
 
-
 
0.34
 
7.10
 
-
 
28
 
 

 
 
 
     
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-3
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(2)
89,000
 
-
 
2.54
 
1.59
 
-
Total
4,457,000
 
-
 
0.28
 
6.81
 
-
                   
2011
                 
Roszkow
2,279,000
 
-
 
0.20
 
6.68
 
-
Zaniemysl-3
799,000
 
-
 
0.22
 
5.11
 
-
Sroda/Kromolice-1
759,000
 
-
 
0.13
 
6.33
 
-
Kromolice-2(3)
138,000
 
-
 
0.94
 
6.25
 
-
Other wells(2)
85,000
 
-
 
1.52
 
1.61
 
-
Total
4,060,000
 
-
 
0.24
 
6.19
 
-
 
___________
 
(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)
Production costs at other wells include the ongoing costs of maintaining the production facilities at our Wilga well, which is not currently in production.
(3)
Kromolice-2 production costs include the cost of a workover performed in early 2011.

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.  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.  Should we choose to export any gas or oil we produce, we will be required to obtain prior governmental approval.

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.

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 2013 follows:

 
Average Daily
     
Average
 
Production (Bbls)
 
Average
 
Net Revenue
 
Gross
 
Net
 
Interest
 
Interest
Montana
147
 
125
 
99%
 
85%
Nevada
28
 
8
 
39
 
29
Total United States producing properties
175
 
133
       
 
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In Montana, we operate the Southwest Cut Bank Sand Unit and Bears Den fields and have an interest in the Rattlers Butte field, which is operated by an industry partner.  Production in the Southwest Cut Bank Sand Unit, producing since the 1940s from an average depth of approximately 2,900 feet, is from a waterflood program with 122 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 six 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 one oil well 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:

 
Year Ended December 31,
 
2013
 
2012
 
2011
United States producing property data:
         
Average daily net oil production (Bbls)
133
 
146
 
155
Average sales price per Bbl
$79.48
 
$76.87
 
$83.02
Average production costs per Bbl(1)
$47.63
 
$45.00
 
$50.41
_______________
 
(1)
Production costs include lifting costs (electricity, fuel, water, disposal, repairs, maintenance, pumper, transportation, and similar items) and production taxes.  Production costs do not include such items as general and administrative costs; depreciation, depletion and amortization; state income taxes, or federal income taxes.  Costs in 2011 include approximately $321,000 associated with the cleanup of a minor oil leak.  Excluding the cleanup costs, lifting costs per barrel in 2011 would have equaled approximately $44.73 per barrel.

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

Oilfield Services – Drilling Rig and Well-Servicing Equipment

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

The Republic of Poland

The Republic of Poland is located in north-central Europe, has a population of approximately 38.5 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.  These measures continue.
 
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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 2013.  While the economy is expected to slow somewhat, economists are still predicting positive growth during 2014.  Poland’s economy remains one of the more attractive and safer debt markets in Europe.

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 agreements and concessions that either modify the obligations or extend the terms of those agreements or concessions.

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 oil and gas exploration rights on the Fences project area to PGNiG and has granted oil and gas exploration rights on all other project areas in which we have an interest to us.  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 will be 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 is set by the Geological and Mining Law and is updated annually for inflation.  The royalty rate for low-methane gas such as we produce is currently set for 2014 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.
 
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We believe all material concession terms have been satisfied to date.

Currently gas produced by us and others in Poland is sold to PGNiG at tariff prices established by the Polish government.  As part of its continuing effort to satisfy European Union requirements to move toward free-market energy prices, in September 2013, Poland adopted legislation requiring companies engaged in gas trading (i.e., excluding producers such as us) to sell a specified percentage, increasing from 30% in 2013 to 55% in 2015 and thereafter, of gas sold domestically on a commodity exchange.  The only existing gas exchange was established by the Polish Power Exchange during 2013, but only small volumes have been traded by a fraction of the licensed trading companies.

In view of the slow market adoption of the gas exchange trading requirements, the viability of the exchange is uncertain.  In turn, it is unclear whether a free-market trading price for gas will be established with sufficient industry acceptance and credibility to replace government-determined tariffs.  Further, we cannot predict how free-market prices, if developed, will compare with established tariffs or whether our gas sales contracts with PGNiG will adopt free-market prices.

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 (853,000 gross and 407,000 net acres) have expiration dates ranging from July 2014 to Sept 2017.  The extension procedure for the concession expiring in 2014 is in progress at the date of this report.  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.

Warsaw South/Wilga Project Area

The Warsaw South/Wilga project area (395,000 gross and 201,000 net acres) consists of a single oil and gas exploration and production concession covering Block 255 held by us.  As required by the current law, it is being converted to an exploration concession.  The procedure should be completed in first half of 2014.  Adjacent to Block 255, we hold one exploration concession expiring in July 2018 covering part of Block 254.  The obligatory work commitment includes acquiring 125 square kilometers of 3-D seismic data and drilling two wells.

Block 287 Project Area

The Block 287 project area (12,000 gross and net acres) consists of a single oil and gas exploration concession held by us.  The concession expires in December 2015.  Our 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 began in the first quarter of 2013.  The third well was recompleted in late 2013 and production began in early 2014.

Edge Project Area

The Edge project area (726,000 gross and net acres) consists of four oil and gas exploration concessions granted in 2008.  In September 2013 two of them were extended for five years and the remaining two for three years.  The total obligatory work commitment includes acquisition of 500 square kilometers of 3-D seismic data and drilling eight wells.

Block 246 Project Area

The Block 246 project area (241,000 gross and net acres) is adjacent to the Fences project area in the southwest and consists of a single concession granted for six years (2008-2014).  All obligatory work has been completed, and we plan to apply for an extension prior to concession expiration in December 2014.
 
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Block 229 Project Area

The Block 229 project area (233,000 gross and net acres) 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, 2013, all required usufruct/concession payments had been made for each of the above existing project areas.

