Attached files
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
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Washington, D.C. 20549
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FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2014
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from _______________ to _______________
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Commission File Number: 001-35012
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FX ENERGY, INC.
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(Exact name of registrant as specified in its charter)
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Nevada
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87-0504461
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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3006 Highland Drive, Suite 206, Salt Lake City, Utah
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84106
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(Address of principal executive offices)
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(Zip Code)
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Registrant’s telephone number, including area code:
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Telephone (801) 486-5555
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Facsimile (801) 486-5575
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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Common Stock, Par Value $0.001
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NASDAQ Global Select Market
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Preferred Share Purchase Rights
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Series B Preferred Stock, Par Value $0.01
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Securities registered pursuant to Section 12(g) of the Act:
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None
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(Title of Class)
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer o
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Accelerated filer x
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Non-accelerated filer o
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Smaller reporting company o
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of June 30, 2014, the aggregate market value of the voting and nonvoting common equity held by nonaffiliates of the registrant was $182,136,000.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. As of March 12, 2015, FX Energy had 54,870,587 shares of its common stock, par value $0.001, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE. Portions of FX Energy’s definitive Proxy Statement in connection with the 2015 Annual Meeting of Stockholders are incorporated by reference in response to Part III of this Annual Report.
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FX ENERGY, INC.
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Form 10-K for the fiscal year ended December 31, 2014
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TABLE OF CONTENTS
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Item
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Page
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Part I
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Special Note on Forward-Looking Statements
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3
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1
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Business
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5
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1A
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Risk Factors
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11
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1B
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Unresolved Staff Comments
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26
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2
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Properties
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26
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3
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Legal Proceedings
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41
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4
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Mine Safety Disclosures
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41
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Part II
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5
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Market for Registrant’s Common Equity, Related Stockholder Matters
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and Issuer Purchases of Equity Securities
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41
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6
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Selected Financial Data
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42
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7
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Management’s Discussion and Analysis of Financial Condition and Results of Operation
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43
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7A
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Quantitative and Qualitative Disclosures about Market Risk
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58
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8
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Financial Statements and Supplementary Data
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58
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9
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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59
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9A
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Controls and Procedures
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59
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9B
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Other Information
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61
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Part III
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10
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Directors, Executive Officers and Corporate Governance
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61
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11
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Executive Compensation
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61
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12
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Security Ownership of Certain Beneficial Owners and Management and Related
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Stockholder Matters
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61
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13
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Certain Relationships and Related Transactions, and Director Independence
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61
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14
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Principal Accountant Fees and Services
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62
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Part IV
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15
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Exhibits and Financial Statement Schedules
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62
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--
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Signatures
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67
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Report of Independent Registered Public Accounting Firm
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F-1
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2
SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS
This report contains “forward-looking” statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically identified by the use of the words “believe,” “may,” “could,” “should,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “intend,” and similar words and expressions. Statements that describe our future strategic plans, goals, or objectives are also forward-looking statements. We intend that the forward-looking statements will be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Readers of this report are cautioned that any forward-looking statements, including those regarding us or our management’s current beliefs, expectations, anticipations, estimations, projections, strategies, proposals, plans, or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as:
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whether we will be able to discover and produce gas or oil in commercial quantities from any exploration prospect;
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whether we will be able to borrow funds to develop our gas discoveries in Poland from our current principal lenders or from any other commercial lenders, even if we increase substantially the quantity and value of our reserves that we may be willing to encumber to secure repayment of these borrowings;
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whether the quantities of gas or oil we discover will be consistent with our initial estimate of an exploration target area’s gross unrisked potential;
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the rates at which our resources will be produced, particularly from properties for which we are not the operator;
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whether we will be able to obtain capital sufficient for our anticipated exploration, development, and other capital expenditures;
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how our efforts to obtain additional capital will affect the trading market for our securities;
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whether actual exploration risks, schedules, and sequences will be consistent with our plans and forecasts;
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the future results of drilling or producing individual wells and other exploration and development activities;
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the prices at which we may be able to sell gas or oil, which impact our revenues, borrowing ability, and reserve amounts and values;
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foreign currency exchange-rate fluctuations, which also impact our revenues, capital expenditures, borrowing ability, and reserve amounts and values;
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the financial and operating viability and stability of Polskie Górnictwo Naftowe i Gazownictwo, or PGNiG, and other third parties with which we conduct business and on which we rely to supply goods and services and to purchase our gas and oil production;
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exploration and development priorities and the financial and technical resources of PGNiG, our principal joint venture and strategic partner in Poland, or other future partners;
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uncertainties inherent in estimating quantities of proved reserves and actual production rates and associated costs;
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the cost and availability of additional capital that we may require and possible related restrictions on our future operating or financing flexibility;
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our future ability to attract industry or financial participants to share the costs of exploration, exploitation, development, and acquisition activities;
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the effect of future changes in reservoir pressure, prices, reservoir mapping, production rates, and other factors on reserve quantities;
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uncertainties related to the future determination of exploitation fees, royalty rates, and other matters governing our oil and gas interests;
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uncertainties, restrictions, and increased costs resulting from the current public interest and regulatory focus on hydraulic fracturing, which we may use in the future;
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price and market changes that may result from the development of an open Polish gas market to replace government-set pricing tariffs;
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changes in the regulatory regime for the exploration, development, and production of hydrocarbons in Poland, including changes in the scheme through which prices at which we sell our production may be governmentally established or market influenced and changes in applicable royalty rates and taxes;
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environmental hazards, such as uncontrollable flows of crude oil, brine, well fluids, hydraulic fracturing fluids, or other pollutants by us or third-party service providers;
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uncertainties regarding future political, economic, regulatory, environmental, fiscal, taxation, and other policies in Poland and the European Union;
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uncertainties that the insurance policies carried by us or by PGNiG, as operator of the Fences area, can continue to be obtained on reasonable terms or that such policies will protect against all risks of loss.
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the impact on us, our industry partners, our lenders, and others with which we deal, of the continuing unsettled economies within the European Union, of which Poland is a member, the political, economic, and financial effects of ongoing Russian political circumstance, the sanctions imposed by Western European countries and the United States, and Russia’s response to such measures; and
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the factors set forth under the headings “Risk Factors” and “Management’s Discussion and Analysis of Analysis of Financial Condition and Results of Operation” and other factors that are not currently known to us that may emerge from time to time.
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The forward-looking information is based on present circumstances and on our predictions respecting events that have not occurred, that may not occur, or that may occur with different consequences from those now assumed or anticipated. Actual events or results may differ materially from those discussed in the forward-looking statements. The forward-looking statements included in this report are made only as of the date of this report.
4
PART I
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ITEM 1. BUSINESS
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Introduction
We are an independent oil and gas exploration and production company with production, development, and exploration activities in Poland. We also have modest oil production and oilfield service activities in the United States. Our corporate headquarters are in Salt Lake City, Utah, and our Polish operations are headquartered in Warsaw, Poland. 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 2014, independent reserve engineers estimated our worldwide proved oil and gas reserves to be 37.4 billion cubic feet, or Bcf, of natural gas and 0.4 million barrels of oil, or Bbl, or a combined total of 39.5 billion cubic feet of natural gas equivalent, or Bcfe (converting oil to gas at a ratio of one barrel of oil to 6,000 cubic feet of natural gas). Of this 39.5 Bcfe, 95% was in Poland and 5% was in the United States. The standardized measure of oil and gas, or SMOG, value, of our proved reserves is approximately $134 million, based on reserve calculations of independent engineers.
Our 2014 oil and gas production was 4.5 Bcfe (12.4 million cubic feet of natural gas equivalent per day, or MMcfed), which was up 2% from 2013 production. Of our 2014 production, 4.2 Bcfe (11.6 MMcfed) of our production was in Poland and 0.3 Bcfe (0.8 MMcfed) was in the United States. All of our production in Poland consisted of natural gas, while all of our U.S. production consisted of crude oil.
Our oil and gas revenues for 2014 were $34.3 million, which is an increase of 3% compared to revenues for the preceding fiscal year. We currently expect that our 2015 production will be slightly higher than our 2014 production rates with a full year of production at our Lisewo-2 well.
Substantially all of our growth in reserves and production in recent years has come from our operations in Poland. We expect this will continue, as most of our technical efforts and capital budget are devoted to these operations. We believe that these operations represent the most favorable opportunities for success that are available to us. See “Corporate Strategy” immediately below. With a view to future growth in reserves and production, we now hold 1.8 million gross acres (1.3 million net acres) in Poland and continually review additional acreage acquisition opportunities, as we drop acreage that we believe has less exploration potential.
During 2014 in Poland, we drilled two commercial wells and two dry holes. At December 31, 2014, we had three wells for which we are designing production facilities. One of those wells will begin production in 2016, and two will begin production in 2017.
As of December 31, 2014, we had approximately 54.4 million shares of common stock outstanding, and our market capitalization was approximately $84 million (approximately $93 million as of the date of this filing). Our shares are listed on the NASDAQ Global Select Market under the symbol “FXEN.” So far during 2015, our average daily trading volume has been approximately 555,000 shares. Our total assets as of December 31, 2014, were $78.9 million, and our working capital was $17.1 million. Total net debt per thousand cubic feet equivalent, or Mcfe, of proved reserves was $0.83 at year end.
Most of our current Polish operations are conducted in partnership with PGNiG, a fully integrated oil and gas company that is largely owned by the Treasury of the Republic of Poland. PGNiG is Poland’s principal domestic oil and gas exploration, production, transportation, and distribution entity. Under our existing agreements, PGNiG has provided us with access to exploration opportunities, previously collected exploration data, and technical and operational support. We also use geophysical and drilling services provided by PGNiG, and we sell almost all of our gas production to PGNiG.
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References to “us,” “we,” and “our” in this report include FX Energy, Inc., and our subsidiaries. In addition to our headquarters in Salt Lake City, Utah, we have operations offices in Warsaw, Poland, and Oilmont, Montana.
Corporate Strategy
We believe Poland is a unique international exploration opportunity. Over the last 50 years or so, Western companies have poured billions of dollars into exploration efforts in the British, Dutch, Norwegian, and German sectors of the offshore and onshore North European Permian Basin (generally the North Sea area). For the industry, these efforts have resulted in the discovery of trillions of cubic feet of gas and more than a billion barrels of oil. However, until the last few years of the twentieth century, Poland was closed to exploration by foreign oil and gas companies. To date, the conventional exploration activities conducted in the Polish onshore portion of the Permian Basin are only a fraction of those conducted in the western part of the basin. Consequently, we believe the Polish Permian Basin is underexplored and underexploited and, therefore, has high potential for discovery of significant amounts of oil and gas similar to the North Sea or other mature oil and gas provinces in the United States and elsewhere. As an example, the estimated gross proved recoverable reserves per well associated with the 11 conventional gas discoveries in our core Fences concession in Poland are 11.6 Bcf of gas. The average initial gross production rate for these 11 wells is approximately 4.9 million cubic feet per day, or MMcfd.
Just as important as the reserve and production potential is the fact that Poland is highly dependent upon imported natural gas, which is expensive. There is an attractive and deep market for gas discoveries and production in-country. For example, as of the date of this report the price we receive for natural gas at our Roszkow well, which has a methane content of 80%, is approximately 110% higher than the spot price under natural gas contracts for 100% methane gas traded on the New York Mercantile Exchange, sometimes referred to as the Henry Hub price.
Acting on this combination of facts, we were one of the first independent oil and gas companies to acquire a large land position, to embark on a focused exploration and development program, and as a result, to begin producing hydrocarbons in Poland. After many years of effort in Poland, our exploration efforts are showing progress. Our producing wells in the Fences concession area are now providing cash flow that we can use in our exploration and production efforts throughout the country. Though we cannot assure that future results will be similar, this success has encouraged us to continue to focus our efforts in Poland.
More specifically, we have directed the majority of our available capital, management, and technical resources to our core Fences concession area in Poland. With the success that we have achieved from our Fences drilling program, we now have the opportunity to turn more of our attention to our Edge concession, through both targeted seismic data acquisition and drilling of higher-risk, higher-reward exploration wells, where we believe we have the opportunity to find significant oil and gas reserves.
Outside our core Fences area, we currently hold acreage in other areas of Poland that we consider underexplored and underdeveloped and, therefore, subject to greater exploration risk. With recent significant discoveries in our Edge concession, where we own a 100% interest, we expect to allocate more of our capital budget to this area because we control the pace at which we can develop potentially larger targets as we seek to optimize opportunities for robust revenue growth. To the extent that our overall strategy results in substantial revenue growth, we plan to continue to increase our funding of exploration projects over a wide area in Poland.
Current Activities and Presence in Poland
General
We have historically concentrated our exploration efforts in Poland, primarily on the Rotliegend sandstones of the Permian Basin. We have identified a core area consisting of approximately 853,000 gross acres surrounding the long-producing 390 Bcf Radlin gas field, which was discovered in the 1980s by our joint venture partner PGNiG (we do not own an interest in this field, but see it as a geologic analog). We have emphasized improved seismic data acquisition and processing in our exploration efforts surrounding this field, using technology developed by others for Rotliegend exploration in the Southern North Sea.
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Since 2000, we have made commercially successful discoveries in 11 of the 17 wells we have drilled on Rotliegend structural trap targets in our core Fences concession. In the aggregate, these 11 discoveries found gross estimated recoverable proved reserves of approximately 127 Bcf of gas, with remaining proved gas reserves of over 66 Bcf gross (32 Bcf net to our interest) as of December 31, 2014. We have acquired three-dimensional, or 3-D, seismic data over several hundred square kilometers in the Fences concession and we are acquiring 3-D seismic data over more of that concession. 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. We expect to drill some wells that do not establish production or reserves, just as we have done in the past. Nonetheless, the extensive production history, well data, and seismic data available for the Fences area have contributed to our success rate there. We plan to continue to direct a significant portion of our available funds to carry out a multiyear exploration, appraisal, and development well drilling program in the Fences concession. We anticipate additional drilling in the Fences area during 2015. These operations are the focus of our strategy to increase production and reserves in our core area as capital is available.
Recently, we have begun spending more of our efforts and capital in our Edge concession. Two recent discoveries lead us to believe that the Edge concession has the potential for significant hydrocarbon accumulations. Unlike the Fences, the Edge concession looks to be characterized by carbonate reservoirs, with multiple types of porosity and natural fracturing in the Lower Zechstein and Upper Devonian formations.
Following on the encouragement from Edge exploration, we have dropped much of our other exploration acreage, including our Block 229, 246, and 287 concessions, retaining a small land position at our Warsaw South area in addition to Fences and Edge.
We have assembled a sophisticated technical team of employees and consultants experienced with using modern exploration tools, and have generated a number of attractive oil and gas prospects. To the extent that our overall strategy results in substantial revenue growth, we plan to direct more of our funds to exploration of our early-stage exploration licenses, with a view toward long-term results.
Polish Exploration Rights
As of December 31, 2014, we held oil and gas exploration rights in Poland in a number of separately designated project areas encompassing approximately 1.8 million gross acres. We are currently the operator in all areas, except our 853,000 gross-acre core Fences project area, in which we hold a 49% interest in approximately 808,000 acres and a 24.5% interest in the remaining 45,000 acres. PGNiG is the operator in the Fences project area. We hold interests in approximately 1.3 million net acres throughout Poland.
Exploratory Activities in Poland
Our ongoing activities in Poland are conducted in several project areas: Fences, Edge, and Warsaw South. Our drilling activities have been focused primarily on the core Fences area. We have focused on this core area because substantial gas reserves have already been discovered and developed there, first by PGNiG alone and more recently by PGNiG and us together. We and PGNiG have discovered proved gas reserves of over 127 Bcf gross (56 Bcf net to our interest) in 11 commercial wells in the Fences area as of the date of this report. We believe it is likely there remains substantial additional natural gas in the same geologic horizon in this area.
We plan to continue concentrating a substantial portion of our efforts and resources on the Fences concession, but we are also increasing our efforts in our Edge concession. In the Fences area during 2014, we completed the Karmin-1 well, on trend with our Roszkow and Zaniemysl fields. In our Edge concession, we drilled the commercial Tuchola-4K well. In 2015, we anticipate new drilling in the eastern part of Fences on trend with some of our existing producing wells as capital is available, and we expect to shoot additional seismic data and evaluate new prospects in the Edge concessions, also as capital is available.
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Fences Area
The Fences concession area encompasses 853,000 gross acres (3,450 sq. km.) in western Poland’s Permian Basin. PGNiG gas fields in the Fences area drilled before 2000 are “fenced off” or excluded from our exploration acreage. These fields, discovered by PGNiG between 1974 and 1985, produce from structural traps in the Rotliegend sandstone. We hold a 49% interest in approximately 808,000 acres and a 24.5% interest in the remaining 45,000 acres in the Fences area (407,000 total net acres).
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. 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.
Our Fences wells produce natural gas with a methane content of approximately 80%, which can be delivered directly into a low-methane pipeline system without further processing to remove nitrogen and other impurities.
We are currently producing approximately 11.9 MMcfd net to us from eight of our 11 wells, including the Lisewo-2 well, which started producing in September 2014. The Zaniemysl-3 well stopped production during mid-2013 due to an influx of water. Sidetrack operations in early 2015 at Zaniemysl-3, which were targeting additional gas reserves that appeared to be higher in the Zaniemysl structure than the existing well, were unsuccessful. The oldest of our 11 wells had a very small reservoir and was depleted in 2010. The wells that are currently in production are producing under the required production licenses obtained by PGNiG in its capacity as operator, or under the two years of test production that is permitted under the exploration concession. During 2014, we completed the Karmin-1 well, which should begin production in 2016. Our independent reservoir engineers have assigned proved reserves of 15.5 Bcf to the Karmin-1 well. The next Fences well, Miloslaw-1, will target a new area east of our Winna Gora field.
Edge Concession Area
In 2008, we acquired a 100% interest in four concessions in north-central Poland covering approximately 726,000 acres (3,567 sq. km.). Having reprocessed existing two dimensional, or 2-D, seismic data, we identified a number of leads, including several Permian age Zechstein and Devonian targets. We acquired additional 2-D and 3-D seismic data in 2011 and 2012 and successfully drilled the Tuchola-3K and Tuchola-4K wells to test both Zechstein and Devonian targets. Unlike our Fences wells, gas from our Tuchola wells have a methane content of approximately 57% and will require additional processing to remove nitrogen and other impurities before the gas can enter the pipeline system. Our independent reservoir engineers have assigned proved reserves of 5.7 Bcf to the two wells, which represents the net sales volume that will be delivered to the pipeline. Total volumes from the two wells are estimated to be approximately 10 Bcf of high methane sales gas.
During 2014, our Angowice well in the Edge concession was a dry hole. We are shooting and interpreting new 3-D seismic data in the Edge area. Additional drilling in this area is pending the identification of new leads and capital availability.
Warsaw South Concession Area
We hold a 51% interest in a total of 236,000 acres (955 sq. km.) in east-central Poland. During 2011, we entered into a farmout agreement with PGNiG under which it earned a 49% interest in the entire Warsaw South concession in return for paying certain seismic and drilling costs. The Warsaw South concession has a number of exploration leads, including carboniferous sands and shales with structural or truncation trapping, and possibly Zechstein reefs trapped by overlying evaporites and salt. We believe this area has good potential for gas and condensate production, but there are few existing wells and relatively little seismic data. Nonetheless, we plan to continue our exploration efforts. In 2012 and in 2014, we elected to drop certain concessions within this area that we deemed less prospective for hydrocarbon potential, while acquiring additional new seismic data on our remaining block. We are continuing to evaluate this area.
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Additional Concession Acreage
We may apply for more concession blocks in Poland in 2015. If we acquire more concession blocks, we will allocate modest technical and financial resources to these areas during 2015, primarily in the form of data collection and seismic reprocessing, with a view to ascertaining relative hydrocarbon potential and exploration risk.
Key Personnel for Poland
Jerzy Maciolek is a director of the Company and heads our exploration team as Vice President of International Exploration. He joined us in 1995 specifically to lead us into Poland, where he had identified the exploration opportunity that today is our principal asset. Before joining us, Mr. Maciolek had over 25 years of experience as a geophysicist with PGNiG and Gulf Oil Research, and as an independent consultant. He received an MS in exploration geophysics from the Mining and Metallurgical Academy in Krakow, Poland.
Our Country Manager in Poland is Zbigniew Tatys, the former General Director of PGNiG’s Upstream Exploration and Production Division. During his 20-year career with PGNiG, he rose through the ranks as a production engineer and was serving as Vice Chairman of PGNiG at the time of his retirement. Mr. Tatys has unique qualifications to lead us through our transition from a pure exploration company to a natural gas and oil producer in Poland.
Our chief technical advisor to the independent directors is Richard Hardman, CBE. Mr. Hardman has built a career in international exploration over the past 50 years in the upstream oil and gas industry as a geologist in Libya, Kuwait, Colombia, and Norway. In the United Kingdom, his career encompasses almost the whole of the exploration history of the North Sea – 1969 to the present. With Amerada Hess from 1983 to 2002 as Exploration Director and later as Vice President of Exploration, he was responsible for key Amerada Hess North Sea and international discoveries, including the Valhall, Scott, and South Arne fields. Mr. Hardman was made Commander of the British Empire in the New Year Honours, 1998, and has served as the Chairman of the Petroleum Society of Great Britain, President of the Geological Society of London, and President of the European Region of American Association of Petroleum Geologists Europe.
Our U.S. Activities and Presence
Unlike our position in Poland, our U.S. operations have not been a focus of our exploration efforts. Our U.S. operations provide a modest amount of cash flow and are not capital intensive. They consist mostly of shallow, waterflood oil-producing wells in the Southwest Cut Bank Sand Unit of Montana. As of December 31, 2014, our U.S. reserves (all of which were proved reserves) were estimated at 357,000 Bbls of crude oil with a SMOG Value of approximately $4.6 million. At year-end 2014, our U.S. reserves were approximately 5% of total proved reserves on a gas equivalent basis. Our oil wells produce approximately 128 Bbls of oil per day, net to our interest. We produce oil from approximately 10,732 gross (10,418 net) acres in Montana and 400 gross (128 net) acres in Nevada.
From our field office in Montana, we also provide oilfield services, which provided approximately $3.8 million in revenue during 2014.
Insurance
We carry third-party liability and property and casualty insurance for our activities and facilities in Poland, but we do not plan to purchase control-of-well insurance on wells we drill in the Fences project area. We may elect to purchase such insurance on wells drilled in other areas in Poland, which we did for our 100%-owned Tuchola-3K well. We rely on the financial responsibility of PGNiG as operator of the wells in which we jointly participate in the Fences project area, as it has control-of-well insurance coverage for those wells.
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In the United States, we maintain general liability insurance with limits of $1.0 million per event with a $2.0 million annual aggregate limit. In addition, we carry an umbrella excess liability policy with a $10.0 million general total limit. There is a $1,000 per claim deductible for our property damage liability and a $10,000 deductible for our commercial umbrella liability insurance. Our general liability insurance covers us for, among other things, covered legal and contractual liabilities arising out of property damage and bodily injury, but not for pollution liability. Our commercial umbrella excess liability insurance is in addition to our general liability insurance policy and is triggered if the general liability insurance policy limits are exceeded. The commercial umbrella excess policy may be broader than the general liability policy, and umbrella excess coverage can also be triggered when coverage is available under the umbrella excess policy, but not the general liability policy. In this case, the $10,000 deductible will apply.
