ITEM 1. BUSINESS
Introduction
We are an independent oil and gas exploration and production company with production, appraisal, and exploration activities in Poland. We also have modest oil production, oilfield service activities, and a shale acreage position in the United States. Our headquarters are in Salt Lake City, Utah. 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 2010, independent reserve engineers estimated our worldwide proved oil and gas reserves to be 40.0 billion cubic feet, or Bcf, of natural gas and 0.6 million barrels of oil, or a combined total of 43.8 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 43.8 Bcfe, 91% was in Poland and 9% was in the United States. The engineers estimated the PV-10 Value of our proved reserves to be approximately $127.3 million.
At year-end 2010, independent reserve engineers estimated our worldwide proved plus probable, or P50, oil and gas reserves to be a combined total of 87.1 Bcfe. The engineers estimated the PV-10 Value of our P50 reserves to be approximately $206.4 million.
Subsequent to year-end 2010, we had a significant exploration discovery, the Lisewo-1 well in Poland. Independent engineers estimate the proved and P50 reserves for this well to be approximately 12.7 and 17.7 Bcf of gas, respectively, net to our interest. The incremental PV-10 Value of these proved and P50 reserves is estimated to be $16.0 and $19.7 million, respectively. This discovery, in combination with our 2010 year-end proved reserves, would equate to 56.5 Bcfe of proved reserves, with an estimated PV-10 Value of $143.3 million. Our year-end P50 reserves would then equate to 104.8 Bcfe, with an estimated PV-10 Value of $226.1 million.
Our 2010 oil and gas production was 3.8 Bcfe (10.5 million cubic feet equivalent per day, or MMcfed), which was up 69% from 2009 production; 3.5 Bcfe (9.5 MMcfed) of our production was in Poland and 0.3 Bcfe (1.0 MMcfed) was in the United States. All of our production in Poland consisted of natural gas, while all of our United States production consisted of crude oil.
We currently expect that our 2011 production will rise significantly from our 2010 production rates. One of our wells in Poland started producing just a few days before the end of 2010, and we have two other wells in Poland scheduled to begin production during the second quarter of 2011. We expect these three new wells, with anticipated aggregate initial production of approximately 14 million cubic feet per day, or MMcfd, of gas (6.9 MMcfd net to us), will add to our 2010 base levels of production of 9.5 MMcfd of gas. Thus, even without the benefit of any production from a fourth well that is waiting on production facilities or from our recent Lisewo-1 well or other possible discoveries, we expect our 2011 production to significantly exceed our 2010 level.
Substantially all of our growth in reserves and production in recent years has come from our operations in Poland. We expect this will continue, as most of our technical efforts and capital budget are devoted to these operations in Poland. We believe that these operations represent the most favorable opportunities for success that are available to us. See “Corporate Strategy” immediately below. With a view to future growth in reserves and production, we now hold 4.6 million gross acres (4.0 million net) in Poland and continually review additional acquisition opportunities.
As of December 31, 2010, we had approximately 45 million shares of common stock outstanding, and our market capitalization was approximately $280 million (approximately $510 million as of the date of this filing). Our shares are listed on the Nasdaq Global Market under the symbol “FXEN.” So far during 2011, our average daily trading volume has been approximately 500,000 shares. Our total assets as of December 31, 2010, were $66.6 million, and our net debt (long-term debt less working capital) was $16.8 million. Net debt per thousand cubic feet equivalent, or Mcfe, of proved reserves was $0.38 at year end, or $0.30 including the 12.7 Bcf of gas reserves associated with the subsequent Lisewo-1 discovery.
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 and Krakow, Poland, and Oilmont, Montana.
Corporate Strategy
Poland is a unique international exploration opportunity. Over the last 40 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, 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 Permian Basin mature oil and gas provinces in the United States and elsewhere. As an example, the gross proved reserves per well associated with our eight discoveries in our core Fences concession in Poland have been 17.1 Bcf. The average initial production rate for these eight wells is estimated to be approximately 6.0 MMcfd of natural gas. We believe these figures are materially higher than those associated with new discoveries in most mature oil and gas provinces.
Just as important as the reserve and production potential is the fact that Poland is highly dependent upon imported natural gas, which is expensive. There is an attractive and deep market for gas discoveries and production in-country. As of the date of this report, the price we receive for natural gas at our Roszkow well, for example, is approximately 69% higher than natural gas contracts traded on the New York Mercantile Exchange, sometimes referred to as the Henry Hub price.
Acting on this combination of facts, we were one of the first independent oil and gas companies to acquire a large land position, to embark on a focused exploration and development program, and as a result, to begin producing hydrocarbons in Poland. After several years of effort in Poland, our exploration efforts are showing significant progress. In fact, our proved oil and gas reserve volumes in Poland have increased at a compound annual growth rate of 22% since 2003. Our production volume has increased at a compound annual growth rate of 52% from 2005 through 2010. Though we cannot assert that future results will be similar, this success has encouraged us to continue to focus our efforts in Poland.
More specifically, we have directed the bulk of our available funds, management, and technical resources to our core “Fences” concession area in Poland. We expect to continue concentrating much of our capital budget to this area in an effort to lower drilling risk, shorten the time to first production from successful wells, and optimize opportunities for robust revenue growth. Over the last several years, we have drilled 11 wells in the Fences concession targeting Rotliegend structural traps, eight of which have been commercial discoveries.
With the success that we have achieved from our Fences drilling program, we now plan to explore selected parts of our other exploration acreage, namely the Warsaw South and Kutno concessions, through both targeted seismic data acquisition and drilling of several higher risk, higher reward exploration wells, where we believe we have the opportunity to find significant oil and gas reserves. To reduce our financial exposure to these higher risk exploration wells, we have successfully executed several farm-out agreements, whereby we may reduce our interest in the concessions in return for a partial carry on drilling costs.
We currently hold substantial acreage in other areas of Poland that we consider underexplored and underdeveloped and, therefore, subject to greater exploration risk. We plan to carry out preliminary exploration work on this acreage and then plan to continue our strategy of utilizing industry farm-outs to finance the bulk of early-stage drilling. 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 wider area in Poland.
Current Activities and Presence in Poland
We concentrate our exploration efforts in Poland primarily on the Rotliegend sandstones of the Permian Basin. We were attracted to the Rotliegend sandstones in Poland by two observations:
(1) Since the 1960s, dozens of western exploration companies working in the North Sea and onshore European portions of the North European Permian Basin have identified approximately 250 trillion cubic feet, or Tcf, of Rotliegend gas. While the Permian Basin extends well into Poland, only five Tcf of Rotliegend gas has been discovered in Poland by the Polish Oil and Gas Company, or PGNiG, which conducted all oil and gas exploration and production in the country until Poland was opened to foreign exploration. We believe political and capital constraints impaired PGNiG’s ability to explore and develop the Polish portion of the basin.
(2) In the last 25 years, very little exploration focused on the Rotliegend has been conducted in Poland, except within the perimeter of our core Fences concession, first by PGNiG in its retained areas and in recent years by us and PGNiG, working together in our jointly owned prospect areas.
We have identified a core area consisting of approximately 852,000 gross acres surrounding PGNiG’s long-producing Radlin field. This 390 Bcf Rotliegend gas field was discovered in the 1980s by our joint venture partner, PGNiG, which owns and produces gas from the field (we do not own an interest in this field, but see it as a geologic analog). We have emphasized improved seismic data acquisition and processing in our exploration efforts surrounding this field, using technology developed by others for Rotliegend exploration in the Southern North Sea.
Since 2000, we have made commercially successful discoveries in eight of the 11 wells we have drilled on Rotliegend structural trap targets. In the aggregate, these eight discoveries, which include the early 2011 Lisewo-1 discovery, found gross estimated proved reserves of approximately 137 Bcf of gas. We have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers in the Fences concession and plan to acquire 3-D seismic data over more of that concession. Using the data acquired to date, we have identified a number of possible structural traps. We believe the 3-D seismic data gives us better definition of the targets and might reduce our drilling risk. However, this is still exploration in an underexplored area. Thus, we expect to drill some wells that do not establish production or reserves, just as we have done in the past. Nonetheless, the extensive production history, well data, and seismic data available for the Fences area have contributed to our success rate there. We plan to continue to direct a significant portion of our available funds to carry out a multi-year exploration, appraisal, and development drilling program in the Fences concession. These operations are the focus of our strategy to increase production and reserves in our core area.
While maintaining our focus on the Rotliegend structural trap exploration model, we are also carrying out work to determine the tight gas potential in the Plawce structure located in the north of our Fences concession. The Plawce horst was discovered in the 1970s and 1980s; wells found large gas columns in tight Rotliegend reservoirs. Modern technology now allows the exploitation of these resources, which have significant potential. We plan to drill an appraisal well on the Plawce structure in 2011.
We have identified several drill-ready prospects outside the Fences concession, in our Warsaw South and Kutno concessions. These wells are higher risk and cost more than our Fences wells, but they are targeting greater resources. In order to reduce our financial exposure to these high risk wells, we have recently executed farm-out agreements with industry participants. These agreements may reduce our interest on these licenses in return for a partial carry on future exploration wells. We plan to begin drilling on the Warsaw South and Kutno concessions in 2011.
Outside the abovementioned licenses, we have accumulated a large land position in known productive regions or geologic trends and in selected “rank wildcat” areas in Poland. We have assembled a sophisticated technical team experienced with using modern exploration tools and generated a number of attractive oil and gas prospects. We will continue our strategy of inviting industry participation in the early-stage drilling of these prospects to reduce our financial exposure in each well. To the extent that our overall strategy results in substantial revenue growth, we plan to direct more of our own funds toward exploration of these early-stage exploration licenses.
Most of our current Polish operations are conducted in partnership with PGNiG. PGNiG is 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 most of our gas production to PGNiG. We sell almost all of our gas production in Poland to PGNiG.
Key Personnel for Poland
Our chief technical advisor is Richard Hardman, CBE. He also serves on our board of directors. Mr. Hardman has built a career in international exploration over the past 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.
Jerzy Maciolek is a director of the Company and heads our exploration team as Vice President of International Exploration. He joined the Company in 1995 specifically to lead us into Poland, where he had identified the exploration opportunity that today is our core asset. Mr. Maciolek has over 25 years of experience as a geophysicist with PGNiG and Gulf Oil Research and as an independent consultant. He received an M.S. in exploration geophysics from the Mining and Metallurgical Academy in Krakow, Poland.
Our Country Manager in Poland is Zbigniew Tatys, the former General Director of PGNiG’s Upstream Exploration and Production Division. During his 20-year career with PGNiG, he rose through the ranks as a production engineer and was serving as Vice Chairman of PGNiG at the time of his retirement. Mr. Tatys has unique qualifications to lead us through our transition from a pure exploration company to a natural gas and oil producer in Poland.
Our U.S. Presence
Unlike our position in Poland, our U.S. operation has not been the 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, oil-producing wells in the Cut Bank oil field of Montana. As of December 31, 2010, our U.S. reserves (all of which were proved reserves) were estimated at 639,000 barrels of crude oil with a PV-10 Value of approximately $9.7 million. At year-end 2010, U.S. reserves were approximately 9% of total proved reserves on a gas equivalent basis. Our oil wells produce approximately 168 barrels of oil per day, net to our interest. From our field office in Montana, we also provide oilfield services, which provided approximately $2.1 million in revenue during 2010.
Recently, U.S. and Canadian oil and gas operators have been drilling for oil in the Bakken and Three Forks formations in the Williston Basin in Montana and in Alberta, Canada. The Bakken (also known in Canada as the Exshaw) and related formations are the focus of a growing trend of testing oil potential with multistage fracturing of horizontal wells. Newfield Exploration Co. (NFX) and Rosetta Resources, Inc. (ROSE), are two of the more active companies among a number operating near our Cut Bank field in northern Montana. We plan to reenter and deepen several of our existing Cut Bank field wells to take core samples from the Bakken and related formations for laboratory testing during the summer of 2011 and may drill one or more wells in the second half of this year, subject to positive laboratory results. We are also discussing the Bakken play with other companies in the area with a view to possibly investigating the Bakken potential over a broader area.
Exploration, Development, and Production Activities
Polish Exploration Rights
As of December 31, 2010, we held oil and gas exploration rights in Poland in a number of separately designated project areas encompassing approximately 4.6 million gross acres. We are currently the operator in all areas, except our 852,000 gross-acre core Fences project area, in which we hold a 49% interest in approximately 807,000 acres and a 24.5% interest in the remaining 45,000 acres. PGNiG is the operator in the Fences project area. We hold interests in approximately 4.0 million net acres throughout Poland.
As we build revenues in our core area and further explore and evaluate our acreage in Poland, we expect to increase the operational and financial efforts we expend outside our core area. As we do so, we may add new concessions that we believe have high potential and relinquish acreage that we believe has lower potential. See “Wells and Acreage” below for further information.
Exploratory Activities in Poland
Our ongoing activities in Poland are conducted in several project areas: Fences, Block 287, Warsaw South, Kutno, Northwest, Edge, Block 229, and Block 246. Our drilling activities have been focused primarily on the core Fences area. We have focused on this core area because substantial gas reserves have already been discovered and developed by PGNiG. We and PGNiG have discovered proved gas reserves of over 137 Bcf gross (59 Bcf net to our interest) in eight commercial wells in the Fences area as of the date of this report. We have concluded that there is likely to be substantial additional natural gas in the same geologic horizon in this area. We are selling gas from wells located in the Fences area and Block 287.
We plan to begin drilling on the Warsaw South and Kutno concessions in 2011. These wells will be targeting greater resources, but will be higher risk than our Fences wells. To help mitigate the financial risk from drilling these wells, we have executed farm-out agreements with industry participants.
We are developing longer-term exploration prospects in the remaining project areas.
Fences Area
The Fences concession area encompasses 852,000 gross acres (3,450 sq. km.) in western Poland’s Permian Basin. PGNiG gas fields located in the Fences area are “fenced off” or excluded from our exploration acreage. These fields, discovered by PGNiG between 1974 and 1985, produce from structural traps in the Rotliegend sandstone. We hold a 49% interest in approximately 807,000 acres and a 24.5% interest in the remaining 45,000 acres in the Fences area for 406,000 total net acres.
The Rotliegend is the primary target horizon throughout most of the Fences concession area, at depths from approximately 2,500 to 4,000 meters. Both structural traps and stratigraphic (“pinch-out”) traps are known to produce gas from the Rotliegend in the region. In addition, we have identified what appear to be carbonates in the Zechstein formation, a third type of trap that is known to produce both oil and gas in the region.
Fences Area: Structural Traps
Based on our drilling experience since 2000 in the Fences area, we have emphasized the use of seismic acquisition, processing, and interpretation techniques that have been used successfully in the Rotliegend gas fields of the United Kingdom’s offshore Southern Gas Basin. With Rotliegend structures as our target and using improved seismic data processing and acquisition techniques, we have drilled 11 wells targeting Rotliegend structures through the date of this filing. Eight of these wells are commercial, with aggregate remaining proved gas reserves of over 112 Bcf gross (51 Bcf net to our interest) as of December 31, 2010, including proved reserves from the Lisewo-1 well, which was completed subsequent to year-end 2010.
Three of these wells have been in production from 2009 or earlier. A newly constructed production facility has been completed for the Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells. One of the KSK wells began production during late December 2010. We expect production from the other two KSK wells to begin during the second quarter of 2011. By the second half of this year, we expect the KSK wells to collectively produce approximately 14 MMcfd of gas (6.9 MMcfd net to us). Our Winna Gora well is expected to begin producing in the first half of 2012. Our recent Lisewo-1 discovery should begin production in mid-2013. Those wells that are currently in production are producing under the required production licenses obtained by PGNiG in its capacity as operator or under the two-year period of test production that is permitted under the exploration concession.
Finally, in the northernmost part of our Fences concession and lying within the area covered by our recently acquired 3-D seismic data, we have identified a very large upthrown block, or horst, of Rotliegend sandstone that encompasses approximately 50 square kilometers, or 12,000 acres. One well, the 1984 Plawce-1, was drilled by PGNiG on this Rotliegend block within what is now our Fences concession. Six other wells have been drilled by others (four of these more than 20 years ago) in this horst block north of our concession boundary. All six of these wells had substantial gas columns, and all but the most recent two wells were plugged due to relatively tight reservoir rocks. The newest well, the Trzek-2, located about 12 kilometers north of our concession, was drilled by another firm in 2010 and 2011 and reportedly tested gas at a rate 17 MMcfd on a short-term test, after high-pressure, hydraulic fracturing along a 1,350 meter horizontal wellbore. Prior to that, the Trzek-1 well, located about six kilometers north of our concession and drilled by the same firm, reportedly tested gas at rates between 2.5 and 7.5 MMcfd after high-pressure, hydraulic fracturing from a vertical wellbore. We are continuing to evaluate our data and are working with PGNiG on a plan to appraise and explore the gas resource in the Plawce area. We expect to start drilling a well here in the second quarter of 2011.
Block 287 Concession Area
The Block 287 concession area is 13,000 acres (52 sq. km.) located approximately 25 miles south of the Fences concession area. We own 100% of the exploration rights. We retained this small portion of Block 287 when we relinquished larger portions in 2007 and 2008.
Within our retained acreage in Block 287, there are three Rotliegend gas wells known as the Grabowka wells. Originally drilled by PGNiG in 1983-85, these three wells tested gas but never produced commercially. In early 2007, we entered into a joint venture agreement with an unrelated party, PL Energia S.A., headquartered in Krzywoploty, Poland, under which all costs of reentering and completing the three Grabowka wells and building production facilities would be paid by our joint venture partner in exchange for discounted pricing on gas. To date, we have reentered only the Grabowka-12 well, which has been producing since July 2009 at an average daily rate of approximately 0.5 MMcfd.