Government Regulation

Poland

Our activities in Poland are subject to political, economic, and other uncertainties, including the adoption of new laws, regulations, or administrative policies that may adversely affect us or the terms of our exploration or production rights; political instability and changes in government or public or administrative policies; export and transportation tariffs and local and national taxes; foreign exchange and currency restrictions and fluctuations; repatriation limitations; inflation; environmental regulations; and other matters.  These operations in Poland are subject to the Geological and Mining Law dated as of 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 (3) prepare and submit field development plans prior to engaging in field-wide development.  Poland’s regulatory framework respecting environmental protection generally follows directives and regulations of the European Union.  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 reviewing 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, requirements for governmental concessions for transporting and marketing gas, mandated governmental equity participation in hydrocarbon firms, more market-based hydrocarbon pricing, and the release of 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 published draft of the new law addresses the concession system and environmental regulation.  Principal proposals for consideration include the replacement of the current three types of concessions with one concession for exploration and production; new requirements for prequalification for applicants for concessions; and increases of revenues to local authorities from oil and gas production.  Administrative changes would be aimed at improving concession administration.
 
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A revised draft, which reflects some of the industry comments, is expected to be approved by the government March 2014, 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.

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, respecting the royalty regime, and January 1, 2020, respecting new taxes.  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.

As the new law has not yet been published and is expected to be significantly modified as compared to the version last published in October 2013, 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, restricting the method of drilling and casing wells, regulating hydraulic fracturing, controlling water injections, setting forth 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, 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.
 
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Numerous governmental agencies, such as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures.  Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil, and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities.  In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

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

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed, or arranged for the disposal, of the hazardous substances.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources, and 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 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.
 
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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.

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 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.
 
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Federal and Indian Leases

A substantial part of our producing properties in Montana consist of oil and gas leases issued by the Bureau of Land Management or 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.

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 Securities and Exchange Commission under the Dodd-Frank Wall Street Reform and Consumer Protection Act, we would have been required to begin reporting annually to the Securities and Exchange Commission the payments we make to governmental entities to further commercial development of oil and gas in 2014.  During 2013, the United States District Court for the District of Columbia vacated the SEC resource extraction disclosure rules.

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.

During 2013, we hydraulically fractured three separate intervals encountering approximately 480 meters of relatively tight Rotliegend sandstone in the Plawce-2 well in Poland, without economic success.  We are currently evaluating the possibility of hydraulically fracturing the Gorka-Duchowna-1 well in Poland during 2014.  We have no current plans for future hydraulic fracturing in the United States.

We expect that PGNiG or we, as the operator of the particular project, will use industry-standard, long-established third-party service providers with specialized experience and equipment in hydraulic fracturing.  In many instances, such service providers will be PGNiG subsidiaries.  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:
 
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●  
instantaneously monitor in real-time the rate and pressure of the fracturing treatment for any abrupt change in rate or pressure;

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

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

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

We and PGNiG 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 rules and regulations.

In order to prevent the underground migration of fracture fluids, we, and we expect PGNiG 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 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 protection.  Other protective measures may include safety briefings prior to conducting fracturing operations, the 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.
 
38
 
 

 


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—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.

“Ca2” refers to a specific calcium-rich geological formation, 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 reserve calculation is used in the reserve estimation.

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

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

“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic conditions.
 
39
 
 

 


“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.

“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.

“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.

“SMOG Value” means the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%, 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 Securities and Exchange Commission, without escalation and without giving effect to non-property-related expenses, general and administrative costs, debt service, and depreciation, depletion, and amortization.

Usufruct” means the Polish equivalent of a U.S. oil and gas lease.
 
40
 
 

 



 
ITEM 3. LEGAL PROCEEDINGS
 

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


 
ITEM 4. MINE SAFETY DISCLOSURES
 

           Not applicable.


PART II

 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
 

Price Range of Common Stock and Dividend Policy

The following table sets forth, for the periods indicated, the high and low 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
2014:
     
First Quarter (through March 12, 2014)
$3.18
 
$4.09
       
2013:
     
Fourth Quarter
3.00
 
3.86
Third Quarter
2.82
 
3.98
Second Quarter
2.48
 
6.18
First Quarter
3.32
 
4.52
       
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

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 7, 2014, 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 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,
  2013   2012   2011   2010   2009
 
(In thousands, except per share amounts)
Statement of Operations Data:  
Revenues:
                 
Oil and gas sales
$ 33,311
 
$ 34,461
 
$ 29,807
 
$ 22,914
 
$ 12,772
Oilfield services
1,218
 
2,137
 
5,631
 
2,099
 
1,892
Total revenues
34,529
 
36,598
 
35,438
 
25,013
 
14,664
Operating costs and expenses:
                 
Lease operating expenses(1)
3,680
 
3,631
 
3,834
 
3,473
 
3,478
Exploration costs(2)
20,792
 
23,795
 
16,618
 
3,038
 
4,829
Impairment of oil and gas properties(3)
6,129
 
2,562
 
72
 
564
 
1,864
Asset retirement obligation gain
--
 
--
 
(52)
 
(264)
 
(529)
Oilfield services costs
1,179
 
1,610
 
4,458
 
1,550
 
1,412
Depreciation, depletion, and
                 
amortization
4,573
 
4,239
 
3,397
 
2,626
 
1,602
Accretion expense
90
 
63
 
68
 
92
 
41
Loss on sale of asset
--
 
49
 
--
 
--
 
--
Stock compensation
2,853
 
2,325
 
1,744
 
1,379
 
1,693
General and administrative costs (G&A)
8,836
 
8,369
 
8,396
 
7,973
 
7,257
Total operating costs and expenses
48,132
 
46,643
 
38,535
 
20,431
 
21,647
                   
Operating income (loss)
(13,603)
 
(10,045)
 
(3,097)
 
4,582
 
(6,983)
                   
Other income (expense):
                 
Interest expense
(3,269)
 
(2,485)
 
(2,167)
 
(1,936)
 
(654)
Interest and other income
105
 
356
 
188
 
829
 
54
Foreign exchange (loss) gain
4,967
 
16,292
 
(23,448)
 