Our insurance policies may not cover costs and expenses related to government-mandated cleanup of pollution, or fines, penalties, or other sanctions resulting from any civil enforcement or criminal proceedings. In addition, these policies do not provide coverage for all liabilities and, in particular, do not provide coverage for losses arising out of hydraulic fracturing operations. We cannot assure that our insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash flows.
Employees and Consultants
As of December 31, 2014, we had 55 employees, consisting of nine in Salt Lake City, Utah; 21 in Oilmont, Montana; one in Greenwich, Connecticut; two in Houston, Texas; and 22 in Poland. Our employees are not represented by a collective bargaining organization. We consider our relationship with our employees to be good. We also regularly engage technical consultants to provide specific geological, geophysical, and other professional services. Our executive officers and other management employees regularly travel to Poland to supervise activities conducted by our staff and others under contract on our behalf.
Offices and Facilities
Our corporate offices, located at 3006 Highland Drive, Salt Lake City, Utah, contain approximately 3,700 square feet and are rented at $3,400 per month under a month-to-month agreement. In Montana, we own a 16,000-square-foot building located at the corner of Central and Main in Oilmont. We also have an office in Warsaw, Poland, located at ul. Chalubinskiego 8, where we rent about 6,900 square feet for approximately 35,000 PLN ($10,000 at the December 31, 2014, exchange rate) per month and in Krakow, Poland, located at ul. Smolensk 21/15, where we rent approximately 215 square feet for approximately 1,500 PLN ($428) per month.
Segment Information
Further information concerning our financial and geographic segments can be found in the notes to the consolidated financial statements included in this report.
Available Information
We make available 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, as well as the proxy statement related to our annual stockholder meeting, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after we file such material with, or furnish it to, the Securities and Exchange Commission. We also make these materials available, free of charge, by contacting our main office in Salt Lake City, Utah at (801) 486-5555. Information on our website is not incorporated by reference in this report.
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ITEM 1A. RISK FACTORS
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Our business is subject to a number of material risks, including the following factors related directly and indirectly to our business activities in Poland and the United States.
Risks Relating to our Business
Our Senior Secured Credit Facility
The amount we can borrow under our Senior Secured Credit Facility is affected by currency exchange-rate fluctuations and gas prices, which affect our dollar-denominated cash flows and reserve values in Poland.
The amount that we can borrow under our up to $100 Million Senior Reserve Base Lending Facility Agreement (“Senior Secured Credit Facility”) is based on our lenders’ evaluation of our reserves, and the expected future cash flow from those reserves, denominated in U.S. dollars. At December 31, 2013, a dollar was convertible into 3.01 Polish zlotys, while at December 31, 2014, the dollar was convertible into 3.51 zlotys, which is a 17% improvement in the value of the dollar relative to the zloty. As a result, the dollar value of the gas we sold declined by the same percentage. The increase in the value of the dollar relative to the zloty is continuing into 2015 and may continue in the future. These changes are outside our influence or control. An increase in the value of the dollar as compared to the zloty may have a proportionately larger impact on our borrowing base because of the resulting reduction in the value of our reserves and estimated future cash flows from production.
We may be unable to meet the reserve and future cash flow criteria to support the borrowing base of our current and/or a revised and amended credit facility.
Under the terms of our Senior Secured Credit Facility, and any amendment thereto, we are required to maintain minimum amounts of dollar-denominated reserves and estimated future net cash flows in order to maintain a specified borrowing base, which is redetermined every six months. If we fail to maintain such minimums, we will be required to reduce the borrowing base and pay down the principal balance if our outstanding borrowing exceeds the redetermined borrowing base, so that our reserves and cash flows provide adequate security to the lenders. We will need to increase reserves and estimated future cash flows in order to increase the amount we are able to draw down under our Senior Secured Credit Facility. We cannot assure that we will be able to maintain existing or increase borrowings from our lenders.
We may not be able to complete an amendment to our Senior Secured Credit Facility.
We are discussing with our lenders an amendment and restatement of our Senior Secured Credit Facility, which we hope to complete during the second quarter of 2015. Our efforts to complete this new arrangement may be adversely affected by further increases in the value of the dollar relative to the zloty, decreases in Polish gas prices, and further economic and political instability in the region. If we are unable to finalize our preliminary understanding or reach another extension agreement, we would likely be required to make principal payments in 2015 resulting from future borrowing base redeterminations, which would be sooner than the scheduled commitment reductions outlined in our Senior Secured Credit Facility.
If our borrowing base drops below our loan balance at any time, we would be required to reduce the principal, which may exceed our liquid resources.
In the event of our default under the Senior Secured Credit Facility, the lenders would be entitled to exercise their full remedies, including taking possession of our Poland producing properties encumbered as collateral for the loan and seek collection from us.
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Our 2015 Capital Budget
We have curtailed our capital budget for 2015, as compared to previous years, in recognition of the potential negative impact on our dollar-denominated Senior Secured Credit Facility borrowing base resulting from negative reserve revisions, exchange-rate fluctuations, and gas-price declines.
Our 2015 budget is expected to be much lower than the actual capital expenditures of approximately $50 million in 2014 and $36 million in 2013. The reduction in our capital budget is due to the potential shortages of available funds resulting from negative reserve revisions, exchange-rate changes and the decline in gas prices in Poland, which may reduce our ability to borrow under our Senior Secured Credit Facility based on dollar-denominated proved reserves and estimated future net revenue from production. We may not be able to resume capital expenditures for exploration and development at our prior levels until the zloty exchange rate and gas prices improve sufficiently to warrant further borrowings, unless we obtain the benefit of capital provided by others through a farm out of an interest in the Edge, or until we obtain external significant capital from other sources. We cannot assure that we will able to obtain capital needed for our capital expenditures.
We may not be successful in farming out our Edge project in order to obtain third-party financial participation in further exploration, production facility construction, and other activities in that concession.
In order to diversify our exploration and financial risk and supplement our capital resources, we are seeking to farm out some of our 100% interest in the Edge concession under a typical industry arrangement in which another firm would provide agreed funding in order to earn an interest in the project. We cannot assure that we will be able to complete such an arrangement. In the absence of a farmout or other funding from external sources, or the successful amendment of our Senior Secured Credit Facility, our exploration of the Edge will be curtailed, and we will have to delay construction of the Tuchola pipeline and related production facilities in the Edge. Currently we have allocated funds only for seismic work and for designing and permitting the Tuchola pipeline and production facility in 2015.
We face increased exploration and financial risk in the Edge concession.
As we allocate more capital to the Edge, where we have drilled a total of three wells, two of which are commercial, we are entering a much less-explored area in which we have substantially less historical geological and geophysical data than the Fences. Further, since we are a 100% owner and operator in the Edge as compared to our 49% position in the Fences, we will bear all of the financial burden and risk of Edge exploration. Development and resulting financial risks are also increased in the Edge because it does not have a network of gas pipelines like the Fences. Therefore, we will have to incur substantial capital costs, and may incur delays, to build production facilities and pipelines in order to sell the gas we discover. For example, in the case of our Tuchola discoveries, with proved reserves as of December 31, 2014, of approximately 5.7 Bcf, we estimate that we may need to spend $25 million additionally to deliver the gas for sale, depending on the capacity, route, desired destination, and other specifications of the facilities. We cannot assure that these costs can be recovered from production.
Our current planned level of reduced capital expenditures for 2015 may impact our relationship with PGNiG, our partner in Poland that controls our exploration and development activities in Poland in the Fences.
As in previous years, PGNiG will propose exploration and development activities for 2015 and beyond based on its expectation of our participation in these activities by bearing our share of project costs and providing technical and management resources. Our limited exploration budget for 2015 may require PGNiG to alter its plans, may jeopardize our working relationship with PGNiG, and may impair our ability to work together in further exploring and developing the Fences. Under our agreements with PGNiG, it has the right to undertake proposed joint activities for its own, sole account and pay all related costs. If we elect not to participate, we would forfeit our interest in such specific activities. Accordingly, we may lose the opportunity to participate fully in significant new discoveries in the Fences. Any failure to provide funding for operations that PGNiG proposes in the Fences could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
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In the Fences, we rely on the funding, operating initiative, and expertise provided by our partner, PGNiG, the operator of the Fences area.
PGNiG, our partner in our Fences area, holds the majority interest and is operator of this area where our principal production and reserves are located. As a paying partner, we rely to a significant extent on the financial capabilities of PGNiG, which bears a share of the costs of many Fences projects as a joint owner. PGNiG’s failure to perform its obligations under contracts with us would most likely have a material adverse effect on our business, financial condition, results of operations, and cash flows. In particular, we have prepared our exploration budget through 2015 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 these activities, which might slow the pace at which we would like to advance our exploration and development efforts. Similarly, as operator, PGNiG controls the level of production as well as other day-to-day operating details. Our ability to conduct certain activities may be affected by whether PGNiG classifies such activities as exploratory or development because of different internal budgetary considerations. Our program in Poland involving PGNiG-controlled acreage would be adversely affected if PGNiG should elect not to pursue activities on this acreage, if our relationship with PGNiG should deteriorate or terminate, or if PGNiG or the governmental agencies should fail to fulfill the requirements of, or elect to terminate, our agreements, licenses, or grants.
Exploration and Development
We cannot assure that the exploration models we are using in Poland will lead to finding gas or oil in Poland.
We cannot assure that the exploration models we or PGNiG develop will provide a useful or effective guide for our exploration or development activities, including selecting exploration prospects and drilling targets, particularly in the Edge, where we have substantially less geological and geophysical data than was the case in the Fences. In the Edge, where PGNiG has no interest, we do not have access to its exploration knowledge and experience. We continually review and revise or replace these exploration models as a guide to further exploration based on new data, including drilling results and interpretations. These exploration models are typically based on incomplete or unconfirmed data and theories that have not been fully tested. The seismic data, other technologies, and the study of producing fields in the area do not enable us to know conclusively prior to drilling that gas or oil will be present in commercial quantities, even for development wells. The fact that some prospects may appear to have similar geological or geophysical subsurface features or may be located near previous wells cannot assure that such prospects are actually similar or that drilling results will be comparable. Every prospect is unique and must be evaluated individually. We cannot assure that the analogies that we draw from available data from other wells, fully explored prospects, or producing fields will be applicable to our drilling prospects or will enable us to forecast accurately drilling results.
Our 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 2015 from 2014 levels as previously drilled wells are placed into production, and that we will generate revenues in excess of direct lease operating costs as well as anticipated general and administrative costs. However, these revenues will not be sufficient to cover exploration and development costs at previous levels. We have reduced our planned 2015 exploration and development expenditures as compared to recent years in Poland because of potential shortages of available capital. Accordingly, we will continue to rely on existing working capital; borrowings under our current Senior Secured Credit Facility secured by future production from our reserves, to the extent that borrowings are available under bank borrowing base calculations; additional funds obtained from the sale of equity securities; other external sources; and industry partners to cover these costs. If we are unable to obtain the funds that we seek from these sources for our exploration and development plans, we may be required to further reduce our capital expenditures. Any reduction in exploration expenditures will have a long-term negative impact on future reserves and revenues.
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Our statements respecting the quantities of potential gas or oil accumulation that we estimate for management purposes should not be converted into reserves.
For purposes of management decisions and risk analysis, we use a variety of geological, engineering, and geophysical techniques to estimate probable or possible reserves and gross, unrisked resource potential. These various methods are important in making many kinds of management decisions during the exploration, development, and production process, but the quantities and values estimated through these methods are not comparable. We cannot assure that any gas or oil quantities or values that we estimate through alternative methods will ever be converted through additional exploration and production into reserves.
Our estimates of proved oil and gas reserves and future net revenues are subject to various risks and uncertainties.
Our estimates of oil and gas reserves and estimated future revenues, calculated by independent, third-party engineering firms, are based on various assumptions and estimates and are very complex and interpretative, as there are numerous uncertainties inherent in estimating quantities and values of proved reserves, projecting future sales of production, and the timing and amount of development expenditures. Many of these factors are beyond our control. Our proved reserve estimates are subject to continuing revisions as additional information becomes available or assumptions change. Although they rely in part on objective information, engineering evaluations of oil and gas reservoirs are essentially subjective processes of estimating the size, characteristics, and recoverability of underground accumulations of oil and gas that cannot be measured exactly. The actual production and future net revenues that we obtain from our oil and gas properties may vary substantially from those estimated, due to the factors and assumptions that have been used in completing these estimates, including:
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our data regarding 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 royalties and other 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, pricing discounts or adjustments, and similar items;
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market prices and demand for the oil and gas we produce;
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exchange rates for the conversion of zlotys to dollars; and
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oil and gas quality and impurities that reduce the sales prices we actually receive below the posted or contract price.
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In accordance with Securities and Exchange Commission’s rules for estimating oil and gas reserves, we use deterministic methods to determine proved reserves, based on 12-month average prices and currency exchange rates. Accordingly, reserve values may vary significantly on exchange-rate and price fluctuations unrelated to actual oil or gas quantities. The estimates of economically recoverable quantities of oil and gas attributable to any particular property, the classifications of those reserves based on risk or probability of recovery, and estimates of the future net cash flows expected from such properties prepared by different engineers or by the same engineers but at different times or with different assumptions may vary substantially. Therefore, reserve estimates may be subject to upward or downward adjustments, and actual production, revenue, and related expenditures are likely to vary, in some cases materially, from estimates.
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We cannot accurately predict the size of exploration targets or foresee related risks.
Notwithstanding the accumulation and study of 2-D and 3-D seismic data, drilling logs, drill-stem tests, production information from established fields, and other engineering, geological, and geophysical data, we cannot predict accurately the gas or oil potential of individual prospects and drilling targets or the related risks. We sometimes estimate the gross potential or possible reserves of gas or oil in a particular area as part of our evaluation of the exploration potential and related risks. Our estimates are only rough, preliminary geological forecasts of the volume and characteristics of possible reservoirs and the calculated potential gas or oil that could be contained if present and are unqualified by any risk evaluation. These forecasts are not an assurance that our exploration will be successful or that we will be able to establish reserves equal to such forecasts. In some cases, our estimates of possible reserves or oil and gas potential may be based on a review of data from other exploration or producing fields in the area that ultimately may be found not to be analogous to our exploration prospects. We may require several test wells and long-term analysis of test data and history of production to determine the gas or oil potential of individual prospects.
We may continue to have exploration failures in Poland.
From 1995 through early 2015, we have participated in drilling or recompleting 49 exploratory wells in Poland, including 16 commercial discoveries, and 33 noncommercial wells. We expect that we will continue to drill noncommercial wells in the future. Of our 16 commercial successes in Poland, as of the date of this report we were producing gas at eight wells, all of which are located in our Fences concession. Production from three other commercial discoveries is scheduled to begin in 2016 and 2017 once requisite permits are obtained and production facilities are constructed. During 2014, we sold our three producing wells that were located in our Block 287 concession. Three early wells have been fully exploited and no longer produce.
We may not achieve the results anticipated in placing our current or future discoveries into production.
We currently estimate that it may take approximately two years or more to place a completed gas well on line so that we can commence production and sell gas from the well. We may encounter delays in commencing the production and sale of gas in Poland from our recent gas discoveries and other possible future discoveries. We may face delays in obtaining rights-of-way to connect to the PGNiG pipeline system, construction permits, and materials and contractors; signing gas or oil purchase/sales contracts; negotiating price and payment details; receiving commitments for required capital expenditures by PGNiG; and managing other factors. These delays could correspondingly postpone the commencement of cash flow and may require us to increase our reliance on borrowings under our Senior Secured Credit Facility pending commencement of production. Further, we may design and construct surface and pipeline facilities to accommodate anticipated production from future wells, but we cannot assure that any future wells will establish additional reserves or production that will provide an economic return for expenditures for those facilities. We may have to change our anticipated expenditures if costs of placing a particular discovery into production are higher, if the actual production is smaller than projected, or if the commencement of production takes longer than expected. Further, producing wells for which PGNiG acts as the operator generally are produced at levels that are established by and acceptable to it, which may be lower as compared to the productive capacity of similar wells in the United States.
We may not fulfill our work commitments on the concessions we hold in Poland.
We are subject to certain exploration concession work commitments that must be satisfied in order to maintain our interest in those concessions. Our exploration budget and related activities may not be focused specifically or primarily on meeting these work commitments. We may not be able to retain any concession rights on areas for which we do not timely complete required work commitments. We cannot assure that we will be granted any requested changes to usufruct and concession agreements that either modify the obligations to reduce our commitments or extend the terms of those agreements. We may lose our rights to exploration acreage if we cannot obtain required changes or extensions.
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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, Executive Vice President; Andrew W. Pierce, Vice President-Operations; Jerzy B. Maciolek, Vice President-Exploration; Zbigniew Tatys, Poland Country Manager, and Richard Hardman, Technical Advisor to our board. The loss of the services of any of these individuals may disrupt our activities as we seek a replacement. Although we have entered into employment agreements with our key executives, we may not be able to retain such key executives. We do not maintain key-man insurance on any of our employees.
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 areas. We may purchase such insurance on Company-operated wells drilled in the Edge or other areas in Poland. 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 the 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, there are limitations on existing insurance coverage, or as a result of other factors. For example, we do not maintain insurance against risks related to violations of environmental laws or damages resulting from hydraulic fracturing. We would be negatively affected by a significant adverse event that is not fully covered by insurance.
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 major oil and gas exploration and production companies.
Our Operating Losses
We have a history of operating net losses and may require additional capital in the future to fund our operations.
From our inception in January 1989 through December 31, 2014, we have incurred cumulative net losses of approximately $258 million. Our exploration and production activities may continue to result in net losses through 2015 and possibly beyond, depending on whether our activities in Poland and the United States are successful and result in sufficient revenues to cover related operating expenses.
Until sufficient cash flow from operations can be obtained, we expect we will need additional capital to fully fund our ongoing planned exploration, appraisal, development, and property maintenance and acquisition programs in Poland. In addition to our long-term project financing, we may seek required funds from the issuance of additional debt, equity, or hybrid securities; project financing; strategic alliances; or other arrangements. Obtaining additional financing may dilute the interest of our existing stockholders or our interest in the specific project being financed. We cannot assure that additional funds could be obtained or, if obtained, would be on terms favorable to us. In addition to planned activities in Poland and the United States, we may require additional funds for general corporate purposes.
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We may incur additional noncash losses due to exchange-rate fluctuations.
Continuing fluctuations in the rates at which U.S. dollars are exchanged into Polish zlotys may result in ongoing noncash exchange-rate losses. As the dollar strengthens relative to the zloty, our dollar-denominated revenue received in zlotys declines; conversely, when the dollar weakens relative to the zloty, our dollar-denominated revenue received in zlotys increases. Should exchange rates in effect during early 2015 continue throughout the year, we expect the exchange rates to have a negative impact on our dollar-denominated revenues in 2015 compared to 2014, with a corresponding decrease in the dollar cost of our capital expenditures in Poland. Applicable exchange rates may be adversely affected by continuing European economic stagnation, the consequences within the European Union of recent political changes in Greece, the collateral consequences of Russia’s weakening economy and regional political and economic repercussions from its actions in Ukraine and elsewhere, the fallout from related economic sanctions on Russia and its actual or potential reaction, and other factors.
Gas Prices and Marketing
The price we receive for gas in Poland is currently partially determined based on trailing Russian prices and, as a consequence of lower oil prices, may decrease in the future.
As in previous years, the prices at which we sell gas in Poland to PGNiG are determined pursuant to published tariffs for gas sold to wholesale consumers. These tariffs are determined, in part, by reference to the cost of Russian imported gas, the price of which, in turn, is based in part on trailing oil prices. The trailing impact of lower oil prices may have a depressive effect on such tariffs and so may reduce the price that we receive for our gas from PGNiG. Conversely, because the tariffs are determined in part by trailing prices, increases in oil prices may result in higher tariffs for the gas we sell in Poland. Changes in the mechanism for determining the applicable tariff may also result in lower prices for gas that we may sell.
Changes in Polish gas markets and pricing may have an adverse impact on our operations.
Market influences are shifting gas prices away from indexing to oil prices, with about half of the gas consumed in Western Europe no longer indexed to oil. In addition, the European Union is pressuring Poland to eliminate tariffs and move toward market pricing. Poland has started trading gas on its commodity exchange, but prices are not considered representative because transactions are dominated by sales from PGNiG to its wholly owned retail trading subsidiary. Imports into Poland from Germany at market prices have reduced PGNiG’s pricing domination. As a result of the foregoing factors, we believe that Poland’s reliance on tariff pricing may decline and that Poland’s gas prices may increasingly be influenced by world gas prices, which in turn may be influenced by Russia’s export policies; the availability to Western Europe of liquefied natural gas (LNG); Asian demand; U.S. gas production; European economic performance; and European Union strategies to move to uniform, market-driven carbon content pricing across various fuels and limit reliance on coal. We cannot predict the effect these changes in Poland’s gas marketing landscape will have on the prices we receive for the gas that we produce in Poland.
All of our natural gas currently produced in Poland is sold to a single purchaser, PGNiG, or its affiliates.
We currently sell all of the natural gas we produce in Poland to PGNiG or one of its affiliates. If PGNiG were to fail to perform its obligations under contracts with us, it would most likely have a material adverse effect on us. The market for the sale of gas in Poland is open to competition, but there are not yet many market participants. While our contracts provide us with the ability to market gas to other purchasers, including those outside of Poland, we do not expect to diversify our gas purchasers in the foreseeable future for production located in our Fences project area.
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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 markets locally and in Russia, on which Polish gas tariffs are currently based;
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changes in the mechanism for determining the applicable tariff for pricing gas;
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changes in the supply of and demand for oil and gas as the European Union seeks to limit reliance on buying Russian gas;
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market uncertainty;
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the opening of a new natural gas exchange in Poland;
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Russia’s gas export policies;
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the impact of potential climate change on oil and gas demand and prices;
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the availability to Western Europe of liquefied natural gas (LNG);
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Asian demand;
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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, alternative energy, and other energy sources, as the European Union moves toward uniform, market-driven carbon content pricing across various fuels;
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the availability, proximity, and capacity of gathering systems, pipelines, and processing facilities;
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the processing and refining 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.
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We have not entered into any agreements, including hedging arrangements, to protect us from price fluctuations and may or may not do so in the future.
The effects of global climate change could adversely impact the market demand for oil and gas products and negatively impact our business.
The value of our oil and gas exploration, development, and production activities is and will continue to be a function of the market demand for oil and gas products. If global climate change results in rising average global temperatures, the market demand for oil and gas products used in residential and commercial heating fuels may decrease. This could result in a decrease in demand for oil and gas products and negatively impact our business.
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Concerns regarding global climate change could spur legislation or regulation, globalized through treaties or otherwise, that could diminish global demand for oil and gas products and negatively impact our business.
Our oil and gas exploration, development, and production activities in Poland are subject to Poland’s laws and regulations, some of which are designed to meet the requirements of the European Union. Future legislation and regulation could be a part of globalized efforts similar to the Kyoto Protocol, regional systems such as the European Union Emissions Trading Scheme, or other campaigns in response to concerns regarding global climate change. These 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.
Regulatory Contingencies
We spent a total of $321,000 in prior years for oil leak cleanup costs and may incur additional significant costs related to this or other environmental matters.