Warsaw South Concession Area
We hold a 100% interest in a total of 638,000 acres (2,581 sq. km.) in east-central Poland that we acquired in 2007. We also hold an 82% interest in 236,000 acres in the same project area. The Warsaw South concession has several exploration leads, including carboniferous sands and shales with structural or truncation trapping and possibly Zechstein reefs trapped by overlying evaporites and salt. Our technical group has reviewed the geological and geophysical data from the area and identified a dozen carboniferous leads and two possible Zechstein reef targets. We are currently acquiring two-dimensional, or 2-D, seismic data over some of these leads and plan to drill two wells in the Warsaw South concession area in 2011.
In December 2010, we entered into a letter of intent with PGNiG under which it may acquire a 49% interest in the Warsaw South concession area in exchange for paying for some of the early-stage exploration work. We will continue as operator.
Kutno Concession Area
We hold a 100% interest in 706,000 gross acres (2,856 sq. km.) acquired in 2007 and 2008. The area encompasses a Rotliegend mega-structure (“Kutno”) with projected four-way dip closure. Depth of the structure is estimated at approximately 6,500 meters (21,000 feet). In view of the depth and cost, we determined to seek industry participation to bear initial exploration costs. In 2010, we entered into agreements under which two other companies agreed to provide most of the drilling costs of a test well in order for them together to earn a 75% interest in the area. We will retain operations and expect to begin drilling a test well on the Kutno structure in 2011.
Northwest Concession Area
We hold concessions on 828,000 acres in west-central Poland, in Poland’s Permian Basin directly north of PGNiG’s BMB and MLG oil and gas fields. The Northwest concession area has at least two separate possible exploration models: Rotliegend sands trapping gas in structural closures and Zechstein calcium-rich, Ca2 dolomitic sands, reefs, and talus trapping oil and gas.
Based on our review of reprocessed old and newly acquired 2-D seismic data, we drilled the Ostrowiec well in the Northwest concession in 2009 to test a Ca2 target at a depth of 3,800 meters and a Rotliegend target at a depth of 4,100 meters. The well did not encounter commercial hydrocarbons in the Ca2 target and was plugged before reaching target depth for the Rotliegend. The well was operated and owned 51% by us. PGNiG paid 100% of the cost to drill the well. As a result, PGNiG holds a 49% interest in 211,000 acres; we hold a 51% interest in that acreage and a 100% interest in the remaining 617,000 acres.
We may seek industry participation on the remaining blocks, while continuing to carry out preliminary exploration work on our own.
Edge Concession Area
In 2008, we acquired a 100% interest in four concessions in north-central Poland covering approximately 881,000 acres (3,567 sq. km.). Having reprocessed existing 2-D seismic data, we identified a number of leads, including several Permian age Ca2 reefs and a large Devonian structure. We plan to acquire additional 2-D seismic data this year over two of these leads to select possible drilling locations. We may seek industry participation in the drilling of wells in this concession area.
Block 229 Concession Area
In 2008, we acquired a 100% interest in a concession east of our Fences project area covering approximately 233,000 acres (941 sq. km.). We have identified a possible Rotliegend prospect and a number of possible Ca2 reef build-ups on 2-D seismic data in Block 229. We plan to seek industry participation while continuing to carry out early-stage exploration work on our own.
Block 246 Concession Area
In 2008, we acquired a 100% interest in a concession south of our Fences project area covering approximately 241,000 acres (975 sq. km.). We have identified an area with potential for Rotliegend gas and a different area with potential for calcium-rich, Ca1 reef build-ups where the Koscian field trend may extend into Block 246. We plan to seek industry participation while continuing to carry out early-stage exploration work on our own.
Additional Concession Acreage
We may apply for more concession blocks in Poland in 2011. If we acquire more concession blocks, we will allocate modest technical and financial resources to these areas during 2011, primarily in the form of data collection and seismic reprocessing, with a view to ascertaining relative hydrocarbon potential and exploration risk.
Activities and Assets in the United States
We produce oil from approximately 10,732 gross (10,418 net) acres in Montana and 400 gross (128 net) acres in Nevada.
Montana
We did not drill any wells in Montana during 2010. We are evaluating plans for drilling in Montana during 2011. During 2011, we plan to deepen several wells in our 10,000 acre Cut Bank field to take core samples from the Bakken and related formations for laboratory testing. We sell all of our Montana production, which constitutes over 94% of our total oil production, to Cenex, a regional refiner and marketer. We are in discussions with other oil and gas companies with a view to possibly investigating the Bakken potential over a broader area.
Nevada
We did not drill any wells in Nevada during 2010 and have no plans for drilling there during 2011.
Segment Information
Further information concerning our financial and geographic segments can be found in the notes to the consolidated financial statements included in this report.
Available Information
We make available, free of charge, on our website (www.fxenergy.com), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we file such material with, or furnish it to, the Securities and Exchange Commission. We also make these materials available, free of charge, by contacting our main office in Salt Lake City, Utah at (801) 486-5555. Information on our website is not incorporated by reference in this report.
ITEM 1A.
ITEM 1A. RISK FACTORS
Our business is subject to a number of material risks, including the following factors related directly and indirectly to our business activities in the United States and Poland.
Risks Relating to our Business
Our long-term success depends largely on our discovery and production of economic quantities of gas or oil in Poland.
We anticipate that our production will increase in 2011 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 expanded credit facility, additional funds obtained from the sale of equity securities and other external sources, and industry partners to cover these costs. If we are unable to obtain the funds that we seek from these sources for our expanded and accelerated exploration and development plans, we may be required to reduce our capital expenditures.
Fluctuations in global oil and gas prices impact the price we receive for gas in Poland.
The prices at which we sell gas in Poland to PGNiG are determined pursuant to published tariffs for gas sold to wholesale consumers. Such tariffs are determined, in part, by reference to the cost of Russian imported gas, which is priced based, in part, on trailing, historical oil prices. The trailing impact of lower oil prices may have a depressing effect on such tariffs, and so may reduce the price that we receive for our gas from PGNiG. Conversely, because the tariffs are determined, in part, by trailing prices, increases in oil prices may result in higher tariffs for the gas we sell in Poland.
We may incur additional losses due to exchange-rate fluctuations.
Continuing fluctuations in the rates at which U.S. dollars are exchanged into Polish zlotys may result in exchange-rate losses. We are subject to exchange-rate fluctuations as we transfer dollar-denominated funds from the United States to Poland for exploration and development and receive payment for the gas we sell in Poland in zlotys. As the U.S. dollar strengthens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys declines; conversely, when the U.S. dollar weakens relative to the zloty, our U.S. dollar-denominated revenue received in Polish zlotys increases. Should exchange rates in effect during early 2011 continue throughout the year, we expect the exchange rates to have a slightly positive impact on our U.S. dollar-denominated revenues in 2011 compared to 2010, but a corresponding negative impact on the U.S. dollar cost of our capital expenditures in Poland.
We have limited control over our exploration and development activities in Poland.
Our partner, PGNiG, holds the majority interest and is operator of our Fences project area, where our principal production and reserves are located. As a paying partner, we rely to a significant extent on the financial capabilities of PGNiG. If PGNiG were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on our business, financial condition, and results of operations. In particular, we have prepared our exploration budget through 2011 and beyond based on the participation of, and funding to be provided by, PGNiG. Although we have rights to participate in exploration and development activities on some PGNiG-controlled acreage, we have limited rights to initiate such activities, which might slow the pace at which we might like to advance our exploration and development efforts if we had full funding. Similarly, as operator, PGNiG controls the level of production as well as other day-to-day operating details. Further, we have no direct interest in some of the underlying agreements, licenses, and grants from the Polish agencies governing the exploration, exploitation, development, or production of acreage controlled by PGNiG. Thus, our program in Poland involving PGNiG-controlled acreage would be adversely affected if PGNiG should elect not to pursue activities on such acreage, if the relationship between us and PGNiG should deteriorate or terminate, or if PGNiG or the governmental agencies should fail to fulfill the requirements of, or elect to terminate, such agreements, licenses, or grants. In our Kutno, Warsaw South, and Block 287 areas, we are dependent on the financial ability of other industry participants to pay the costs of agreed exploration activities. We may undertake this work at our own cost or seek replacement industry participants if one or more of these third parties fail to pay these costs.
We cannot assure the exploration models we are using in Poland will lead to finding gas or oil in Poland.
We cannot assure the exploration models we and PGNiG develop will provide a useful or effective guide for selecting exploration prospects and drilling targets. We continually review and revise or replace these exploration models as a guide to further exploration based on ongoing drilling results. These exploration models are typically based on incomplete or unconfirmed data and theories that have not been fully tested. The seismic data, other technologies, and the study of producing fields in the area do not enable us to know conclusively prior to drilling that gas or oil will be present in commercial quantities. The fact that some prospects may appear to have similar geological or geophysical subsurface features or may be located near previous wells cannot assure that such prospects are in fact similar or that drilling results will be comparable. Every prospect is unique and must be evaluated individually. We cannot assure that the analogies that we draw from available data from other wells, fully explored prospects, or producing fields will be applicable to our drilling prospects or will enable us to forecast accurately drilling results.
We use various methods to evaluate various categories of potential gas or oil accumulations.
For purposes of management decisions and risk analysis, we use a variety of geological, engineering, and geophysical techniques to estimate probable or possible reserves and gross, unrisked resource potential. These various methods are important in making many kinds of management decisions during the exploration, development, and production process, but the quantities and values estimated through these methods are not comparable and should not be compared. We cannot assure that any gas or oil quantities or values that we estimate through alternative methods will ever be converted through additional exploration and production into reserves.
Our estimates of proved and probable oil and gas reserves are subject to various risks and uncertainties and include voluntarily disclosed information regarding probable reserves.
Our estimates of oil and gas reserves are based on various assumptions and estimates and are very complex and interpretative, as there are numerous uncertainties inherent in estimating quantities and values of proved and probable reserves, projecting future sales of production, and the timing and amount of development expenditures. Many of these factors are beyond our control. Our proved and probable reserve estimates are subject to continuing revisions as additional information becomes available or assumptions change. Although they rely in part on objective information, engineering evaluations of oil and gas reservoirs are essentially subjective processes of estimating the size and recoverability of underground accumulations of oil and gas that cannot be measured in any exact manner. The actual production that we obtain from our oil and gas properties may vary substantially from the factors and assumptions that have been used in completing these estimates, including:
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the geological, geophysical, and engineering characteristics of the underground reservoir;
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known production from other properties that we believe are analogs to our own wells;
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the assumed effects of regulatory requirements and government payments;
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the costs of the construction of production facilities and pipeline connections and the timing of completing those facilities;
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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, and similar items; and
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market prices and demand for the oil and gas we produce.
In accordance with Securities and Exchange Commission’s revisions to the rules for estimating oil and gas reserves that we adopted effective December 31, 2009, our reserve estimates are based on 12-month average prices, rather than year-end prices. The application of these rules resulted in the use of lower prices for estimating reserves as of December 31, 2009 and 2010, than under the previous rules. Furthermore, as permitted by the revised rules, our estimates of probable reserves as of December 31, 2009 and 2010, are calculated using probabilistic, as distinguished from deterministic, methods used in estimating proved reserves. The larger quantity of proved plus probable reserves, as compared to proved reserves only, is attributable largely to using a less certain interpretation of reservoir size and a higher recovery factor in estimating probable reserves that reduces the likelihood of the actual recovery of probable reserves. For example, probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. Such uncertainties preclude the reserves at issue from being classified as proved.
Because of the foregoing, the estimates of the economically recoverable quantities of oil and gas attributable to any particular property, the classifications of those reserves based on risk or probability of recovery, and estimates of the future net cash flows expected from such properties prepared by different engineers or by the same engineers but at different times may vary substantially. Therefore, reserve estimates may be subject to upward or downward adjustments, and actual production, revenue, and related expenditures are likely to vary, in some cases materially, from estimates.
We cannot accurately predict the size of exploration targets or foresee all related risks.
Notwithstanding the accumulation and study of 2-D and 3-D seismic data, drilling logs, production information from established fields, and other engineering, geological, and geophysical data, we cannot predict accurately the gas or oil potential of individual prospects and drilling targets or the related risks. We sometimes estimate the gross potential or possible reserves of gas or oil in a particular area as part of our evaluation of the exploration potential and related risks. Our estimates are only rough, preliminary geological forecasts of the volume and characteristics of possible reservoirs and the calculated potential gas or oil that could be contained if present and are unqualified by any risk evaluation. Such forecasts are not an assurance that our exploration will be successful or that we will be able to establish reserves equal to such forecasts. In some cases, our estimates of possible reserves or oil and gas potential may be based on a review of data from other exploration or producing fields in the area that ultimately may be found not to be analogous to our exploration prospects. We may require several test wells and long-term analysis of test data and history of production to determine the gas or oil potential of individual prospects.
We have had some exploration failures in Poland.
Since 1995 and through early 2011, we have participated in drilling 30 exploratory wells in Poland, including nine commercial discoveries (Wilga 2, Kleka 11, Zaniemysl-3, Sroda-4, Winna Gora-1, Roszkow-1, Kromolice-1, Kromolice-2, and Lisewo-1), and 21 noncommercial wells. Of our nine commercial successes in Poland, we were producing gas at our Roszkow-1, Zaniemysl-3, and Sroda-4 wells as of December 31, 2010. Our Wilga 2 and Kleka 11 wells have been fully exploited and no longer produce. Production from the four other commercial discoveries will not commence until requisite permits are obtained and production facilities are constructed.
We may not achieve the results anticipated in placing our current or future discoveries into production.
We may encounter delays in commencing the production and sale of gas in Poland, including our recent gas discoveries and other possible future discoveries. We may face delays in obtaining rights-of-way to connect to the PGNiG pipeline system, construction permits, and materials and contractors; signing gas or oil purchase/sales contracts; receiving commitments for required capital expenditures by PGNiG; and other factors. Such delays could correspondingly postpone the commencement of cash flow and may require us to obtain additional short-term financing pending commencement of production. Further, we may design and construct surface and pipeline facilities to accommodate anticipated production from additional drilling. We cannot assure that additional drilling will establish additional reserves or production that will provide an economic return for expenditures for facilities. We may have to change our anticipated expenditures if costs of placing a particular discovery into production are higher, if the project is smaller, or if the commencement of production takes longer than expected.
We have a history of operating losses and may require additional capital in the future to fund our operations.
From our inception in January 1989 through December 31, 2010, we have incurred cumulative net losses of approximately $161 million. Our exploration and production activities may continue to result in net losses through 2011 and possibly beyond, depending on whether our activities in Poland and the United States are successful and result in sufficient revenues to cover related operating expenses.
Until sufficient cash flow from operations can be obtained, we expect we will need additional capital to fully fund our ongoing planned exploration, appraisal, development, and property acquisition programs in Poland. We may seek required funds from the issuance of additional debt, equity or hybrid securities, project financing, strategic alliances, or other arrangements. Obtaining additional financing may dilute the interest of our existing stockholders or our interest in the specific project being financed. We cannot assure that additional funds could be obtained or, if obtained, would be on terms favorable to us. In addition to planned activities in Poland, we may require additional funds for general corporate purposes.
We may not fulfill our work commitments on the exploration rights we hold in Poland.
We are subject to certain work commitments respecting various exploration concessions that must be satisfied in order to maintain our interest in those concessions. These work commitments must be satisfied in order to maintain our interest in those concessions. We cannot assure that we will be granted any requested changes to usufruct and concession agreements that either modify the obligations to reduce our commitments or extend the terms of those agreements. Our exploration budget and related activities are not focused specifically or primarily on meeting these work commitments. We may not be able to retain any concession rights on areas for which we do not timely complete required work commitments.
The loss of key personnel could have an adverse impact on our operations.
We rely on our officers, key employees, and consultants and their expertise, particularly David N. Pierce, President and Chief Executive Officer; Thomas B. Lovejoy, Chairman of the Board and Executive Vice President; Andrew W. Pierce, Vice President-Operations; Jerzy B. Maciolek, Vice President-Exploration; Zbigniew Tatys, Poland Country Manager; and Richard Hardman, Director and Chairman of our Technical and Advisory Panel. The loss of the services of any of these individuals may materially and adversely affect us. Although we have entered into employment agreements with our key executives, we may not be able to retain such key executives. We do not maintain key-man insurance on any of our employees.
Substantially all of the oil and gas currently produced in Poland is sold to PGNiG or its affiliates.
We currently sell substantially all of the oil and gas we produce in Poland to PGNiG or one of its affiliates. If PGNiG were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on us. The market for the sale of gas in Poland is open to competition, but there are not yet many market participants. While our contracts provide us with the ability to market gas to other purchasers, including those outside of Poland, we do not expect to have the opportunity to diversify our gas markets in the foreseeable future.
Oil and gas price volatility could adversely affect our operations and our ability to obtain financing.
Oil and gas prices have been and are likely to continue to be volatile and subject to wide fluctuations in response to the following factors:
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the market and price structure in local markets;
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changes in the supply of and demand for oil and gas;
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market uncertainty;
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the impact of potential climate change on oil and gas demand and prices;
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political conditions in international oil and gas producing regions;
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the extent of production and importation of oil and gas into existing or potential markets;
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the level of consumer demand;
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weather conditions affecting production, transportation, and consumption;
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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;
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the refining and processing capacity of prospective gas or oil purchasers;
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the effect of governmental regulation on the production, transportation, and sale of oil and gas; and
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other factors beyond our control.
We have not entered into any agreements to protect us from price fluctuations and may or may not do so in the future.
Our industry is subject to numerous operating risks. Insurance may not be adequate to protect us against all these risks.