(4,233)
 
7,053
Total other (expense) income
1,803
 
14,163
 
(25,427)
 
(5,340)
 
6,453
                   
Net income (loss)
$(11,800)
 
$   4,118
 
$(28,524)
 
$     (758)
 
$    (530)

– Continued –
 
42
 
 

 


  Year Ended December 31,
  2013   2012   2011   2010   2009
   (In thousands, except per share amounts)
    Basic and diluted net income (loss)                  
per common share
$    (0.22)
 
$      0.08
 
$    (0.57)
 
$  (0.02)
 
$   (0.01)
                   
Basic and diluted weighted average
                 
shares outstanding
52,752
 
52,274
 
50,262
 
43,387
 
42,529
                   
Cash Flow Statement Data:
                 
Net cash provided by (used in) operating
                 
activities
$    2,308
 
$   (1,233)
 
$      (120)
 
$  7,249
 
$ (5,829)
Net cash used in investing activities
(27,945)
 
(16,350)
 
(18,486)
 
(7,814)
 
(3,999)
Net cash provided by (used in)
                 
financing activities
2,964
 
--
 
50,842
 
16,092
 
(2,676)
                   
Balance Sheet Data:
                 
Working capital(4)
$  11,300
 
$  30,395
 
$  49,787
 
$18,212
 
$  3,452
Total assets
100,692
 
105,954
 
110,224
 
66,604
 
42,070
Notes payable
45,000
 
40,000
 
40,000
 
35,000
 
25,000
Total stockholders’ equity
43,545
 
54,799
 
58,627
 
23,837
 
10,745
_______________
(1)
Includes lease operating expenses and production taxes.
(2)
Includes geophysical and geological costs, exploratory dry hole costs, and nonproducing leasehold impairments.
(3)
Includes proved and unproved property write-downs relating to our properties in the United States and Poland.
(4)
Working capital represents current assets minus current liabilities.



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

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

Overview

As discussed in Item 1, Business, above, the majority of our operations are in Poland, and we have devoted most of our technical talent and capital expenditures in the last several years to our operations in that country.  The decision to devote most of our available capital to this area drives our operating results and the changes to our balance sheet and liquidity.  Our operations in Poland, which are a combination of existing production and substantial exploration, have grown considerably.  Oil and gas production, oil and gas revenues, cash flow, and oil and gas expenditures in this area have increased significantly over the last five 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, while smaller than our Polish operations, our U.S. operations are a relatively stable source of revenue.  This, too, is reflected in our operating results.
 
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Current highlights include:

●  
During 2013, we successfully replaced our $55 million Reserve Based Lending Facility with a new, five-year, up to $100 Million Senior Reserve Based Lending Facility with BNP Paribas (Suisse) SA and ING Bank N.V.  The initial commitment of the facility amounts to $65 million.  We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism.  We believe this is a positive reflection of the success we have been experiencing in Poland and provides us with important financial flexibility as we increase the pace of our capital spending going forward.

●  
In order to increase the commitment under our lending facility, we must continue to add proved reserves in Poland.  To that end, we have invested heavily over the past three years in prospect development.  During the past three years, we have spent more than $40 million in various 3D and 2D seismic projects, both in our Fences area and in our other, 100%-owned concessions.  As a result, our inventory of drill-ready prospects is at its highest level.

●  
We are continuing to build momentum in our capital spending program.  Since 2010, our capital spending has increased at a compound annual growth rate of 55%, reaching a record $50 million in 2013.  We expect our capital spending from available sources in 2014 to exceed 2013 levels.

●  
Poland remains economically attractive for us.  Natural gas prices continue to show strength in the face of unsettled global economies.  At the time of this report, the low-methane tariff in Poland was 31% higher than at year-end 2010.

●  
The average gas price we received in 2013, taking into account currency fluctuations throughout the year, was 32% higher than the amount we received in 2010.

●  
We continue to diversify our production risk profile.  At the time of this report, we were producing gas from seven wells in the Fences concession, with one additional well scheduled to begin production during 2014, and a second well scheduled to begin production in 2015.  We also have a minor amount of production from our three wells in the Grabowka area.  At the end of 2010, we were producing gas from only four wells in Poland.

●  
Since 2009 through 2013, we have been designated to act as the operator for permitting, designing, and constructing all new production facilities in Poland.

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

●  
a possible new hydrocarbon law that, 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 Lisewo-1 well in 2013, and our Winna Gora and Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells in prior years, which prevented higher production and revenue gains during those years;

●  
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 nonoperating 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 and first production, and lower initial production rates; and

●  
volatile noncash adjustments for foreign currency fluctuations that continue to affect our net income in an unpredictable fashion.
 
44
 
 

 


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:

  ●  
a government-established tariff price for our Polish gas production rather than a free-market price; and

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

Our operations are also affected by reduced drilling success ratios as we increasingly explore outside our core Fences area.

Commodity Prices

Global oil prices continued to be volatile in 2013.  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.

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 to consumers 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.  Laws enacted in 2013 require Poland to establish a competitive market for gas sold by nonproducers, but so far a liquid market with significant trading volumes and representative prices has not developed.  If a free market for gas develops, our tariff gas prices may be replaced by market prices.  At this early stage, we cannot predict how competitive market prices may compare with tariff prices.

Poland continues to enjoy one of the strongest economies in the European Union and was the only country in Europe to record positive GDP growth every year from 2008 through 2013.  While the economy is expected to slow somewhat, economists are still predicting positive growth during 2014.  These factors may act as cushions against possible declines in prices.  As of year-end 2013, gas prices in Poland remained firm and were significantly higher than those of an equivalent BTU content in the United States.  In early 2014, the public utility regulator increased the low-methane tariff by 3.1%.  While domestic U.S. gas prices have strengthened considerably in early 2014, 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 80% higher than the spot price under natural gas contracts for 100% methane gas traded on the New York Mercantile Exchange, or the Henry Hub price.  The volumes of our gas reserves in Poland from 2010 through 2013 were not impacted by changing prices.  However, all of our oil and gas reserves can be price-sensitive, and future material reductions in the prices at which we sell our oil and gas could result in the impairment of reserves.