Following a June 2011 oil leak at our Southwest Cut Bank Sand Unit in Montana, we spent approximately $321,000 in completing cleanup, mitigation, and restoration pursuant to an approved plan in cooperation with the Blackfeet Tribe and the United States Environmental Protection Agency, commonly referred to as the EPA. We cannot assure that the satisfactory completion of the cleanup according to the specifications provided by the Blackfeet Tribe and the EPA will not result in additional costs or civil or criminal sanctions. Investigation into the 2011 Southwest Cut Bank Sand Unit incident continues, and we cannot predict whether authorities may initiate criminal or other proceedings against us or our personnel, exposing us or our employees to penalties. 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.
We may incur significant litigation or settlement costs as a result of actual or threatened litigation that could have an adverse effect on our business.
From time to time we may be a defendant in various lawsuits, including civil or criminal proceedings based on environmental claims. The nature of our operations exposes us to further possible threats of litigation or actual litigation claims in the future. When we or our personnel are threatened with civil ligation or criminal charges, we may seek early resolution through settlement and may agree to payments or sanctions greater than might be determined after trial. Further, we may agree to sanctions informally in order to avoid further proceedings or more significant charges. Finally, we may assume Company responsibility to keep our personnel from individual liability or charges for activities undertaken by them on our behalf and for which they may be entitled to indemnification. There is risk that any civil or criminal litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation and cause collateral consequences we do not foresee.
Compliance with environmental requirements may not be offset by our limited oil production revenue in Montana.
We have limited oil production in Montana, so substantial environmental compliance, mitigation, and reclamation costs may not be offset by revenue from ongoing production from the wells or facilities involved in any incident or even the entire field. Accordingly, environmental costs expose our entire Montana operations, and the subsidiary through which these operations are conducted, to risk. As an owner or lessee and operator of oil and gas properties in the United States, we are subject to various federal, tribal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations, subject the lessee to liability for pollution damages, require suspension or cessation of operations in affected areas, and expose us to civil and criminal sanctions or fines, with attendant negative publicity.
19
Our U.S. operations are subject to governmental risks that may impact our operations.
Our U.S. operations have been, and at times in the future may be, affected by political developments and by federal, state, tribal, and local laws and regulations such as restrictions on production; changes in taxes, royalties, and other amounts payable to governments or governmental agencies; price or gathering rate controls; and environmental protection laws and regulations. New political developments, laws, and regulations may adversely impact our results on operations.
Polish legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to explore and produce from our properties.
We may use hydraulic fracturing in vertical and horizontal wells in Poland to enhance oil and natural gas production. Hydraulic fracturing is a process that involves injecting water, sand, and chemicals into the foundation under high pressure to fracture the surrounding rock to stimulate production.
Recent changes in Poland’s regulations require us to apply for and obtain a permit before fracturing any well and impose reporting and disclosure obligations regarding hydraulic fracturing activities, which could cause operational delays, increase operating costs, and add regulatory burdens on our exploration and production activities. This could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced and booked as reserves in the future, delayed exploration and development, and increased costs of compliance and doing business. Such consequences could limit the potential upside of any activities we undertake in Poland.
The demand for hydraulic fracturing expertise and equipment may make it difficult for us to complete any hydraulic fracturing we might plan.
Oil and gas exploration firms in Poland have expanded their use of hydraulic fracturing, and the resulting demand on the availability of third parties with fracturing expertise and equipment, particularly in Poland, may make it difficult for us to complete planned fracturing activities within estimated schedules or budgets.
Our activities may be directly or indirectly adversely affected by unauthorized invasion of our data processing and communications systems.
We are dependent on a number of computerized data storage and processing and communications systems to operate our business and interconnect our activities in Poland and Montana with our principal executive offices in Utah. We use these systems to gather and store raw exploration, development, and production data; interpret geophysical and geological data as part of our exploration and development activities; model the resource potential and reserves or project areas; forecast production; administer contracts with third parties; gather and report financial and other data to our stockholders and regulatory authorities; and complete other critical functions throughout the company. Our vendors and suppliers also rely on similar systems in conducting their own businesses. Our reliance, like others in the industry, on these technologies makes us increasingly vulnerable to risks of technological failures resulting from others gaining unauthorized access, intentional and unintentional cyber incidents, network failures, breaches of security, and similar events that could result in the unauthorized release, gathering, monitoring, misuse, loss, destruction of proprietary and other information, including the release of such information to competitors, or other damaging disruption of our activities. We cannot assure that the measures we implement to protect against these kinds of cyber risks will be successful or that our operations will not be adversely affected by cyber events. We expect that the financial and managerial resources that we devote to protective measures or to remediate breaches will increase.
20
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. We cannot predict the full impact on our operations of significant amendments in 2014 to governing laws respecting environmental compliance, the concessions system, and other matters. Additionally, if significant quantities of gas are produced with oil, regulations prohibiting the flaring of gas may inhibit oil production. In these 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 these 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.
Risks Relating to Conducting Business in Poland
Poland is indirectly affected by economic and political changes in Russia, which is Poland’s neighbor to the east.
Russia is currently experiencing economic and political changes resulting from reduced world prices for oil, a principal export; an overall stressed economy; political fallout from its actions in Ukraine, including Crimea; Western European and U.S. economic sanctions against Russia and Russia’s reactions to those sanctions; and other factors. Russia currently exports substantial quantities of gas to Poland and Western Europe at prices Russia establishes. These imports influence gas prices in those areas. Any interruption or long-term curtailment of Russian gas exports could create pressure to increase short-term gas prices in Poland and Western Europe, but may have adverse long-term impacts on the economies of Poland and Western Europe, which could adversely affect our activities in Poland.
A substantial amount of our revenues is attributable to our operations in Poland.
Any disruption in production, development, or our ability to produce and sell oil and gas 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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●
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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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the potential adoption of an entirely new regulatory regime for the exploration, development, extraction, and taxation of all natural resources, including oil and gas;
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21
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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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●
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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.
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Our operations are concentrated in Poland such that any impediment to these operations would have a material adverse effect on our business, financial condition, and results of operations.
Poland has a developing regulatory regime, regulatory policies, and interpretations.
Poland has a regulatory regime governing exploration and development, production, marketing, transportation, and storage of oil and gas. These provisions were promulgated during the past two decades and are relatively untested. Therefore, there is little or no administrative or enforcement history or established practice that can aid us in evaluating how the regulatory regime will affect our operations. It is possible those governmental policies will change or that new laws and regulations, administrative practices or policies, or interpretations of existing laws and regulations will materially and adversely affect our activities in Poland. For example, many of Poland’s laws, policies, and procedures were changed to conform to the requirements that had to be met before Poland was admitted as a full member of the European Union. Further, since the history and practice of industry regulation is sparse, our activities may be particularly vulnerable to the decisions and positions of individuals, who may change, be subject to external pressures, or administer policies inconsistently. Internal bureaucratic politics may have unpredictable and negative consequences.
Privatization or nationalization of PGNiG could affect our relationship and future opportunities in Poland.
Our activities in Poland have benefited from our relationship with PGNiG, which has provided us with exploration acreage, seismic data, expertise, and production data under our agreements. The Polish government commenced the privatization of PGNiG by selling PGNiG’s refining assets in the mid-90s and by successfully completing an initial public offering of approximately 15% of its stock. Recently, PGNiG has announced plans to privatize its service affiliates, including the geophysical and drilling companies that we regularly engage. Complete privatization or a re-nationalization of PGNiG may result in new policies, strategies, or ownership that could adversely affect our existing relationship and agreements, as well as the availability of opportunities with PGNiG in the future.
22
We are dependent on PGNiG to accurately account for expenditures on our behalf and for which we are responsible.
Many of our activities in Poland are undertaken in collaboration with PGNiG, which frequently owns a majority of the interest in the project and acts as operator under our agreements. As operator, PGNiG incurs costs for agreed activities, such as gathering seismic data, drilling and completing wells, constructing production facilities, and other costs, and we are obligated to advance or reimburse our share of these costs. We have limited rights to audit or otherwise examine the records of reimbursable expenditures on our behalf. The limitation on our rights and our inability to undertake audits to determine compliance with our agreements may expose us to overcharges or other irregularities.
Certain risks of loss arise from our need to conduct transactions in foreign currency.
The amounts in our agreements relating to our activities in Poland are sometimes expressed and payable in U.S. dollars and sometimes in Polish zlotys. In the future, our financial results and cash flows in Poland may be affected by fluctuations in exchange rates between the zloty and the dollar for dollar-denominated agreements. Other currencies used by us may not be convertible at satisfactory rates. In addition, the official conversion rates between U.S. and Polish currencies may not accurately reflect the relative value of goods and services available or required in Poland. Further, inflation may lead to the devaluation of the Polish zloty.
The ongoing European sovereign debt crises and collateral financial issues may adversely affect our ability to borrow money.
Our Senior Secured Credit Facility is financed with two European banks. Although both lending banks in our credit facility recently successfully passed required European bank stress tests, there is no guarantee that they will maintain their required capital and other ratios, and our access to the remaining available funds may be adversely affected in view of the continuing unresolved sovereign debt conditions in Europe, the unsettled circumstances surrounding the secondary credit crisis in Europe, and the uncertain success of efforts to resolve the Euro crisis. These factors may adversely impact the capital stability of our lenders as well as other lenders from which we might seek additional or replacement financing.
The Polish Ministry of the Environment has the authority to terminate immediately the mining usufruct agreements and may impose contractual penalties if we do not comply with the terms and obligations indicated in such agreements.
Pursuant to the Polish Geological and Mining Law, a mining usufruct is the right to carry out work connected with prospecting and exploring for, or extracting, oil and gas. A mining usufruct is established based on an agreement concluded with the Polish State Treasury, in that case represented by the Polish Ministry of the Environment. The provisions respecting mining usufruct fees continue to evolve and may be more stringent in more recent and future usufructs. Under newer usufructs, the Polish Ministry of the Environment has the authority, if we fail to comply with the terms and obligations indicated in the mining usufruct agreement, in particular with the obligation to pay fees due under the agreement, to terminate immediately a mining usufruct agreement, and may impose on us a contractual penalty in an amount equal to up to 200% of the annual fixed component of the fees. We anticipate that usufructs will continue to include higher fixed and variable payment requirements, and increased penalties or other sanctions, for nonpayment. We cannot ensure that we have complied, and will comply, with all the terms and obligations imposed on us under the mining usufruct agreements. The loss of the usufruct rights under the mining usufruct agreements would have a material adverse effect on our business, financial condition, and results of operations.
23
Our operations in Poland require our compliance with the Foreign Corrupt Practices Act.
We must conduct our activities in or related to Poland in compliance with the United States Foreign Corrupt Practices Act, or FCPA, and similar anti-bribery laws that generally prohibit companies and their intermediaries from making improper payments to foreign government officials for the purpose of obtaining or retaining business. Enforcement officials interpret the FCPA’s prohibition on improper payments to government officials to apply to officials of state-owned enterprises such as PGNiG, our principal partner in Poland. While our employees and agents are required to acknowledge and comply with these laws, we cannot assure that our internal policies and procedures will always protect us from violations of these laws, despite our commitment to legal compliance and corporate ethics. The occurrence or allegation of these types of risks may adversely affect our business, performance, prospects, value, financial condition, reputation, and results of operations.
We cannot predict the impact of the recently adopted Polish Hydrocarbon Industry Tax Regime on our activities.
In 2014, Poland enacted the Polish Hydrocarbon Industry Tax Regime and adopted implementing regulations to become effective over the next several years. In addition to increased royalties, new laws have been enacted regarding two new taxes on hydrocarbons, one based on positive cumulative cash flows from hydrocarbon activity and the other based on production volumes. The new legislation is meant to increase governmental revenue from the oil and gas industry, with the stated intention for the total royalty and tax burden of an energy company to approach 40% of taxable income, which is approximately double that of the current fiscal regime. The new laws will become effective January 1, 2016, respecting the royalty regime, and January 1, 2020, respecting new taxes. The new royalty and tax structure would be applicable to all production, without regard to when the well was drilled or the relevant concession granted. Aside from stated royalty increases, we cannot predict whether the different taxation regime will impact our operations or cash flows. We cannot assure that industry resistance to these new burdens will result in modifications before the new provisions become fully implemented in 2020.
Risks Related to our Common Stock
Our ability to obtain equity capital will be adversely affected because of the relatively low prices at which our securities are currently traded.
In the past, we have obtained external capital from time to time by selling equity securities in the public market and have an effective universal shelf registration statement permitting us to sell publicly up to $179.3 million of equity or debt securities of various kinds. Although our common stock traded as high as $5.65 per share between January 1 and December 31, 2014, it reached a five-year low in early 2015 of $1.20 per share, and as of March 11, 2015, traded at approximately $1.69. A low trading price for our common stock may make it impracticable or financially unattractive to seek equity through the sale of common stock. If we do determine to seek equity at relatively low prices, the sale of stock at these prices may dilute the stock ownership and value of existing stockholders.
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 revised stockholder rights plan that we propose to submit to the stockholders for approval at the 2015 annual meeting that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the stockholder rights plan, if approved, 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 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.
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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.
24
Our common stock price has been and may continue to be extremely volatile.
Our common stock has closed as low as $1.20 per share and as high as $5.65 per share between January 1, 2014, 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 and the United States;
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the potential sale by us of newly issued common stock to raise capital;
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market reactions to political and economic circumstances in Europe and, in particular, in Russia;
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European gas prices and currency exchange-rate uncertainties;
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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 our partners 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 Senior Secured Credit Facility;
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prevailing world prices for oil and gas;
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changes in regulatory environments or taxation measures that may adversely affect the trading prices for our common stock;
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the potential of our current and planned activities in Poland and the United States;
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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; and
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all other risks as previously discussed.
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Our current rating by third-party corporate governance consultants advising institutional stockholders may result in recommendations that incumbent directors not be reelected or against the approval of other matters in accordance with management’s recommendations.
Various corporate governance consultants advising institutional investors and others provide scores or ratings of our governance measures, nominees for election as directors, whether our executive compensation practices effectively incentivize performance, and other matters that may be submitted to the stockholders for consideration. 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 30% of our stock may be held by institutions that may be advised directly by these consultants. Other stockholders consider the ratings and recommendations of proxy advisers as well. Certain of our stockholders have raised concerns similar to those noted by proxy advisers. 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 and implemented changes that we believe are significant and responsive to some concerns that have been raised, but we have not changed other things that we believe are in the best interests of our stockholders, notwithstanding the adverse effect of these provisions on our scores or ratings.
25
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ITEM 1B. UNRESOLVED STAFF COMMENTS
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None.
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ITEM 2. PROPERTIES
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Proved Reserve Disclosures
Internal Controls over Reserve Estimates
Our policies regarding internal controls over the recording of reserve estimates require such estimates to comply with the Securities and Exchange Commission’s definitions and guidance and prepared in accordance with customary petroleum engineering practices. Responsibility for compliance in reserve bookings is delegated to our operations and financial staff. Clay Newton, our principal financial officer, reviews the independence and professional qualifications of the third-party engineering firms we engage. He also supervises the submission of technical and financial data to third-party engineering firms and reviews the prepared reports to verify that such data has been appropriately reflected in the reports. Mr. Newton has more than 25 years’ experience in senior financial positions in the oil and gas industry. He earned a BA in accounting at the University of Utah in 1981 and is a certified public accountant.
Estimates of our proved Polish reserves were calculated by RPS Energy, an independent engineering firm in the United Kingdom. Estimates of our proved domestic reserves were calculated by Hohn Engineering, an independent engineering firm in Billings, Montana. The technical personnel responsible for calculating the reserve estimates at both RPS Energy and Hohn Engineering meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The qualifications of the individuals primarily responsible for the preparation of our reserve reports are included in their respective reports, which are included as exhibits to this filing. Both RPS Energy and Hohn Engineering are independent firms of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent-fee basis.
Proved Reserves
Proved reserves are estimated quantities of oil and gas calculated using deterministic methods that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward and recoverable in future years from known reservoirs and under existing economic conditions, operating methods, and governmental regulations, prior to the expiration of the contracts providing the right to operate, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to: (i) those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances; and (ii) other undrilled locations if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
26
We emphasize that the reserve volumes are estimates and by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. These reserve revisions result primarily from increases or decreases in performance due to a variety of factors such as an addition to or a reduction in recoveries below or above previously established, lowest, known hydrocarbon levels, improvements or deteriorations in drainage from natural drive mechanisms, and increases or decreases to drainage areas. If the estimates of proved reserves were to decline, the rate at which we record depletion expense would increase.
Proved Undeveloped Reserves
As of December 31, 2014, our proved undeveloped reserves totaled 14.1 Bcf of natural gas. All of our proved undeveloped reserves are located in Poland, and all are associated with wells that have been drilled, tested, and completed for production. These reserves are classified as proved undeveloped because relatively major expenditures are required for the completion of production facilities, which includes the construction of gathering lines to connect the wells to the existing pipeline in order to fully develop the reserves and commence production. We do not have any proved undeveloped reserves attributable to undrilled locations, so the development of such undeveloped reserves is not dependent on additional drilling. All development activities will be completed within five years of reserve bookings.
Changes in Proved Undeveloped Reserves
All reserves classified as proved undeveloped reserves at December 31, 2013, were associated with our Zaniemsyl-3 well, which remained in this category at year-end 2014. In addition, we assigned proved undeveloped reserves to our Karmin-1, Tuchola-3K, and Tuchola-4K wells at December 31, 2014.
Development Costs
Costs incurred relating to the development of proved undeveloped reserves were approximately $1.3 million in 2014, including the construction costs of production facilities at our Lisewo-2 well.
Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $12.4 million in 2015. The estimated development costs represent our share of the cost of the sidetrack project planned for our Zaniemsyl well and initial design and construction costs at our Karmin-1, Tuchola-3K, and Tuchola-4K wells.
For more information, see the following:
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Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations–Proved Reserves, for a discussion of changes in proved reserves;
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Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies–Oil and Gas Reserves, for further discussion of our reserve estimation process; and
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Item 8, Financial Statements and Supplementary Data–Supplemental Information, for additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.
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Other Reserve Information
Since January 1, 2014, no crude oil or natural gas reserve information has been filed with, or included in any report to, any other federal authority or agency.
27
Reserve Volumes and Values
The following table sets forth our estimated proved developed and proved undeveloped reserve volumes as of December 31, 2014:
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United States
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Poland
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Total
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MBbls
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MMcf
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MMcfe
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|||
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Proved developed reserves
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357
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23,271
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25,413
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Proved undeveloped reserves
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--
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14,118
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14,118
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Total proved reserves
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357
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37,389
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39,531
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The following table sets forth the estimated SMOG Value of our proved reserves as of December 31, 2014:
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Total Net
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SMOG
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||
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Reserves
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Value
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(MMcfe)
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(In thousands)
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||
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Proved
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39,531
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$133,628
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Economic producibility of reserves and discounted cash flows are based on the use of unweighted, 12-month, first-day-of-the-month, historical average prices, adjusted for basis and quality differentials, rather than year-end prices. In Poland, average gas prices used in calculating reserve values also take into consideration exchange rates between the dollar and zloty in effect on the first day of each month. The average prices used to calculate year-end reserve values were $7.75 and $6.82 per thousand cubic feet, or Mcf, of gas and $74.94 and $78.18 per Bbl for 2014 and 2013, respectively.
Drilling Activities
The following table sets forth the exploratory wells that we drilled:
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Year Ended December 31,
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|||||||||||
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2014
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2013
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2012
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|||||||||
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Gross
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Net
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Gross
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Net
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Gross
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Net
|
||||||
|
Exploratory productive wells:
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|||||||||||
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Poland
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2.0
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1.5
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2.0
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1.5
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1.0
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0.5
|
|||||
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United States
|
--
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--
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--
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--
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--
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--
|
|||||
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Total
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2.0
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1.5
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2.0
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1.5
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1.0
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0.5
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|||||
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Exploratory dry holes:
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|||||||||||
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Poland
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2.0
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1.5
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3.0
|
2.0
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2.0
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1.5
|
|||||
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United States
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--
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--
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--
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--
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4.0
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1.6
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|||||
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Total
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2.0
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1.5
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3.0
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2.0
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6.0
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3.1
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|||||
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Total wells drilled
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4.0
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3.0
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5.0
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3.5
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7.0
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3.6
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The productive exploratory wells drilled in 2014 were our Karmin-1 and Tuchola-4K wells. The exploratory dry holes in 2014 were our Baraniec-1 and Angowice-1 wells in Poland. The productive exploratory wells drilled in 2013 were our Lisewo-2 and Tuchola-3K wells. The Lisewo-2 well was drilled as a production acceleration well adjacent to the Lisewo-1 well, so no new reserves have been assigned to that well. The Tuchola-3K well was deemed commercial in 2014. The exploratory dry holes in 2013 were the Mieczewo-1K, Gorka-Duchowna-1, and Szymanowice-1 wells in Poland. The Szymanowice-1 well had gross proved reserves of 8.1 Bcf of natural gas at year-end 2013, but was plugged following an unsuccessful sidetrack operation. The Gorka-Duchowna-1 well was determined to be noncommercial during 2014. The productive exploratory well drilled in 2012 was our Komorze-3K well, which had gross proved reserves of 4.7 Bcf of natural gas at year-end 2012. The exploratory dry holes in 2012 include the Kutno-2 and Frankowo-1 wells in Poland and four Alberta Bakken wells drilled in Montana. The Frankowo-1 well was abandoned during 2014 as we relinquished our interest in Block 246. Of the remaining wells, three were drilled in 2011, but all were determined to be noncommercial during 2012. We did not drill any development wells in 2014, 2013, or 2012.
28
Wells and Acreage
As of December 31, 2014, our gross and net producing wells consisted of the following:
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Number of Wells
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|||||||
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Gas
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Oil
|
||||||
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Gross
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Net
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Gross
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Net
|
||||
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Well count:
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|||||||
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Poland(1)
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8.0
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3.9
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--
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--
|
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United States
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--
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--
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122.3
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104.7
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|||
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Total
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8.0
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3.9
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122.3
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104.7
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|||
_______________
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(1)
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In addition to the wells producing at year-end 2014, we also had three additional wells in Poland awaiting the construction of production facilities.
|
The following table sets forth our gross and net acres of developed and undeveloped oil and gas acreage as of December 31, 2014. All of our gas production is in Poland, and all of our oil production is in the United States:
|
Developed
|
Undeveloped
|
||||||
|
Gross
|
Net
|
Gross
|
Net
|
||||
|
Poland:(1)
|
|||||||
|
Fences project area
|
4,160
|
1,869
|
853,000
|
407,000
|
|||
|
Warsaw South project area
|
--
|
--
|
237,000
|
121,000
|
|||
|
Edge project area
|
--
|
--
|
726,000
|
726,000
|
|||
|
Total Polish acreage
|
4,160
|
1,869
|
1,816,000
|
1,254,000
|
|||
|
United States:
|
|||||||
|
Montana
|
10,732
|
10,418
|
4,510
|
4,417
|
|||
|
Nevada
|
400
|
128
|
9,332
|
6,351
|
|||
|
Total
|
11,132
|
10,546
|
13,842
|
10,768
|
|||
|
Total Acreage
|
15,292
|
12,415
|
1,829,842
|
1,264,768
|
|||
_______________
|
(1)
|
All gross and net undeveloped Polish acreage is rounded to the nearest 1,000 acres.
|
Polish Properties
Producing Properties
A summary of our average daily production, weighted average interest, and weighted average net revenue interest for our Poland producing properties during 2014 follows:
|
Average Daily
|
Average
|
||||||
|
Production (Mcfe)
|
Average
|
Net Revenue
|
|||||
|
Gross
|
Net
|
Interest
|
Interest
|
||||
|
Fences project area
|
23,967
|
11,744
|
49%
|
49%
|
|||
|
Grabowka
|
219
|
219
|
100%
|
100%
|
|||
|
Total
|
24,186
|
11,963
|
|||||
We sold our interest in Grabowka in early 2015.