Our oil and gas drilling and production operations are subject to hazards incidental to the industry. These hazards include blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas, and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. To lessen the effects of these hazards, we maintain insurance of various types to cover our domestic and international operations. We cannot assure that the insurance policies carried by us or by PGNiG, as operator of the Fences area, can continue to be obtained on reasonable terms. While we do carry limited third-party liability and all-risk insurance in Poland, we do not plan to purchase well control insurance on wells we drill in the Fences project area and may elect not to purchase such insurance on wells drilled in other areas in Poland as well. The current level of insurance does not cover all of the risks involved in oil and gas exploration, drilling, and production. Where additional insurance coverage does exist, the amount of coverage may not be sufficient to pay the full amount of such liabilities. We may not be insured against all losses or liabilities that may arise from all hazards because such insurance is unavailable at economic rates, because of limitations on existing insurance coverage, or other factors. For example, we do not maintain insurance against risks related to violations of environmental laws. We would be adversely affected by a significant adverse event that is not fully covered by insurance. Further, we cannot assure that we will be able to maintain adequate insurance in the future at rates we consider reasonable.
Our operations are subject to various litigation that could have an adverse effect on our business.
From time to time we are a defendant in various litigation matters. The nature of our operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be adversely decided against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition and results of operations. Litigation is highly costly and the costs associated with defending litigation could also have a material adverse effect on our financial condition.
We face competition from larger oil and gas companies, which could result in adverse effects on our business.
The exploration and production business is highly competitive. Many of our competitors have substantially larger financial resources, staffs, and facilities. Our competitors in Poland and the United States include numerous major oil and gas exploration and production companies.
The effects of global climate change could adversely impact the market demand for oil and gas products and negatively impact our business.
The value of our oil and gas exploration, development, and production activities is and will continue to be a function of the market demand for oil and gas products. If global climate change results in rising average global temperatures, the market demand for oil and gas products used in residential and commercial heating fuels may decrease. This could result in a decrease in demand for oil and gas products and negatively impact our business.
Concerns regarding global climate change could spur legislation or regulation, globalized through treaties or otherwise, that could diminish global demand for oil and gas products and negatively impact our business.
Our oil and gas exploration, development, and production activities in Poland are subject to Poland’s laws and regulations, some of which are designed to meet the requirements of the European Union. Future legislation and regulation could be a part of globalized efforts similar to the Kyoto Protocol, regional systems such as the European Union Emissions Trading Scheme, or other campaigns in response to concerns regarding global climate change. Such laws or regulations could result in taxes or direct limitations on the production of fossil fuels that could diminish global market demand for oil and gas products or curtail or limit our activities in Poland and correspondingly have a negative impact on our business.
We may incur significant costs related to environmental matters.
As an owner or lessee and operator of oil and gas properties in the United States, 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 clean-up resulting from operations, subject the lessee to liability for pollution damages, and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in a significant adverse effect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.
Our United States operations are subject to governmental risks that may impact our operations.
Our United States operations have been, and at times in the future may be, affected by political developments and by federal, state, tribal, and local laws and regulations such as restrictions on production, changes in taxes, royalties, and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations. New political developments, laws, and regulations may adversely impact our results on operations.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to explore and produce from the Bakken shale in our Montana properties.
We may test the oil potential of the Bakken, Three Forks, and related shale formations underlying our Cut Bank field in Montana with multistage hydraulic fracturing of horizontal wells. Hydraulic fracturing is a practice used to enhance oil and natural gas production. The process involves the injection of fluids, typically water, sand, and chemical additives, under pressure into a well in order to create fractures in the surrounding rock and stimulate production from the reservoir to the wellbore. Hydraulic fracturing may prove to be the primary production method used to economically produce natural gas and oil from the Bakken/Three Forks formations. The process of hydraulic fracturing has typically been regulated by state oil and natural gas regulators but has not been subject to federal oversight or regulation. However, the United States Congress is currently considering bills that would eliminate an existing exemption under the Safe Drinking Water Act and subject hydraulic fracturing to federal regulation. Moreover, the U.S. Environmental Protection Agency has begun a study of the potential environmental impacts of hydraulic fracturing, and a committee of the U.S. House of Representatives is also conducting a study of the chemicals used in the fracturing process. Additionally, some states have adopted, and Montana might consider adopting, conditions, restrictions, and regulations that could prohibit hydraulic fracturing under certain circumstances.
If new federal or Montana state laws or regulations are adopted that significantly restrict hydraulic fracturing, such restrictions could make it more difficult or costly for us to perform hydraulic fracturing. In addition, if federal or Montana state authorities regulate hydraulic fracturing, exploration and production activities that involve hydraulic fracturing could be subject to new regulatory regimes and additional permitting requirements that involve permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. Such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and natural gas resources from shale formations that are not commercial without the use of hydraulic fracturing. This could limit the potential upside of any activities we undertake with respect to shale plays in Montana.
Risks Relating to Conducting Business in Poland
A substantial amount of our revenues are 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:
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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;
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possible changes to the laws, regulations, and policies applicable to our partners and us or the oil and gas industry in Poland in general;
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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;
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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;
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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;
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political instability and possible changes in government;
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export and transportation tariffs;
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local and national tax requirements;
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expropriation or nationalization of private enterprises and other risks arising out of foreign government sovereignty over our acreage in Poland; and
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possible significant delays in obtaining opinions of local authorities or satisfying other governmental requirements in connection with a grant of permits to conduct exploration and production activities.
Our operations are concentrated in Poland such that any impediment to these operations would have a material adverse effect on our business, financial condition, and results of operations.
Poland has a developing regulatory regime, regulatory policies, and interpretations.
Poland has a regulatory regime governing exploration and development, production, marketing, transportation, and storage of oil and gas. These provisions were promulgated during the past two decades and are relatively untested. Therefore, there is little or no administrative or enforcement history or established practice that can aid us in evaluating how the regulatory regime will affect our operations. It is possible those governmental policies will change or that new laws and regulations, administrative practices or policies, or interpretations of existing laws and regulations will materially and adversely affect our activities in Poland. For example, many of Poland’s laws, policies, and procedures were changed to conform to the requirements that had to be met before Poland was admitted as a full member of the European Union.
Our oil and gas operations are subject to changing environmental laws and regulations that could have a negative impact on our operations.
Operations on our project areas are subject to environmental laws and regulations in Poland that provide for restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with oil and gas exploration and development. Additionally, if significant quantities of gas are produced with oil, regulations prohibiting the flaring of gas may inhibit oil production. In such circumstances, the absence of a gas-gathering and delivering system may restrict production or may require significant expenditures to develop such a system prior to producing oil and gas. We are required to prepare and obtain approval of environmental impact assessments by governmental authorities in Poland prior to commencing gas or oil production, transportation, and processing functions. We are also subject to the requirements of Natura 2000, which is an ecological network in the territory of the European Union. In May 1992, governments of the European Union adopted legislation designed to protect the most seriously threatened habitats and species across Europe.
Neither our partners nor we can assure that we have complied with all applicable laws and regulations in drilling wells, acquiring seismic data, or completing other activities in Poland to date. The Polish government may adopt more restrictive regulations or administrative policies or practices. The cost of compliance with current regulations or any changes in environmental regulations could require significant expenditures. Further, breaches of such regulations may result in the imposition of fines and penalties, any of which may be material. These environmental costs could have an adverse effect on our financial condition, results of operations, or cash flows in the future.
Privatization/Nationalization of PGNiG could affect our relationship and future opportunities in Poland.
Our activities in Poland have benefited from our relationship with PGNiG, which has provided us with exploration acreage, seismic data, and production data under our agreements. The Polish government commenced the privatization of PGNiG by selling PGNiG’s refining assets in the mid-90s and by successfully completing an initial public offering of approximately 15% of its stock. Complete privatization or a re-nationalization of PGNiG may result in new policies, strategies, or ownership that could adversely affect our existing relationship and agreements, as well as the availability of opportunities with PGNiG in the future.
Certain risks of loss arise from our need to conduct transactions in foreign currency.
The amounts in our agreements relating to our activities in Poland are sometimes expressed and payable in U.S. dollars and sometimes in Polish zlotys. In the future, our financial results and cash flows in Poland may be affected by fluctuations in exchange rates between the Polish zloty and the U.S. dollar. Currencies used by us may not be convertible at satisfactory rates. In addition, the official conversion rates between United States and Polish currencies may not accurately reflect the relative value of goods and services available or required in Poland. Further, inflation may lead to the devaluation of the Polish zloty.
The interests that we hold in concessions and usufructs owned in the name of PGNiG may be jeopardized or lost, and we may not be able to obtain new concessions, without compensation to us, in the event of PGNiG’s bankruptcy, persistent breaches of laws such as environmental requirements, winding up, or other circumstances.
The Poland Ministry of the Environment, which administers the Geologic and Mining Law, has the authority to terminate concessions and usufructs in the name of PGNiG and in which we have a fractional undivided interest if PGNiG is declared bankrupt, persistently violates environmental regulations or other laws, is wound up, rescinds the concession, or otherwise breaches material usufruct or concession terms. There can be no assurance that PGNiG’s current 72.5% government ownership will continue or that the Poland government will in any circumstance intervene to prevent PGNiG’s insolvency or bankruptcy. We may not be able to implement effective measures to preserve and protect our property interests by curing any concession or usufruct default by PGNiG, assuring fair compensation in the event of any such loss, or implementing new legal strategies that would insulate our interests from loss due to PGNiG’s actions or condition.
The Polish Ministry of the Environment has the authority to terminate the mining usufruct agreements with immediate effect and may impose a contractual penalty in the amount of 25% of the fee due under the mining agreement if we do not comply with the terms and obligations indicated in such agreements.
Pursuant to the Polish Geological and Mining Law, a mining usufruct is the right to carry out work connected with the prospecting and exploration for or the extraction of gas. A mining usufruct is established based on an agreement concluded with the Polish State Treasury, in that case represented by the Polish Ministry of the Environment. The Polish Ministry of the Environment has the authority to terminate a mining usufruct agreement with immediate effect and may impose on us a contractual penalty in the amount of 25% of the fee due under the mining usufruct agreement if we fail to comply with the terms and obligations indicated in such agreement, in particular with the obligation to pay the fee due under the agreement. We cannot ensure that we have complied and will comply in the future with all the terms and obligations imposed on us under the mining usufruct agreements. The loss of the usufruct rights under the mining usufruct agreements would have a material adverse effect on our business, financial condition, and results of operations.
Our operations in Poland require our compliance with the Foreign Corrupt Practices Act.
We must conduct our activities in or related to Poland in compliance with the United States Foreign Corrupt Practices Act, or FCPA, and similar anti-bribery laws that generally prohibit companies and their intermediaries from making improper payments to foreign government officials for the purpose of obtaining or retaining business. Enforcement officials interpret the FCPA’s prohibition on improper payments to government officials to apply to officials of state-owned enterprises such as PGNiG, our principal partner in Poland. While our employees and agents are required to acknowledge and comply with these laws, we cannot be sure that our internal policies and procedures will always protect us from violations of these laws, despite our commitment to legal compliance and corporate ethics. The occurrence or allegation of these types of risks may adversely affect our business, performance, prospects, value, financial condition, reputation, and results of operations.
Risks Related to our Common Stock
Our stockholder rights plan and bylaws discourage unsolicited takeover proposals and could prevent our stockholders from realizing a premium on our common stock.
We have a stockholder rights plan that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the stockholder rights plan would cause substantial dilution to a person or group that attempts to acquire us on terms not approved in advance by our board of directors. In addition, our articles of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that our stockholders may consider to be in their best interests that include:
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members of the board of directors are elected and retire in rotation; and
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the ability of the board of directors to designate the terms of, and to issue new series of, preferred shares.
Together, these provisions and our stockholder rights plan may discourage transactions that otherwise could involve payment to our stockholders of a premium over prevailing market prices for our common shares.
Our common stock price has been and may continue to be extremely volatile.
Our common stock has traded as low as $2.85 and as high as $12.20 during intraday trading between January 1, 2010, and the date of this report. Some of the factors leading to this volatility include:
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the outcome of individual wells or the timing of exploration efforts in Poland;
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the potential sale by us of newly issued common stock to raise capital;
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price and volume fluctuations in the general securities markets that are unrelated to our results of operations;
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the investment community’s view of companies with assets and operations outside the United States in general and in Poland in particular;
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actions or announcements by PGNiG that may affect us;
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announced drilling or other exploration results by others in or near the areas of our activities;
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turmoil in the financial sector that may impact our revolving credit facility;
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prevailing world prices for oil and gas;
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the potential of our current and planned activities in Poland; and
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changes in stock market analysts’ recommendations regarding us, other oil and gas companies, or the oil and gas industry in general.
Exploration failures or changes in the regulatory environment in Poland may adversely affect the trading prices for our common stock.
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 stock of record in their name 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. As a result, brokerage firms and other institutions may not return sufficient proxies to constitute a quorum if the beneficial owners of such shares do not provide instructions. Even if a quorum is obtained, these recently adopted provisions may reduce substantially the number of votes cast for the election of directors, which may result in the failure to elect one or more directors. Notwithstanding the failure to elect directors at the annual meeting, such directors may hold-over and continue to serve until their successors are elected at a subsequent meeting. If this were to occur, the board would include directors not recently elected by the stockholders.
Our current rating by third-party corporate governance consultants advising institutional stockholders may result in recommendations that incumbent directors not be reelected.
Various corporate governance consultants advising institutional investors and others provide scores or ratings of our governance measures, nominees for election as directors, and other matters that may be submitted to the stockholders for consideration. Although the full details of such scores or ratings by consultants are not available to us, we expect that certain nominees or matters that we propose for approval from time to time may not merit a favorable score or rating or may result in a negative score or rating or recommendation that the nominee or matter be rejected. We believe that approximately 25% of our stock may be held by institutions that may be advised by such consultants. Accordingly, unfavorable scores or ratings by such consultants could adversely affect our ability to obtain reelection of incumbent directors or the approval of other matters in accordance with management’s recommendations. We have reviewed certain governance measures, such as our classified board and stockholder rights plan, that we believe contribute to our low scores and ratings and have determined that such governance provisions are in the best interests of our stockholders notwithstanding the adverse effect of such provisions on such scores or ratings.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Proved Reserves Disclosures
Securities and Exchange Commission Modernization of Oil and Gas Reserves Reporting
On December 31, 2009, we adopted the Securities and Exchange Commission’s rule revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
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Commodity Prices - Economic producibility of reserves and discounted cash flows are now based on the use of unweighted, 12-month first day of the month historical average prices adjusted for basis and quality differentials, rather than year-end prices.
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Disclosure of Unproved Reserves - Probable and possible reserves may be disclosed separately on a voluntary basis.
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Proved Undeveloped Reserves Guidelines - Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
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Third-Party Reserves Preparation - If a company represents that its estimates of reserves are prepared or audited by a third party, the company must file a report of the third party as an exhibit to the relevant registration statement or report.
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Use of Probabilistic Methods - Reserves may be estimated using probabilistic methods in which there is at least a 90% probability of recovery of “proved” reserves, at least a 50% probability of recovery of “probable” reserves, and at least a 10% probability of recovery of “possible” reserves.
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Disclosure by Geographic Area - Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total oil and gas proved reserves.
Additional disclosure as provided below was also required by the Securities and Exchange Commission revisions.
Effect of Adoption
Application of the current rules resulted in the use of lower prices at December 31, 2009 and 2010, for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009, as required by the current rules, resulted in a decrease in proved developed oil reserves of approximately 1.0 MMcfe in 2009. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.
Internal Controls over Reserves Estimates
Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the Securities and Exchange Commission’s definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Responsibility for compliance in reserves bookings is delegated to our operations and finance staff, who submit technical and financial data to third-party engineering firms.
Estimates of our proved and probable Polish reserves were calculated by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved domestic reserves were calculated by Hohn Engineering, an independent engineering firm in Billings, Montana. The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both RPS Energy and Hohn Engineering are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Proved and Probable Reserves
Proved reserves are estimated quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward and recoverable in future years from known reservoirs, and under existing economic conditions, operating methods, and governmental regulations, prior to the expiration of the contracts providing the right to operate, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited: (i) to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances; and (ii) to other undrilled locations if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
We emphasize that the volume of reserves are estimates that by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. These reserve revisions result primarily from improved or a decline in performance from a variety of sources such as an addition to or a reduction in recoveries below or above previously established lowest known hydrocarbon levels, improved or a decline in drainage from natural drive mechanisms, and the realization of improved or declined 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, 2010, our proved undeveloped reserves totaled 8.3 Bcf of natural gas. All of our proved undeveloped reserves are located in Poland, and all are associated with wells that have been drilled, tested, and completed for production. We do not have any proved undeveloped reserves attributable to undrilled locations. These reserves are classified as proved undeveloped because relatively major expenditures are required for the completion of production facilities, which includes the construction of pipelines to connect the wells to the existing pipeline in order to fully develop the reserves and commence production. The development of such undeveloped reserves is not dependent on additional drilling on undrilled acreage. All development activities will be completed within five years of reserve bookings.
Changes in Proved Undeveloped Reserves
Reserves of 19.2 Bcf associated with our KSK wells were converted from undeveloped reserves at December 31, 2009, to developed reserves at December 31, 2010, as a result of the completion of production facilities for those wells during the year.
Development Costs
Costs incurred relating to the development of proved undeveloped reserves were approximately $4.7 million in 2010, all of which were attributable to the construction of production facilities at our KSK wells.
Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $6.9 million in 2011. The estimated development costs are for the cost of facilities construction at our KSK wells that carried over year-end and our Winna Gora production facilities and not for the drilling of development wells.