Functional Currency and Exchange Rates

The functional currency of our Polish subsidiary is the Polish zloty.  Accounting standards require the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation.  Because FX Energy Poland’s functional currency is the Polish zloty, translation adjustments result from the process of translating its financial statements into the 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.
 
45
 
 

 


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 2013, the zloty fluctuated between a low of 3.01 zlotys per dollar to a high of 3.37 zlotys per dollar, a fluctuation of 12%.  Variations in exchange rates affect the dollar-denominated amount of revenue we report, compared to what we receive in zlotys.  As the dollar strengthens relative to the zloty, our dollar-denominated revenue actually received in zlotys declines; conversely, when the 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 dollar-denominated drilling, capital, and exploration costs, while a strong dollar has the opposite effect for the cost structure of our Polish operations.  Should exchange rates in effect during early 2014 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our dollar-denominated revenues, and a slightly negative impact on our dollar-denominated costs, compared to 2013.

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 2013, the exchange rate was 3.01 zlotys per U.S. dollar compared to 3.10 zlotys per U.S. dollar at the end of 2012.  This 3% 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, 2013, 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 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 initial draft addresses the concession system and environmental regulation.  Principal proposals for consideration include the replacement of the current three types of concessions with one concession for exploration and production; new requirements for prequalification for applicants for concessions; and increases of revenues to local authorities from oil and gas production.  Administrative changes would be aimed at improving concession administration.

A revised draft, which reflects some of the industry comments, is expected to be approved by the government in March 2014, 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.

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, respecting the royalty regime, and January 1, 2020, respecting new taxes.  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.

As the new law has not yet been adopted and is expected to be significantly modified as compared to the version last published in October 2013, 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.
 
46
 
 

 


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, 2013, 2012, and 2011 (in thousands):

 
Reportable Segments
   
 
Exploration & Production
     
 
Poland
U.S.
Oilfield Services
Non-Segmented
Total
Year ended December 31, 2013:
         
Revenues
$29,450
$3,861
$1,218
$         --
$  34,529
Net income (loss)(1)
    (1,889)
    929
    (917)
     (9,923)
    (11,800)
           
Year ended December 31, 2012:
         
Revenues
$30,344
$4,117
$2,137
$         --
$  36,598
Net income (loss)(2)
     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)(3)
    5,250
  1,668
    189
   (35,631)
    (28,524)
_______________
 
(1)
Nonsegmented reconciling items for 2013 include $8,836 of G&A costs, $2,853 of noncash stock compensation expense, $4,967 of noncash foreign exchange gains, $3,164 of interest expense (net of other income), and $37 of corporate DD&A.
(2)
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.
(3)
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.

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 $29.5 million during 2013, compared to $30.3 million and $25.1 million in 2012 and 2011, respectively.  Our 2013 gas revenues decreased by $0.8 million from 2012 levels by approximately $1.7 million due to lower production, which was partially offset by $0.9 million in higher revenues due to higher gas prices.  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.

Company-wide net gas production decreased from a daily rate in 2012 of approximately 12.2 MMcfd to a rate of approximately 11.4 MMcfd in 2013, a decrease of 7%.  In mid-February 2014, gas was flowing in Poland at an average rate of 12.6 MMcfd, net to our interest.

Gas prices were 4% higher in 2013 than in 2012.  The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 3.3% lower during the full year of 2013 compared to 2012, due to a decrease in the tariff that was effective January 1, 2013.  However, the decrease in the tariff was partially offset by the effect of currency changes from year to year.  Strength in the Polish zloty increased our U.S. dollar-denominated gas prices.  The average exchange rate during 2012 was 3.26 zlotys per U.S. dollar.  The average exchange rate during 2013 was 3.16 zlotys per U.S. dollar, a change of approximately 3.1%.  Lastly, gas production at our Zaniemsyl well, where we receive 70% of the low-methane tariff, stopped in mid-2013, which caused our average price per thousand cubic feet to increase.  Gas from our other Fences area wells is sold at a minimum of 86% of the tariff.
 
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Gas production at our three KSK wells averaged 11.1 MMcfd during 2013, compared to 9.5 MMcfd during 2012.  At year-end, the wells were producing at a combined rate of 11.1 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 8.9 MMcfd during 2013, compared to 12.1 MMcfd during 2012.  At year-end, the well was producing at a rate of 8.1 MMcfd.  We plan to install compression equipment at the well during 2014 to maintain production levels.  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 approximately 2.0 MMcfd through the first six months of 2013, at which point it was terminated due to an influx of water.  We plan to sidetrack the well in 2014 to access additional gas accumulations that appear to be present higher in the structure.  Gas at Zaniemysl is 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 and averaged 2.0 MMcfd during the year.  At year-end, the well was producing approximately 2.1 MMcfd.  Gas at Winna Gora 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 Winna Gora well.

Gas production began at our Lisewo-1 well in December of 2013.  At year-end, the well was producing approximately 4.9 MMcfd.  Gas at Lisewo-1 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 Lisewo-1 well.

A summary of the amount and percentage change, as compared to their respective prior-year periods, for gas revenues, average gas prices, gas production volumes, and lifting costs per Mcf is set forth in the following table:

 
Year Ended December 31,
 
2013
 
2012
 
2011
Revenues
$29,450,000
 
$30,344,000
 
$25,120,000
Percent change versus prior year
-3%
 
+21%
 
+34%
Average price (per Mcf)
$7.11
 
$6.81
 
$6.19
Percent change versus prior year
+4%
 
+10%
 
+15%
Production volumes (Mcf)
4,147,000
 
4,457,000
 
4,060,000
Percent change versus prior year
-7%
 
+10%
 
+17%
Lifting costs per Mcf(1)
$0.33
 
$0.28
 
$0.23
Percent change versus prior year
+18%
 
+22%
 
-21%
_______________
(1)
Lifting costs per Mcf are computed by dividing the related lease operating expenses by the total volume of gas produced.