29
Production, Transportation and Marketing
The following table sets forth, by well, our net annual oil and gas production and volume weighted average sales prices and production costs associated with our Polish production:
|
Average
|
|||||||||
|
Production
|
Production Cost
|
Average Sales Price
|
|||||||
|
Gas
|
Oil
|
per Mcfe(1)
|
Gas
|
Oil
|
|||||
|
(Mcf)
|
(Bbls)
|
(Per Mcf)
|
(Per Bbl)
|
||||||
|
2014
|
|||||||||
|
Roszkow
|
1,140,000
|
-
|
$0.33
|
$7.88
|
$ -
|
||||
|
Sroda/Kromolice-1
|
1,056,000
|
-
|
0.29
|
7.37
|
-
|
||||
|
Kromolice-2
|
679,000
|
-
|
0.29
|
7.24
|
-
|
||||
|
Winna Gora
|
367,000
|
-
|
0.69
|
7.18
|
-
|
||||
|
Lisewo/Komorze
|
913,000
|
-
|
0.58
|
6.92
|
|||||
|
Other wells(2)
|
80,000
|
-
|
0.35
|
1.95
|
-
|
||||
|
Total
|
4,235,000
|
-
|
0.42
|
7.27
|
-
|
||||
|
2013
|
|||||||||
|
Roszkow
|
1,596,000
|
-
|
0.24
|
7.63
|
-
|
||||
|
Zaniemysl-3
|
90,000
|
-
|
1.50
|
5.84
|
-
|
||||
|
Sroda/Kromolice-1
|
1,190,000
|
-
|
0.32
|
7.10
|
-
|
||||
|
Kromolice-2
|
806,000
|
-
|
0.27
|
7.00
|
-
|
||||
|
Winna Gora
|
315,000
|
-
|
0.51
|
6.95
|
-
|
||||
|
Other wells(2)
|
150,000
|
-
|
0.91
|
3.05
|
-
|
||||
|
Total
|
4,147,000
|
-
|
0.34
|
7.10
|
-
|
||||
|
2012
|
|||||||||
|
Roszkow
|
2,169,000
|
-
|
0.18
|
7.27
|
-
|
||||
|
Zaniemysl-3
|
492,000
|
-
|
0.36
|
5.44
|
-
|
||||
|
Sroda/Kromolice-1
|
1,027,000
|
-
|
0.24
|
6.90
|
-
|
||||
|
Kromolice-2
|
680,000
|
-
|
0.27
|
6.89
|
-
|
||||
|
Other wells(2)
|
89,000
|
-
|
2.54
|
1.59
|
-
|
||||
|
Total
|
4,457,000
|
-
|
0.28
|
6.81
|
-
|
||||
_______________
|
(1)
|
Production costs include lifting costs (electricity, fuel, water disposal, repairs, maintenance, transportation, and similar items) and contract operator fees. Production costs do not include such items as general and administrative costs; depreciation, depletion and amortization; or Polish income taxes.
|
|
(2)
|
Production costs at other wells include the ongoing costs of maintaining the production facilities at our Wilga well, which is not currently in production.
|
Poland has a network of gas pipelines and crude oil pipelines traversing the country serving major metropolitan, commercial, industrial, and gas production areas, including significant portions of our acreage. We are currently selling substantially all of our oil and gas production in Poland to PGNiG or one of its affiliates. We are dependent on PGNiG for the sale of gas in Poland, since there are few other competitive purchasers. Gas is sold pursuant to long-term sales contracts, typically for the life of each well, which obligate PGNiG to purchase all gas produced. Should we choose to export any gas or oil we produce, we will be required to obtain prior governmental approval.
Poland has a well-developed infrastructure of hard-surfaced roads and railways over which oil produced can be transported for sale. There are refineries in Gdansk and Plock in Poland and one in Germany near the western Polish border that we believe could process crude oil produced in Poland.
30
United States Properties
Producing Properties
In the United States, we currently produce oil in Montana and Nevada. All of our producing properties, except for the Rattlers Butte field (an exploratory discovery during 1997), were purchased during 1994. A summary of our average daily production and average working and net revenue interests, based on the number of producing wells, for our United States producing properties during 2014 follows:
|
Average Daily
|
Average
|
||||||
|
Production (Bbls)
|
Average
|
Net Revenue
|
|||||
|
Gross
|
Net
|
Interest
|
Interest
|
||||
|
Montana
|
141
|
120
|
99%
|
85%
|
|||
|
Nevada
|
28
|
8
|
39
|
29
|
|||
|
Total United States producing properties
|
169
|
128
|
|||||
In Montana, we operate the Southwest Cut Bank Sand Unit and Bears Den fields and have an interest in the Rattlers Butte field, which is operated by an industry partner. Production in the Southwest Cut Bank Sand Unit, producing since the 1940s from an average depth of approximately 2,900 feet, is from a waterflood program with 113 producing oil wells, 21 active injection wells, and one active water supply well. The Bears Den field, under waterflood since 1990, is producing oil from seven wells at a depth of approximately 2,430 feet, with one active water injection well. In the Rattlers Butte field, we own a 0.683% interest in one oil well producing at a depth of approximately 5,800 feet and one active water injection well.
In Nevada, we operate the Trap Springs and Munson Ranch fields and have an interest in the Bacon Flat field, which is operated by an industry partner. In the Trap Springs field, discovered in 1976, we produce oil from a depth of approximately 3,700 feet from one well. In the Munson Ranch field, discovered in 1988, we produce oil at an average depth of 3,800 feet from five wells. In the Bacon Flat field, discovered in 1981, we produce oil from one well at a depth of approximately 5,000 feet.
Production, Transportation, and Marketing
The following table sets forth our average net daily oil production, average sales prices, and production costs associated with our United States oil production:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
2012
|
|||
|
United States producing property data:
|
|||||
|
Average daily net oil production (Bbls)
|
128
|
133
|
146
|
||
|
Average sales price per Bbl
|
$74.24
|
$79.48
|
$76.87
|
||
|
Average production costs per Bbl(1)
|
$61.94
|
$47.64
|
$44.80
|
||
_______________
|
(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 95% of our total oil sales, to Cenex, a regional refiner and marketer. Posted prices are generally competitive among crude oil purchasers. Our crude oil sales contracts may be terminated by either party upon 30 days’ notice.
Oilfield Services–Drilling Rig and Well-Servicing Equipment
In Montana, we perform, through our drilling subsidiary, FX Drilling Company, Inc., a variety of third-party contract oilfield services, including drilling, workovers, location work, cementing, and acidizing. We currently have a drilling rig capable of drilling to a vertical depth of 6,000 feet, a workover rig, two service rigs, cementing equipment, acidizing equipment, and other associated oilfield-servicing equipment.
31
The Republic of Poland
The Republic of Poland is located in north-central Europe, has a population of approximately 38.5 million people, and covers an area comparable to New Mexico. During 1989, Poland peacefully asserted its independence and became a parliamentary democracy. Since 1989, Poland has enacted comprehensive economic reforms and stabilization measures that have enabled it to form a free-market economy and turn its economic ties from the east to the west, with most of its current international trade with the countries of the European Union and the United States. The economy has undergone extensive restructuring in the post-communist era. The Polish government credits foreign investment as a forceful growth factor in successfully creating a stable, free-market economy.
Since its transition to a free-market economy and a parliamentary democracy, Poland has experienced significant economic growth and political change. Poland has developed and is refining legal, tax, and regulatory systems characteristic of parliamentary democracies with interpretation and procedural safeguards. The Polish government has taken steps to harmonize Polish legislation with that of the European Union, which it joined in May of 2004. These measures continue.
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, raising a total of 2.7 billion Polish zlotys (approximately USD$900 million).
Prior to becoming a parliamentary democracy during 1989, the exploration and development of Poland’s oil and gas resources were hindered by a combination of foreign influence, a centrally controlled economy, limited financial resources, and a lack of modern exploration technology. As a result of these and other factors, Poland is currently a net energy importer. Oil is imported primarily from countries of the former Soviet Union and the Middle East, and gas is imported primarily from Russia.
Poland continues to enjoy the strongest economy in the European Union and was the only country in Europe to record positive GDP growth every year from 2008 through 2014, and economists are predicting positive growth during 2015. Poland’s economy remains one of the more attractive and safer debt markets in Europe.
Legal Framework
General Usufruct and Concession Terms
All of our rights in Poland have been awarded to us or to PGNiG pursuant to the Geological and Mining Law, or the former Geological and Mining Law of February 4, 1994 (as amended), which specifies the process for obtaining domestic exploration and exploitation rights. The Geological and Mining Law was substantially amended as of January 1, 2015. Prior to January 1, 2015, under the Geological and Mining Law, the concession authority entered into mining usufruct (lease) agreements that granted 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 also had to acquire an exploration concession by applying to the concession authority and providing the opportunity for comment by local governmental authorities. The usufruct agreements included provisions that gave the usufruct holder a claim for an extension of the usufruct (and the underlying concession), subject to having fulfilled all obligations under the usufruct agreements and/or the related concession.
The provisions respecting mining usufruct terms and fees issued under the amended law continue to evolve and may be more stringent in more recent and future usufructs. Under newer usufructs, the Polish Ministry of the Environment has the authority, if we fail to comply with the terms and obligations indicated in the mining usufruct agreement, in particular with the obligation to pay fees due under the agreement, to terminate immediately a mining usufruct agreement, and may impose on us a contractual penalty in an amount equal to up to 200% of the annual fixed component of the fees. We anticipate that usufructs will continue to include higher fixed and variable payment requirements, and increased penalties or other sanctions, for nonpayment.
32
We can request changes to usufruct agreements and concessions that either modify the obligations or extend the terms of those agreements or concessions by up to three years. We can also apply, by December 31, 2016, for conversion of the existing concessions into concessions covering both exploration and production, for up to 30 years.
For concessions issued before January 1, 2015, the concession authority required 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. Under the new legislation, concessions (including concessions granted as a result of conversion of the concessions issued prior to January 1, 2015) can be held by more than one party; however, the ownership will be subject to continued eligibility of the operator.
The concession authority has granted oil and gas exploration rights on the Fences project area to PGNiG and has granted oil and gas exploration rights on all other project areas in which we have an interest to us. The agreements divide these areas into blocks, each containing up to 300,000 acres.
If commercially viable gas or oil is discovered, the concession owner may be able to produce gas or oil for test purposes for two years based on the exploration concession. During the two-year period, the concession owner typically applies for an exploitation concession, which generally will have a term of up to 30 years, with possible extensions for as long as commercial production continues. Upon the grant of the exploitation concession, the concession owner will be obligated to pay a fee, to be negotiated. The concession owner would also be required to pay a royalty on any production, the amount of which is set by the Geological and Mining Law and is updated annually for inflation. The royalty rate for low-methane gas such as we produce is currently set for 2015 at approximately $0.04 per Mcf. Local governments of various tiers will receive 90% 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 terms of our concessions have been satisfied to date.
Currently gas produced by us in Poland is sold to PGNiG at prices negotiated by us with PGNiG but linked to tariff prices established by the Polish government. As part of its continuing effort to satisfy European Union requirements to move toward free-market energy prices, in September 2013 Poland adopted legislation requiring companies engaged in gas trading (i.e., excluding producers such as us) to sell a specified percentage, increasing from 30% in 2013 to 55% in 2015 and thereafter, of gas sold domestically on a commodity exchange. The only existing gas exchange was established by the Polish Power Exchange during 2013. The volumes traded on the commodity exchange are substantial, but heavily dominated by sales from PGNiG to its wholly owned retail trading subsidiary.
In view of the slow development of an open gas market, it is unclear whether a free-market trading price for gas will be established with sufficient industry acceptance and credibility to replace government-determined tariffs. Further, we cannot predict how free-market prices, if developed, will compare with established tariffs or whether our gas sales contracts with PGNiG will adopt free-market prices.
Existing Project Areas
Fences Project Area
The Fences project area consists of four oil and gas exploration concessions operated by PGNiG. Three producing fields (Radlin, Kleka, and Kaleje) lie within the concession boundaries, but are excluded from the Fences area in which we participate. The Fences concessions (853,000 gross and 407,000 net acres) have expiration dates ranging from July 2015 to July 2022. The total joint remaining work commitment, which must be satisfied by us and PGNiG according to our respective interests, includes acquiring 250 kilometers of 2-D seismic data, acquiring 110 square kilometers of 3-D seismic data, and drilling seven wells.
33
Edge Project Area
The Edge project area (726,000 gross and net acres) consists of four oil and gas exploration concessions granted in 2008. In September 2013 two of them were extended for five years and the remaining two for three years. The total obligatory work commitment, to be completed in 2016-18, includes acquiring 500 square kilometers of 3-D seismic data and drilling eight wells.
Warsaw South/Wilga Project Area
The Warsaw South/Wilga project area (236,000 gross and 121,000 net acres) consists of a single oil and gas exploration concession covering Block 255 held by us, expiring in March 2019. The obligatory work commitment includes acquiring 180 square kilometers of 3-D seismic data and drilling two wells.
As of December 31, 2014, all required usufruct/concession payments had been made for each of the above existing project areas.
Government Regulation
Poland
Our activities in Poland are subject to political, economic, and other uncertainties, including the adoption of new laws, regulations, or administrative policies that may adversely affect us or the terms of our exploration or production rights; political instability and changes in government or public or administrative policies; export and transportation tariffs and local and national taxes; foreign exchange and currency restrictions and fluctuations; repatriation limitations; inflation; environmental regulations; and other matters. These operations in Poland are subject to the Geological and Mining Law dated as of June 9, 2011 (as amended), and the Environment Protection Law dated as of April 27, 2001 (as amended), which are the current primary statutes governing environmental protection. Agreements with the government of Poland respecting our exploration and production areas create certain standards to be met regarding environmental protection. Participants in oil and gas exploration, development, and production activities generally are required to: (1) adhere to good international petroleum industry practices, including practices relating to the protection of the environment; (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 and exploratory drilling; (3) prepare and submit field development plans prior to engaging in field-wide development; and (4) obtain decisions on environmental conditions from the relevant environmental authority before entering into the production phase. Poland’s regulatory framework respecting environmental protection generally follows directives and regulations of the European Union. We intend to conduct our operations in Poland in accordance with good international petroleum industry practices and, as they continue to develop, Polish requirements.
Significant amendments to the Geological and Mining Law and to tax regulations were enacted in 2014 and enter into effect in 2015, 2016, and 2020 as a result of political and administrative interest in reviewing and potentially altering the current natural resources regulatory scheme that has been in place for some years. New policies may result in a more openly competitive process for obtaining exploration concessions and retaining rights to discovered hydrocarbons, increased production taxes, requirements for governmental concessions for transporting and marketing gas, more market-based hydrocarbon pricing, and the release of exploration data and similar matters, all or any one of which could increase our costs and reduce our expansion opportunities.
Recent Changes to the Polish Hydrocarbon Industry Licensing and Tax Regimes
Principal 2014 amendments to the Geological and Mining Law include the replacement of the current three types of concessions with one concession for exploration and production; new requirements for prequalification for applicants for concessions; and increased royalty revenues to local authorities from oil and gas production. Administrative changes are aimed at improving concession administration.
34
In addition to the increased royalties, new legislation has been enacted regarding two new taxes on hydrocarbons: one based on positive cumulative cash flows from hydrocarbon activity and the other based on production volumes. The new legislation is meant to increase governmental revenue from the oil and gas industry, with the stated intention for the total royalty and tax burden of an energy company to approach 40% of taxable income, which is approximately double that of the current fiscal regime. The new laws will become effective January 1, 2016, respecting the royalty regime, and January 1, 2020, respecting new taxes. The new royalty and tax structure would be applicable to all production, without regard to when the well was drilled or the relevant concession granted.
While these new regulations are implemented, we may encounter delays or policy changes for the approval by the Minister of Environment of changes to provisions of our concessions, such as our requests for extensions of work commitments or other modifications.
United States
State and Local Regulation of Drilling and Production
Our U.S. exploration and production operations are subject to various types of federal, state, and local regulation. This regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, restricting the method of drilling and casing wells, regulating hydraulic fracturing, controlling water injections, setting forth the surface use and restoration of properties upon which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and impose certain requirements regarding the ratability of production.
Our oil production is affected to some degree by state regulations. States in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. These statutes and related regulations are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.
Environmental Regulations
Our operations are subject to stringent federal, state, and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. These laws and regulations require the acquisition of a permit by operators before drilling commences; mandate the use of specific procedures and facilities in handling specific substances and restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and impose substantial liabilities for pollution resulting from our operations. These laws and regulations increase the costs of drilling and operating wells and storing and transporting oil.
Numerous governmental agencies, such as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil, and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.
35
Environmental regulatory programs typically regulate the permitting, construction, and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can issue a cease-and-desist order to terminate operations. New programs and changes in existing programs are routinely proposed, considered, and in some cases adopted, which both complicate compliance and potentially make it more expensive. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition, results of operations, and cash flows.
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed, or arranged for the disposal, of the hazardous substances. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources, and the costs of certain health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, or RCRA, and regulations promulgated thereunder govern the generation, storage, transfer, and disposal of hazardous wastes. RCRA, however, excludes from the definition of hazardous wastes “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, gas, or geothermal energy.” Because of this exclusion, many of our operations are exempt from RCRA regulation. However, these wastes may be regulated by the EPA or state agencies as nonhazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, wastes generated in connection with our exploration and production activities may be regulated as hazardous waste under RCRA or hazardous substances under CERCLA.
Our operations are also subject to the federal Clean Water Act and analogous state laws. The Clean Water Act regulates discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for these discharges could result in civil and criminal penalties, orders to cease such discharges, and payment of costs to remediate and natural resources damages. These laws also require the preparation and implementation of spill prevention, control, and countermeasure plans in connection with on-site storage of significant quantities of oil. In June 2011, an oil leak occurred at our Southwest Cut Bank Sand Unit in Montana. We spent approximately $321,000 in 2011 in completing cleanup, mitigation, and restoration pursuant to an approved plan in cooperation with the Blackfeet Tribe and the EPA. Although we believe that we have satisfactorily completed the cleanup according to the specifications provided by the Blackfeet Tribe and the EPA, we cannot assure that the leak will not result in additional costs, sanctions, or penalties arising from civil or criminal actions and attendant negative publicity.
The federal Safe Drinking Water Act (SWDA), the Underground Injection Control (UIC) program promulgated under the SWDA, and state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
36
The federal Clean Air Act and comparable state laws regulate air emissions of various pollutants through permitting programs and other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for noncompliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, in certain circumstances and locations, may be subject to permits and restrictions under these statutes for emissions of air pollutants. In addition, in December 2012, the EPA announced its study on the environmental effects of hydraulic fracturing and reported the methodologies and focus of this ongoing study, with a draft initial report yet to be released.
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of these evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current and proposed exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act, and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where the taking of, harm, or damage to a species, wetlands, habitat, or natural resources occurs or may occur, governmental entities or, at times, private parties may act to prevent oil and gas exploration activities or seek damages, and in some cases criminal penalties, for harm to a species, wetlands, habitat, or natural resources resulting from drilling, construction, or releases of oil, wastes, hazardous substances, or other regulated materials.
We are subject to federal and state hazard communications and community right-to-know statutes and regulations. These regulations govern recordkeeping and reporting of the use and release of hazardous substances, including the federal Emergency Planning and Community Right-to-Know Act.
Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future, such as proposals made in Congress and at the state level from time to time, that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes” and make the reclassified wastes subject to more stringent and costly handling, disposal, and cleanup requirements. The impact of any such changes, however, would not likely be any more burdensome to us than to any other similarly situated company involved in oil and gas exploration and production.
We believe that we are in compliance in all material respects with these laws, rules, and regulations and that continued compliance will not have a material adverse effect on our operations or financial condition. Furthermore, we do not believe that we are affected in a significantly different manner by these laws and regulations than our competitors in the oil and gas industry.
Federal and Indian Leases
A substantial part of our producing properties in Montana consist of oil and gas leases issued by the Bureau of Land Management or the Blackfeet Tribe under the supervision of the Bureau of Indian Affairs. Our activities on these properties must comply with rules and orders that regulate aspects of the oil and gas industry, including drilling and operating on leased land and the calculation and payment of royalties to the federal government or the governing Indian nation. Our operations on Indian lands must also comply with applicable requirements of the governing body of the tribe involved including, in some instances, the employment of tribal members and the use of tribal contractors. We believe we are currently in full compliance with all material provisions of such regulations.
37
Safety and Health Regulations
In all of our field activities, particularly our oilfield services segment, we are subject to the requirements of the federal Occupational Safety and Health Act, commonly referred to as OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public. Currently, we do not foresee expending material amounts to comply with these occupational safety and health laws and regulations. However, since these laws and regulations are frequently changed, we are unable to predict the future effect of these laws and regulations.
Resource Extraction Reporting
Under 2012 regulations adopted by the Securities and Exchange Commission under the Dodd-Frank Wall Street Reform and Consumer Protection Act, we would have been required to begin reporting annually to the Securities and Exchange Commission the payments we make to governmental entities to further commercial development of oil and gas in 2014. During 2013, the United States District Court for the District of Columbia vacated the SEC resource extraction disclosure rules.
2011 Montana Oil Leak
In June 2011, an oil leak occurred at our Southwest Cut Bank Sand Unit in Montana. We spent approximately $321,000 in completing cleanup, mitigation, and restoration pursuant to an approved plan in cooperation with the Blackfeet Tribe and the EPA. Both the Blackfeet Tribe and the EPA advised us in writing that our cleanup and mitigation efforts were satisfactory. However, we are advised that a federal investigation into the 2011 Southwest Cut Bank Sand Unit incident continues. We are cooperating with the investigation and have asserted that no federal law was violated by us or our employees and that no one should be sanctioned civilly or criminally. We have engaged independent counsel to represent separately current and former employees in connection with this matter. We cannot predict whether authorities may initiate criminal or other proceedings against us or our personnel, exposing us or our employees to penalties.
Hydraulic Fracturing
We have no current plans for future hydraulic fracturing in either Poland or the United States. Were we to engage in hydraulic fracturing we expect that PGNiG or we, as the operator of the particular project, would use industry-standard, long-established third-party service providers with specialized experience and equipment in hydraulic fracturing. In many instances, these service providers would be PGNiG subsidiaries. Prior to initiating a horizontal lateral to an existing well or drilling a new well that might result in a horizontal extension, we would include in the planning and budgetary process all costs associated with the fracture treatment, including applicable regulatory compliance, such as monitoring operations, evaluating the environmental impact of fluid additives, minimizing fluid quantities and fracturing fluid disposal. We expect to follow industry standard procedures and meet increasing stringent regulatory standards, which continue to evolve. Regulatory approval of proposed fracturing operations may require us to complete an environmental impact statement. The costs of a well vary based on the depth to which it would be drilled, its horizontal length, and the completion technique to be used, which would include the added expenditure for the fracture treatment, as well as anticipated environmental and safety considerations.