For more information see the following:
·
Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Proved Reserves, for a discussion of changes in proved reserves;
·
Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies - Oil and Gas Reserves, for further discussion of our reserves estimation process; and
·
Item 8, Financial Statements and Supplementary Data - Supplementary Oil and Gas Information (Unaudited), for additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.
Other Reserves Information
Since January 1, 2010, no crude oil or natural gas reserves information has been filed with, or included in any report to, any other federal authority or agency.
Reserve Volumes and Values
The following table sets forth our estimated proved developed, proved undeveloped, and probable reserves volumes as of December 31, 2010:
The following table sets forth the estimated PV-10 Value of our proved plus probable reserves as of December 31, 2010:
The following tables illustrate the effect of combining our reserves and the estimated PV-10 Value of our reserves as of December 31, 2010, with the reserves and PV-10 Value from our early 2011 Lisewo-1 discovery:
_______________
(1)
Lisewo-1 reserves were calculated by RPS Energy, a United Kingdom-based reservoir engineering firm that calculates reserves for all of our Polish properties. The date of its report is February 28, 2011. In calculating Lisewo-1 PV-10 values, RPS used the same average prices that were used to calculate PV-10 values for our KSK wells at year-end 2010.
Our proved reserves were calculated using deterministic methods. Our probable reserves were calculated using probabilistic methods and represent the 50% probability that the actual quantities recovered will be equal to or greater than the proved plus probable estimate. No additional drilling is required at any of our Polish wells to achieve the recovery of the probable reserves. The larger quantity of proved reserves plus probable reserves, as compared to proved reserves only, is attributable largely to using a less certain interpretation of reservoir size and a higher recovery factor in estimating probable reserves.
Drilling Activities
The following table sets forth the exploratory wells that we drilled during the years ended December 31, 2010, 2009, and 2008:
The foregoing does not include the Lisewo-1 well being drilled at 2010 year end, which was determined to be a commercial success in January 2011. We did not drill any development wells in 2008, 2009, or 2010.
Wells and Acreage
As of December 31, 2010, our gross and net producing wells consisted of the following:
_______________
(1)
One well commenced production in late December 2010. As of December 31, 2010, we had three wells in Poland awaiting the construction of production facilities.
(2)
All of our producing United States wells are oil wells. We have no gas production in the United States.
The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2010. All of our gas production is in Poland and all of our oil production is in the United States:
_______________
(1)
All gross and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.
Polish Properties
Producing Properties
A summary of our average daily production, average interest, and net revenue interest for our Poland producing properties during 2010 follows:
_______________
(1)
Average daily net production amounts shown are calculated based on days of actual production.
Production, Transportation and Marketing
We began producing and selling gas from our Roszkow well in late 2009. Production from our Wilga well ceased during 2009. We expect production will increase from one well we placed into production in late December 2010 and from three other, previous discoveries that we plan to place into production in 2011 and 2012.
The following table sets forth our net daily oil and gas production, average sales price, and average production costs associated with our Polish production during 2010, 2009, and 2008:
_______________
(1)
Production costs include lifting costs (electricity, fuel, water, disposal, repairs, maintenance, transportation, and similar items) and contract operator fees. Production costs do not include such items as general and administrative costs; depreciation, depletion and amortization; or Polish income taxes.
Poland has a network of gas pipelines and crude oil pipelines traversing the country serving major metropolitan, commercial, industrial, and gas production areas, including significant portions of our acreage. Poland has a well-developed infrastructure of hard-surfaced roads and railways over which oil produced can be transported for sale. There are refineries in Gdansk and Plock in Poland and one in Germany near the western Polish border that we believe could process crude oil produced in Poland. Should we choose to export any gas or oil we produce, we will be required to obtain prior governmental approval.
We are currently selling substantially all of our oil and gas production in Poland to PGNiG or one of its affiliates. We are dependent on PGNiG for the sale of gas in Poland, since there are few other competitive purchasers. Gas is sold pursuant to long-term sales contracts, typically for the life of each well, which obligate PGNiG to purchase all gas produced.
United States Properties
Producing Properties
In the United States, we currently produce oil in Montana and Nevada. All of our producing properties, except for the Rattlers Butte field (an exploratory discovery during 1997), were purchased during 1994. A summary of our average daily production, average interest, and net revenue interest for our United States producing properties during 2010 follows:
In Montana, we operate the Cut Bank and Bears Den fields and have an interest in the Rattlers Butte field, which is operated by an industry partner. Production in the Cut Bank field, producing since the 1940s from an average depth of approximately 2,900 feet, is from a waterflood program with 124 producing oil wells, 26 active injection wells, and one active water supply well. The Bears Den field, under waterflood since 1990, is producing oil from five wells at a depth of approximately 2,430 feet, with one active water injection well. In the Rattlers Butte field, we own a 0.683% interest in two oil wells producing at a depth of approximately 5,800 feet and one active water injection well.
In Nevada, we operate the Trap Springs and Munson Ranch fields and have an interest in the Bacon Flat field, which is operated by an industry partner. In the Trap Springs field, discovered in 1976, we produce oil from a depth of approximately 3,700 feet from one well. In the Munson Ranch field, discovered in 1988, we produce oil at an average depth of 3,800 feet from five wells. In the Bacon Flat field, discovered in 1981, we produce oil from one well at a depth of approximately 5,000 feet.
Production, Transportation and Marketing
The following table sets forth our average net daily oil production, average sales price, and average production costs associated with our United States oil production during 2010, 2009, and 2008:
_______________
(1)
Production costs include lifting costs (electricity, fuel, water, disposal, repairs, maintenance, pumper, transportation, and similar items) and production taxes. Production costs do not include such items as general and administrative costs; depreciation, depletion and amortization; state income taxes, or federal income taxes.
We sell oil at posted field prices to one of several purchasers in each of our production areas. We sell all of our Montana production, which represents over 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 central Europe, has a population of approximately 39 million people, and covers an area comparable to New Mexico. During 1989, Poland peacefully asserted its independence and became a parliamentary democracy. Since 1989, Poland has enacted comprehensive economic reform programs and stabilization measures that have enabled it to form a free-market economy and turn its economic ties from the east to the west, with most of its current international trade with the countries of the European Union and the United States. The economy has undergone extensive restructuring in the post-communist era. The Polish government credits foreign investment as a forceful growth factor in successfully creating a stable, free-market economy.
Since its transition to a free-market economy and a parliamentary democracy, Poland has experienced significant economic growth and political change. Poland has developed and is refining legal, tax, and regulatory systems characteristic of parliamentary democracies with interpretation and procedural safeguards. The Polish government has taken steps to harmonize Polish legislation with that of the European Union, which it joined in May of 2004.
Poland has created an attractive legal framework and fiscal regime for oil and gas exploration by actively encouraging investment by foreign companies. In July 1995, Poland’s Council of Ministers approved a program to restructure and privatize the Polish petroleum sector. So far under this plan, a refinery located in Plock has been privatized as a publicly held company with its stock trading on the London and Warsaw stock exchanges. In September of 2005, 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.
During 2009 and 2010, Poland was one of only a few countries in Europe to record positive gross domestic product, or GDP, growth. Current forecasts project that Poland will again lead all European countries in economic performance in 2011.
Legal Framework
General Usufruct and Concession Terms
All of our rights in Poland have been awarded to us or to PGNiG pursuant to the Geological and Mining Law, which specifies the process for obtaining domestic exploration and exploitation rights. Under the Geological and Mining Law, the concession authority enters into mining usufruct (lease) agreements that grant the holder the exclusive right to explore for oil and gas in a designated area or to exploit the designated oil and/or gas field for a specified period under prescribed terms and conditions. The holder of the mining usufruct covering exploration must also acquire an exploration concession by applying to the concession authority and providing the opportunity for comment by local governmental authorities. The usufruct agreements include provisions that give the usufruct holder a claim for an extension of the usufruct (and the underlying concession), subject to having fulfilled all obligations under the usufruct and/or concession agreements. We can request changes to usufruct and concession agreements that either modify the obligations or extend the terms of those agreements. During our time in Poland, we have been granted either modifications or extensions each time we have requested them.
Under current law, the concession authority requires that concessions be owned by a single entity, without recognizing any minority record ownership such as would reflect our interest in those areas in which we previously have been granted a minority ownership. As such, our ownership is subject to continued compliance with applicable law, the usufruct and concession terms, and respecting the Fences area, the continuity of PGNiG as the record owner.
The concession authority has granted PGNiG oil and gas exploration rights on the Fences project area and has granted us oil and gas exploration rights on all other project areas in which we have an interest. The agreements divide these areas into blocks, each containing up to 300,000 acres.
If commercially viable gas or oil is discovered, the concession owner may be able to produce such gas or oil for test purposes for a period of two years based on the exploration concession. After the lapse of such two-year period, the concession owner must then apply for an exploitation concession, which generally will have a term of 25 to 30 years or as long as commercial production continues. Upon the grant of the exploitation concession, the concession owner may become obligated to pay a fee, to be negotiated, but expected to be less than 1% of the market value of the estimated recoverable reserves in place. The concession owner would also be required to pay a royalty on any production, the amount of which will be set by the Council of Ministers, within a range established by legislation for the mineral being extracted. The royalty rate for low-methane gas such as we produce is currently set for 2011 at approximately $0.04 per Mcf. Local governments will receive 60% of any royalties paid on production. The holder of the exploitation concession must also acquire rights to use the land from the surface owner and could be subject to significant delays in obtaining the consents of local authorities or satisfying other governmental requirements prior to obtaining an exploitation concession.
We believe all material concession terms have been satisfied to date.
Existing Project Areas
Fences Project Area
The Fences project area consists of four oil and gas exploration concessions controlled by PGNiG. Three producing fields (Radlin, Kleka, and Kaleje) lie within the concession boundaries, but are excluded from the Fences area in which we participate. The Fences concessions have expiration dates ranging from August 2012 to July 2015. The total joint remaining work commitment, which must be satisfied by us and PGNiG according to our respective interests, includes: acquiring 50 kilometers of 2-D seismic data, acquiring 250 square kilometers of 3-D seismic data, and drilling four wells.
Wilga/Block 255 Project Area
The Wilga project area consists of a single oil and gas exploration concession held by us that expires in August 2012. The remaining period carries a work commitment of 80 kilometers of 2-D seismic data and optional drilling of up to three wells.
Warsaw South Project Area
This project area is adjacent to Block 255 and consists of four exploration concessions with expiration dates ranging from September 2012 to July 2013. The total work commitment for the four concessions is outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 450 kilometers of new 2-D seismic data, 275 kilometers of which have already been completed; Phase III - three years: drilling four wells.
Block 287 Project Area
The Block 287 project area consists of a single oil and gas exploration concession held by us. The concession expires in December 2012. Work commitment includes reentering and producing the Grabowka gas field; reconstruction of one out of three wells was completed and production began in 2009.
Northwest Project Area
The Northwest project area consists of four oil and gas exploration concessions granted at various times in 2006, 2007, and 2008, with expiration dates ranging from October 2012 through September 2014. The total work commitment for the four concessions is outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - three years: acquiring 620 kilometers of new 2-D seismic data; Phase III - two years: drilling four wells. Presently, 240 kilometers of new 2-D seismic have been completed and part of the drilling commitment was satisfied during 2009 by drilling the Ostrowiec well.
Kutno Project Area
The Kutno project area consists of three oil and gas exploration concessions. The first concession was granted in 2007 for a period of six years, and two new concessions were added in 2008 for a period of three years. The total work commitment for the initial concession is outlined in three phases: Phase I - one and one half years: reprocessing and reinterpretation of existing data; Phase II - two years: drilling one well or acquiring 100 kilometers of 2-D seismic data; Phase III - two and a half years: drilling one well. The work commitments for the 2008 concessions are outlined in two phases: Phase 1 - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 200 kilometers of 2-D seismic data.
Edge Project Area
The Edge project area consists of four oil and gas exploration concessions granted for the period of five years. The total work commitment is outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 350 kilometers of 2-D seismic data; Phase III - two years: drilling four wells. The concession expires in September 2013.
Block 246 Project Area
The Block 246 project area is adjacent to the Fences project area in the southwest and consists of a single concession granted for six years. The work commitment is outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 120 kilometers of 2-D seismic data; Phase III - three years: drilling one well. The concession expires in December 2014.
Block 229 Project Area
The Block 229 project area is adjacent to the Fences project area in the east and consists of two explorations concessions granted for the period of six years. The total work commitment is outlined in three phases: Phase I - one year: reprocessing and reinterpretation of existing data; Phase II - two years: acquiring 300 kilometers of 2-D seismic data; Phase III - three years: drilling two wells. The concession expires in August 2014.
As of December 31, 2010, all required usufruct/concession payments had been made for each of the above project areas.
Government Regulation
Poland
Our activities in Poland are subject to political, economic, and other uncertainties, including the adoption of new laws, regulations, or administrative policies that may adversely affect us or the terms of our exploration or production rights; political instability and changes in government or public or administrative policies; export and transportation tariffs and local and national taxes; foreign exchange and currency restrictions and fluctuations; repatriation limitations; inflation; environmental regulations; and other matters. These operations in Poland are subject to the Geological and Mining Law dated as of February 4, 1994 (as amended), and the Environment Protection Law dated as of April 27, 2001 (as amended), which are the current primary statutes governing environmental protection. Agreements with the government of Poland respecting our exploration and production areas create certain standards to be met regarding environmental protection. Participants in oil and gas exploration, development, and production activities generally are required to: (1) adhere to good international petroleum industry practices, including practices relating to the protection of the environment; and (2) prepare and submit geological work plans, with specific attention to environmental matters, to the appropriate agency of state geological administration for its approval prior to engaging in field operations such as seismic data acquisition, exploratory drilling, and field-wide development. Poland’s regulatory framework respecting environmental protection is not as fully developed and detailed as that which exists in the United States. We intend to conduct our operations in Poland in accordance with good international petroleum industry practices and, as they continue to develop, Polish requirements.
United States
State and Local Regulation of Drilling and Production
Our exploration and production operations are subject to various types of regulation at the federal, state, and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and impose certain requirements regarding the ratability of production.
Our oil production is affected to some degree by state regulations. States in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes and related regulations are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.
Environmental Regulations
The federal government and various state and local governments have adopted laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and impose substantial liabilities for pollution resulting from our operations. These laws and regulations may also increase the costs of drilling and operating wells. We may also be held liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990, or OPA ‘90. In addition, we may be subject to other civil claims arising out of any such incident. As with any owner of property, we are also subject to clean-up costs and liability for hazardous materials, asbestos, or any other toxic or hazardous substance that may exist on or under any of our properties. We believe that we are in compliance in all material respects with such laws, rules, and regulations and that continued compliance will not have a material adverse effect on our operations or financial condition. Furthermore, we do not believe that we are affected in a significantly different manner by these laws and regulations than our competitors in the oil and gas industry.
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Furthermore, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
The Resource Conservation and Recovery Act, or RCRA, and regulations promulgated thereunder govern the generation, storage, transfer, and disposal of hazardous wastes. RCRA, however, excludes from the definition of hazardous wastes “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, gas, or geothermal energy.” Because of this exclusion, many of our operations are exempt from RCRA regulation. Nevertheless, we must comply with RCRA regulations for any of our operations that do not fall within the RCRA exclusion.
The OPA ‘90 and related regulations impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 establishes strict liability for owners of facilities that are the site of a release of oil into “waters of the United States.” While OPA ‘90 liability more typically applies to facilities near substantial bodies of water, at least one district court has held that OPA ‘90 liability can attach if the contamination could enter waters that may flow into navigable waters.
Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future, such as proposals made in Congress and at the state level from time to time, that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes” and make the reclassified wastes subject to more stringent and costly handling, disposal, and clean-up requirements. The impact of any such changes, however, would not likely be any more burdensome to us than to any other similarly situated company involved in oil and gas exploration and production.
Federal and Indian Leases
A substantial part of our producing properties in Montana consists of oil and gas leases issued by the Bureau of Land Management or by the Blackfeet Tribe under the supervision of the Bureau of Indian Affairs. Our activities on these properties must comply with rules and orders that regulate aspects of the oil and gas industry, including drilling and operating on leased land and the calculation and payment of royalties to the federal government or the governing Indian nation. Our operations on Indian lands must also comply with applicable requirements of the governing body of the tribe involved including, in some instances, the employment of tribal members. We believe we are currently in full compliance with all material provisions of such regulations.
Safety and Health Regulations
We must also conduct our operations in accordance with various laws and regulations concerning occupational safety and health. Currently, we do not foresee expending material amounts to comply with these occupational safety and health laws and regulations. However, since such laws and regulations are frequently changed, we are unable to predict the future effect of these laws and regulations.
Title to Properties
We rely on sovereign ownership of exploration rights and mineral interests by the Polish government in connection with our activities in Poland and have not conducted and do not plan to conduct any independent title examination. We regularly consult with our Polish legal counsel when doing business in Poland.
Nearly all of our United States 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.
Employees and Consultants
As of December 31, 2010, we had 49 employees, consisting of nine in Salt Lake City, Utah; 23 in Oilmont, Montana; one in Greenwich, Connecticut; two in Houston, Texas; and 14 in Poland. Our employees are not represented by a collective bargaining organization. We consider our relationship with our employees to be satisfactory. We also regularly engage technical consultants to provide specific geological, geophysical, and other professional services. Our executive officers and other management employees regularly travel to Poland to supervise activities conducted by our staff and others under contract on our behalf.
Offices and Facilities
Our corporate offices, located at 3006 Highland Drive, Salt Lake City, Utah, contain approximately 3,500 square feet and are rented at $3,400 per month under a month-to-month agreement. In Montana, we own a 16,160 square-foot building located at the corner of Central and Main in Oilmont. We also have an office in Warsaw, Poland, located at ul. Chalubinskiego 8, where we rent 404 square meters for approximately $7,700 per month and in Krakow, Poland, located in the Nafta Building, ul. Lubicz 25, where we rent approximately 20 square meters for approximately $300 per month.