Oil Revenues.  Oil revenues were $3.9 million, $4.1 million, and $4.7 million for the years ended December 31, 2013, 2012, and 2011, respectively.  Higher average oil prices in 2013 compared to 2012 were offset by lower production to cause the decrease in revenues.  Lower average oil prices in 2012 compared to 2011 combined with lower production to cause the decrease in revenues.  Our average oil price during 2013 was $79.48 per barrel, a 3% increase compared to $76.87 per barrel received during 2012.  Production from our U.S. properties declined by 9% due to normal production declines.

U.S. oil revenues in 2013 increased from 2012 levels by approximately $0.1 million due to higher oil prices, offset by approximately $0.3 million related to production declines.  U.S. oil revenues in 2012 decreased from 2011 levels by approximately $0.3 million due to lower oil prices, combined with 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 is set forth in the following table:

 
Year Ended December 31,
 
2013
 
2012
 
2011
Revenues
$3,861,000
 
$4,117,000
 
$4,688,000
Percent change versus prior year
-6%
 
-12%
 
+12%
Average price (per Bbl)
$79.48
 
$76.87
 
$83.02
Percent change versus prior year
+3%
 
-7%
 
+22%
Production volumes (Bbl)
48,575
 
53,553
 
56,462
Percent change versus prior year
-9%
 
-5%
 
-8%
Lifting costs per Bbl(1)
$47.64
 
$44.80
 
$50.41
Percent change versus prior year
+6%
 
-11%
 
+27%
_______________
(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 $3.7 million in 2013, $3.6 million in 2012, and $3.8 million in 2011.  Operating costs in the United States decreased in 2013 by approximately $0.1 million over 2012 costs, due to lower workover costs incurred on our existing producing wells during that year.  Operating costs in Poland increased 11% in 2013 from 2012 levels, primarily due to new production from our Winna Gora and Lisewo-1 wells.

Exploration Costs.  Exploration expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes.  Exploration costs were $20.8 million, $23.8 million, and $16.6 million for the years ended December 31, 2013, 2012, and 2011, respectively.  Higher geological and geophysical costs were offset by lower dry-hole costs in 2013.

Geological and geophysical costs, or G&G costs, were $14.1 million, $11.1 million, and $15.3 million for the years ended December 31, 2013, 2012, and 2011, 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, Edge, and other concession areas in Poland.

Exploratory dry-hole costs were $6.7 million, $12.7 million, and $1.3 million for the years ended December 31, 2013, 2012, and 2011, respectively.  Our 2013 dry-hole cost were associated with our Mieczewo-1K and Plawce-2 wells in Poland.  Our 2012 dry-hole costs were associated primarily with our Kutno-2 well in Poland.  The Kutno-2 well, which was the deepest well ever drilled in Poland, was found to be noncommercial during the third quarter of 2012.  Total costs to us were approximately $12.2 million.  Our 2011 dry-hole costs were associated with our Machnatka-2 well.

Impairment Costs.  Impairments of oil and gas properties were $6.1 million, $2.6 million, and $72,000 for the years ended December 31, 2013, 2012, and 2011, respectively.  During 2013, we impaired approximately $4.5 million of prior-year costs associated with our Plawce-2 well following its unsuccessful fracture stimulation, along with approximately $0.2 million of prior-year costs associated with our Mieczewo-1K well.  In addition, our Zaniemysl-3 well ceased production during 2013, causing us to charge its remaining net book value of $0.4 million to impairment expense.  Finally, we recorded an impairment charge of $1.0 million related to concession costs in our Northwest and Warsaw South project areas, where we have dropped acreage that we believe is less prospective for oil and gas accumulations. During 2012, we impaired $0.8 million in costs of certain concessions in Poland that we determined were not prospective.  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, $0, and $52,000 for the years ended December 31, 2013, 2012 and 2011, 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, 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 $3.6 million, $3.1 million, and $2.3 million for the years ended December 31, 2013, 2012, and 2011, respectively.  The 16% increase from 2012 to 2013 is due primarily to new production from our Winna Gora and Lisewo-1 wells.  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-3 wells.

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 $90,000, $63,000, and $68,000 for the years ended December 31, 2013, 2012 and 2011, 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 $1.2 million, $2.1 million, and $5.6 million for the years ended December 31, 2013, 2012, and 2011, respectively.  We drilled three wells for third parties during 2013, along with additional well service work.  During 2012, we drilled five wells for third parties, including one drilled for our Alberta Bakken joint venture, 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.  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 $1.2 million, $1.6 million, and $4.5 million for the years ended December 31, 2013, 2012, and 2011, respectively, or 97%, 76%, and 79% 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, along with higher equipment repair costs in 2013.  In general, oilfield-servicing costs are closely associated with oilfield services revenues.  As such, oilfield services costs will continue to fluctuate period to period based on the number of wells drilled, revenues generated, weather, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.

DD&A Expense – Oilfield Services.  DD&A expense for oilfield services was $1.0 million, $1.1 million, and $1.0 million for the years ended December 31, 2013, 2012, and 2011, respectively.  We spent $1.1 million, $0.7 million, and $1.2 million on upgrading our oilfield-servicing equipment during 2013, 2012, and 2011, respectively.

Nonsegmented Items

G&A Costs - Corporate.  G&A costs were $8.8 million, $8.4 million, and $8.4 million for the years ended December 31, 2013, 2012, and 2011, respectively.  The increase in 2013 is primarily due to higher compensation costs, including the payment of a company-wide incentive award of approximately $500,000 related to 2008, which had been deferred until we met certain performance benchmarks, which were met in 2013.  Increased costs in 2012 associated with higher headcount in Poland were offset by lower legal and other fees in the United States.
 
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Stock Compensation.  Stock compensation expense recorded for 2013 represents $2.9 million of amortization related to restricted stock and stock options granted to employees in previous years.  Stock compensation expense recorded for 2012 represents $2.3 million of amortization related to restricted stock and stock option grants in previous years.  Stock compensation expense recorded for 2011 represents $1.7 million of amortization related to restricted stock and stock option grants in previous years.