Applicable laws typically impose responsibility on owners and operators for any costs resulting from underground migration of fracture fluids, and we are not fully insured against this risk. The occurrence of a significant event resulting from the underground migration of fracture fluids or surface spillage, mishandling, or leakage of fracture fluids could have a materially adverse effect on our financial condition and results of operations. To date, there have been no such incidents, and the members of our management team have not encountered such an incident in their long-term experience in this industry.
For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “Risk Factors—Risks Related to Our Business—Polish legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to explore and produce from our properties.”
38
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 U.S. interests are held under leases from third parties. We typically obtain a title opinion concerning these properties prior to the commencement of drilling operations. We have obtained 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 U.S. properties are subject to typical burdens, including customary royalty interests and liens for current taxes, but we have concluded that these burdens do not materially interfere with our activities on these properties. Further, we believe the economic effects of these burdens have been appropriately reflected in our carrying cost of the properties and reserve estimates. Title investigation before the acquisition of undeveloped properties is less thorough than that conducted prior to drilling, as is standard practice in the industry.
Oil and Gas Terms
The following terms have the indicated meaning when used in this report, in our public releases, or investor presentations:
“Bbl” means oilfield barrel.
“Bcf” means billion cubic feet of natural gas.
“Bcfe” means billion cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.
“BTU” means British thermal unit.
“Ca2” refers to a specific calcium-rich geological formation, typically a dolomitic reef.
“Deterministic” means a method of estimating reserves in which a simple value for each parameter of geoscience, engineering, or economic data in the reserve calculation is used in the reserve estimation.
“Development well” means a well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
“Exploratory well” means a well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil in another reservoir, or to extend a known reservoir.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic conditions.
“Fracturing” means injecting fluids or slurry under sufficient pressure and rate to fracture the formation, leaving proppants that keep the fractures open to serve as a pathway for gas or oil to flow to the well bore.
“Gross acres” and “gross wells” mean the total number of acres or wells, as the case may be, in which a working interest is owned, either directly or through a subsidiary or other enterprise in which we have an interest.
“Horizon” means an underground geological formation that is the portion of the larger formation that has sufficient porosity and permeability to constitute a reservoir.
“MBbls” means thousand oilfield barrels.
39
“Mcf” means thousand cubic feet of natural gas.
“Mcfe” means thousand cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.
“MMcf” means million cubic feet of natural gas.
“MMcfd” means million cubic feet of natural gas per day.
“MMcfe” means million cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas.
“MMcfed” means million cubic feet of natural gas equivalent using a ratio of one barrel of oil to 6,000 cubic feet of natural gas per day.
“Net” means, when referring to wells or acres, the fractional ownership working interests held by us, either directly or through a subsidiary or other Polish enterprise in which we have an interest, multiplied by the gross wells or acres.
“PLN” means the Polish zloty.
“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%, before taxes. These amounts are calculated net of estimated production costs and future development costs, using prices and costs determined using guidelines established by the Securities and Exchange Commission, without escalation and without giving effect to non-property-related expenses, general and administrative costs, debt service, and depreciation, depletion, and amortization.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and that is distinct and separate from other reservoirs.
“SMOG (Standard Measure of Oil and Gas) Value” means the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs, future development costs, and future income taxes, using prices and costs determined using guidelines established by the Securities and Exchange Commission, without escalation and without giving effect to non-property-related expenses, general and administrative costs, debt service, and depreciation, depletion, and amortization.
“USD” means the U.S. dollar.
“Usufruct” means the Polish equivalent of a U.S. oil and gas lease.
40
|
ITEM 3. LEGAL PROCEEDINGS
|
We are not a party to any material legal proceedings, and no material legal proceedings have been threatened by us or, to the best of our knowledge, against us.
|
ITEM 4. MINE SAFETY DISCLOSURES
|
Not applicable.
PART II
|
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY,
|
|
RELATED STOCKHOLDER MATTERS AND
|
|
ISSUER PURCHASES OF EQUITY SECURITIES
|
Price Range of Common Stock and Dividend Policy
The following table sets forth, for the periods indicated, the high and low trading prices for our common stock as quoted under the symbol “FXEN” on the NASDAQ Global Select Market, or its predecessor, NASDAQ National Market:
|
Low
|
High
|
||
|
2015:
|
|||
|
First Quarter (through March 12, 2015)
|
$1.20
|
$2.86
|
|
|
2014:
|
|||
|
Fourth Quarter
|
1.46
|
3.17
|
|
|
Third Quarter
|
2.88
|
3.64
|
|
|
Second Quarter
|
3.13
|
5.85
|
|
|
First Quarter
|
3.18
|
4.09
|
|
|
2013:
|
|||
|
Fourth Quarter
|
3.00
|
3.86
|
|
|
Third Quarter
|
2.82
|
3.98
|
|
|
Second Quarter
|
2.48
|
6.18
|
|
|
First Quarter
|
3.32
|
4.52
|
We have never paid cash dividends on our common stock and do not anticipate that we will pay dividends on our common stock in the foreseeable future. We intend to reinvest any future earnings to further expand our business. As of March 5, 2015, we had approximately 8,000 stockholders.
Recent Sales of Unregistered Securities
None.
41
|
ITEM 6. SELECTED FINANCIAL DATA
|
The following selected financial data are derived from our audited consolidated financial statements and notes thereto, certain of which are included in this report. The selected financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and the notes thereto included elsewhere in this report:
| Year Ended December 31, | ||||||||||||||
| 2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||
| (In thousands, except per share amounts) | ||||||||||||||
| Statement of Operations Data: | ||||||||||||||
|
Revenues:
|
||||||||||||||
|
Oil and gas sales
|
$ |
34,265
|
$ |
33,311
|
$ |
34,461
|
$ |
29,807
|
$ |
22,914
|
||||
|
Oilfield services
|
3,761
|
1,218
|
2,137
|
5,631
|
2,099
|
|||||||||
|
Total revenues
|
38,026
|
34,529
|
36,598
|
35,438
|
25,013
|
|||||||||
|
Operating costs and expenses:
|
||||||||||||||
|
Lease operating expenses(1)
|
4,745
|
3,680
|
3,631
|
3,834
|
3,473
|
|||||||||
|
Exploration costs(2)
|
21,173
|
20,792
|
23,795
|
16,618
|
3,038
|
|||||||||
|
Impairment of oil and gas properties(3)
|
23,293
|
6,129
|
2,562
|
72
|
564
|
|||||||||
|
Asset retirement obligation gain
|
--
|
--
|
--
|
(52)
|
(264)
|
|||||||||
|
Oilfield services costs
|
2,486
|
1,179
|
1,610
|
4,458
|
1,550
|
|||||||||
|
Depreciation, depletion, and
|
||||||||||||||
|
amortization
|
5,531
|
4,573
|
4,239
|
3,397
|
2,626
|
|||||||||
|
Accretion expense
|
96
|
90
|
63
|
68
|
92
|
|||||||||
|
Loss on sale of asset
|
--
|
--
|
49
|
--
|
--
|
|||||||||
|
Stock compensation
|
2,495
|
2,853
|
2,325
|
1,744
|
1,379
|
|||||||||
|
General and administrative costs (G&A)
|
8,500
|
8,836
|
8,369
|
8,396
|
7,973
|
|||||||||
|
Total operating costs and expenses
|
68,319
|
48,132
|
46,643
|
38,535
|
20,431
|
|||||||||
|
Operating income (loss)
|
(30,293)
|
(13,603)
|
(10,045)
|
(3,097)
|
4,582
|
|||||||||
|
Other income (expense):
|
||||||||||||||
|
Interest expense
|
(2,824)
|
(3,269)
|
(2,485)
|
(2,167)
|
(1,936)
|
|||||||||
|
Interest and other income
|
75
|
105
|
356
|
188
|
829
|
|||||||||
|
Foreign exchange (loss) gain
|
(26,178)
|
4,967
|
16,292
|
(23,448)
|
(4,233)
|
|||||||||
|
Total other (expense) income
|
(28,297)
|
1,803
|
14,163
|
(25,427)
|
(5,340)
|
|||||||||
|
Net income (loss)
|
$
|
(59,220)
|
$ |
(11,800)
|
$ |
4,118
|
$ |
(28,524)
|
$ |
(758)
|
||||
– Continued –
42
| Year Ended December 31, | ||||||||||||||
| 2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||
| (In thousands, except per share amounts) | ||||||||||||||
|
Basic and diluted net income (loss)
|
||||||||||||||
|
per common share
|
$ |
(1.12)
|
$ |
(0.22)
|
$ |
0.08
|
$ |
(0.57)
|
$ |
(0.02)
|
||||
|
Basic and diluted weighted average
|
||||||||||||||
|
shares outstanding
|
53,416
|
52,752
|
52,274
|
50,262
|
43,387
|
|||||||||
|
Cash Flow Statement Data:
|
||||||||||||||
|
Net cash provided by (used in) operating
|
||||||||||||||
|
activities
|
$ |
2,120
|
$ |
2,308
|
$ |
(1,233)
|
$ |
(120)
|
$ |
7,249
|
||||
|
Net cash used in investing activities
|
(17,452)
|
(27,945)
|
(16,350)
|
(18,486)
|
(7,814)
|
|||||||||
|
Net cash provided by (used in)
|
||||||||||||||
|
financing activities
|
16,208
|
2,964
|
--
|
50,842
|
16,092
|
|||||||||
|
Balance Sheet Data:
|
||||||||||||||
|
Working capital(4)
|
$ |
17,131
|
$ |
11,300
|
$ |
30,395
|
$ |
49,787
|
$ |
18,212
|
||||
|
Total assets
|
78,893
|
100,692
|
105,954
|
110,224
|
66,604
|
|||||||||
|
Notes payable
|
50,000
|
45,000
|
40,000
|
40,000
|
35,000
|
|||||||||
|
Total stockholders’ equity
|
20,584
|
43,545
|
54,799
|
58,627
|
23,837
|
|||||||||
_______________
|
(1)
|
Includes lease operating expenses and production taxes.
|
|
(2)
|
Includes geophysical and geological costs, exploratory dry hole costs, and nonproducing leasehold impairments.
|
|
(3)
|
Includes proved and unproved property write-downs relating to our properties in the United States and Poland.
|
|
(4)
|
Working capital represents current assets minus current liabilities.
|
|
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
|
|
CONDITION AND RESULTS OF OPERATIONS
|
The following discussion of our historical financial condition and results of operations should be read in conjunction with Item 6, Selected Financial Data, and our consolidated financial statements and related notes contained in this report.
Introduction
As discussed in Item 1, Business, above, the majority of our operations are in Poland, and we have devoted most of our technical talent and capital expenditures in the last several years to our operations in that country. The decision to devote most of our available capital to this area drives our operating results and the changes to our balance sheet and liquidity. Our operations in Poland are a combination of existing production and exploration. Oil and gas production, oil and gas revenues, cash flow, and oil and gas expenditures in this area have increased over the last five years.
Our U.S. operations also have an impact. Our U.S. operations are smaller than those in Poland and do not present the same level of opportunities for expansion; however, while smaller than our Polish operations, our U.S. operations are a relatively stable source of revenue. This is also reflected in our operating results.
43
Overview
While our Tuchola discoveries signal a potentially significant new exploration play in our Edge license, and our Karmin discovery in the Fences license builds upon our success in this core area, a combination of unanticipated economic events occurring during the second half of 2014 creates a challenging financial environment in 2015 for us, as well as for most oil and gas companies:
|
●
|
Beginning in the late summer months of 2014, worldwide oil prices began declining; slowly, at first, then more rapidly during the fourth quarter. Brent crude oil prices dropped from a high of $115 per barrel to a low of $45 per barrel in early January 2015. While prices have recovered slightly to around $58 per barrel at the time of this report, they remain more than 40% below their highest levels of last year.
|
|
●
|
Around the same time that oil prices began their decline, the U.S. dollar began appreciating against most worldwide currencies, including the British pound and the Euro. In Poland, the change was dramatic. The exchange rate between the zloty and the dollar has been fairly stable over the past three years, generally ranging between 3.15 and 3.25 PLN/USD. During late 2014, and continuing into 2015, the exchange rate moved from a low of 3.00 to a high of 3.91 PLN/USD at the report date, a deprecation in the value of the zloty of approximately 30%.
|
|
●
|
Falling oil and gas prices cause anxiety not only for producers, but for their lenders as well. Many producers that have reserve-based credit facilities are seeing reductions in their borrowing base, which may be followed by other credit challenges. These lower prices also affect public market values for most producers, making access to capital markets less attractive.
|
|
●
|
More specific to Poland, the government recently adopted new tax policies aimed at increasing the amount of taxes to be paid on oil and gas production. While the early impact is minimal, the long-term impact could be significant. New concession terms have also become more demanding.
|
|
●
|
Lower prices, lower available credit, and lack of access to capital markets usually leads to lower capital budgets, project deferrals, cost-cutting initiatives, rationalization of properties, and other strategies used to maintain operations in a cost-efficient manner.
|
The following discussion examines how each of these factors impacts FX Energy and outlines our strategies to minimize their impact on our 2015 operations and financial condition.
Commodity Prices
Global oil prices continued to be volatile in 2014, reaching multi-year lows. Gas prices in the United States remained at depressed levels, which have persisted since 2009. However, the Polish gas market operates quite differently than the U.S. domestic market. In Poland, substantially all of our gas production is sold to PGNiG and is currently tied to published tariffs (wholesale prices) set from time to time by the public utility regulator for gas sold to wholesale consumers.
A major component of the gas tariff calculation is the cost of Russian imported gas, which is based in part on trailing oil prices. Thus, Brent oil prices can have a significant impact on Polish gas prices. Other major components of the tariff calculation include the cost of gas provided by PGNiG itself, as well as the necessity for PGNiG to cover its internal cost structure. Natural gas prices to consumers in Poland are, and for years have been, below European Union average prices for both households and industry, because the prices have been subsidized by the government. European Union rules require Poland to gradually abandon market subsidies and bring Polish gas prices to Western Europe free-market levels.
44
Poland continues to enjoy one of the strongest economies in the European Union and was the only country in Europe to record positive GDP growth every year from 2008 through 2014, and economists are predicting positive growth during 2015. These factors may act as cushions against possible declines in gas prices. As of year-end 2014, gas prices in Poland remained significantly higher than those of an equivalent BTU content in the United States. As of the date of this report the price we receive for natural gas at our Roszkow well, which has a methane content of 80%, is approximately 110% higher than the spot price under natural gas contracts for 100% methane gas traded on the New York Mercantile Exchange, or the Henry Hub price.
Laws enacted in 2013 require Poland to establish a competitive market for gas sold by nonproducers. Poland has started trading gas on its commodity exchange, but prices are not yet considered representative because transactions are dominated by sales from PGNiG to its wholly owned retail trading subsidiary. Imports into Poland from Germany at market prices have reduced PGNiG’s pricing domination. As a result of the foregoing factors, we believe that Poland’s reliance on tariff pricing may decline and that Poland’s gas prices may increasingly be influenced by European gas prices. We cannot predict the effect these changes in Poland’s gas marketing landscape will have on the prices we receive for the gas that we produce in Poland. In early 2015, the public utility regulator decreased the low-methane tariff by 6.0%. The tariff decrease is scheduled to end after four months; at that time, prices may or may not be changed. While we expect our 2015 production to be equal to or slightly higher than 2014, our expectation is that our 2015 revenues in Poland, expressed in zlotys, will likely be lower than in 2014.
Functional Currency and Exchange Rates
The functional currency of our Polish subsidiary is the Polish zloty. Accounting standards require the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Translation adjustments result from the process of translating its financial statements into the parent company’s U.S. dollar reporting currency. Translation adjustments are not included in determining net income, but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities affected by the change is adjusted to reflect the difference between the exchange rate when the asset or liability was first recorded and the exchange rate on the date of the change.
The difference in functional currency also affects the amounts we report for our Polish assets, liabilities, revenues, and expenses from those that would be reported were the U.S. dollar the functional currency for our Polish operations. The differences will depend on changes in period-average and period-end exchange rates. Transaction gains or losses may be significant given the volatility of the exchange rate.
We enter into various agreements in Poland denominated in the Polish zloty. The exchange rate between the U.S. dollar and the Polish zloty is subject to fluctuations that are beyond our control. As discussed above, the value of the zloty relative to the dollar has depreciated by about 30% over the past several months. Variations in exchange rates affect the dollar-denominated amount of revenue we report, compared to what we receive in zlotys. As the dollar strengthens relative to the zloty, our dollar-denominated revenue actually received in zlotys declines; conversely, when the dollar weakens relative to the zloty, our dollar-denominated revenue received in zlotys increases. Likewise, a weak dollar leads to higher dollar-denominated drilling, capital, and exploration costs, while a strong dollar has the opposite effect for the cost structure of our Polish operations. Should exchange rates in effect during early 2015 continue throughout the year, we expect the exchange rates to have a negative impact on our dollar-denominated revenues, and a positive impact on our dollar-denominated costs, compared to 2014.
In addition, the change in the exchange rate from the end of each reporting period to the next has an impact on foreign exchange gains and losses. At the end of 2014, the exchange rate was 3.51 zlotys per dollar compared to 3.01 zlotys per dollar at the end of 2013. This 17% year-end to year-end depreciation of the zloty represents an increase in the amount of Polish currency required to satisfy outstanding dollar-denominated intercompany and other loans of FX Energy Poland as of December 31, 2014, and creates the noncash foreign exchange loss recorded on our consolidated statements of operations.
More information concerning the impact of foreign currency transactions can be found in the discussion that follows, as well as in note 1 of the notes to the consolidated financial statements included in this report.
45
Commodity Prices, Exchange Rates, and Credit
At the end of 2014, our borrowing base was reduced from $65 million to $55 million as a result of the lenders’ redetermination. At year-end 2014, our outstanding debt totaled $50 million. The amount that we can borrow under our Senior Secured Credit Facility is based on our lenders’ evaluation of our Polish reserves, and the expected future cash flow from those reserves, denominated in U.S. dollars. All of the natural gas we produce in Poland is sold under gas sales agreements that are denominated in zlotys. At the time of each semiannual reserve redetermination, our lenders calculate the net cash flows expected to be generated during the remaining term of our loan, as denominated in dollars. Part of that calculation is an assumption by the lenders concerning future gas prices and exchange rates. These assumptions can have a significant impact on the estimated future net cash flows denominated in dollars.
As we discussed above, the effect of a 6.0% price decrease in the Polish low-methane tariff in a borrowing base recalculation is straightforward. Equally important is the effect of exchange-rate changes. At the end of 2013, the exchange rate was 3.01 zlotys per dollar compared to 3.51 zlotys per dollar at the end of 2014. The use of the latter rate by our lenders, instead of the former rate, results in a 17% reduction of estimated future net cash flows, denominated in dollars, from our production. This is turn would have a negative effect on our borrowing base and could cause us either to be limited in our access to credit or to be required to make earlier than scheduled principal payments. These changes are outside our influence or control. Our next redetermination is scheduled for June 30, 2015. In the meantime, we are discussing with our lenders an amendment and restatement of our existing facility, which we hope to close before the next redetermination, and which would likely increase our borrowing base beyond the $55 million current level. However, should these discussions not result in an increased borrowing base or revisions to the amortization language of the existing credit agreement, then we would likely have to begin amortization of our loan in 2015, which would be sooner than the scheduled commitment reductions outlined in our Senior Secured Credit Facility. This amortization would substantially impair the amount of capital we would have available for additional capital expenditures.
Changes to Poland’s Hydrocarbon Legislation
In late 2012, the Polish government approved guidelines for new hydrocarbon legislation, including, among other things, higher royalties on hydrocarbons produced and a new cash flow tax based on the positive cumulate cash flow of exploration and development projects. The law was passed in 2014.
The new legislation is meant to increase governmental revenue from the oil and gas industry, with the stated intention for the total royalty and tax burden of an energy company to approach 40% of taxable income, which is approximately double that of the current fiscal regime. The new law became effective January 1, 2015; however, the first royalty increase is delayed until January 1, 2016. Beginning in 2016, the royalty on the gas we produce will increase from 5.18 PLN per thousand cubic meters of gas to 20.00 PLN per thousand cubic meters. On January 1, 2020, an additional royalty equal to 3% of the sales value of gas produced will become effective. The new royalty and tax structure would be applicable to all production, without regard to when the well was drilled or the relevant concession granted.
The tax on profits from hydrocarbon production, which is based on the positive cumulative cash flow of exploration and development projects, goes into effect on January 1, 2020. Each company subject to the tax is allowed to include all qualifying costs incurred between January 1, 2016, and December 31, 2019, as part of a beginning cost pool. The new tax does not go into effect until the company’s cumulative cash flow from oil and gas sales is positive, taking into consideration the beginning cost pool, and all revenues and costs subsequent to January 1, 2020. The maximum tax burden is equal to 25% of the cumulative cash flow and may be reduced or eliminated depending on the ratio of revenues to costs.
2015 Financial and Operational Outlook
Each of the above factors has an impact on our financial condition and on our operations, either directly or indirectly. In response, we have taken the following steps in order to preserve capital, continue operations, and when possible, increase the amount of capital available to us:
|
●
|
We are in discussions with our lenders concerning an amendment and restatement of our Senior Secured Credit Facility, which we hope to complete during the second quarter of 2015.
|
46
|
●
|
We have made reductions to our capital budget to reflect the current constraints on available resources to fund many of the projects we are currently pursuing. In addition, we are working with PGNiG, our partner in the Fences, to move some projects into the second half of the year, after our revised credit facility is in place.
|
|
●
|
We have frozen all executive salaries and incentive payments and are taking steps to reduce other fixed overhead costs.
|
|
●
|
We have begun discussions with several interested parties in pursuing a farmout arrangement of our Edge concessions. If successful, such an arrangement could provide funds to cover the cost of our Tuchola facilities, as well as for additional drilling in the area.
|
|
●
|
We have earmarked the balance of our marketable securities to cover current and future dividends for our preferred stock.
|
We intend to be prudent during 2015, undertaking only those projects in which we can best minimize risk, and that will result in the earliest possible cash flow. The following discussion reviews our results for 2014 and discusses in more detail our current financial condition and resources for the coming year.