Oil and Gas Terms
The following terms have the indicated meaning when used in this report:
“Bbl” means oilfield barrel.
“Bcf” means billion cubic feet of natural gas.
“Bcfe” means billion cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.
“BTU” means British thermal unit.
“Ca1” and “Ca2” refers to specific calcium-rich geological formations, typically a dolomitic reef.
“Deterministic” means a method of estimating reserves in which a simple value for each parameter of geoscience, engineering, or economic data in the reserves calculation is used in the reserves estimation.
“Development well” means a well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
“Exploratory well” means a well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil in another reservoir, or to extend a known reservoir.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic conditions.
“Gross” acres and “gross” wells mean the total number of acres or wells, as the case may be, in which an interest is owned, either directly or through a subsidiary or other Polish enterprise in which we have an interest.
“Horizon” means an underground geological formation that is the portion of the larger formation that has sufficient porosity and permeability to constitute a reservoir.
“MBbls” means thousand oilfield barrels.
“Mcf” means thousand cubic feet of natural gas.
“Mcfe” means thousand cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.
“MMcf” means million cubic feet of natural gas.
“MMcfd” means million cubic feet of natural gas per day.
“MMcfe” means million cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.
“MMcfed” means million cubic feet of natural gas equivalent (using a ratio of one barrel of oil to 6,000 cubic feet of natural gas) per day.
“Net” means, when referring to wells or acres, the fractional ownership interests held by us, either directly or through a subsidiary or other Polish enterprise in which we have an interest, multiplied by the gross wells or acres.
“P50 reserves” means proved reserves plus probable reserves.
“Probabilistic” means a method of estimating reserves using the full range of values that could reasonably occur for each unknown from the geoscience and engineering data to generate a full range of possible outcomes and their associated probabilities of occurrence.
“Probable reserves” means those reserves determined by probabilistic methods that are less certain than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“Proved reserves” means the estimated quantities of crude oil, gas and gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. “Proved reserves” may be developed or undeveloped.
“PV-10 Value” means the estimated future net revenue to be generated from the production of proved or probable reserves discounted to present value using an annual discount rate of 10.0%, the Standardized Measure of Future Net Cash Flows (“SMOG”). These amounts are calculated net of estimated production costs, future development costs, and future income taxes, using prices and costs determined using guidelines established by the SEC, without escalation and without giving effect to non-property-related expenses, such general and administrative costs, debt service, and depreciation, depletion, and amortization.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and that is distinct and separate from other reservoirs.
“Tcf” means trillion cubic feet of natural gas.
“Usufruct” means the Polish equivalent of a U.S. oil and gas lease.
ITEM 3.
Item 3
Articles of Incorporation and Bylaws
3.01
Restated and Amended Articles of Incorporation
Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended September 30, 2000, filed November 7, 2000.
3.03
Articles of Amendment to the Restated Articles of Incorporation of FX Energy, Inc.
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2005, filed March 14, 2006.
3.04
Amendment to Articles of Incorporation Revising and Restating Designation of Rights, Privileges, and Preferences of Series A Preferred Stock
Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.
3.05
Bylaws of FX Energy, Inc., as amended May 24, 2010
Incorporated by reference from the current report on Form 8-K filed June 8, 2010.
Exhibit
Number*
Title of Document
Location
Item 4
Item 4
Instruments Defining the Rights of Security Holders
4.01
Specimen Stock Certificate
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
4.04
Rights Agreement dated as of April 4, 2007, between FX Energy, Inc. and Fidelity Transfer Company
Incorporated by reference from the quarterly report on Form 10-Q for the period ended June 30, 2007, filed August 8, 2007.
4.05
Amendment to Rights Agreement dated as of March 7, 2011
This filing.
Item 10
Material Contracts
10.26
Frontier Oil Exploration Company 1995 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.27
FX Energy, Inc. 1996 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.28
FX Energy, Inc. 1997 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.29
FX Energy, Inc. 1998 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.53
Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to Fences I project area
Incorporated by reference from the current report on Form 8-K filed May 2, 2000.
10.59
Sales / Purchase Agreement Special Provisions between Plains Marketing Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.60
Form of Non-Qualified Stock Option awarded August 14, 2002, with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.62
Agreement Regarding Cooperation within the Poznan Area (Fences II) entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
Exhibit
Number*
Title of Document
Location
10.63
Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.64
Farmout Agreement Entered into by and between FX Energy Poland Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. covering the “Fences Area” in the Foresudetic Monocline made as of January 9, 2003
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.67
FX Energy, Inc. 1999 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.68
FX Energy, Inc. 2000 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.69
FX Energy, Inc. 2001 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.70
FX Energy, Inc. 2003 Long-Term Incentive Plan
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.74
Greater Zaniemysl Area Agreement made as of March 12, 2004, among FX Energy Poland Sp. z o.o. and CalEnergy Resources Poland Sp. z o.o.
Incorporated by reference from the quarterly report on Form 10-Q for the period ended March 31, 2004, filed May 11, 2004.
10.75
Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2008, filed March 16, 2009.
10.77
Description of compensation arrangement with executive officers and directors**
This filing.
10.78
Form of Employment Agreement with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.79
Change in Control Compensation Agreement with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.81
FX Energy, Inc. 2004 Long-Term Incentive Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2004, filed March 15, 2005.
10.82
Letter of Engagement, H. Allen Turner, dated February 14, 2007
Incorporated by reference from the current report on Form 8-K filed February 20, 2007.
Exhibit
Number*
Title of Document
Location
10.98
Placement Agent Agreement between FX Energy, Inc., and Pritchard Capital Partners, LLC, with exhibits, including Form of Subscription Agreement
Incorporated by reference from the current report on Form 8-K filed December 9, 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.
Item 21
Subsidiaries of the Registrant
21.01
Schedule of Subsidiaries
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2007, filed March 10, 2008.
Item 23
Consents of Experts and Counsel
23.01
Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm
This filing.
23.02
Consent of Hohn Engineering PLLC, Petroleum Engineers
This filing.
23.03
Consent of RPS Energy, Petroleum Engineers
This filing.
Item 31
Rule 13a-14(a)/15d-14(a) Certifications
31.01
Certification of Principal Executive Officer Pursuant to Rule 13a-14
This filing.
31.02
Certification of Principal Financial Officer Pursuant to Rule 13a-14
This filing.
Item 32
Section 1350 Certifications
32.01
Certification 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.
99.03
Evaluation of the Lisewo Discovery of RPS Energy, Petroleum Engineers
This filing.
*
All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601, and the number following the decimal indicating the sequence of the particular document. Omitted numbers in the sequence refer to documents previously filed as an exhibit, but no longer required.
**
Identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit, as required by Item 15(a)(3) of Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
/s/ Thomas B. Lovejoy
Dated: March 7, 2011
Thomas B. Lovejoy, Director
/s/ David N. Pierce
Dated: March 7, 2011
David N. Pierce, Director, President,
and Principal Executive Officer
/s/ Dennis B. Goldstein
Dated: March 7, 2011
Dennis B. Goldstein, Director
/s/ Arnold S. Grundvig, Jr.
Dated: March 7, 2011
Arnold S. Grundvig, Jr., Director
/s/ Jerzy B. Maciolek
Dated: March 7, 2011
Jerzy B. Maciolek, Director
/s/ Richard Hardman
Dated: March 7, 2011
Richard Hardman, Director
/s/ H. Allen Turner
Dated: March 7, 2011
H. Allen Turner, Director
/s/ Clay Newton
Dated: March 7, 2011
Clay Newton, Principal Financial and
Accounting Officer
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of FX Energy, Inc., together with its consolidated subsidiaries (the Company), is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed by the Company’s principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles.
As of the end of the Company’s 2010 fiscal year, management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has determined that the Company’s internal control over financial reporting as of December 31, 2010, was effective.
The Company’s internal control over financial reporting includes policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, independent registered public accounting firm, as stated in its report appearing on pages and.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors
of FX Energy, Inc. and its subsidiaries
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive loss, of cash flows and of stockholders’ equity (deficit) present fairly, in all material respects, the financial position of FX Energy, Inc. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Salt Lake City, Utah
March 7, 2011
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2010 and 2009
(in thousands)
-Continued-
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2010 and 2009
(in thousands, except share data)
-Continued-
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2010, 2009, and 2008
(in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Comprehensive Loss
For the years ended December 31, 2010, 2009, and 2008
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2010, 2009, and 2008
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statement of Stockholders’ Equity (Deficit)
For the years ended December 31, 2010, 2009, and 2008
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
Organization
FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively referred to hereinafter as “us,” “we,” “our,” or “the Company”), is an independent oil and gas exploration and production company with principal production, reserves, and exploration in Poland and oil production and oilfield service activities in the United States. In Poland, we have projects involving the exploration and exploitation of oil and gas prospects in partnership with the Polish Oil and Gas Company (“PGNiG”), other industry partners, and for our own account. In the United States, we explore for and produce oil from fields in Montana and Nevada, and we have an oilfield services company in northern Montana that performs contract drilling and well-servicing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and its undivided interests in Poland. All significant intercompany accounts and transactions have been eliminated in consolidation. At December 31, 2010, we owned 100% of the voting common stock or other equity securities of our subsidiaries.
Cash and Cash Equivalents and Marketable Securities
We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. We determine the appropriate classification of our investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluate such designation at each balance sheet date.
Fair Value of Financial Instruments and Nonfinancial Assets and Liabilities
The carrying amounts of our financial instruments, including cash and cash equivalents, marketable securities, accounts receivable, accounts payable, and accrued liabilities, approximate fair value because of their generally short maturities. The accounting standards for fair value measurements provide for fair value measurements of all nonfinancial assets and nonfinancial liabilities not recognized or disclosed at fair value in the financial statements on a recurring basis.
Concentration of Credit Risk
The majority of our receivables are within the oil and gas industry, primarily from the purchasers of our oil and gas, and fees generated from oilfield services and our industry partners. Substantially all of our domestic receivables are with Cenex, a regional refiner and marketer, and substantially all of our Polish receivables are with PGNiG or one of its affiliates. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts at December 31, 2010 and 2009. The majority of our cash and cash equivalents are held by four financial institutions in Utah, Montana, and Poland.
Derivative Instruments
Accounting standards require derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of derivative instruments depends on their intended use and resulting hedge designation. For derivative instruments designated as hedges, the changes in fair value are recorded in the balance sheet as a component of accumulated other comprehensive income. Changes in the fair value of derivative instruments not designated as hedges are recorded in the Consolidated Statements of Operations, generally as a component of interest and other income (expense). At December 31, 2010 and 2009, we had no derivative instruments designated as hedges.
Inventory
Inventory consists primarily of tubular goods and production-related equipment and is valued at the lower of average cost or market.
Oil and Gas Properties
We follow the successful-efforts method of accounting for our oil and gas operations. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether an individual well has found proved reserves. If it is determined that an exploratory well has not found proved reserves, if the determination that proved reserves have been found cannot be made within one year, or if we are not making sufficient progress assessing the reserves and the economic and operating viability of the project, the costs of the well are expensed. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment charge is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are not considered to be realizable. Depletion, depreciation, and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is provided on a field-by-field basis using the units-of-production method. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net revenues determined on a field-by-field basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value determined on a property-by-property basis. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as a recovery of costs and any resulting gain or loss is recorded as other income.
During 2010, production ceased at our Kleka well in western Poland. We impaired the remaining capitalized costs of the well of $564,000. During 2009, production ceased at our Wilga well in eastern Poland. We impaired the remaining capitalized costs of the well of $1,864,000.
Low year-end oil prices resulted in a negative revision to our oil reserves and their estimated future net revenues in the United States for 2008. As a result of the negative revisions, the net book value of our domestic oil properties was greater than their estimated future net revenues at December 31, 2008. In accordance with accounting standards, we recorded an impairment of capitalized costs in the amount of $3,774,000 in 2008. The impairment amount was calculated by reducing the net capitalized costs of the U.S. oil properties to their year-end fair value, which was equal to their remaining estimated discounted future net cash flows.
During 2008, we impaired the costs of the Grundy-1 and Sroda-6 wells. Accounting standards require capitalized costs of exploratory wells to be expensed if the enterprise is not making sufficient progress assessing the reserves and economic viability of the project. Under then-current economic conditions, we did not have firm plans to further develop these two wells. Accordingly, we recorded an impairment charge of $7,220,000 associated with the Grundy-1 well and $3,752,000 associated with the Sroda-6 well in 2008.
During 2010, we recorded a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008. The gain is included in interest and other income.
The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves, during 2010, 2009, and 2008.
The 2010 activity includes costs associated with the Lisewo-1 well, which was drilling at year-end 2010 and was determined to be a commercial well subsequent to year-end. Activity during 2009 and 2008 included costs associated with the Kromolice-2 well, which was drilling at year-end 2008. During 2009, the well was completed for production, and the determination of proved reserves was made. The 2008 charge to expense of $669,000 was related to the Grundy well in Poland, the costs of which were impaired in 2008.
Other Property and Equipment
Other property and equipment, including oilfield-servicing equipment, is stated at cost. Depreciation of other property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from three to 40 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of other property and equipment sold, or otherwise disposed of, and the related accumulated depreciation are removed from the accounts and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation, is summarized as follows:
Supplemental Disclosure of Cash Flow Information
Noncash investing and financing transactions not reflected in the consolidated statements of cash flows include the following:
Cash paid for interest in 2010 and 2008 includes $149,177 and $188,715, respectively, in commitment fees on our Senior Facility Agreements.
Revenue Recognition
Revenues associated with oil and gas sales are recorded when title passes, which is upon delivery to the pipeline or other purchaser, and are net of royalties. Oilfield service revenues are recognized when the related service is performed.
Stock-Based Compensation
We maintain several share-based incentive plans. Under these plans, we may issue options or restricted stock awards. Options are granted at an option price equal to the market value of the stock at the date of grant, have terms ranging from five to seven years, and vest in three equal annual installments. Restricted stock awards have similar terms and vesting requirements. Accounting standards require share-based compensation costs to be measured at the grant date, based on the estimated fair value of the award, and recognized as expense over the employee’s requisite service period.
Income Taxes
Deferred income taxes are provided for the differences between the tax bases of assets or liabilities and their reported amounts in the consolidated financial statements. Such differences may result in taxable or deductible amounts in future years when the asset or liability is recovered or settled, respectively.
We did not have any unrecognized tax benefits at December 31, 2010. We are subject to audit in the United States by the Internal Revenue Service and various states for the prior three years and in Poland by Polish tax authorities for the prior five years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months. Our policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. No tax-related interest expense was recognized during the year ended December 31, 2010.
Subsequent Events
We have evaluated subsequent events after the balance sheet date of December 31, 2010, through the time of filing with the Securities and Exchange Commission.
New Accounting Standards
In January 2010, the Financial Accounting Standards Board issued new standards intended to improve disclosures about fair value measurements. The new standards require details of transfers in and out of Level 1 and 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. We adopted these new rules effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward, which we adopted December 31, 2010.
In all cases referenced above, the adoption of the new rules or standards did not have a material impact on our results of operations and financial condition. We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position, and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.
Foreign Operations
Effective October 1, 2008, we changed the functional currency of our Polish subsidiary from the U.S. dollar to the Polish zloty. The change in functional currency for the Polish subsidiary affects the amounts reported for Polish assets, liabilities, revenues, and expenses from those that would be reported had the U.S. dollar been maintained as the functional currency. The differences depend on changes in period-average and period-end exchange rates. Translation adjustments result from the process of translating the Polish subsidiary’s financial statements into the U.S. dollar reporting currency. Translation adjustments are not included in determining net income but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities of FX Energy Poland, our wholly owned subsidiary, is adjusted to reflect the difference between the exchange rate when the asset or liability was first recorded and the exchange rate on the date of the change. Upon the change in functional currency, we recorded a cumulative translation adjustment (“CTA”) of approximately $3.6 million. At December 31, 2010 and 2009, the CTA balance was $14.0 million and $10.7 million, respectively. Because of the fluctuation in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.
During 2010, we identified a misclassification between intercompany equity and intercompany debt. This misclassification resulted in an overstatement of foreign exchange loss of $145,000 in 2008 and an overstatement of foreign exchange gain of $29,000 in 2009 with corresponding misstatements in the cumulative translation adjustment. This error had no impact on total stockholders' equity (deficit) or the Statement of Cash Flows. The net impact of correcting this error in the fourth quarter of 2010 resulted in a decrease in the cumulative translation adjustment and a decrease in foreign exchange loss and net loss of $116,000 with no impact to earnings per share. We concluded that the impact of the error is immaterial to the financial statements in the periods in which it occurred as well as to the period in which it was corrected.
During 2010, we recorded foreign currency transaction losses of approximately $4.2 million. We recorded a loss of approximately $4.2 million attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc, as well as dollar-denominated notes payable held by FX Energy Poland. There was a corresponding credit to other comprehensive income for the losses attributable to the dollar-denominated loans, notes payable, and unpaid interest, which was then offset by translation adjustments of approximately $1.0 million related to our other balance sheet accounts as discussed above. The total amount of outstanding intercompany loans and accrued interest at December 31, 2010, was approximately $103 million.
During 2009, we recorded foreign currency transaction gains of approximately $7.1 million. We recorded a gain of approximately $8.3 million attributable to decreases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. There was a corresponding debit to other comprehensive income for the gains attributable to the intercompany loans and unpaid interest, which was then offset by translation adjustments of approximately $1.9 million related to our other balance sheet accounts as discussed above. The remaining $1.2 million loss was primarily attributable to the settlement of outstanding zloty forward-purchase contracts and the translation of period-end cash balances.