Interest and Other (Income) Expense - Corporate.  Interest and other (income) expense was $3.2 million, $2.1 million, and $2.0 million for the years ended December 31, 2013, 2012, and 2011, respectively.  During 2013, we incurred $3.3 million in interest expense.  We recorded $1.2 million of amortization of loan fees, including $0.7 million related to our prior credit facility that was charged to interest expense by virtue of our refinance, and $0.3 million in unused commitment fees.  Interest and other income was $0.1 million during 2013.

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.

Foreign Exchange.  We recognized foreign exchange gains of $5.0 million and $16.3 million for the years ended December 31, 2013 and 2012, respectively, and we incurred foreign exchange losses of $23.4 million for the year ended December 31, 2011.  Foreign exchange gains and losses arise from decreases and increases, respectively, in the amount of Polish zlotys necessary to satisfy outstanding intercompany and other U.S. dollar-denominated loans and unpaid interest between FX Energy Poland and FX Energy, Inc.

Income Taxes.  We reported a net loss of $11.8 million for the year ended December 31, 2013, net income of $4.1 million for the year ended December 31, 2012, and a net loss of $28.5 million for the year ended December 31, 2011.  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 2013 due primarily to negative revisions at our Grabowka, Zaniemysl-3, Winna Gora, and Lisewo-1 wells due to declining production and well head pressures, along with negative revisions in the United States due to higher than previously estimated production declines.  Positive reserve revisions at our Roszkow and KSK wells due to more favorable technical data, along with new reserves at our Szymanowice-1 well (which was completed during the year), partially offset our 2013 gas production and the negative revisions.

The following table highlights year-end reserve volumes and values and shows the change from 2012 to 2013:

 
2013
 
2012
  Change
 
(In thousands)
Proved Reserve Volumes:          
Gas reserves (Mcf)
42,012
 
44,121
 
-5%
Oil reserves (Bbls)
461
 
594
 
-22%
Total reserves (Mcfe)
44,778
 
47,688
 
-6%
           
Proved Reserve Values:
         
Reserve SMOG Value
$151,802
 
$157,603
 
-4%
 
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Changes in proved reserves were as follows:

 
2013
 
2012
 
2011
Proved Reserves (MMcfe) Beginning of Year
47,688
 
53,470
 
43,793
Extensions, Discoveries, and Other Additions
3,947
 
2,313
 
12,245
Revisions of Previous Estimates
(2,416)
 
(3,317)
 
1,828
Production
(4,441)
 
(4,778)
 
(4,396)
Proved Reserves (MMcfe) End of Year
44,778
 
47,688
 
53,470

Extensions, Discoveries, and Other Additions.  All of the 2013 additions to proved reserves that result from the discovery of new fields are associated with our Szymanowice-1 well.

Revisions.  Revisions represent changes in previous reserve 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 2013, excluding the volume reduction due to annual production, we recorded downward revisions at our Grabowka, Zaniemysl-3, Winna Gora, Roszkow, and Lisewo-1 wells due to declining production and well head pressures.  These were partially offset by upward reserve revisions at our KSK wells, where new pressure data indicates that the initial gas-in-place for these wells may be more than estimated at year-end 2012.  We also recorded negative revisions of approximately 84,000 barrels of oil in the United States, primarily due to higher than previously estimated production declines.  During 2012, excluding the volume reduction due to annual production, we recorded downward revisions at our Zaniemysl-3 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-1, 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-3 and KSK wells.  At Roszkow, new pressure data indicated 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.  (See Items 1 and 2, Business and Properties).

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

2014 Operational Trends

We currently expect that our 2014 production will rise from our 2013 production rates with the start of production at our Lisewo-2 and Komorze-3K wells, coupled with a full year of production from our Lisewo-1 and Winna Gora wells, which we believe will be greater than the natural declines in production from our currently producing wells.  We currently expect to receive 86% of the published low-methane tariff, adjusted for energy content, for each of the two new wells.  The amount of revenue from this increased production will depend on applicable gas sales prices and prevailing currency exchange rates.

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

Costs that vary in concert with production, such as lease operating expenses and DD&A costs, will trend up or down with production increases or decreases.  Our 2014 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.
 
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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, our internally generated cash flow has become a significant source of operations financing.

2013 Liquidity and Capital

Working Capital (current assets less current liabilities).  Our working capital was $11.3 million as of December 31, 2013, a decrease of $19.1 million from December 31, 2012.  The primary cause of the decrease is the increased level of our exploration and capital costs in 2013.

Our current assets at year-end 2013 included approximately $11.2 million in cash and cash equivalents, $3.5 million in accrued oil and gas sales from both the United States and Poland, and $5.0 million in receivables from our joint interest partners in both the United States and Poland that were collected in early 2014.  At year-end 2013, $8.9 million of our cash and cash equivalents were held in Poland at ING Bank N.V.  We have not historically repatriated, and do not plan in the foreseeable future to repatriate, any cash held in Poland to the United States.  Consequently, we do not expect to incur repatriation taxes in the foreseeable future.  Almost the entire balance of joint interest receivables at year-end 2013 was due from PGNiG, all of which are related to joint projects in which we act at the operator.  Our current liabilities at year-end included approximately $8.7 million payable by FX Poland for various drilling and development operations in Poland that were paid in early 2014.

Operating Activities.  Net cash provided by operations during 2013 was $2.3 million.  Net cash used in operations during 2012 was $1.2 million.  Cash flow from operating activities in 2013 benefited from positive change in working capital items.  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.

Investing Activities.  We used net cash in investing activities of $27.9 million, $16.3 million, and $18.5 million in 2013, 2012, and 2011, respectively.  In 2013, we spent $26.8 million for oil and gas property additions, $26.0 million of which were related to our Polish drilling activities, with the remainder being spent on our domestic properties.  We also spent $1.1 million adding to our oilfield services equipment.  In 2012, we spent $15.8 million for oil and gas property additions, all of which were 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.