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the exploration and production, or E&P, segment in Poland and the United States and the oilfield services segment in the United States. Direct revenues and costs, including depreciation, depletion and amortization costs, or DD&A, general and administrative costs, or G&A, and other income directly associated with their respective segments are detailed within the following discussion. DD&A, G&A, amortization of deferred compensation, interest income, other income, interest expense, and other costs, which are not allocated to individual operating segments for management or segment reporting purposes, are discussed fully following the segment discussion. The following table summarizes the results of operations by segment (in thousands):
|
Reportable Segments
|
|||||||||
|
Exploration & Production
|
|||||||||
|
Poland
|
U.S.
|
Oilfield Services
|
Non-Segmented
|
Total
|
|||||
|
Year ended December 31, 2014:
|
|||||||||
|
Revenues
|
$30,796
|
$3,469
|
$3,761
|
$ --
|
$ 38,026
|
||||
|
Net income (loss)(1)
|
(16,755)
|
(2,746)
|
265
|
(39,984)
|
(59,220)
|
||||
|
Year ended December 31, 2013:
|
|||||||||
|
Revenues
|
$29,450
|
$3,861
|
$1,218
|
$ --
|
$ 34,529
|
||||
|
Net income (loss)(1)
|
(1,889)
|
929
|
(917)
|
(9,923)
|
(11,800)
|
||||
|
Year ended December 31, 2012:
|
|||||||||
|
Revenues
|
$30,344
|
$4,117
|
$2,137
|
$ --
|
$ 36,598
|
||||
|
Net income (loss)(2)
|
2,031
|
(770)
|
(582)
|
3,439
|
4,118
|
||||
_______________
|
(1)
|
Nonsegmented reconciling items for 2014 include $8,500 of G&A costs, $2,495 of noncash stock compensation expense, $26,178 of noncash foreign exchange losses, $2,749 of interest expense (net of other income), and $62 of corporate DD&A.
|
|
(2)
|
Nonsegmented reconciling items for 2013 include $8,836 of G&A costs, $2,853 of noncash stock compensation expense, $4,967 of noncash foreign exchange gains, $3,164 of interest expense (net of other income), and $37 of corporate DD&A.
|
|
(3)
|
Nonsegmented reconciling items for 2012 include $8,369 of G&A costs, $2,325 of noncash stock compensation expense, $16,292 of noncash foreign exchange gains, $2,129 of interest expense (net of other income), and $30 of corporate DD&A.
|
See note 11 in the notes to the consolidated financial statements for additional detail concerning our segment results.
47
Exploration and Production Segment
Gas Revenues. Revenues from gas sales were $30.8 million during 2014, compared to $29.5 million and $30.3 million in 2013 and 2012, respectively. Our 2014 gas revenues increased $1.3 million from 2013 levels by approximately $0.8 million due to higher gas prices, coupled with approximately $0.5 million related to higher annual production. Our 2013 gas revenues decreased by $0.8 million from 2012 levels by approximately $1.7 million due to lower production, which was partially offset by $0.9 million in higher revenues due to higher gas prices.
Company-wide net gas production increased from a daily rate in 2013 of approximately 11.4 MMcfd to a rate of approximately 11.6 MMcfd in 2014, an increase of 2%. In mid-February 2015, gas was flowing in Poland at an average rate of 12.0 MMcfd, net to our interest.
Gas prices were 2.3% higher in 2014 than in 2013. The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 3.0% higher during the full year of 2014 compared to 2013, due to an increase in the tariff that was effective January 1, 2014. Gas production at our Roszkow well, where we receive 95% of the low-methane tariff, declined from 38% of our total production in 2013 to 27% of our total production in 2014, which caused our average price per thousand cubic feet to decrease. Gas from our other producing Fences area wells is sold at a minimum of 86% of the tariff. The effect of exchange-rate changes between the U.S. dollar and Polish zloty on gas prices was minimal during 2014.
Gas production at our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells averaged 9.7 MMcfd during 2014, compared to 11.1 MMcfd during 2013. At year-end, the wells were producing at a combined rate of 10.1 MMcfd. Gas at KSK is being sold to PGNiG at a contracted rate equal to 86% of the published low-methane tariff. We have a 49% interest in the KSK wells.
Gas production at our Roszkow well averaged 6.4 MMcfd during 2014, compared to 8.9 MMcfd during 2013. At year-end, the well was producing approximately 5.3 MMcfd. We plan to install compression equipment at the well during the second half of 2015 to maintain production levels at 5.8 MMcfd. Gas at Roszkow is being sold to PGNiG at a contracted rate equal to 95% of the published low-methane tariff. We have a 49% interest in the Roszkow well.
Gas production at our Zaniemysl well averaged approximately 2.0 MMcfd through the first six months of 2013, at which point it was terminated due to an influx of water. Sidetrack operations in early 2015, conducted to access additional gas accumulations that appeared to be present higher in the structure, were unsuccessful. Gas at Zaniemysl is sold to PGNiG at a contracted rate equal to 70% of the published low-methane tariff. We have a 24.5% interest in the Zaniemysl well.
Gas production at our Winna Gora well averaged 2.3 MMcfd during 2014, compared to 2.0 MMcfd during 2013. At year-end, the well was producing approximately 2.1 MMcfd. Gas at Winna Gora is being sold to PGNiG at a contracted rate equal to 86% of the published low-methane tariff. We have a 49% interest in the Winna Gora well.
Gas production began at our Lisewo-1 well in December of 2013 and at Lisewo-2 in September of 2014. At year-end, the Lisewo-1 well was producing at a rate of approximately 4.3 MMcfd, and the Lisewo-2 well was shut-in pending a workover. Following a successful workover in early 2015, the Lisewo wells were producing at a combined rate of 7.0 MMcfd. Gas at Lisewo is being sold to PGNiG at a contracted rate equal to 86% of the published low-methane tariff. We have a 49% interest in the Lisewo wells.
48
A summary of the amount and percentage change, as compared to their respective prior-year periods, for gas revenues, average gas prices, gas production volumes, and lifting costs per Mcf is set forth in the following table:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
2012
|
|||
|
Revenues
|
$30,796,000
|
$29,450,000
|
$30,344,000
|
||
|
Percent change versus prior year
|
+5%
|
-3%
|
+21%
|
||
|
Average price per Mcf
|
$7.27
|
$7.11
|
$6.81
|
||
|
Percent change versus prior year
|
+2%
|
+4%
|
+10%
|
||
|
Production volumes Mcf
|
4,235,000
|
4,147,000
|
4,457,000
|
||
|
Percent change versus prior year
|
+2%
|
-7%
|
+10%
|
||
|
Lifting costs per Mcf(1)
|
$0.42
|
$0.33
|
$0.28
|
||
|
Percent change versus prior year
|
+27%
|
+18%
|
+22%
|
||
_______________
|
(1)
|
Lifting costs per Mcf are computed by dividing the related lease operating expenses by the total volume of gas produced.
|
Oil Revenues. Oil revenues were $3.5 million, $3.9 million, and $4.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. Lower production and oil prices in 2014 compared to 2013 caused the decrease in revenues. Higher average oil prices in 2013 compared to 2012 were offset by lower production to cause the decrease in revenues. Our average oil price during 2014 was $74.24 per barrel, a 7% decrease compared to $79.48 per barrel received during 2013. Production from our U.S. properties declined by 4% due to normal production declines. The current oil price environment will make most of our U.S. production uneconomic. However, due to high field-level pressures, it is problematic for us to shut-in more than a few wells at a time. As a consequence, we will likely see negative cash flows from our oil production until the oil price we receive returns to approximately $50 per barrel.
U.S. oil revenues in 2014 decreased from 2013 levels by approximately $0.2 million due to lower oil prices, combined with approximately $0.2 million related to production declines. U.S. oil revenues in 2013 increased from 2012 levels by approximately $0.1 million due to higher oil prices, offset by approximately $0.3 million related to production declines.
A summary of the amount and percentage change, as compared to their respective prior-year period, for oil revenues, average oil prices, oil production volumes, and lifting costs per barrel is set forth in the following table:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
2012
|
|||
|
Revenues
|
$3,469,000
|
$3,861,000
|
$4,117,000
|
||
|
Percent change versus prior year
|
-10%
|
-6%
|
-12%
|
||
|
Average price per Bbl
|
$74.24
|
$79.48
|
$76.87
|
||
|
Percent change versus prior year
|
-7%
|
+3%
|
-7%
|
||
|
Production volumes (Bbl)
|
46,723
|
48,575
|
53,553
|
||
|
Percent change versus prior year
|
-4%
|
-9%
|
-5%
|
||
|
Lifting costs per Bbl(1)
|
$61.94
|
$47.64
|
$44.80
|
||
|
Percent change versus prior year
|
+30%
|
+6%
|
-11%
|
||
_______________
|
(1)
|
Lifting costs per barrel are computed by dividing the related lease operating expenses by the total barrels of oil produced. Light crude oil lifting costs in Poland are based on an allocation of total costs based on relative revenues between oil and gas. Lifting costs include production taxes incurred in the United States.
|
Lease Operating Costs. Lease operating costs were $4.7 million in 2014, $3.7 million in 2013, and $3.6 million in 2012. Operating costs in the United States increased in 2014 by approximately $0.6 million due to higher third-party workover costs. Operating costs in Poland increased $0.5 million in 2014 from 2013 levels, primarily due to new production from our Komorze-1 and Lisewo-2 wells.
Exploration Costs. Exploration expenses consist of geological and geophysical costs as well as the costs of exploratory dry holes. Exploration costs were $21.2 million, $20.8 million, and $23.8 million for the years ended December 31, 2014, 2013, and 2012, respectively.
49
Geological and geophysical costs, or G&G costs, were $10.8 million, $14.1 million, and $11.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. During all three years, most of our G&G costs were spent on acquiring, processing, and interpreting new 3-D and 2-D seismic data in the Fences, Edge, and other concession areas in Poland.
Exploratory dry-hole costs were $10.4 million, $6.7 million, and $12.7 million for the years ended December 31, 2014, 2013, and 2012, respectively. Our 2014 dry-hole cost were associated with our Polish Baraniec-1 and Angowice-2 wells, along with some costs associated with an unsuccessful recompletion at our Szymanowice well that was drilled in 2013. Our 2013 dry-hole costs were associated with our Mieczewo-1K and Plawce-2 wells in Poland. Our 2012 dry-hole costs were associated primarily with our Kutno-2 well in Poland. The Kutno-2 well, which was the deepest well ever drilled in Poland, was found to be noncommercial during the third quarter of 2012. Total costs to us were approximately $12.2 million.
Impairment Costs. Impairments of oil and gas properties were $23.3 million, $6.1 million, and $2.6 million for the years ended December 31, 2014, 2013, and 2012, respectively. During 2014, as part of narrowing our operational focus in Poland moving forward, we dropped our concession blocks 246 and 287 and impaired the approximately $0.3 million concession costs associated with those blocks. In addition, we impaired approximately $9.2 million of costs associated with the Frankowo and Gorka Duchowna wells, located in Block 246. We also sold our interest in the Grabowka wells, located in Block 287, with costs totaling approximately $0.1 million. Finally, in Poland, we impaired prior-year costs at our Szymanowice and Komorze wells of $3.7 million and $7.1 million, respectively, as those wells were determined to be uneconomic during the year. In the United States, we reviewed our year-end oil reserves on a fair value basis, considering that current oil prices are much lower than the average prices used in our reserve report, which were determined using SEC pricing guidelines. Based on current and forecast oil prices, most of our oil reserves are uneconomic. The result of this review caused us to impair approximately $2.9 million of capital costs associated with our Montana producing properties.
During 2013, we impaired approximately $4.5 million of prior-year costs associated with our Plawce-2 well following its unsuccessful fracture stimulation, along with approximately $0.2 million of prior-year costs associated with our Mieczewo-1K well. In addition, our Zaniemysl-3 well ceased production during 2013, causing us to charge its remaining net book value of $0.4 million to impairment expense. Finally, we recorded an impairment charge of $1.0 million related to concession costs in our Northwest and Warsaw South project areas, where we have dropped acreage that we believe is less prospective for oil and gas accumulations than retained areas. During 2012, we impaired $0.8 million in costs of certain concessions in Poland that we determined were not prospective. Also during 2012, we impaired all capitalized costs associated with our Alberta Bakken project in Montana, which included $1.4 million in drilling costs incurred during 2011 and $0.4 million in leasehold costs.
DD&A Expense—Producing Operations. DD&A expense for producing properties was $4.5 million, $3.6 million, and $3.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. The increase from 2013 to 2014 is a combination of higher DD&A expenses due to increased production at our Lisewo wells, along with higher DD&A expenses resulting from negative revisions in proved reserves at our Lisewo, Komorze, and Roszkow wells. The 16% increase from 2012 to 2013 is due primarily to new production from our Winna Gora and Lisewo-1 wells.
Future DD&A costs are expected to generally, but not completely, follow future production trends. However, future DD&A rates can be very different depending upon future capitalized costs and changes in reserve volumes.
Accretion Expense. Accretion expense was $96,000, $90,000, and $63,000 for the years ended December 31, 2014, 2013 and 2012, respectively. Accretion expense is related entirely to our asset retirement obligation associated with expected future plugging and abandonment costs.
50
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $3.8 million, $1.2 million, and $2.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. We drilled 12 wells for third parties during 2014, along with additional well service work. We drilled three wells for third parties during 2013, along with additional well service work. During 2012, we drilled five wells for third parties, including one drilled for our Alberta Bakken joint venture, along with additional well service work. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors. We cannot accurately predict future oilfield services revenues.
Oilfield Services Costs. Oilfield services costs were $2.5 million, $1.2 million, and $1.6 million for the years ended December 31, 2014, 2013, and 2012, respectively, or 66%, 97%, and 76% of oilfield-servicing revenues, respectively. The changes in services costs from year to year were primarily due to the nature of our drilling activity discussed above, along with higher equipment repair costs in 2013. In general, oilfield-servicing costs are closely associated with oilfield services revenues. As such, oilfield services costs will continue to fluctuate period to period based on the number of wells drilled, revenues generated, weather, downtime for equipment repairs, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.
DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $1.0 million, $1.0 million, and $1.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. We spent $0.8 million, $1.1 million, and $0.7 million on upgrading our oilfield-servicing equipment during 2014, 2013, and 2012, respectively.
Nonsegmented Items
G&A Costs—Corporate. G&A costs were $8.5 million, $8.8 million, and $8.4 million for the years ended December 31, 2014, 2013, and 2012, respectively. The decrease in 2014 is primarily due to lower compensation costs. During 2013, compensation costs included the payment of a company-wide incentive award of approximately $500,000 related to 2008, which had been deferred until we met certain performance benchmarks, which were met in 2013.
Stock Compensation. Stock compensation expense was $2.5 million, $2.9 million, and $2.3 million for the years ended December 31, 2014, 2013, and 2012, respectively, reflecting the amortization related to restricted stock and stock options granted to employees in previous years.
Interest and Other (Income) Expense—Corporate. Interest and other (income) expense was $2.7 million, $3.2 million, and $2.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. During 2014, we incurred $2.8 million in interest expense, which included $0.5 million of amortization of loan fees and $0.4 million in unused commitment fees. Interest and other income expense was $0.1 million during 2014. During 2013, we recorded $1.2 million of amortization of loan fees, including $0.7 million related to our prior credit facility that was charged to interest expense by virtue of our refinance that year and $0.3 million in unused commitment fees. Interest and other income was $0.1 million during 2013. During 2012, we incurred $2.5 million in interest expense, which included $0.5 million of amortization of loan fees and $0.5 million in unused commitment fees. Interest and other income expense was $0.4 million during 2012.
Foreign Exchange. We incurred foreign exchange losses of $26.2 million for the year ended December 31, 2014. We recognized foreign exchange gains of $5.0 million and $16.3 million for the years ended December 31, 2013 and 2012, respectively. Foreign exchange gains and losses arise from decreases and increases, respectively, in the amount of Polish zlotys necessary to satisfy outstanding intercompany and other U.S. dollar-denominated loans and unpaid interest between FX Energy Poland and FX Energy, Inc.
51
Income Taxes. We reported a net loss of $59.2 million and $11.8 million for the years ended December 31, 2014 and 2013, respectively, and net income of $4.1 million for the year ended December 31, 2012. No income tax expense was recognized for 2012 due to the reversal of valuation allowances that offset income tax expense for the period. Accounting standards require that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our exploration and development activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided. Accordingly, we did not recognize any income tax benefit in our consolidated statement of operations for these years.
Proved Reserves
Oil and Gas Reserves
Reserve volumes decreased at year-end 2014 due primarily to negative revisions at several of our wells in Poland due to declining production and wellhead pressures, along with negative revisions in the United States due to a reduction of economic values caused by lower oil prices. New reserves at our Karmin-1, Tuchola-3K, and Tuchola-4K wells partially offset the reduction in our reserves from our 2014 gas production and negative revisions.
The following table highlights year-end reserve volumes and values and shows the change from 2013 to 2014:
| 2014 | 2013 |
Change
|
|||
| Proved Reserve Volumes |
(In thousands)
|
||||
|
Gas reserves (Mcf)
|
37,389
|
42,012
|
-11%
|
||
|
Oil reserves (Bbls)
|
357
|
461
|
-23%
|
||
|
Total reserves (Mcfe)
|
39,531
|
44,778
|
-12%
|
||
|
Proved Reserve Values:
|
|||||
|
Reserve SMOG Value (000s)
|
$133,628
|
$151,802
|
-12%
|
||
Changes in proved reserves were as follows:
|
2014
|
2013
|
2012
|
|||
|
Proved Reserves (MMcfe) Beginning of Year
|
44,778
|
47,688
|
53,470
|
||
|
Extensions, Discoveries, and Other Additions
|
13,315
|
3,947
|
2,313
|
||
|
Revisions of Previous Estimates
|
(14,045)
|
(2,416)
|
(3,317)
|
||
|
Production
|
(4,517)
|
(4,441)
|
(4,778)
|
||
|
Proved Reserves (MMcfe) End of Year
|
39,531
|
44,778
|
47,688
|
Extensions, Discoveries, and Other Additions. All of the 2014 additions to proved reserves that resulted from the discovery of new fields are associated with our Karmin-1, Tuchola-3K, and Tuchola-4K wells in Poland.
Revisions. Revisions represent changes in previous reserve estimates, either positive revisions upward or negative revisions downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. During 2014, excluding the volume reduction due to annual production, we recorded downward revisions at several of our producing wells in Poland. Significant downward revisions were recorded at our Szymanowice well, which we plugged in early 2014 following an unsuccessful sidetrack operation, and at our Komorze and Lisewo wells, whose downhole pressure dropped unexpectedly apparently due to compartmentalization issues. We also disposed of our Grabowka wells due to the large amount of time required to manage the wells compared to their marginal economics. These were partially offset by upward reserve revisions at our Roszkow and Kromolice South wells, where new pressure data indicates that the initial gas-in-place for these wells may be more than estimated at year-end 2013. We also recorded negative revisions of approximately 57,000 barrels of oil in the United States, primarily due to the reduction of economic barrels caused by lower oil prices and higher operating costs.
52
During 2013, excluding the volume reduction due to annual production, we recorded downward revisions at our Grabowka, Zaniemysl-3, Winna Gora, Roszkow, and Lisewo-1 wells due to declining production and wellhead pressures. These were partially offset by upward reserve revisions at our KSK wells, where new pressure data indicates that the initial gas-in-place for these wells may be more than estimated at year-end 2012. We also recorded negative revisions of approximately 84,000 barrels of oil in the United States, primarily due to higher than previously estimated production declines.
During 2012, excluding the volume reduction due to annual production, we recorded downward revisions at our Zaniemysl-3 and KSK wells due to, respectively, water influx and lower than expected wellhead pressures obtained during the fourth quarter of the year. These were partially offset by upward reserve revisions at our Roszkow, Lisewo-1, and Winna Gora wells, where new pressure data indicates that the initial gas-in-place for these wells may be more than estimated at year-end 2011. We also recorded upward revisions of approximately 9,000 barrels of oil in the United States, primarily due to lower operating costs resulting in more economically recoverable barrels. (See Items 1 and 2, Business and Properties).
Production. See “Gas Revenues” and “Oil Revenues” above.
2015 Operational Trends
We currently expect that our 2015 production volume will rise slightly from our 2014 production rates with a full year of production at our Lisewo-2 well, which we believe will be greater than the natural declines in production from our currently producing wells. The amount of revenue from this increased production will depend on applicable gas sales prices and prevailing currency exchange rates.
Future oil revenues from our domestic production will depend on the impact of prices we receive as we continue to experience normal production declines. We cannot accurately predict future oilfield services revenues and related costs, which will continue to fluctuate based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the nature and extent of any equipment upgrading, the degree of emphasis on using our oilfield services equipment on our own properties, and other factors.
Costs that vary in conjunction with production, such as lease operating expenses and DD&A costs, will trend up or down with production increases or decreases. Our 2015 plans for capital expenditures are detailed in the following section, “Liquidity and Capital Resources–Our Capital Resources and Future Expenditures.”
Our U.S. dollar-denominated financial results will continue to be impacted by exchange-rate fluctuations, which cannot be predicted.
Liquidity and Capital Resources
For much of our history, we have financed our operations principally through the sale of equity securities, bank borrowings, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. However, as our oil and gas production has increased in Poland in the last several years, our internally generated cash flow has become a significant source of operations financing.
2014 Liquidity and Capital
Working Capital (current assets less current liabilities). Our working capital was $17.1 million as of December 31, 2014, an increase of $5.8 million from December 31, 2013. The primary cause of the increase is the proceeds from our preferred stock offering.
During 2014, we closed an underwritten public offering of 800,000 shares of our 9.25% Series B Cumulative Convertible Preferred Stock (the “Series B Preferred Stock”) at a public offering price of $25.00 per share. The aggregate gross proceeds from the offering were $20 million, with net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $18.4 million. Cumulative dividends of 9.25%, or $1.9 million per year, are payable out of funds legally available therefor. We are using the proceeds for exploration efforts in our Edge concession in Poland and for general corporate purposes, including declaring and paying dividends on our Series B Preferred Stock.
53
Our current assets at December 31, 2014, included approximately $18.6 million in cash, cash equivalents, and marketable securities, $2.9 million in accrued oil and gas sales from both the United States and Poland, $0.6 million in receivables from our joint interest partners in both the United States and Poland, and a value-added tax receivable in Poland of $0.9 million. At December 31, 2014, $6.7 million of our cash and cash equivalents were held in Poland at ING Bank N.V. We have not historically repatriated, and do not plan in the foreseeable future to repatriate, any cash held in Poland to the United States. Consequently, we do not expect to incur repatriation taxes in the foreseeable future.
Operating Activities. Net cash provided by operations during 2014 and 2013 was $2.1 million and $2.3 million, respectively. Net cash used in operations during 2012 was $1.2 million. Cash flow from operating activities in both years benefited from positive change in working capital items. A $7.2 million increase in exploration costs offset higher revenues in 2012, leading to a decline in cash provided from operating activities in 2012.
Investing Activities. We used net cash in investing activities of $24.8 million, $27.9 million, and $16.3 million in 2014, 2013, and 2012, respectively. In 2014, we spent $16.6 million for oil and gas property additions, $16.0 million of which were related to our Polish drilling activities, with the remainder being spent on our domestic properties. Following the issuance of the Series B Preferred Stock, we purchased $7.4 million of marketable securities. We spent $0.9 million adding to our oilfield services equipment. In 2013, we spent $26.8 million for oil and gas property additions, $26.0 million of which were related to our Polish drilling activities, with the remainder being spent on our domestic properties. We also spent $1.1 million adding to our oilfield services equipment. In 2012, we spent $15.8 million for oil and gas property additions, all of which were related to our Polish drilling activities. We also spent $0.7 million adding to our oilfield services and office equipment.
Financing Activities. Our cash flow from financing activities was $23.6 million, $3.0 million, and $0 during 2014, 2013, and 2012, respectively. During 2014, as described above, we sold 800,000 shares of Series B Preferred Stock during 2014. After associated offering costs, the net proceeds from the offering were approximately $18.4 million, from which we paid preferred dividends of $0.4 million. We also sold 163,639 shares of common stock under our at-the-market agreement in connection with our existing shelf registration. Net proceeds from the stock sale were approximately $0.6 million after deducting associated costs. During 2013, we borrowed $43.0 million under our new credit facility, using $40 million to repay our 2010 credit facility and $2.0 million in fees associated with the new credit facility. There were no financing transactions during 2012.