The following table provides a summary of changes in CTA (in thousands) for the years ended December 31, 2010 and 2009:
Future transaction gains or losses may be significant given the amount of dollar-denominated intercompany loans and notes payable and the volatility of exchange rates. Future translation adjustments will also vary in concert with changes in exchange rates. These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.
We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes. We have used forward-purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense are recognized in the consolidated financial statements. As of December 31, 2010 and 2009, there were no outstanding zloty forward-purchase contracts.
The change in functional currency will have no impact on our actual zloty-based revenues and expenditures in Poland.
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes, including uncertain tax positions, stock-based compensation, future development and abandonment costs, estimates to certain oil and gas revenues and expenses, and estimates of proved oil and natural gas reserve quantities used to calculate depletion, depreciation, and impairment of proved oil and natural gas properties and equipment.
Net Loss per Share
Basic earnings per share is computed by dividing the net loss applicable to common shares by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing the net loss by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options, warrants, unvested restricted stock, and convertible preferred stock or debt.
Outstanding options, warrants, and unvested restricted stock as of December 31, 2010, 2009, and 2008, were as follows:
We recorded net losses in 2010, 2009, and 2008. The above options, warrants, and unvested restricted stock were not included in the computation of diluted earnings per share for the years presented because the effect would have been antidilutive.
Note 2: Asset Retirement Obligation
We account for future site restoration costs by recording a liability for the fair value of asset retirement obligations (“ARO”) when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. We use an expected cash flow approach to estimate our asset retirement obligations. We recorded accretion expense of $91,624, $41,296, and $83,739 in 2010, 2009, and 2008, respectively. At December 31, 2010, there were no assets legally restricted for purposes of settling asset retirement obligations.
Following is a reconciliation of the yearly changes in the asset retirement obligation at December 31, 2010 and 2009:
When the present value of a future asset retirement obligation changes due to the increase or decrease of the estimated plugging costs of that asset, we adjust the related asset retirement cost. During both 2010 and 2009, the economic lives of our United States oil wells were increased, as higher oil prices resulted in more economic barrels. This change resulted in a decrease in the net present value of the retirement obligations, which in turn resulted in gains associated with those obligations, as the related asset retirement costs had been previously written off.
Note 3: Other Assets
As of December 31, 2010 and 2009, we had reclamation bonds with federal and state agencies with face amounts of $731,500, which were collateralized by certificates of deposit totaling $381,500. In addition, there are certificates of deposit totaling $25,000 covering performance bonds in other states.
Note 4: Accrued Liabilities
Our accrued liabilities as of December 31, 2010 and 2009, were comprised of the following:
Note 5: Notes Payable
On August 5, 2010, we refinanced our existing facility by executing an expanded credit facility with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The expanded credit facility calls for a periodic interest rate of LIBOR plus an interest margin of 4.0% and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on June 30, 2013. The expanded credit facility is an interest-only facility until June 2013. Unamortized deferred financing costs of approximately $577,000 associated with our prior credit facility were charged to interest expense during the third quarter of 2010. Payment of the expanded credit facility is secured by our assets in Poland and guaranteed by the Company. As of December 31, 2010, the total amount drawn under the expanded credit facility was $35 million. The year-end 2010 interest rate was 4.26% per annum.
We have access to $40 million under the expanded credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been on production for 30 days, at which time the full $55 million becomes available. Proceeds from the expanded credit facility are intended to support our development, production, and operating activities in Poland.
In consideration for the expanded credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.5 million. These fees, which were paid by increasing the amount of debt drawn under the expanded credit facility, have been capitalized as deferred financing costs and are being amortized over the five-year term of the loan, beginning in the third quarter of 2010. An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the expanded credit facility. There are no financial covenants associated with the expanded credit facility. The carrying value of the long-term debt at December 31, 2010, approximates its fair value.
The following table provides a summary of changes in notes payable (in thousands):
The borrowing base is redetermined twice a year, based on reserve volumes and values estimated by independent engineers as of the last day of the prior year. Our last redetermination was completed in December 2010, with no change in the borrowing base amount.
Note 6: Commitments and Contingencies
On December 20, 2010, the United States District Court for the District of Utah dismissed all claims in the matter Leilani York, derivatively on behalf of nominal defendant FX Energy, Inc., plaintiff, v. David N. Pierce, Dennis B. Goldstein, Arnold S. Grundvig, Jr., Richard Hardman, Tom Lovejoy, Jerzy Maciolek, Clay Newton, Andrew W. Pierce, and David Worrell, defendants, and FX Energy, Inc., nominal defendant, case no. 2:08-cv-00143, which asserted derivative claims on our behalf against certain of our current and former directors and certain of our current and former executive officers.
Note 7: Fair Value Measurements and Marketable Securities
The accounting standard for fair value measurements provides a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. Fair value is defined as the price that would be received for an asset or the exit price that would be paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date. The accounting standard established a fair value hierarchy that requires an entity to maximize the use of observable inputs, where available. The following summarizes the three levels of inputs required as well as the assets and liabilities that we value using those levels of inputs.
·
Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities.
·
Level 2: Observable inputs other than those included in Level 1. For example, quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in inactive markets.
·
Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no Level 3 assets as of December 31, 2010 or 2009.
Recurring Fair Value
The following tables set forth the financial assets and liabilities that we measured at fair value on a recurring basis by level within the fair value hierarchy. We classify assets and liabilities measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.
Assets and liabilities measured at fair value on a recurring basis consisted of the following as of December 31, 2010 and 2009 (in thousands):
_______________
(1)
Quoted prices in active markets for identical assets.
(2)
Significant other observable inputs.
(3)
Significant unobservable inputs.
Liabilities
At December 31, 2008, we had three outstanding zloty forward-purchase contracts denominated in U.S. dollars as follows: $2,500,000 that matured January 30, 2009; $2,100,000 that matured February 27, 2009; and $1,100,000 that matured March 31, 2009. All contracts were settled on their maturity dates.
Note 8: Income Taxes
We recognized no income tax benefit from the losses generated during 2010, 2009, and 2008. The components of the net deferred tax asset as of December 31, 2010 and 2009, are as follows:
The change in the valuation allowance during 2010, 2009, and 2008 is as follows:
Accounting standards require that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations through expansion of our oil and gas producing activities. The risks associated with that growth requirement are considerable, resulting in our conclusion that a full valuation allowance be provided at December 31, 2010, 2009, and 2008. Due to the full valuation allowance, our effective income tax rate for all three years was zero percent. The statutory rate was increased by permanent differences relating to changes associated with stock options and that tax treatment of interest income, and reduced by adjustments for net operating losses expiring, exchange rate differences, and changes to deferred taxes related to temporary differences.
United States NOL
At December 31, 2010, we had net operating loss (“NOL”) carryforwards in the United States of approximately $84,460,000 available to offset future taxable income. The carryforwards begin to expire in 2011 and will fully expire in 2030. The utilization of the NOL carryforwards against future taxable income in the United States may become subject to an annual limitation if there is a change in ownership. The NOL carryforwards in the United States include $23,128,000 relating to tax deductions resulting from the exercise of stock options. The tax benefit from adjusting the valuation allowance related to this portion of the NOL carryforward will be credited to additional paid-in capital.
Polish NOL
As of December 31, 2010, we had NOL carryforwards in Poland totaling approximately $16,092,000. The NOLs begin to expire in 2011 and will be fully expired in 2013. The normal carryforward period in Poland is five years. However, in any given year, no more than 50% of the NOL carryforward may be applied against Polish income in succeeding years.
The following table lists the years of expiration for our net operating losses:
The domestic and foreign components of our net loss are as follows:
Note 9: Stockholders’ Equity
In December 2010, we sold 1,500,000 shares of common stock in a registered-direct offering at a price of $6.00 per share. After offering costs, our net proceeds from the offering were $8,403,000.
Also during 2010, option holders exercised a total of 39,507 outstanding options at a price of $3.98 per share, resulting in proceeds to us of $157,000. Additionally, option holders exercised a total of 598,602 outstanding options at prices ranging from $3.14 to $3.98 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 152,892 incremental shares.
In 2009, option holders exercised a total of 55,000 outstanding options at a price of $2.40 per share, resulting in proceeds to us of $132,000. Additionally, option holders exercised a total of 380,000 outstanding options at a price of $2.40 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 169,860 incremental shares.
During 2008, we received proceeds from the exercise of 3,648,369 stock options and warrants of $12,312,649.
We issued 216,977, 228,100, and 110,090 shares in 2010, 2009, and 2008, respectively, as contributions to our employee benefit plan. In addition, we issued 6,000, 21,000, and 7,000 shares in 2010, 2009, and 2008, respectively, to consultants for services.
We have a stockholder rights plan, adopted in 2007, that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the stockholder rights plan would cause substantial dilution to a person or group that attempts to acquire us on terms not approved in advance by our board of directors. In addition, our articles of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that our stockholders may consider to be in their best interests.
Note 10: Stock Options, Warrants, and Restricted Stock
Equity Compensation Plans
Our equity compensation consists of annual stock option and award plans that have been adopted by the board of directors and subsequently approved by the stockholders at an annual meeting.
The following table summarizes information regarding our stock option and award plans as of December 31, 2010:
All stock option and award plans are administered by the Compensation Committee, consisting of the independent members of the board of directors. At its discretion, the Compensation Committee may grant stock, incentive stock options, or non-qualified options to any employee, including officers. The granted options have terms ranging from five to seven years and vest in three equal annual installments. Under terms of the stock option award plans, we may also issue restricted stock.
The following table summarizes option activity for 2010, 2009, and 2008:
The following table summarizes information about stock options outstanding as of December 31, 2010:
The aggregate intrinsic value of outstanding stock options at December 31, 2010, was $375.
In 2008, we recognized $15,508 in expense related to unvested stock options granted prior to the adoption of current accounting standards. There was no unamortized expense related to unvested options at December 31, 2010 and 2009. All options outstanding at December 31, 2010, are fully vested.
Restricted Stock
The following table summarizes restricted stock activity during 2010, 2009, and 2008:
The aggregate intrinsic value of unvested restricted stock at December 31, 2010, was $4,590,348. The aggregate intrinsic value represents the total pretax intrinsic value, based on our stock price of $6.15 as of December 31, 2010, which would have been received by the restricted stock award holders had all in-the-money restricted stock awards and options been vested as of that date. The weighted average period over which stock compensation expense related to the restricted stock awards will be recognized is 2.0 years.
During 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2,259,675, which will be amortized ratably over a three-year vesting period. Expense recognized during 2010 totaled $26,899.
During 2009, we issued 379,500 shares of restricted stock, resulting in deferred compensation of $1,043,625, which is being amortized ratably over a three-year vesting period. Expense recognized during 2010 and 2009 totaled and $347,253 and $10,269, respectively.
During 2008, we issued 367,000 shares of restricted stock, resulting in deferred compensation of $1,005,580, which is being amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010, 2009, and 2008 totaled $331,330, $335,214, and $9,184, respectively.
During 2007, we issued 370,925 shares of restricted stock, resulting in deferred compensation of $2,284,991, which is being amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010, 2009, and 2008 totaled $673,626, $761,649, and $761,805, respectively.
In December of 2006, we issued 318,400 shares of restricted stock, resulting in deferred compensation of $2,053,680, which was amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010, 2009, and 2008 totaled $0, $585,398, and $684,608, respectively.
In November of 2005, we issued 298,950 shares of restricted stock, resulting in deferred compensation of $3,096,600, which was amortized ratably over the three-year vesting period. Expense recognized for these shares during 2008 totaled $895,805.
Warrants
The following table summarizes warrant activity during 2008:
There were no warrants issued and outstanding during 2010 and 2009.
Note 11: Business Segments
We operate within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. Revenues associated with our E&P activities are comprised of oil and gas sales from our producing properties in Poland and oil sales from our producing properties in the United States. During the last three years, all sales of oil and gas in Poland were made to PGNiG or its affiliated companies. Over 90% of our oil sales in the United States were to Cenex during 2010, 2009, and 2008. Gas sales in Poland are sold pursuant to long-term sales contracts that obligate the buyer to purchase all gas produced. Individual oil sales are negotiated with PGNiG-affiliated entities and are not subject to sales contracts. We believe the purchasers of our oil production in the United States could be replaced, if necessary, without a loss in revenue.
E&P operating costs are comprised of: (1) exploration costs (geological and geophysical costs, exploratory dry holes, and proved property and non-producing leasehold impairments); and (2) lease operating costs (lease operating expenses and production taxes). Substantially all exploration costs are related to our operations in Poland. The majority of lease operating costs are related to our domestic production.
Revenues associated with our oilfield services segment are comprised of contract drilling and well-servicing fees generated by our oilfield-servicing equipment in Montana. Oilfield-servicing costs are comprised of direct costs associated with our oilfield services.
DD&A directly associated with a respective business segment is disclosed within that business segment. We do not allocate current assets, corporate DD&A, general and administrative costs, amortization of deferred compensation, interest income, interest expense, other income, or other expense to our operating business segments for management and business segment reporting purposes. All material intercompany transactions between our business segments are eliminated for management and business segment reporting purposes.
Information on our operations by business segment for 2010, 2009, and 2008 is summarized as follows:
A reconciliation of the segment information to the consolidated totals for 2010, 2009, and 2008 follows:
Note 12: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2010 and 2009 is as follows:
The net loss for 2010 includes a foreign exchange loss of $4.2 million primarily related to FX Energy Poland’s dollar-denominated intercompany loans from FX Energy, Inc., and notes payable. The net loss for 2009 includes a foreign exchange gain of $7.1 million primarily related to FX Energy Poland’s dollar-denominated intercompany loans from FX Energy, Inc.
FX ENERGY, INC., AND SUBSIDIARIES
Supplemental Information
Disclosure about Oil and Gas Properties and Producing Activities (Unaudited)
Capitalized Oil and Gas Property Costs
Capitalized costs relating to oil and gas exploration and production activities as of December 31, 2010 and 2009, are summarized as follows:
Results of Operations
Results of operations are reflected in Note 12, Business Segments. There is no tax provision because we are not likely to pay, and have not received any benefit from, any federal or local income taxes due to our operating losses. Total production costs (in thousands) for 2010, 2009, and 2008 were $3,473, $3,478, and $3,441, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration, and development activities during 2010, 2009, and 2008, whether capitalized or expensed, are summarized as follows:
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
Impairment of Oil and Gas Properties
We recorded impairment charges in our E&P segment related to oil and gas properties as follows (in thousands):
Exploratory Dry Hole Costs
Total dry hole costs in 2009 of $150,821 were related to a single dry hole drilled in the United States. Dry hole costs for 2008 included three wells plugged and abandoned in the United States in the amount of $463,744. There were no dry holes drilled in 2010.
Summary Oil and Gas Reserve Data (Unaudited)
The following disclosures about our crude oil and natural gas reserves and exploration and production activities are in accordance with accounting principles generally accepted in the United States of America for disclosures about oil and gas producing activities and Securities and Exchange Commission rules for oil and gas reporting disclosures.
Reserves
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
Recent SEC and FASB Rule-Making Activity
In December 2008, the Securities and Exchange Commission announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
·
Commodity Prices - Economic producibility of reserves and discounted cash flows are now based on the use of unweighted, 12-month first day of the month historical average prices adjusted for basis and quality differentials, rather than year-end prices.
·
Disclosure of Unproved Reserves - Probable and possible reserves may be disclosed separately on a voluntary basis.
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
·
Proved Undeveloped Reserves Guidelines - Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
·
Third-Party Reserves Preparation - If a company represents that its estimates of reserves are prepared or audited by a third party, the company must file a report of the third party as an exhibit to the relevant registration statement or report.
·
Use of Probabilistic Methods - Reserves may be estimated using probabilistic methods in which there is at least a 90% probability of recovery of “proved” reserves, at least a 50% probability of recovery of “probable” reserves, and at least a 10% probability of recovery of “possible” reserves.
·
Disclosure by Geographic Area - Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total oil and gas proved reserves.
We adopted the rules effective December 31, 2009.
Application of the current rules resulted in the use of lower prices at December 31, 2009, for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009, as required by the current rules, resulted in a decrease in proved developed oil reserves of approximately 990,000 cubic feet of natural gas equivalent. We did not calculate the impact of the current rules on our 2010 reserves. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.
Because we use year-end reserves and add back production to calculate DD&A, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense. We estimate the impact of using 12-month average commodity prices, as required by the current standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $14,000.
Definitions
The following definitions apply to the terms used in this disclosure:
Reserves Estimate-The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Proved Oil and Gas Reserves-Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the expiration of the contracts providing the right to operate, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves-Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
Undeveloped Oil and Gas Reserves-Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion or production facilities.
For complete definitions of proved natural gas, natural gas liquids, and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
Reserves Estimates Preparation
Estimates of our proved Polish reserves were prepared by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved domestic reserves were prepared by Hohn Engineering, an independent engineering firm in Billings, Montana. The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both RPS Energy and Hohn Engineering are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Proved Developed Reserves:
The following unaudited summary of proved developed reserve quantity information represents estimates only and should not be construed as exact:
Total Proved Reserves:
The following unaudited summary of proved reserve quantity information represents estimates only and should not be construed as exact:
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
_______________
(1)
Upward oil revisions in the United States attributable to higher average oil prices during 2010 compared to average 2009 oil prices. Downward gas revisions in Poland due to the reduction of proved reserves calculated at the Roszkow well based on new pressure data and cessation of production at the Kleka well
(2)
Volume increase in Poland attributable to new Kromolice-2 and Grabowka wells drilled or recompleted during 2009.
(3)
Upward oil revisions in the United States attributable to higher average oil prices during 2009 compared to year-end 2008 oil prices. Downward gas revisions due to the cessation of production at the Wilga well in Poland.