Financing Activities.  Our cash flow from financing activities was $3.0 million, 0, and $50.8 million, during 2013, 2012, and 2011, respectively.  During 2013, we borrowed $43.0 million under our new credit facility, using $40 million to repay our 2010 credit facility and $2.0 million in fees associated with the new credit facility.  There were no financing transactions during 2012.  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 $0.8 million from the exercise of stock options.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2014 include our working capital of $11.3 million at year-end 2013, available credit under our new credit facility, and cash available from our operations.

In July 2013, we finalized a new, five-year, up to $100 Million Senior Reserve Based Lending Facility with BNP Paribas (Suisse) SA and ING Bank N.V.  The initial commitment of the facility amounts to $65 million.  We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism.  Initial proceeds from the new facility were used to repay our previously existing facility.  Payment of the credit facility is secured by our assets in Poland and guaranteed by us.
 
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The credit facility calls for a periodic interest rate of LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years.  The facility has a term of five years, with semiannual borrowing base reductions of $13 million beginning on June 30, 2016.  There are no financial covenants associated with the new credit facility.  As of December 31, 2013, we had $45 million outstanding under the facility and $20 million of available credit.

We expect to generate cash from our operating activities to help fund our exploration and development activities in 2014.  We expect that our 2014 production will approximate or be higher than our 2013 production with the addition of production at our Lisewo-2 and Komorze-3K wells.  Production began at Komorze-3K in late February of 2014.  Production is expected to begin at Lisewo-2 during the second half of 2014.  We currently expect to receive 86% of the published low-methane tariff, adjusted for energy content, for each of the two 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 2013, we were in the process of completing production facilities at our Komorze-3K well and were completing the design and permitting of similar facilities for our Lisewo-2 and Szymanowice-1 wells.  We began drilling the Tuchola-4K well in early 2014.  Our total costs for these facilities and the well once production begins and drilling is completed are expected to be approximately $11 million.  We had no other firm commitments for future capital and exploration costs at 2013 year end.

We expect our primary use of cash for 2014 will be for our exploration and development activities in Poland.  Our board of directors has approved projects whose costs are expected to range from $50 million to $60 million for production facilities for existing discoveries, exploration and development wells, capital additions for our drilling rigs, 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 2014, but we do expect to start work on all of them in the next 12 months.  In 2013, we approved a capital budget of similar size.  Our actual costs in 2013 were approximately $50.0 million.

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, 2013, we have incurred cumulative net losses of approximately $198 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 interests of our existing stockholders or our interest in the specific project financed.
 
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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, 2013, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:

 
Total
 
2014
 
2015
 
2016
 
2017
 
2018
 
(In thousands)
Credit facility
$45,000
 
$      --
 
$      --
 
$6,000
 
$26,000
 
$13,000
Interest payments on long-term debt
6,843
 
1,762
 
1,762
 
1,819
 
1,354
 
271
Total
$51,843
 
$1,762
 
$1,762
 
$7,819
 
$27,354
 
$13,271

Under the terms of our up to $100 million credit facility, the amount of credit available is reduced by $13 million each six months, beginning on June 30, 2016.  As of December 31, 2013, we had borrowed $45 million under the facility, and the reduction of that amount is illustrated in the table above.

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

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

Asset Retirement Obligation.  We have liabilities of $1.6 million related to asset retirement obligations on our Consolidated Balance Sheet at December 31, 2013, 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 evaluated the provisions of the new standards and determined that they did not a significant effect on current or future earnings or operations.
 
55
 
 

 


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

Critical Accounting Policies

Oil and Gas Activities

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

Oil and Gas Reserves

All of the reserve 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 reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.  As a result, reserve 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 reserve estimate.  We based our December 31, 2013, reserve 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 reserve 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

Stock-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.
 
56 
 
 

 

 
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 2013, the zloty fluctuated between a low of 3.01 zlotys per dollar to a high of 3.37 zlotys per dollar, a fluctuation of 12%.  Variations in exchange rates affect the dollar-denominated amount of revenue we receive in zlotys.  As the dollar strengthens relative to the zloty, our dollar-denominated revenue received in zlotys declines; conversely, when the dollar weakens relative to the zloty, our dollar-denominated revenue received in zlotys increases.  Conversely, a weak dollar leads to lower dollar-denominated drilling, capital, and exploration costs, while a strong dollar has the opposite effect for the cost structure of our Polish operations.  Should exchange rates in effect during early 2014 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our dollar-denominated revenues compared to 2013.  We are also generating revenues in Poland in zlotys, and we keep those zlotys in Poland and use them to pay zloty-based invoices.


 
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-1 immediately following the signature page of this report.


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

None.
 
57 
 
 

 

 
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, 2013, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2013, our disclosure controls and procedures were effective.

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.

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.  Our internal control over financial reporting is a process designed by our principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles.

As of the end of our 2013 fiscal year, management conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework established in the 1992 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this assessment, management has determined that our internal control over financial reporting as of December 31, 2013, was effective.

Our internal control over financial reporting includes policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our consolidated financial statements.

The effectiveness of our internal control over financial reporting as of December 31, 2013, has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that follows.

/s/ David N. Pierce
President and Chief Executive Officer

/s/ Clay Newton
Principal Financial and Accounting Officer
 
58 
 
 

 
Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders
FX Energy, Inc.

We have audited the internal control over financial reporting of FX Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2013, and our report dated March 13, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP
Salt Lake City, Utah
March 13, 2014


 
ITEM 9B. OTHER INFORMATION
 

None.
 
59
 
 

 
PART III

 
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 

The information from our definitive proxy statement for our 2014 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 2014 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 2014 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 2014 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 2014 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.
 
60
 
 

 
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
 
Report of Independent Registered Public Accounting Firm
F-1
 
Report of Independent Registered Public Accounting Firm
F-2
 
Consolidated Balance Sheets as of December 31, 2013 and 2012
F-3
 
Consolidated Statements of Operations for the Years Ended
 
 
December 31, 2013, 2012, and 2011
F-5
 
Consolidated Statements of Comprehensive Loss for the Years Ended
 
 
December 31, 2013, 2012, and 2011
F-6
 
Consolidated Statements of Cash Flows for the Years Ended
 
 
December 31, 2013, 2012, and 2011
F-7
 
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years
 
 
Ended December 31, 2013, 2012, and 2011
F-8
 
Notes to the Consolidated Financial Statements
F-9

 
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 March 12, 2014
 
This filing.