Our Capital Resources and Future Expenditures
Our anticipated sources of liquidity and capital for 2015 include our working capital of $17.1 million at year-end 2014, credit that may be available under our Senior Secured Credit Facility, and cash available from our operations.
In July 2013, we finalized our Senior Secured Credit Facility with BNP Paribas (Suisse) SA and ING Bank N.V. The initial commitment of the facility amounts to $65 million. We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism. The credit facility calls for a periodic interest rate of LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years. The facility has a term of five years, with scheduled semiannual borrowing base reductions of $13 million beginning on June 30, 2016.
As of December 31, 2014, we had $50 million outstanding under the facility and $5 million of available credit. We are discussing with our lenders an amendment and restatement of our existing facility, which would likely increase our borrowing base beyond the $55 million current level, which was set at our most recent redetermination. However, should these discussions not result in an increased borrowing base or revisions to the amortization language of the existing credit agreement, then we would likely have to begin amortization of our loan in 2015, which would be sooner than the scheduled commitment reductions outlined in our Senior Secured Credit Facility. This amortization would substantially impair the amount of capital we would have available for additional capital expenditures.
54
We expect to generate cash from our operating activities to help fund our exploration and development activities in 2015. We expect that our 2015 production will approximate or be higher than our 2014 production with a full year of production at our Lisewo-2 well. The amount of revenue from our production will depend on applicable gas sales prices and prevailing currency exchange rates.
We have an effective Securities Act universal shelf registration statement under which we may sell up to $200 million of equity or debt securities of various kinds. As discussed above, we closed a $20 million preferred stock offering in 2014, which was made under the shelf registration. In 2012, we entered into an agreement to possibly sell up to $50 million in common stock during the next two years in at-the-market transactions. During 2014, we sold approximately $0.7 million of common stock under that agreement. Currently, we have approximately $179.3 million of securities available for sale at any time under the registration statement, $49.3 million of which is covered by the at-the-market facility. We intend to renew our universal shelf registration statement and at-the-market offering before they expire mid-year. Future issuances of stock under the shelf registration to finance our exploration and development plans in Poland and for other corporate purposes are subject to market conditions and our ability to access the capital markets.
Sidetrack operations in early 2015 at Zaniemysl-3, which were targeting additional gas reserves that appeared to be higher in the Zaniemysl structure than the existing well, were unsuccessful. We were also partially complete on two 3-D seismic surveys in our Fences and Edge concession. Total 2015 costs for these three projects are expected to be approximately $7.3 million. We had no other firm commitments for future capital and exploration costs at 2014 year end. In addition to these projects, we are beginning the process of designing and permitting production facilities at our Karmin-1, Tuchola-3K, and Tuchola-4K wells.
As discussed earlier, we are reducing our exploration and development activities in Poland during 2015 until we have more clarity respecting exchange rates and gas prices in Poland, along with our success in amending and restating our Senior Secured Credit Facility.
The actual amount of our expenditures will depend on ongoing exploration results; the pace at which PGNiG, our operating partner in the Fences project area, wishes to proceed or the extent it wishes to continue to participate with us in concessions we operate; the availability of drilling and other exploration services; and the amount of capital we obtain from the various sources discussed above. Our various sources of liquidity and capital outlined above should enable us to meet our projected capital needs in Poland and the United States for the next 12 months. We have the ability to control the timing and amount of most of our future capital and exploration costs.
We have a history of operating losses, and we may continue to incur operating losses in future periods, as we continue to fund substantial exploration and development in Poland. From our inception in January 1989 through December 31, 2014, we have incurred cumulative net losses of approximately $258 million. Despite our production and revenues, our exploration and production activities may continue to result in net losses in future years, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses.
We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements such as those negotiated in prior years for our Kutno and Warsaw South project areas in which industry participants are bearing the initial exploration costs to earn an interest in the project or other arrangements, all of which may dilute the interests of our existing stockholders or our interest in the specific project financed. Currently we are exploring such a farmout arrangement as a possible source of external capital for Tuchola production and related facilities and further exploration.
We will allocate our existing capital, as well as funds we may obtain in the future, among our various projects at our discretion. We may change the allocation of capital among the categories of anticipated expenditures depending upon future events. For example, we may change the allocation of our expenditures based on the actual results and costs of future exploration, appraisal, development, production, property acquisition, and other activities. In addition, we may have to change our anticipated expenditures if costs of placing any particular discovery into production are higher, if the field is smaller, or if the commencement of production takes longer than expected.
55
Contractual Obligations and Contingent Liabilities and Commitments
Contractual Obligations. At December 31, 2014, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:
|
Total
|
2015
|
2016
|
2017
|
2018
|
|||||
|
Credit facility
|
$50,000
|
$ --
|
$11,000
|
$26,000
|
$13,000
|
||||
|
Interest payments on long-term debt
|
5,604
|
1,958
|
2,021
|
1,354
|
271
|
||||
|
Total
|
$55,604
|
$ 1,958
|
$13,021
|
$27,354
|
$13,271
|
Under the terms of our Senior Secured Credit Facility, the amount of credit available is reduced by $13 million each six months, beginning on June 30, 2016. As of December 31, 2014, we had borrowed $50 million under the facility, and the reduction of that amount is illustrated in the table above.
During the ordinary course of business in Poland, we enter into agreements for the drilling of wells, the construction of production facilities, and for seismic projects. These are typically short-term agreements and are completed in less than one year. We are subject to certain work commitments respecting our 100%-owned exploration concessions that must be satisfied in order to maintain our interest in those concessions. These work commitments are optional on our part; however, they must be satisfied in order to maintain our interest in those concessions. We can request changes to usufruct and concession agreements that either modify the obligations to reduce our commitments or extend the terms of those agreements. In addition, we routinely relinquish acreage that we believe has lower potential rather than continue to be subject to the related work commitment. Our exploration budget and related activities are focused on exploration and long-term exploitation of our most promising exploration opportunities and are not specifically or primarily focused on meeting these work commitments.
Our oil and gas drilling and production operations are subject to hazards incidental to the industry that can cause severe damage to and destruction of property and equipment, pollution or environmental damage, suspension of operations, personal injury, and loss of life. To lessen the effects of these hazards, we maintain insurance of various types to cover our U.S. and Poland operations and also rely on the insurance or financial capabilities of our exploration partners in Poland. These measures do not cover risks related to violations of environmental laws or all other risks involved in oil and gas exploration, drilling, and production. We would be adversely affected by a significant event that is not fully covered by insurance or by our inability to maintain adequate insurance in the future at rates we consider reasonable.
Asset Retirement Obligation. We have liabilities of $2.0 million related to asset retirement obligations on our Consolidated Balance Sheet at December 31, 2014, excluded from the table above. Due to the nature of these obligations, we cannot determine precisely when the payments will be made to settle these obligations.
New Accounting Pronouncements
On May 28, 2014, the Financial Accounting Standards Board issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. generally accepted accounting principles when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method or determined the effect of the standard on our ongoing financial reporting.
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.
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Critical Accounting Policies
Oil and Gas Activities
We follow the successful efforts method of accounting for our oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, these costs plus the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that net capitalized costs of unproved properties, on a property-by-property basis, are not considered to be realizable. An impairment loss is recorded if the net capitalized costs of proved oil and gas properties exceed the aggregate undiscounted future net cash flows determined on a property-by-property basis. The impairment loss recognized equals the excess of net capitalized costs over the related fair value, determined on a property-by-property basis. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as a recovery of costs, and any resulting gain or loss is recorded as other income. Revenues associated with oil and gas sales are recorded when title passes, which is upon delivery to the pipeline or purchaser, and are net of royalties. Oilfield service revenues are recognized when the related service is performed. As a result of the foregoing, our results of operations for any particular period may not be indicative of the results that could be expected over longer periods.
Oil and Gas Reserves
All of the reserve data in this Form 10-K are estimates. Estimates of our crude oil and natural gas reserves are prepared by our engineers in accordance with guidelines established by the Securities and Exchange Commission. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserve estimate. We based our December 31, 2014, reserve estimates on a 12-month average commodity price, unless contractual arrangements designated the price to be used, in accordance with Securities and Exchange Commission rules. However, oil and gas prices are volatile and, as a result, our reserve estimates will change in the future.
Estimates of proved crude oil and natural gas reserves significantly affect our DD&A expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of crude oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. See Item 8, Financial Statements and Supplementary Data–Supplemental Information.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period.
57
|
ITEM 7A. QUANTITATIVE AND QUALITATIVE
|
|
DISCLOSURES ABOUT MARKET RISK
|
Price Risk
Substantially all of our gas in Poland is sold to PGNiG or its affiliates under contracts that extend for the life of each field. Prices are determined contractually and, in the case of our producing wells in Poland, are tied to published tariffs. The tariffs are set from time to time by the public utility regulator in Poland. Although we are not directly subject to such tariffs, we have agreed to link our price to these tariffs in our contracts with PGNiG. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in an unregulated setting and may be lower than prevailing Western European prices. We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.
Realized pricing for our oil production in the United States is primarily driven by the prevailing worldwide price of oil, subject to gravity and other adjustments for the actual oil sold. Historically, oil prices have been volatile and unpredictable. Price volatility relating to our oil production is expected to continue in the foreseeable future.
We currently do not engage in any hedging activities to protect ourselves against market risks associated with oil and gas price fluctuations, although we may elect to do so in the future.
Foreign Currency Risk
We enter into various agreements in Poland denominated in the Polish zloty. The exchange rate between the U.S. dollar and the Polish zloty is subject to fluctuations that are beyond our control. During 2014, the zloty fluctuated between a low of 3.00 zlotys per dollar to a high of 3.55 zlotys per dollar, a fluctuation of 18%. Variations in exchange rates affect the dollar-denominated amount of revenue we receive in zlotys. As the dollar strengthens relative to the zloty, our dollar-denominated revenue received in zlotys declines; on the other hand, when the dollar weakens relative to the zloty, our dollar-denominated revenue received in zlotys increases. Conversely, a weak dollar leads to lower dollar-denominated drilling, capital, and exploration costs, while a strong dollar has the opposite effect for the cost structure of our Polish operations. Should exchange rates in effect during early 2015 continue throughout the year, we expect the exchange rates to have a negative impact on our dollar-denominated revenues compared to 2014. We are also generating revenues in Poland in zlotys, and we keep those zlotys in Poland and use them to pay zloty-based invoices.
Subsequent to year-end 2014, we entered into two separate dollar/zloty hedge agreements. The agreements are in the form of a costless collar, with floors of approximately 3.57 PLN/USD and ceilings of approximately 3.85 PLN/USD. One of the agreements, in the amount of $6.0 million, terminates on June 26, 2015, and the other, in the amount of $6.5 million, terminates on December 29, 2015. If on the settlement date of the agreements, the exchange rate is more than 3.85 PLN, the hedge will be terminated in our favor. If, on the other hand, the exchange rate is less than 3.57 PLN, we will be required to settle the difference.
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
Our consolidated financial statements, including the independent registered public accounting firm’s report on our consolidated financial statements, are included beginning at page F-1 immediately following the signature page of this report.
58
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
|
|
ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
None.
|
ITEM 9A. CONTROLS AND PROCEDURES
|
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the periods specified by the Securities and Exchange Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2014, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2014, our disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management of FX Energy, Inc., together with its consolidated subsidiaries (the Company), is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed by our principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles.
As of the end of our 2014 fiscal year, management conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has determined that our internal control over financial reporting as of December 31, 2014, was effective.
Our internal control over financial reporting includes policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our consolidated financial statements.
59
The effectiveness of our internal control over financial reporting as of December 31, 2014, has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that follows.
/s/ David N. Pierce
President and Chief Executive Officer
/s/ Clay Newton
Principal Financial and Accounting Officer
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
FX Energy, Inc.
We have audited the internal control over financial reporting of FX Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2014, and our report dated March 16, 2015 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Salt Lake City, Utah
March 16, 2015
60
|
ITEM 9B. OTHER INFORMATION
|
None.
PART III
|
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
The information from our definitive proxy statement for our 2015 annual meeting of stockholders under the captions “Corporate Governance,” “Proposal 1. Election of Directors,” and “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.
|
ITEM 11. EXECUTIVE COMPENSATION
|
The information from our definitive proxy statement for our 2015 annual meeting of stockholders under the caption “Executive Compensation” is incorporated herein by reference.
|
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
|
|
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
The information from our definitive proxy statement for our 2015 annual meeting of stockholders under the captions “Principal Stockholders” and “Equity Compensation Plans” is incorporated herein by reference.
|
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
|
|
AND DIRECTOR INDEPENDENCE
|
The information from our definitive proxy statement for our 2015 annual meeting of stockholders under the captions “Certain Relationships and Related-Party Transactions” and “Director Independence” is incorporated herein by reference.
61
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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
|
The information from our definitive proxy statement for our 2015 annual meeting of stockholders under the caption “Relationship with Independent Auditors” is incorporated herein by reference.
PART IV
|
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
(a) The following documents are filed as part of this report or incorporated herein by reference.
|
|
1.
|
Financial Statements. See the following beginning at page F-1:
|
|
Page
|
|
|
Report of Independent Registered Public Accounting Firm
|
F-1
|
|
Report of Independent Registered Public Accounting Firm
|
F-2
|
|
Consolidated Balance Sheets as of December 31, 2014 and 2013
|
F-3
|
|
Consolidated Statements of Operations for the Years Ended
|
|
|
December 31, 2014, 2013, and 2012
|
F-5
|
|
Consolidated Statements of Comprehensive Loss for the Years Ended
|
|
|
December 31, 2014, 2013, and 2012
|
F-6
|
|
Consolidated Statements of Cash Flows for the Years Ended
|
|
|
December 31, 2014, 2013, and 2012
|
F-7
|
|
Consolidated Statement of Stockholders’ Equity (Deficit) for the Years
|
|
|
Ended December 31, 2014, 2013, and 2012
|
F-8
|
|
Notes to the Consolidated Financial Statements
|
F-9
|
|
|
2.
|
Supplemental Schedules. The supplemental schedules have been omitted because they are not applicable or the required information is otherwise included in the accompanying consolidated financial statements and the notes thereto.
|
|
|
3.
|
Exhibits. The following exhibits are included as part of this report:
|
|
Exhibit
Number*
|
Title of Document
|
Location
|
||
|
Item 1
|
Underwriting Agreement
|
|||
|
1.01
|
At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC
|
See Exhibits 10.99 and 10.107
|
||
|
1.02
|
Underwriting Agreement dated July 10, 2014, between and among FX Energy, Inc., and MLV & Co. LLC and Euro Pacific Capital, Inc., for themselves and as representatives of the underwriters named in Schedule II thereto
|
Incorporated by reference from the current report on Form 8-K filed July 14, 2014.
|
||
|
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.
|
||
62
|
Exhibit
Number*
|
Title of Document
|
Location
|
||
|
3.03
|
Articles of Amendment to the Restated Articles of Incorporation of FX Energy, Inc.
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2005, filed March 14, 2006.
|
||
|
3.04
|
Amendment to Articles of Incorporation Revising and Restating Designation of Rights, Privileges, and Preferences of Series A Preferred Stock
|
Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended June 30, 2007, filed August 8, 2007.
|
||
|
3.05
|
Bylaws of FX Energy, Inc., as amended March 12, 2014
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2013, filed March 13, 2014.
|
||
|
3.06
|
Amendment to the Articles of Incorporation Designating Rights, Privileges, and Preferences of 9.25% Series B Cumulative Convertible Preferred Stock dated July 11, 2014
|
Incorporated by reference from the current report on Form 8-K filed July 14, 2014.
|
||
|
Item 4
|
Instruments Defining the Rights of Security Holders
|
|||
|
4.01
|
Specimen Common Stock Certificate
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2006, filed March 13, 2007.
|
||
|
4.04
|
Rights Agreement dated as of April 4, 2007, between FX Energy, Inc. and Fidelity Transfer Company
|
Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended June 30, 2007, filed August 8, 2007.
|
||
|
4.05
|
Amendment to Rights Agreement dated as of March 7, 2011
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2010, filed March 7, 2011.
|
||
|
Item 10
|
Material Contracts
|
|||
|
10.53
|
Agreement on Cooperation in Exploration of Hydrocarbons on Foresudetic Monocline dated April 11, 2000, between Polskie Górnictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG] and FX Energy Poland, Sp. z o.o. relating to Fences I project area
|
Incorporated by reference from the current report on Form 8-K filed May 2, 2000.
|
||
|
10.62
|
Agreement Regarding Cooperation within the Poznan Area (Fences II) entered into January 8, 2003, by and between Polskie Górnictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG] and FX Energy Poland Sp. z o.o.
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2002, filed March 27, 2003.
|
||
|
10.63
|
Settlement Agreement Regarding the Fences I Area entered into January 8, 2003, by and between Polskie Górnictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG] and FX Energy Poland Sp. z o.o.
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2002, filed March 27, 2003.
|
||
63
|
Exhibit
Number*
|
Title of Document
|
Location
|
||
|
10.64
|
Farmout Agreement Entered into by and between FX Energy Poland Sp. z o.o. and CalEnergy Power (Polska) Sp. z o.o. covering the “Fences Area” in the Foresudetic Monocline made as of January 9, 2003
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2002, filed March 27, 2003.
|
||
|
10.74
|
Greater Zaniemysl Area Agreement made as of March 12, 2004, among FX Energy Poland Sp. z o.o. and CalEnergy Resources Poland Sp. z o.o.
|
Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended March 31, 2004, filed May 11, 2004.
|
||
|
10.75
|
Form of Indemnification Agreement between FX Energy, Inc. and directors and officers with related schedule**
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2008, filed March 16, 2009.
|
||
|
10.77
|
Description of compensation arrangement with executive officers and directors**
|
This filing.
|
||
|
10.78
|
Form of Employment Agreement with related schedule**
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2006, filed March 13, 2007.
|
||
|
10.79
|
Change in Control Compensation Agreement with related schedule**
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2006, filed March 13, 2007.
|
||
|
10.82
|
Letter of Engagement, H. Allen Turner, dated February 14, 2007
|
Incorporated by reference from the current report on Form 8-K filed February 20, 2007.
|
||
|
10.87
|
Restated FX Energy, Inc. 401(k) Stock Bonus Plan dated January 25, 2007**
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2006, filed March 13, 2007.
|
||
|
10.89
|
Agreement No. PL/012216736/05-0030/DH/HB for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG], dated December 8, 2005 [Zaniemysl]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2006, filed March 13, 2007.
|
||
|
10.90
|
Agreement for the Sale of Wellhead Natural Gas between FX Energy Poland Sp. z o.o. and PL Energia S.A., dated January 26, 2007 [Grabowka]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2006, filed March 13, 2007.
|
||
|
10.92
|
Amendment and Reconfirmation of Supplemental Indemnification Agreement between FX Energy, Inc. and Dennis B. Goldstein
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2008, filed March 16, 2009.
|
||
|
10.93
|
Agreement No. for the Sale of Natural Gas between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A. [POGC-PGNiG], dated June 19, 2009 [Roszkow]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2009, filed March 17, 2010.
|
||
|
10.99
|
At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC
|
Incorporated by reference from the current report on Form 8-K filed December 23, 2010.
|
||
64
|
Exhibit
Number*
|
Title of Document
|
Location
|
||
|
10.100
|
Form of Relinquishment Agreement dated August 9, 2011, with schedule of signatories
|
Incorporated by reference from the current report on Form 8-K filed August 10, 2011.
|
||
|
10.101
|
FX Energy, Inc., 2011 Incentive Plan
|
Incorporated by reference from the definitive Proxy Statement on Schedule 14A filed August 8, 2011.
|
||
|
10.102
|
Participation Agreement among American Eagle Energy Inc., Big Sky Operating LLC, and FX Producing Company, Inc. [Alberta Bakken]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
|
||
|
10.103
|
Cenex Contract Number 3000748 Amendment No. 1 between Cenex Harvest States Cooperatives and FX Drilling Company, Inc.
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
|
||
|
10.104
|
Agreement no 10/K/Z/2010 for the Sale of Natural Gas concluded between FX Energy Poland Sp. z o.o. and Polish Oil and Gas S.A. [KSK]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
|
||
|
10.105
|
Joint Operating Agreement between Polskie Górnictwo Naftowe i Gazownictwo S.A. [PGNiG] and FX Energy Poland Sp. z o.o. [Warsaw South]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2011, filed March 12, 2012.
|
||
|
10.106
|
Amendment No. 1 to At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak, LLC
|
Incorporated by reference from the current report on Form 8-K filed August 24, 2012.
|
||
|
10.107
|
Agreement no 11/K/Z/2012 for the Sale of Natural Gas concluded between FX Energy Poland Sp. z o.o. and Polish Oil and Gas S.A. [Winna Gora]
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2012, filed March 14, 2013.
|
||
|
10.108
|
Up to USD 100,000,000 Senior Reserve Base Lending Facility Agreement among FX Energy Poland Sp. z o.o., FX Energy, Inc., FX Energy Netherlands Partnership C.V., FX Energy Netherlands B.V., BNP Paribas (Suisse) SA and ING Bank N.V. dated July 3, 2013
|
Incorporated by reference from the current report on Form 8-K filed July 17, 2013.
|
||
|
10.109
|
Intercreditor Deed among FX Energy Poland Sp. z o.o, BNP Paribas (Suisse) SA, ING Bank N.V., BNP Paribas SA, and the subordinated lenders dated July 3, 2013
|
Incorporated by reference from the current report on Form 8-K filed July 17, 2013.
|
||
|
10.110
|
Deed of Pledge of Registered Shares among Frontier Exploration Company and FX Drilling Company, Inc., in their capacity of general partners of FX Energy Netherlands Partnership C.V.; BNP Paribas (Suisse) SA; and FX Energy Netherlands B.V., dated July 5, 2013
|
Incorporated by reference from the current report on Form 8-K filed July 17, 2013.
|
||
|
10.111
|
Agreement No. 12/KZ/2013 for the Sale of Gas from Lisewo gas field between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A.
|
Incorporated by reference from the quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed August 8, 2013.
|
65
|
Exhibit
Number*
|
Title of Document
|
Location
|
||
|
10.112
|
Agreement No. 13/KZ/2013 for the Sale of Gas from Komorze gas field between FX Energy Poland Sp. z o.o. and Polskie Górnictwo Naftowe i Gazownictwo S.A.