(4)
Volume increase in Poland attributable to new Kromolice-1 well drilled during 2008.
(5)
Upward gas revisions in Poland attributable to Sroda-4 and Zaniemysl-3 wells due to additional technical data acquired during 2008. Downward oil revisions due to lower year-end oil prices in the United States.
Standardized Measure of Discounted Future Net Cash Flows (“SMOG”) and Changes Therein Relating to Proved Oil Reserves
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. We believe such information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute the proved reserve valuation do not necessarily reflect our expectations of actual revenues to be derived from those reserves or their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rates also could result directly or indirectly from factors outside our control, such as unintentional delays in development, environmental concerns, and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating expenditures to be incurred in developing and producing the proved oil reserves at the end of the period, based on period-end costs and assuming continuation of existing economic conditions. A discount rate of 10% per year was used to reflect the timing of the future net cash flows. The future net cash flows for our Polish reserves are based on gas sales contracts we have with PGNIG.
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
The components of SMOG are detailed below:
The principal sources of changes in SMOG are detailed below:
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
Subsequent to December 31, 2010, we completed drilling and testing at the Lisewo-1 well in western Poland. Based on a reserve report issued by our independent petroleum reservoir engineers, the Lisewo-1 well contains proved reserves of 12,733 million cubic feet of gas, net to our 49% working interest, and increased our year-end discounted net present values, discounted at 10%, by approximately $16.0 million.
Item 10
Material Contracts
10.26
Frontier Oil Exploration Company 1995 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.27
FX Energy, Inc. 1996 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.28
FX Energy, Inc. 1997 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.29
FX Energy, Inc. 1998 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.53
Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Gornictwo Naftowe I Gazownictwo S.A. (POGC) and FX Energy Poland, Sp. z o.o. relating to Fences I project area
Incorporated by reference from the current report on Form 8-K filed May 2, 2000.
10.59
Sales / Purchase Agreement Special Provisions between Plains Marketing Canada, L.P. and FX Drilling Company Inc. agreed April 29, 2002
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.60
Form of Non-Qualified Stock Option awarded August 14, 2002, with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.62
Agreement Regarding Cooperation within the Poznan Area (Fences II) entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
Exhibit
Number*
Title of Document
Location
10.63
Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Gornictwo Naftowe i Gazownictwo S.A. and FX Energy Poland Sp. z o.o.
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.64
Farmout Agreement Entered into by and between FX Energy Poland Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. covering the “Fences Area” in the Foresudetic Monocline made as of January 9, 2003
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2002, filed March 27, 2003.
10.67
FX Energy, Inc. 1999 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.68
FX Energy, Inc. 2000 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.69
FX Energy, Inc. 2001 Stock Option and Award Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.70
FX Energy, Inc. 2003 Long-Term Incentive Plan
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2003, filed March 15, 2004.
10.74
Greater Zaniemysl Area Agreement made as of March 12, 2004, among FX Energy Poland Sp. z o.o. and CalEnergy Resources Poland Sp. z o.o.
Incorporated by reference from the quarterly report on Form 10-Q for the period ended March 31, 2004, filed May 11, 2004.
10.75
Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2008, filed March 16, 2009.
10.77
Description of compensation arrangement with executive officers and directors**
This filing.
10.78
Form of Employment Agreement with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.79
Change in Control Compensation Agreement with related schedule**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2006, filed March 13, 2007.
10.81
FX Energy, Inc. 2004 Long-Term Incentive Plan**
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2004, filed March 15, 2005.
10.82
Letter of Engagement, H. Allen Turner, dated February 14, 2007
Incorporated by reference from the current report on Form 8-K filed February 20, 2007.
Exhibit
Number*
Title of Document
Location
10.98
Placement Agent Agreement between FX Energy, Inc., and Pritchard Capital Partners, LLC, with exhibits, including Form of Subscription Agreement
Incorporated by reference from the current report on Form 8-K filed December 9, 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.
Item 21
Subsidiaries of the Registrant
21.01
Schedule of Subsidiaries
Incorporated by reference from the annual report on Form 10-K for the period ended December 31, 2007, filed March 10, 2008.
Item 23
Consents of Experts and Counsel
23.01
Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm
This filing.
23.02
Consent of Hohn Engineering PLLC, Petroleum Engineers
This filing.
23.03
Consent of RPS Energy, Petroleum Engineers
This filing.
Item 31
Rule 13a-14(a)/15d-14(a) Certifications
31.01
Certification of Principal Executive Officer Pursuant to Rule 13a-14
This filing.
31.02
Certification of Principal Financial Officer Pursuant to Rule 13a-14
This filing.
Item 32
Section 1350 Certifications
32.01
Certification 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.
99.03
Evaluation of the Lisewo Discovery of RPS Energy, Petroleum Engineers
This filing.
*
All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601, and the number following the decimal indicating the sequence of the particular document. Omitted numbers in the sequence refer to documents previously filed as an exhibit, but no longer required.
**
Identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit, as required by Item 15(a)(3) of Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
/s/ Thomas B. Lovejoy
Dated: March 7, 2011
Thomas B. Lovejoy, Director
/s/ David N. Pierce
Dated: March 7, 2011
David N. Pierce, Director, President,
and Principal Executive Officer
/s/ Dennis B. Goldstein
Dated: March 7, 2011
Dennis B. Goldstein, Director
/s/ Arnold S. Grundvig, Jr.
Dated: March 7, 2011
Arnold S. Grundvig, Jr., Director
/s/ Jerzy B. Maciolek
Dated: March 7, 2011
Jerzy B. Maciolek, Director
/s/ Richard Hardman
Dated: March 7, 2011
Richard Hardman, Director
/s/ H. Allen Turner
Dated: March 7, 2011
H. Allen Turner, Director
/s/ Clay Newton
Dated: March 7, 2011
Clay Newton, Principal Financial and
Accounting Officer
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of FX Energy, Inc., together with its consolidated subsidiaries (the Company), is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed by the Company’s principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles.
As of the end of the Company’s 2010 fiscal year, management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has determined that the Company’s internal control over financial reporting as of December 31, 2010, was effective.
The Company’s internal control over financial reporting includes policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, independent registered public accounting firm, as stated in its report appearing on pages and.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors
of FX Energy, Inc. and its subsidiaries
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive loss, of cash flows and of stockholders’ equity (deficit) present fairly, in all material respects, the financial position of FX Energy, Inc. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Salt Lake City, Utah
March 7, 2011
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2010 and 2009
(in thousands)
-Continued-
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2010 and 2009
(in thousands, except share data)
-Continued-
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2010, 2009, and 2008
(in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Comprehensive Loss
For the years ended December 31, 2010, 2009, and 2008
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2010, 2009, and 2008
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statement of Stockholders’ Equity (Deficit)
For the years ended December 31, 2010, 2009, and 2008
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC., AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
Organization
FX Energy, Inc., a Nevada corporation, and its subsidiaries (collectively referred to hereinafter as “us,” “we,” “our,” or “the Company”), is an independent oil and gas exploration and production company with principal production, reserves, and exploration in Poland and oil production and oilfield service activities in the United States. In Poland, we have projects involving the exploration and exploitation of oil and gas prospects in partnership with the Polish Oil and Gas Company (“PGNiG”), other industry partners, and for our own account. In the United States, we explore for and produce oil from fields in Montana and Nevada, and we have an oilfield services company in northern Montana that performs contract drilling and well-servicing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and its undivided interests in Poland. All significant intercompany accounts and transactions have been eliminated in consolidation. At December 31, 2010, we owned 100% of the voting common stock or other equity securities of our subsidiaries.
Cash and Cash Equivalents and Marketable Securities
We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. We determine the appropriate classification of our investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluate such designation at each balance sheet date.
Fair Value of Financial Instruments and Nonfinancial Assets and Liabilities
The carrying amounts of our financial instruments, including cash and cash equivalents, marketable securities, accounts receivable, accounts payable, and accrued liabilities, approximate fair value because of their generally short maturities. The accounting standards for fair value measurements provide for fair value measurements of all nonfinancial assets and nonfinancial liabilities not recognized or disclosed at fair value in the financial statements on a recurring basis.
Concentration of Credit Risk
The majority of our receivables are within the oil and gas industry, primarily from the purchasers of our oil and gas, and fees generated from oilfield services and our industry partners. Substantially all of our domestic receivables are with Cenex, a regional refiner and marketer, and substantially all of our Polish receivables are with PGNiG or one of its affiliates. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts at December 31, 2010 and 2009. The majority of our cash and cash equivalents are held by four financial institutions in Utah, Montana, and Poland.
Derivative Instruments
Accounting standards require derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of derivative instruments depends on their intended use and resulting hedge designation. For derivative instruments designated as hedges, the changes in fair value are recorded in the balance sheet as a component of accumulated other comprehensive income. Changes in the fair value of derivative instruments not designated as hedges are recorded in the Consolidated Statements of Operations, generally as a component of interest and other income (expense). At December 31, 2010 and 2009, we had no derivative instruments designated as hedges.
Inventory
Inventory consists primarily of tubular goods and production-related equipment and is valued at the lower of average cost or market.
Oil and Gas Properties
We follow the successful-efforts method of accounting for our oil and gas operations. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether an individual well has found proved reserves. If it is determined that an exploratory well has not found proved reserves, if the determination that proved reserves have been found cannot be made within one year, or if we are not making sufficient progress assessing the reserves and the economic and operating viability of the project, the costs of the well are expensed. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment charge is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are not considered to be realizable. Depletion, depreciation, and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is provided on a field-by-field basis using the units-of-production method. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net revenues determined on a field-by-field basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value determined on a property-by-property basis. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as a recovery of costs and any resulting gain or loss is recorded as other income.
During 2010, production ceased at our Kleka well in western Poland. We impaired the remaining capitalized costs of the well of $564,000. During 2009, production ceased at our Wilga well in eastern Poland. We impaired the remaining capitalized costs of the well of $1,864,000.
Low year-end oil prices resulted in a negative revision to our oil reserves and their estimated future net revenues in the United States for 2008. As a result of the negative revisions, the net book value of our domestic oil properties was greater than their estimated future net revenues at December 31, 2008. In accordance with accounting standards, we recorded an impairment of capitalized costs in the amount of $3,774,000 in 2008. The impairment amount was calculated by reducing the net capitalized costs of the U.S. oil properties to their year-end fair value, which was equal to their remaining estimated discounted future net cash flows.
During 2008, we impaired the costs of the Grundy-1 and Sroda-6 wells. Accounting standards require capitalized costs of exploratory wells to be expensed if the enterprise is not making sufficient progress assessing the reserves and economic viability of the project. Under then-current economic conditions, we did not have firm plans to further develop these two wells. Accordingly, we recorded an impairment charge of $7,220,000 associated with the Grundy-1 well and $3,752,000 associated with the Sroda-6 well in 2008.
During 2010, we recorded a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008. The gain is included in interest and other income.
The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves, during 2010, 2009, and 2008.
The 2010 activity includes costs associated with the Lisewo-1 well, which was drilling at year-end 2010 and was determined to be a commercial well subsequent to year-end. Activity during 2009 and 2008 included costs associated with the Kromolice-2 well, which was drilling at year-end 2008. During 2009, the well was completed for production, and the determination of proved reserves was made. The 2008 charge to expense of $669,000 was related to the Grundy well in Poland, the costs of which were impaired in 2008.
Other Property and Equipment
Other property and equipment, including oilfield-servicing equipment, is stated at cost. Depreciation of other property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from three to 40 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of other property and equipment sold, or otherwise disposed of, and the related accumulated depreciation are removed from the accounts and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation, is summarized as follows:
Supplemental Disclosure of Cash Flow Information
Noncash investing and financing transactions not reflected in the consolidated statements of cash flows include the following:
Cash paid for interest in 2010 and 2008 includes $149,177 and $188,715, respectively, in commitment fees on our Senior Facility Agreements.
Revenue Recognition
Revenues associated with oil and gas sales are recorded when title passes, which is upon delivery to the pipeline or other purchaser, and are net of royalties. Oilfield service revenues are recognized when the related service is performed.
Stock-Based Compensation
We maintain several share-based incentive plans. Under these plans, we may issue options or restricted stock awards. Options are granted at an option price equal to the market value of the stock at the date of grant, have terms ranging from five to seven years, and vest in three equal annual installments. Restricted stock awards have similar terms and vesting requirements. Accounting standards require share-based compensation costs to be measured at the grant date, based on the estimated fair value of the award, and recognized as expense over the employee’s requisite service period.
Income Taxes
Deferred income taxes are provided for the differences between the tax bases of assets or liabilities and their reported amounts in the consolidated financial statements. Such differences may result in taxable or deductible amounts in future years when the asset or liability is recovered or settled, respectively.
We did not have any unrecognized tax benefits at December 31, 2010. We are subject to audit in the United States by the Internal Revenue Service and various states for the prior three years and in Poland by Polish tax authorities for the prior five years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months. Our policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. No tax-related interest expense was recognized during the year ended December 31, 2010.
Subsequent Events
We have evaluated subsequent events after the balance sheet date of December 31, 2010, through the time of filing with the Securities and Exchange Commission.
New Accounting Standards
In January 2010, the Financial Accounting Standards Board issued new standards intended to improve disclosures about fair value measurements. The new standards require details of transfers in and out of Level 1 and 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. We adopted these new rules effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward, which we adopted December 31, 2010.
In all cases referenced above, the adoption of the new rules or standards did not have a material impact on our results of operations and financial condition. We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position, and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.
Foreign Operations
Effective October 1, 2008, we changed the functional currency of our Polish subsidiary from the U.S. dollar to the Polish zloty. The change in functional currency for the Polish subsidiary affects the amounts reported for Polish assets, liabilities, revenues, and expenses from those that would be reported had the U.S. dollar been maintained as the functional currency. The differences depend on changes in period-average and period-end exchange rates. Translation adjustments result from the process of translating the Polish subsidiary’s financial statements into the U.S. dollar reporting currency. Translation adjustments are not included in determining net income but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities of FX Energy Poland, our wholly owned subsidiary, is adjusted to reflect the difference between the exchange rate when the asset or liability was first recorded and the exchange rate on the date of the change. Upon the change in functional currency, we recorded a cumulative translation adjustment (“CTA”) of approximately $3.6 million. At December 31, 2010 and 2009, the CTA balance was $14.0 million and $10.7 million, respectively. Because of the fluctuation in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.
During 2010, we identified a misclassification between intercompany equity and intercompany debt. This misclassification resulted in an overstatement of foreign exchange loss of $145,000 in 2008 and an overstatement of foreign exchange gain of $29,000 in 2009 with corresponding misstatements in the cumulative translation adjustment. This error had no impact on total stockholders' equity (deficit) or the Statement of Cash Flows. The net impact of correcting this error in the fourth quarter of 2010 resulted in a decrease in the cumulative translation adjustment and a decrease in foreign exchange loss and net loss of $116,000 with no impact to earnings per share. We concluded that the impact of the error is immaterial to the financial statements in the periods in which it occurred as well as to the period in which it was corrected.
During 2010, we recorded foreign currency transaction losses of approximately $4.2 million. We recorded a loss of approximately $4.2 million attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc, as well as dollar-denominated notes payable held by FX Energy Poland. There was a corresponding credit to other comprehensive income for the losses attributable to the dollar-denominated loans, notes payable, and unpaid interest, which was then offset by translation adjustments of approximately $1.0 million related to our other balance sheet accounts as discussed above. The total amount of outstanding intercompany loans and accrued interest at December 31, 2010, was approximately $103 million.
During 2009, we recorded foreign currency transaction gains of approximately $7.1 million. We recorded a gain of approximately $8.3 million attributable to decreases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. There was a corresponding debit to other comprehensive income for the gains attributable to the intercompany loans and unpaid interest, which was then offset by translation adjustments of approximately $1.9 million related to our other balance sheet accounts as discussed above. The remaining $1.2 million loss was primarily attributable to the settlement of outstanding zloty forward-purchase contracts and the translation of period-end cash balances.
The following table provides a summary of changes in CTA (in thousands) for the years ended December 31, 2010 and 2009:
Future transaction gains or losses may be significant given the amount of dollar-denominated intercompany loans and notes payable and the volatility of exchange rates. Future translation adjustments will also vary in concert with changes in exchange rates. These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.
We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes. We have used forward-purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense are recognized in the consolidated financial statements. As of December 31, 2010 and 2009, there were no outstanding zloty forward-purchase contracts.
The change in functional currency will have no impact on our actual zloty-based revenues and expenditures in Poland.
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes, including uncertain tax positions, stock-based compensation, future development and abandonment costs, estimates to certain oil and gas revenues and expenses, and estimates of proved oil and natural gas reserve quantities used to calculate depletion, depreciation, and impairment of proved oil and natural gas properties and equipment.
Net Loss per Share
Basic earnings per share is computed by dividing the net loss applicable to common shares by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing the net loss by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options, warrants, unvested restricted stock, and convertible preferred stock or debt.
Outstanding options, warrants, and unvested restricted stock as of December 31, 2010, 2009, and 2008, were as follows:
We recorded net losses in 2010, 2009, and 2008. The above options, warrants, and unvested restricted stock were not included in the computation of diluted earnings per share for the years presented because the effect would have been antidilutive.
Note 2: Asset Retirement Obligation
We account for future site restoration costs by recording a liability for the fair value of asset retirement obligations (“ARO”) when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. We use an expected cash flow approach to estimate our asset retirement obligations. We recorded accretion expense of $91,624, $41,296, and $83,739 in 2010, 2009, and 2008, respectively. At December 31, 2010, there were no assets legally restricted for purposes of settling asset retirement obligations.