61
 
 

 
 
 
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 Górnictwo 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 Górnictwo 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.
 
62
 
 

 
 
 
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.
         
10.99
 
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.
 
63
 
 

 
 
 
Exhibit
Number*
 
Title of Document
 
Location
         
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]
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2012, filed March 14, 2013.
         
10.108
 
Up to USD 100,000,000 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., BNP Paribas (Suisse) SA and ING Bank N.V. dated July 3, 2013
 
Incorporated by reference from the current report on Form 8-K filed July 17, 2013.
         
10.109
 
Intercreditor Deed among FX Energy Poland Sp. z o.o, BNP Paribas (Suisse) SA, ING Bank N.V., BNP Paribas SA, and the subordinated lenders dated July 3, 2013
 
Incorporated by reference from the current report on Form 8-K filed July 17, 2013.
         
10.110
 
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.; BNP Paribas (Suisse) SA; and FX Energy Netherlands B.V., dated July 5, 2013
 
Incorporated by reference from the current report on Form 8-K filed July 17, 2013.
         
10.111
 
Agreement No. 12/KZ/2013 for the Sale of Gas from Lisewo gas field between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A.
 
Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed August 8, 2013.
         
10.112
 
Agreement No. 13/KZ/2013 for the Sale of Gas from Komorze gas field between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A.
 
This filing.
         
Item 16
 
Letter re Change in Certifying Accountant
   
16.01
 
Letter from PricewaterhouseCoopers LLP dated September 10, 2013
 
Incorporated by reference from the current report on Form 8-K filed September 10, 2013.
         
 
64
 
 

 
 
 
Exhibit
Number*
 
Title of Document
 
Location
         
Item 21
 
Subsidiaries of the Registrant
   
21.01
 
Schedule of Subsidiaries
 
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2007, filed March 10, 2008.
         
Item 23
 
Consents of Experts and Counsel
   
23.01
 
Consent of Grant Thornton, independent registered public accounting firm
 
This filing.
         
23.02
 
Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm
 
This filing.
         
23.03
 
Consent of Hohn Engineering PLLC, Petroleum Engineers
 
This filing.
         
23.04
 
Consent of RPS Energy, Petroleum Engineers
 
This filing.
         
Item 31
 
Rule 13a-14(a)/15d-14(a) Certifications
   
31.01
 
Certification of Principal Executive Officer Pursuant to Rule 13a-14
 
This filing.
         
31.02
 
Certification of Principal Financial Officer Pursuant to Rule 13a-14
 
This filing.
         
Item 32
 
Section 1350 Certifications
   
32.01
 
Certification 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.
 
65
 
 

 


 
SIGNATURES
 

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

 
FX ENERGY, INC. (Registrant)
 
       
       
       
Dated: March 13, 2014
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 13, 2014
Thomas B. Lovejoy, Director
 
     
 
/s/ David N. Pierce
 
Dated: March 13, 2014
David N. Pierce, Director, President,
 
 
and Principal Executive Officer
 
     
 
/s/ Dennis B. Goldstein
 
Dated: March 13, 2014
Dennis B. Goldstein, Director
 
     
 
/s/ Arnold S. Grundvig, Jr.
 
Dated: March 13, 2014
Arnold S. Grundvig, Jr., Director
 
     
 
/s/ Jerzy B. Maciolek
 
Dated: March 13, 2014
Jerzy B. Maciolek, Director
 
     
 
/s/ Richard Hardman
 
Dated: March 13, 2014
Richard Hardman, Director
 
     
 
/s/ H. Allen Turner
 
Dated: March 13, 2014
H. Allen Turner, Director
 
     
 
/s/ Clay Newton
 
Dated: March 13, 2014
Clay Newton, Principal Financial and
 
 
Accounting Officer
 

66
 
 

 

 
 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

Board of Directors and Shareholders
FX Energy, Inc.

We have audited the accompanying consolidated balance sheet of FX Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2013, and the related consolidated statement of operations, comprehensive income (loss), cash flows, and stockholders’ equity for the year then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of FX Energy, Inc. and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 13, 2014 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ GRANT THORNTON LLP
 
Salt Lake City, Utah
March 13, 2014
 


F-1
 
 

 




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors
of FX Energy, Inc. and its subsidiaries

In our opinion, the consolidated balance sheet as of December 31, 2012 and the related consolidated statements of operations, of comprehensive income (loss), of cash flows and of stockholders’ equity for each of two years in the period ended December 31, 2012 and December 31, 2011 present fairly, in all material respects, the financial position of FX Energy, Inc. and its subsidiaries at December 31, 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2012 and December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 14, 2013


F-2
 
 

 

  FX ENERGY, INC., AND SUBSIDIARIES
  Consolidated Balance Sheets
  As of December 31, 2013 and 2012
  (in thousands)


 
2013
 
2012
ASSETS
         
           
Current assets:
         
Cash and cash equivalents
$
11,153 
 
$
33,990 
Receivables:
         
Accrued oil and gas sales
 
3,464 
   
3,447 
Joint interest and other receivables
 
5,029 
   
7,733 
Value-added tax receivable
 
1,847 
   
1,136 
Inventory
 
100 
   
199 
Other current assets
 
234 
   
614 
Total current assets
 
21,827 
   
47,119 
           
Property and equipment, at cost:
         
Oil and gas properties (successful-efforts method):
         
Proved
 
85,244 
   
63,821 
Unproved
 
2,404 
   
2,337 
Other property and equipment
 
11,857 
   
10,717 
Gross property and equipment
 
99,505 
   
76,875 
Less accumulated depreciation, depletion, and amortization
 
(23,369)
   
(19,786)
Net property and equipment
 
76,136