Following is a reconciliation of the yearly changes in the asset retirement obligation at December 31, 2010 and 2009:
When the present value of a future asset retirement obligation changes due to the increase or decrease of the estimated plugging costs of that asset, we adjust the related asset retirement cost. During both 2010 and 2009, the economic lives of our United States oil wells were increased, as higher oil prices resulted in more economic barrels. This change resulted in a decrease in the net present value of the retirement obligations, which in turn resulted in gains associated with those obligations, as the related asset retirement costs had been previously written off.
Note 3: Other Assets
As of December 31, 2010 and 2009, we had reclamation bonds with federal and state agencies with face amounts of $731,500, which were collateralized by certificates of deposit totaling $381,500. In addition, there are certificates of deposit totaling $25,000 covering performance bonds in other states.
Note 4: Accrued Liabilities
Our accrued liabilities as of December 31, 2010 and 2009, were comprised of the following:
Note 5: Notes Payable
On August 5, 2010, we refinanced our existing facility by executing an expanded credit facility with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The expanded credit facility calls for a periodic interest rate of LIBOR plus an interest margin of 4.0% and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on June 30, 2013. The expanded credit facility is an interest-only facility until June 2013. Unamortized deferred financing costs of approximately $577,000 associated with our prior credit facility were charged to interest expense during the third quarter of 2010. Payment of the expanded credit facility is secured by our assets in Poland and guaranteed by the Company. As of December 31, 2010, the total amount drawn under the expanded credit facility was $35 million. The year-end 2010 interest rate was 4.26% per annum.
We have access to $40 million under the expanded credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been on production for 30 days, at which time the full $55 million becomes available. Proceeds from the expanded credit facility are intended to support our development, production, and operating activities in Poland.
In consideration for the expanded credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.5 million. These fees, which were paid by increasing the amount of debt drawn under the expanded credit facility, have been capitalized as deferred financing costs and are being amortized over the five-year term of the loan, beginning in the third quarter of 2010. An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the expanded credit facility. There are no financial covenants associated with the expanded credit facility. The carrying value of the long-term debt at December 31, 2010, approximates its fair value.
The following table provides a summary of changes in notes payable (in thousands):
The borrowing base is redetermined twice a year, based on reserve volumes and values estimated by independent engineers as of the last day of the prior year. Our last redetermination was completed in December 2010, with no change in the borrowing base amount.
Note 6: Commitments and Contingencies
On December 20, 2010, the United States District Court for the District of Utah dismissed all claims in the matter Leilani York, derivatively on behalf of nominal defendant FX Energy, Inc., plaintiff, v. David N. Pierce, Dennis B. Goldstein, Arnold S. Grundvig, Jr., Richard Hardman, Tom Lovejoy, Jerzy Maciolek, Clay Newton, Andrew W. Pierce, and David Worrell, defendants, and FX Energy, Inc., nominal defendant, case no. 2:08-cv-00143, which asserted derivative claims on our behalf against certain of our current and former directors and certain of our current and former executive officers.
Note 7: Fair Value Measurements and Marketable Securities
The accounting standard for fair value measurements provides a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. Fair value is defined as the price that would be received for an asset or the exit price that would be paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date. The accounting standard established a fair value hierarchy that requires an entity to maximize the use of observable inputs, where available. The following summarizes the three levels of inputs required as well as the assets and liabilities that we value using those levels of inputs.
·
Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities.
·
Level 2: Observable inputs other than those included in Level 1. For example, quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in inactive markets.
·
Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no Level 3 assets as of December 31, 2010 or 2009.
Recurring Fair Value
The following tables set forth the financial assets and liabilities that we measured at fair value on a recurring basis by level within the fair value hierarchy. We classify assets and liabilities measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.
Assets and liabilities measured at fair value on a recurring basis consisted of the following as of December 31, 2010 and 2009 (in thousands):
_______________
(1)
Quoted prices in active markets for identical assets.
(2)
Significant other observable inputs.
(3)
Significant unobservable inputs.
Liabilities
At December 31, 2008, we had three outstanding zloty forward-purchase contracts denominated in U.S. dollars as follows: $2,500,000 that matured January 30, 2009; $2,100,000 that matured February 27, 2009; and $1,100,000 that matured March 31, 2009. All contracts were settled on their maturity dates.
Note 8: Income Taxes
We recognized no income tax benefit from the losses generated during 2010, 2009, and 2008. The components of the net deferred tax asset as of December 31, 2010 and 2009, are as follows:
The change in the valuation allowance during 2010, 2009, and 2008 is as follows:
Accounting standards require that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations through expansion of our oil and gas producing activities. The risks associated with that growth requirement are considerable, resulting in our conclusion that a full valuation allowance be provided at December 31, 2010, 2009, and 2008. Due to the full valuation allowance, our effective income tax rate for all three years was zero percent. The statutory rate was increased by permanent differences relating to changes associated with stock options and that tax treatment of interest income, and reduced by adjustments for net operating losses expiring, exchange rate differences, and changes to deferred taxes related to temporary differences.
United States NOL
At December 31, 2010, we had net operating loss (“NOL”) carryforwards in the United States of approximately $84,460,000 available to offset future taxable income. The carryforwards begin to expire in 2011 and will fully expire in 2030. The utilization of the NOL carryforwards against future taxable income in the United States may become subject to an annual limitation if there is a change in ownership. The NOL carryforwards in the United States include $23,128,000 relating to tax deductions resulting from the exercise of stock options. The tax benefit from adjusting the valuation allowance related to this portion of the NOL carryforward will be credited to additional paid-in capital.
Polish NOL
As of December 31, 2010, we had NOL carryforwards in Poland totaling approximately $16,092,000. The NOLs begin to expire in 2011 and will be fully expired in 2013. The normal carryforward period in Poland is five years. However, in any given year, no more than 50% of the NOL carryforward may be applied against Polish income in succeeding years.
The following table lists the years of expiration for our net operating losses:
The domestic and foreign components of our net loss are as follows:
Note 9: Stockholders’ Equity
In December 2010, we sold 1,500,000 shares of common stock in a registered-direct offering at a price of $6.00 per share. After offering costs, our net proceeds from the offering were $8,403,000.
Also during 2010, option holders exercised a total of 39,507 outstanding options at a price of $3.98 per share, resulting in proceeds to us of $157,000. Additionally, option holders exercised a total of 598,602 outstanding options at prices ranging from $3.14 to $3.98 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 152,892 incremental shares.
In 2009, option holders exercised a total of 55,000 outstanding options at a price of $2.40 per share, resulting in proceeds to us of $132,000. Additionally, option holders exercised a total of 380,000 outstanding options at a price of $2.40 per share by surrendering currently owned shares to pay the exercise price. As a result of this exercise, we issued 169,860 incremental shares.
During 2008, we received proceeds from the exercise of 3,648,369 stock options and warrants of $12,312,649.
We issued 216,977, 228,100, and 110,090 shares in 2010, 2009, and 2008, respectively, as contributions to our employee benefit plan. In addition, we issued 6,000, 21,000, and 7,000 shares in 2010, 2009, and 2008, respectively, to consultants for services.
We have a stockholder rights plan, adopted in 2007, that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the stockholder rights plan would cause substantial dilution to a person or group that attempts to acquire us on terms not approved in advance by our board of directors. In addition, our articles of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that our stockholders may consider to be in their best interests.
Note 10: Stock Options, Warrants, and Restricted Stock
Equity Compensation Plans
Our equity compensation consists of annual stock option and award plans that have been adopted by the board of directors and subsequently approved by the stockholders at an annual meeting.
The following table summarizes information regarding our stock option and award plans as of December 31, 2010:
All stock option and award plans are administered by the Compensation Committee, consisting of the independent members of the board of directors. At its discretion, the Compensation Committee may grant stock, incentive stock options, or non-qualified options to any employee, including officers. The granted options have terms ranging from five to seven years and vest in three equal annual installments. Under terms of the stock option award plans, we may also issue restricted stock.
The following table summarizes option activity for 2010, 2009, and 2008:
The following table summarizes information about stock options outstanding as of December 31, 2010:
The aggregate intrinsic value of outstanding stock options at December 31, 2010, was $375.
In 2008, we recognized $15,508 in expense related to unvested stock options granted prior to the adoption of current accounting standards. There was no unamortized expense related to unvested options at December 31, 2010 and 2009. All options outstanding at December 31, 2010, are fully vested.
Restricted Stock
The following table summarizes restricted stock activity during 2010, 2009, and 2008:
The aggregate intrinsic value of unvested restricted stock at December 31, 2010, was $4,590,348. The aggregate intrinsic value represents the total pretax intrinsic value, based on our stock price of $6.15 as of December 31, 2010, which would have been received by the restricted stock award holders had all in-the-money restricted stock awards and options been vested as of that date. The weighted average period over which stock compensation expense related to the restricted stock awards will be recognized is 2.0 years.
During 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2,259,675, which will be amortized ratably over a three-year vesting period. Expense recognized during 2010 totaled $26,899.
During 2009, we issued 379,500 shares of restricted stock, resulting in deferred compensation of $1,043,625, which is being amortized ratably over a three-year vesting period. Expense recognized during 2010 and 2009 totaled and $347,253 and $10,269, respectively.
During 2008, we issued 367,000 shares of restricted stock, resulting in deferred compensation of $1,005,580, which is being amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010, 2009, and 2008 totaled $331,330, $335,214, and $9,184, respectively.
During 2007, we issued 370,925 shares of restricted stock, resulting in deferred compensation of $2,284,991, which is being amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010, 2009, and 2008 totaled $673,626, $761,649, and $761,805, respectively.
In December of 2006, we issued 318,400 shares of restricted stock, resulting in deferred compensation of $2,053,680, which was amortized ratably over a three-year vesting period. Expense recognized for these shares during 2010, 2009, and 2008 totaled $0, $585,398, and $684,608, respectively.
In November of 2005, we issued 298,950 shares of restricted stock, resulting in deferred compensation of $3,096,600, which was amortized ratably over the three-year vesting period. Expense recognized for these shares during 2008 totaled $895,805.
Warrants
The following table summarizes warrant activity during 2008:
There were no warrants issued and outstanding during 2010 and 2009.
Note 11: Business Segments
We operate within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. Revenues associated with our E&P activities are comprised of oil and gas sales from our producing properties in Poland and oil sales from our producing properties in the United States. During the last three years, all sales of oil and gas in Poland were made to PGNiG or its affiliated companies. Over 90% of our oil sales in the United States were to Cenex during 2010, 2009, and 2008. Gas sales in Poland are sold pursuant to long-term sales contracts that obligate the buyer to purchase all gas produced. Individual oil sales are negotiated with PGNiG-affiliated entities and are not subject to sales contracts. We believe the purchasers of our oil production in the United States could be replaced, if necessary, without a loss in revenue.
E&P operating costs are comprised of: (1) exploration costs (geological and geophysical costs, exploratory dry holes, and proved property and non-producing leasehold impairments); and (2) lease operating costs (lease operating expenses and production taxes). Substantially all exploration costs are related to our operations in Poland. The majority of lease operating costs are related to our domestic production.
Revenues associated with our oilfield services segment are comprised of contract drilling and well-servicing fees generated by our oilfield-servicing equipment in Montana. Oilfield-servicing costs are comprised of direct costs associated with our oilfield services.
DD&A directly associated with a respective business segment is disclosed within that business segment. We do not allocate current assets, corporate DD&A, general and administrative costs, amortization of deferred compensation, interest income, interest expense, other income, or other expense to our operating business segments for management and business segment reporting purposes. All material intercompany transactions between our business segments are eliminated for management and business segment reporting purposes.
Information on our operations by business segment for 2010, 2009, and 2008 is summarized as follows:
A reconciliation of the segment information to the consolidated totals for 2010, 2009, and 2008 follows:
Note 12: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2010 and 2009 is as follows:
The net loss for 2010 includes a foreign exchange loss of $4.2 million primarily related to FX Energy Poland’s dollar-denominated intercompany loans from FX Energy, Inc., and notes payable. The net loss for 2009 includes a foreign exchange gain of $7.1 million primarily related to FX Energy Poland’s dollar-denominated intercompany loans from FX Energy, Inc.
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Supplemental Information
Disclosure about Oil and Gas Properties and Producing Activities (Unaudited)
Capitalized Oil and Gas Property Costs
Capitalized costs relating to oil and gas exploration and production activities as of December 31, 2010 and 2009, are summarized as follows:
Results of Operations
Results of operations are reflected in Note 12, Business Segments. There is no tax provision because we are not likely to pay, and have not received any benefit from, any federal or local income taxes due to our operating losses. Total production costs (in thousands) for 2010, 2009, and 2008 were $3,473, $3,478, and $3,441, respectively.
Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration, and development activities during 2010, 2009, and 2008, whether capitalized or expensed, are summarized as follows:
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Impairment of Oil and Gas Properties
We recorded impairment charges in our E&P segment related to oil and gas properties as follows (in thousands):
Exploratory Dry Hole Costs
Total dry hole costs in 2009 of $150,821 were related to a single dry hole drilled in the United States. Dry hole costs for 2008 included three wells plugged and abandoned in the United States in the amount of $463,744. There were no dry holes drilled in 2010.
Summary Oil and Gas Reserve Data (Unaudited)
The following disclosures about our crude oil and natural gas reserves and exploration and production activities are in accordance with accounting principles generally accepted in the United States of America for disclosures about oil and gas producing activities and Securities and Exchange Commission rules for oil and gas reporting disclosures.
Reserves
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
Recent SEC and FASB Rule-Making Activity
In December 2008, the Securities and Exchange Commission announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
·
Commodity Prices - Economic producibility of reserves and discounted cash flows are now based on the use of unweighted, 12-month first day of the month historical average prices adjusted for basis and quality differentials, rather than year-end prices.
·
Disclosure of Unproved Reserves - Probable and possible reserves may be disclosed separately on a voluntary basis.
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Proved Undeveloped Reserves Guidelines - Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
·
Third-Party Reserves Preparation - If a company represents that its estimates of reserves are prepared or audited by a third party, the company must file a report of the third party as an exhibit to the relevant registration statement or report.
·
Use of Probabilistic Methods - Reserves may be estimated using probabilistic methods in which there is at least a 90% probability of recovery of “proved” reserves, at least a 50% probability of recovery of “probable” reserves, and at least a 10% probability of recovery of “possible” reserves.
·
Disclosure by Geographic Area - Reserves in foreign countries or continents must be presented separately if they represent more than 15% of total oil and gas proved reserves.
We adopted the rules effective December 31, 2009.
Application of the current rules resulted in the use of lower prices at December 31, 2009, for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009, as required by the current rules, resulted in a decrease in proved developed oil reserves of approximately 990,000 cubic feet of natural gas equivalent. We did not calculate the impact of the current rules on our 2010 reserves. Changes in the proved undeveloped reserves rules had no impact on our reserve quantities, as we do not include any reserves for undrilled locations.
Because we use year-end reserves and add back production to calculate DD&A, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense. We estimate the impact of using 12-month average commodity prices, as required by the current standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $14,000.
Definitions
The following definitions apply to the terms used in this disclosure:
Reserves Estimate-The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
Proved Oil and Gas Reserves-Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the expiration of the contracts providing the right to operate, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Developed Oil and Gas Reserves-Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
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Undeveloped Oil and Gas Reserves-Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion or production facilities.
For complete definitions of proved natural gas, natural gas liquids, and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(6), (22) and (31).
Reserves Estimates Preparation
Estimates of our proved Polish reserves were prepared by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved domestic reserves were prepared by Hohn Engineering, an independent engineering firm in Billings, Montana. The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Both RPS Energy and Hohn Engineering are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Proved Developed Reserves:
The following unaudited summary of proved developed reserve quantity information represents estimates only and should not be construed as exact:
Total Proved Reserves:
The following unaudited summary of proved reserve quantity information represents estimates only and should not be construed as exact:
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(1)
Upward oil revisions in the United States attributable to higher average oil prices during 2010 compared to average 2009 oil prices. Downward gas revisions in Poland due to the reduction of proved reserves calculated at the Roszkow well based on new pressure data and cessation of production at the Kleka well
(2)
Volume increase in Poland attributable to new Kromolice-2 and Grabowka wells drilled or recompleted during 2009.
(3)
Upward oil revisions in the United States attributable to higher average oil prices during 2009 compared to year-end 2008 oil prices. Downward gas revisions due to the cessation of production at the Wilga well in Poland.
(4)
Volume increase in Poland attributable to new Kromolice-1 well drilled during 2008.
(5)
Upward gas revisions in Poland attributable to Sroda-4 and Zaniemysl-3 wells due to additional technical data acquired during 2008. Downward oil revisions due to lower year-end oil prices in the United States.
Standardized Measure of Discounted Future Net Cash Flows (“SMOG”) and Changes Therein Relating to Proved Oil Reserves
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. We believe such information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute the proved reserve valuation do not necessarily reflect our expectations of actual revenues to be derived from those reserves or their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rates also could result directly or indirectly from factors outside our control, such as unintentional delays in development, environmental concerns, and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating expenditures to be incurred in developing and producing the proved oil reserves at the end of the period, based on period-end costs and assuming continuation of existing economic conditions. A discount rate of 10% per year was used to reflect the timing of the future net cash flows. The future net cash flows for our Polish reserves are based on gas sales contracts we have with PGNIG.
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The components of SMOG are detailed below:
The principal sources of changes in SMOG are detailed below:
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Subsequent to December 31, 2010, we completed drilling and testing at the Lisewo-1 well in western Poland. Based on a reserve report issued by our independent petroleum reservoir engineers, the Lisewo-1 well contains proved reserves of 12,733 million cubic feet of gas, net to our 49% working interest, and increased our year-end discounted net present values, discounted at 10%, by approximately $16.0 million.