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2013, filed March 13, 2014.
|
||
|
Item 21
|
Subsidiaries of the Registrant
|
|||
|
21.01
|
Schedule of Subsidiaries
|
Incorporated by reference from the annual report on Form 10-K for the year ended December 31, 2007, filed March 10, 2008.
|
||
|
Item 23
|
Consents of Experts and Counsel
|
|||
|
23.01
|
Consent of Grant Thornton, independent registered public accounting firm
|
This filing.
|
||
|
23.02
|
Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm
|
This filing.
|
||
|
23.03
|
Consent of Hohn Engineering PLLC, Petroleum Engineers
|
This filing.
|
||
|
23.04
|
Consent of RPS Energy, Petroleum Engineers
|
This filing.
|
||
|
Item 31
|
Rule 13a-14(a)/15d-14(a) Certifications
|
|||
|
31.01
|
Certification of Principal Executive Officer Pursuant to Rule 13a-14
|
This filing.
|
||
|
31.02
|
Certification of Principal Financial Officer Pursuant to Rule 13a-14
|
This filing.
|
||
|
Item 32
|
Section 1350 Certifications
|
|||
|
32.01
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer)
|
This filing.
|
||
|
32.02
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Principal Financial Officer)
|
This filing.
|
||
|
Item 99
|
Additional Exhibits
|
|||
|
99.01
|
Evaluation of Polish Gas Assets of RPS Energy, Petroleum Engineers
|
This filing.
|
||
|
99.02
|
Appraisal of Certain Properties of Hohn Engineering PLLC, Petroleum Engineers
|
This filing.
|
||
|
Item 101
|
Interactive Data
|
|||
|
101
|
Interactive Data files
|
This filing.
|
_______________
|
*
|
All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601, and the number following the decimal indicating the sequence of the particular document. Omitted numbers in the sequence refer to documents previously filed as an exhibit, but no longer required.
|
|
**
|
Identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit, as required by Item 15(a)(3) of Form 10-K.
|
66
|
SIGNATURES
|
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
FX ENERGY, INC. (Registrant)
|
|||
|
Dated: March 16, 2015
|
By:
|
/s/ David N. Pierce
|
|
|
David N. Pierce
|
|||
|
President and Chief Executive Officer
|
|||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
/s/ David N. Pierce
|
||
|
Dated: March 16, 2015
|
David N. Pierce, Director, President,
|
|
|
and Principal Executive Officer
|
||
|
/s/ Dennis B. Goldstein
|
||
|
Dated: March 16, 2015
|
Dennis B. Goldstein, Director
|
|
|
/s/ Arnold S. Grundvig, Jr.
|
||
|
Dated: March 16, 2015
|
Arnold S. Grundvig, Jr., Director
|
|
|
/s/ Jerzy B. Maciolek
|
||
|
Dated: March 16, 2015
|
Jerzy B. Maciolek, Director
|
|
|
/s/ H. Allen Turner
|
||
|
Dated: March 16, 2015
|
H. Allen Turner, Director
|
|
|
/s/ Clay Newton
|
||
|
Dated: March 16, 2015
|
Clay Newton, Principal Financial and
|
|
|
Accounting Officer
|
67
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
|
Board of Directors and Shareholders
FX Energy, Inc.
We have audited the accompanying consolidated balance sheets of FX Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of FX Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2015, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ GRANT THORNTON LLP
Salt Lake City, Utah
March 16, 2015
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors
of FX Energy, Inc. and its subsidiaries
In our opinion, the consolidated statements of operations, of comprehensive income (loss), of cash flows and of stockholders’ equity for the year ended December 31, 2012 present fairly, in all material respects, the results of their operations and their cash flows for the year ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Denver, Colorado
March 14, 2013
F-2
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2014 and 2013
(in thousands)
|
2014
|
2013
|
||||
|
ASSETS
|
|||||
|
Current assets:
|
|||||
|
Cash and cash equivalents
|
$
|
11,232
|
$
|
11,153
|
|
|
Marketable securities
|
7,313
|
--
|
|||
|
Receivables:
|
|||||
|
Accrued oil and gas sales
|
2,948
|
3,464
|
|||
|
Joint interest and other receivables
|
551
|
5,029
|
|||
|
Value-added tax receivable
|
895
|
1,847
|
|||
|
Inventory
|
97
|
100
|
|||
|
Other current assets
|
415
|
234
|
|||
|
Total current assets
|
23,451
|
21,827
|
|||
|
Property and equipment, at cost:
|
|||||
|
Oil and gas properties (successful-efforts method):
|
|||||
|
Proved
|
65,621
|
85,244
|
|||
|
Unproved
|
1,991
|
2,404
|
|||
|
Other property and equipment
|
12,738
|
11,857
|
|||
|
Gross property and equipment
|
80,350
|
99,505
|
|||
|
Less accumulated depreciation, depletion, and amortization
|
(26,867)
|
(23,369)
|
|||
|
Net property and equipment
|
53,483
|
76,136
|
|||
|
Other assets:
|
|||||
|
Certificates of deposit
|
406
|
406
|
|||
|
Loan fees
|
1,553
|
2,323
|
|||
|
Total other assets
|
1,959
|
2,729
|
|||
|
Total assets
|
$
|
78,893
|
$
|
100,692
|
|
-Continued-
The accompanying notes are an integral part of these consolidated financial statements.
F-3
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2013 and 2012
(in thousands, except share data)
-Continued-
|
2014
|
2013
|
||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|||||
|
Current liabilities:
|
|||||
|
Accounts payable
|
$
|
5,036
|
$
|
9,694
|
|
|
Accrued liabilities
|
821
|
833
|
|||
|
Accrued dividends
|
463
|
--
|
|||
|
Total current liabilities
|
6,320
|
10,527
|
|||
|
Long-term liabilities:
|
|||||
|
Notes payable
|
50,000
|
45,000
|
|||
|
Asset retirement obligation
|
1,989
|
1,620
|
|||
|
Total long-term liabilities
|
51,989
|
46,620
|
|||
|
Total liabilities
|
58,309
|
57,147
|
|||
|
Commitments and Contingencies (Note 6)
|
|||||
|
Stockholders’ equity:
|
|||||
|
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of
|
|||||
|
December 31, 2014 and 2013; 800,000 and 0 shares outstanding as
|
|||||
|
December 31, 2014 and 2013, respectively
|
1
|
--
|
|||
|
Common stock, $0.001 par value, 100,000,000 shares authorized as of
|
|||||
|
December 31, 2014 and 2013; 54,401,967 and 53,733,398 shares issued
|
|||||
|
and outstanding as of December 31, 2014 and 2013, respectively
|
54
|
54
|
|||
|
Additional paid-in capital
|
248,186
|
226,060
|
|||
|
Cumulative translation adjustment
|
30,072
|
15,025
|
|||
|
Accumulated other comprehensive loss
|
(67)
|
--
|
|||
|
Accumulated deficit
|
(257,662)
|
(197,594)
|
|||
|
Total stockholders’ equity
|
20,584
|
43,545
|
|||
|
Total liabilities and stockholders’ equity
|
$
|
78,893
|
$
|
100,692
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2014, 2013, and 2012
(in thousands, except per share amounts)
|
2014
|
2013
|
2012
|
||||||
|
Revenues:
|
||||||||
|
Oil and gas sales
|
$
|
34,265
|
$
|
33,311
|
$
|
34,461
|
||
|
Oilfield services
|
3,761
|
1,218
|
2,137
|
|||||
|
Total revenues
|
38,026
|
34,529
|
36,598
|
|||||
|
Operating costs and expenses:
|
||||||||
|
Lease operating expenses
|
4,745
|
3,680
|
3,631
|
|||||
|
Exploration costs
|
21,173
|
20,792
|
23,795
|
|||||
|
Impairment of oil and gas properties
|
23,293
|
6,129
|
2,562
|
|||||
|
Loss on sale of assets
|
--
|
--
|
49
|
|||||
|
Oilfield services costs
|
2,486
|
1,179
|
1,610
|
|||||
|
Depreciation, depletion, and amortization (DD&A)
|
5,531
|
4,573
|
4,239
|
|||||
|
Accretion expense
|
96
|
90
|
63
|
|||||
|
Stock compensation
|
2,495
|
2,853
|
2,325
|
|||||
|
General and administrative costs (G&A)
|
8,500
|
8,836
|
8,369
|
|||||
|
Total operating costs and expenses
|
68,319
|
48,132
|
46,643
|
|||||
|
Operating loss
|
(30,293)
|
(13,603)
|
(10,045)
|
|||||
|
Other income (expense):
|
||||||||
|
Interest expense
|
(2,824)
|
(3,269)
|
(2,485)
|
|||||
|
Interest and other income
|
75
|
105
|
356
|
|||||
|
Foreign exchange gain (loss)
|
(26,178)
|
4,967
|
16,292
|
|||||
|
Total other income (expense)
|
(28,927)
|
1,803
|
14,163
|
|||||
|
Net income (loss)
|
$
|
(59,220)
|
$
|
(11,800)
|
$
|
4,118
|
||
|
Dividends on preferred stock
|
(848)
|
--
|
--
|
|||||
|
Net income (loss) attributable to common stockholders
|
$
|
(60,068)
|
$
|
(11,800)
|
$
|
4,118
|
||
|
Basic and diluted
net income (loss) per common share
|
$
|
(1.12)
|
$
|
(0.22)
|
$
|
0.08
|
||
|
Basic and diluted weighted average number
|
||||||||
|
of shares outstanding
|
53,416
|
52,752
|
52,274
|
|||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
For the years ended December 31, 2014, 2013, and 2012
(in thousands)
|
2014
|
2013
|
2012
|
||||||
|
Net income (loss)
|
$
|
(59,220)
|
$
|
(11,800)
|
$
|
4,118
|
||
|
Other comprehensive income (loss)
|
||||||||
|
Decrease in market value of available
|
||||||||
|
for sale marketable securities
|
(67)
|
--
|
--
|
|||||
|
Foreign currency translation adjustment
|
15,047
|
(3,002)
|
(10,937)
|
|||||
|
Comprehensive loss
|
$
|
(44,240)
|
$
|
(14,802)
|
$
|
(6,819)
|
||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2014, 2013, and 2012
(in thousands)
|
2014
|
2013
|
2012
|
||||||
|
Cash flows from operating activities:
|
||||||||
|
Net income (loss)
|
$
|
(59,220)
|
$
|
(11,800)
|
$
|
4,118
|
||
|
Adjustments to reconcile net income (loss) to net cash provided by
|
||||||||
|
(used in) operating activities:
|
||||||||
|
Depreciation, depletion, and amortization
|
5,531
|
4,573
|
4,239
|
|||||
|
Impairment of oil and gas properties
|
23,256
|
6,129
|
6,979
|
|||||
|
Accretion expense
|
96
|
90
|
63
|
|||||
|
Loss on property dispositions
|
--
|
--
|
49
|
|||||
|
Stock compensation
|
2,495
|
2,853
|
2,325
|
|||||
|
Foreign exchange (gains) losses
|
26,149
|
(4,986)
|
(16,289)
|
|||||
|
Common stock issued for services (G&A)
|
655
|
694
|
666
|
|||||
|
Asset retirement obligation revisions
|
--
|
(6)
|
408
|
|||||
|
Loan fee amortization
|
494
|
1,182
|
504
|
|||||
|
Increase (decrease) from changes in working capital items:
|
||||||||
|
Receivables
|
5,066
|
2,097
|
(2,905)
|
|||||
|
Inventory
|
4
|
98
|
(2)
|
|||||
|
Other current assets
|
(185)
|
370
|
(50)
|
|||||
|
Other assets
|
--
|
(25)
|
25
|
|||||
|
Accounts payable and accrued liabilities
|
(2,221)
|
1,089
|
(1,320)
|
|||||
|
Asset retirement obligations settled
|
--
|
(50)
|
(43)
|
|||||
|
Net cash provided by (used in) operating activities
|
2,120
|
2,308
|
(1,233)
|
|||||
|
Cash flows from investing activities:
|
||||||||
|
Additions to oil and gas properties
|
(16,555)
|
(26,792)
|
(15,836)
|
|||||
|
Additions to other property and equipment
|
(897)
|
(1,153)
|
(735)
|
|||||
|
Purchases of marketable securities
|
(7,379)
|
--
|
--
|
|||||
|
Proceeds from sale of assets
|
--
|
--
|
221
|
|||||
|
Net cash used in investing activities
|
(24,831)
|
(27,945)
|
(16,350)
|
|||||
|
Cash flows from financing activities:
|
||||||||
|
Proceeds from issuance of common stock, net of offering costs
|
615
|
--
|
--
|
|||||
|
Proceeds from notes payable, net of deferred loan fees
|
5,000
|
42,964
|
--
|
|||||
|
Payment of preferred stock dividends
|
(385)
|
--
|
--
|
|||||
|
Payments of notes payable
|
--
|
(40,000)
|
--
|
|||||
|
Proceeds from issuance of preferred stock, net of offering costs
|
18,357
|
--
|
--
|
|||||
|
Net cash provided by financing activities
|
23,587
|
2,964
|
--
|
|||||
|
Effect of exchange rate changes on cash
|
(797)
|
(164)
|
714
|
|||||
|
Net increase (decrease) in cash
|
79
|
(22,837)
|
(16,869)
|
|||||
|
Cash and cash equivalents at beginning of year
|
11,153
|
33,990
|
50,859
|
|||||
|
Cash and cash equivalents at end of year
|
$
|
11,232
|
$
|
11,153
|
$
|
33,990
|
||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
FX ENERGY, INC., AND SUBSIDIARIES
Consolidated Statement of Stockholders’ Equity
For the years ended December 31, 2014, 2013, and 2012
(in thousands)
|
Preferred Stock
|
Common Stock
|
Accumulated
|
Total
|
||||||||||||||||||
| $0.001 |
$0.001
|
Additional
|
Other
|
Stockholders’
|
|||||||||||||||||
|
Shares
|
Par |
Shares
|
Par
|
Paid-in
|
Comprehensive
|
Accumulated
|
Equity
|
||||||||||||||
|
Issued
|
Value |
Issued
|
Value
|
Capital
|
Income (Loss)
|
Deficit
|
(Deficit)
|
||||||||||||||
|
Balance as of December 31, 2011
|
--
|
$ |
--
|
52,787
|
$
|
53
|
$
|
219,522
|
$
|
28,964
|
$
|
(189,912)
|
$
|
58,627
|
|||||||
|
Common stock issued for services
|
--
|
--
|
460
|
--
|
666
|
--
|
--
|
666
|
|||||||||||||
|
Stock compensation
|
--
|
--
|
--
|
--
|
2,325
|
--
|
--
|
2,325
|
|||||||||||||
|
Other comprehensive loss
|
--
|
--
|
--
|
--
|
--
|
(10,937)
|
--
|
(10,937)
|
|||||||||||||
|
Net income for year
|
--
|
--
|
--
|
--
|
--
|
--
|
4,118
|
4,118
|
|||||||||||||
|
Balance as of December 31, 2012
|
--
|
--
|
53,247
|
53
|
222,513
|
18,027
|
(185,794)
|
54,799
|
|||||||||||||
|
Common stock issued for services
|
--
|
--
|
486
|
1
|
694
|
--
|
--
|
695
|
|||||||||||||
|
Stock compensation
|
--
|
--
|
--
|
--
|
2,853
|
--
|
--
|
2,853
|
|||||||||||||
|
Other comprehensive loss
|
--
|
--
|
--
|
--
|
--
|
(3,002)
|
--
|
(3,002)
|
|||||||||||||
|
Net loss for year
|
--
|
--
|
--
|
--
|
--
|
--
|
(11,800)
|
(11,800)
|
|||||||||||||
|
Balance as of December 31, 2013
|
--
|
--
|
53,733
|
54
|
226,060
|
15,025
|
(197,594)
|
43,545
|
|||||||||||||
|
Common stock issued for services
|
--
|
--
|
505
|
--
|
660
|
--
|
--
|
660
|
|||||||||||||
|
Stock compensation
|
--
|
--
|
--
|
--
|
2,495
|
--
|
--
|
2,495
|
|||||||||||||
|
Issuance of preferred stock, net of costs
|
800
|
1
|
--
|
--
|
18,356
|
--
|
--
|
18,357
|
|||||||||||||
|
Issuance of common stock, net of costs
|
--
|
--
|
164
|
--
|
615
|
--
|
--
|
615
|
|||||||||||||
|
Preferred stock dividends
|
--
|
--
|
--
|
--
|
--
|
--
|
(848)
|
(848)
|
|||||||||||||
|
Other comprehensive loss
|
--
|
--
|
--
|
--
|
--
|
14,980
|
--
|
14,980
|
|||||||||||||
|
Net loss for year
|
--
|
--
|
--
|
--
|
--
|
--
|
(59,220)
|
(59,220)
|
|||||||||||||
|
Balance as of December 31, 2014
|
800
|
$ |
1
|
54,402
|
$
|
54
|
$
|
248,186
|
$
|
30,005
|
$
|
(257,662)
|
$
|
20,584
|
|||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-8
FX ENERGY, INC., AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
Organization
FX Energy, Inc., a Nevada corporation, together with its subsidiaries (collectively referred to hereinafter as “us,” “we,” “our,” or “the Company”), is an independent oil and gas exploration and production company with principal production, reserves, and exploration in Poland and oil production, oilfield service, and exploration activities in the United States. In Poland, we have projects involving the exploration and exploitation of oil and gas prospects in partnership with Polskie Górnictwo Naftowe i Gazownictwo (“PGNiG”), the Polish national oil and gas company, 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 FX Energy, Inc., 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, 2014, we owned 100% of the voting common stock or other equity securities of our subsidiaries.
Cash and Cash Equivalents
We consider all highly liquid 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 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, 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 for oilfield services and from our industry partners. Substantially all of our Polish receivables are with PGNiG or one of its affiliates, and substantially all of our domestic receivables are with Cenex, a regional refiner and marketer. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts at December 31, 2014 and 2013. The majority of our cash and cash equivalents are held by four financial institutions in Utah, Montana, and Poland.
Inventory
Inventory consists primarily of tubular goods and production-related equipment and is valued at the lower of average cost or market.
F-9
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 then 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 field-by-field basis, are not considered to be realizable. Depreciation, depletion, 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 discounted future net cash flows determined on field-by-field 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.
Total dry-hole costs of $10.4 million in 2014 were principally related with our Polish Baraniec-1 and Angowice-2 wells, along with some costs associated with an unsuccessful recompletion at our Szymanowice well that was drilled in 2013. Dry-hole costs of $6.7 million in 2013 were principally related to the Mieczewo-1K and Plawce-2 wells in Poland. Dry-hole costs of $12.7 million in 2012 were principally related to the Kutno-2 well drilled in Poland and one Alberta Bakken well drilled in Montana.
During 2014, we recorded impairments of oil and gas properties of $23.3 million. As part of narrowing our operational focus moving forward, we dropped our concession blocks 246 and 287 and impaired the concession costs associated with those blocks, which totaled approximately $0.3 million. In addition, we also impaired the costs of the Frankowo and Gorka Duchowna wells, located in Block 246, with costs of approximately $9.2 million. We also sold our interest in the Grabowka wells, located in Block 287, with costs totaling approximately $0.1 million. Finally, we impaired prior-year costs at our Szymanowice and Komorze wells of $3.7 million and $7.1 million, respectively, as those wells were determined to be uneconomic during the year. In the United States, we also impaired approximately $2.9 million of costs associated with all of our producing oil wells, where the majority of our reserves, measured at current prices, became uneconomic due to the recent decline in these prices.
During 2013, we recorded impairments of oil and gas properties of $6.1 million. We relinquished certain concessions in Poland, impairing the remaining capitalized costs of $1.0 million. In addition, we impaired approximately $4.5 million of prior-year costs associated with our Plawce-2 well following its unsuccessful fracture stimulation, along with approximately $200,000 of prior-year costs associated with our Mieczewo-1K well. Finally, our Zaniemysl-3 well ceased production during 2013, causing us to charge its remaining net book value of $367,000 to impairment expense.
During 2012, we recorded impairments of oil and gas properties of $2.6 million. We relinquished certain concessions in Poland, impairing the remaining capitalized costs of $787,000. In Montana, we determined that our Alberta Bakken-related wells and leases were not prospective for hydrocarbon potential. We impaired the remaining capitalized costs of $1.8 million. The $7.0 million of impairment of oil and gas properties on the statements of cash flows includes both the $2.6 million of impairment recognized, as well as $4.4 million of exploration costs capitalized in 2011 related to the Kutno-1 dry hole, which were recognized in the third quarter of 2012.
F-10
The following table reflects the net changes in capitalized exploratory well costs, which are capitalized pending the determination of proved reserves:
|
Year Ended December 31,
|
||||||||
|
2014
|
2013
|
2012
|
||||||
|
(in thousands)
|
||||||||
|
Beginning balance at January 1
|
$
|
19,241
|
$
|
11,160
|
$
|
9,965
|
||
|
Additions to capitalized exploratory well costs
|
||||||||
|
pending the determination of proved reserves
|
6,335
|
13,022
|
6,984
|
|||||
|
Reclassifications to wells, facilities, and equipment
|
||||||||
|
based on the determination of proved reserves
|
(16,366)
|
--
|
--
|
|||||
|
Capitalized exploratory well costs charged to expense
|
(9,210)
|
(4,941)
|
(5,789)
|
|||||
|
Ending balance at December 31
|
$
|
--
|
$
|
19,241
|
$
|
11,160
|
||
The 2014 additions include costs associated with our Tuchola-4K well in Poland. Proved reserves were assigned to both the Tuchola-3K and Tuchola-4K at year-end 2014, and their costs were reclassified to proved property costs. The Frankowo-1 and Gorka-Duchowna-1 wells were both determined to be noncommercial during 2014, and their costs were charged to expense. The following table shows the capitalized costs, by well:
|
Total at
|
||
|
December 31,
|
||
|
2013
|
||
|
Well:
|
||
|
Tuchola-4K
|
$
|
290
|
|
Tuchola-3K
|
8,980
|
|
|
Gorka-Duchowna-1
|
4,747
|
|
|
Frankowo-1
|
5,224
|
|
|
Total cost
|
$
|
19,241
|
Other Property and Equipment
Other property and equipment, including oilfield-servicing equipment, is stated at cost. Depreciation of other property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from three to 40 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of other property and equipment sold, or otherwise disposed of, and the related accumulated depreciation are removed from the accounts, and any gain or loss is reflected in current operations.
The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation, is summarized as follows:
|
Estimated
|
|||||||
|
December 31,
|
Useful Life
|
||||||
|
2014
|
2013
|
(in years)
|
|||||
|
(in thousands)
|
|||||||
|
Other property and equipment:
|
|||||||
|
Drilling rigs
|
$
|
10,583
|
$
|
9,797
|
6
|
||
|
Other vehicles
|
421
|
414
|
5
|
||||
|
Building
|
297
|
293
|
40
|
||||
|
Office equipment and furniture
|
1,437
|
1,353
|
3 to 6
|
||||
|
Total cost
|
12,738
|
11,857
|
|||||
|
Accumulated depreciation
|
(10,123)
|
(9,125)
|
|||||
|
Net other property and equipment
|
$
|
2,615
|
$
|
2,732
|
|||
F-11
Supplemental Disclosure of Cash Flows Information
Noncash investing and financing transactions not reflected in the consolidated statements of cash flows include the following:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
2012
|
|||
|
(in thousands)
|
|||||
|
Noncash investing transactions:
|
|||||
|
Additions to properties included in current liabilities
|
$ 875
|
$2,999
|
$3,374
|
||
|
Noncash financing transactions:
|
|||||
|
Dividends accrued but not paid
|
463
|
--
|
--
|
||
|
Cash paid for interest:
|
|||||
|
Cash paid during the year for interest
|
2,435
|
2,111
|
1,983
|
||
Cash paid for interest in 2014, 2013, and 2012 (in thousands) includes $409, $270, and $454, respectively, in commitment and other fees on our expanded credit facility.
Revenue Recognition
Revenues associated with oil and gas sales are recorded when title passes, which is upon delivery to the third-party pipeline or other purchaser, and are net of royalties and value-added taxes. Oilfield service revenues are recognized when the related service is performed.
Stock-Based Compensation
We maintain several stock-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 a term of ten years, and vest in three equal annual installments. Restricted stock awards have similar terms and vesting requirements. Accounting standards require stock-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. These 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, 2014. 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 or penalties were recognized during the year ended December 31, 2014.
New Accounting Standards
On May 28, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. generally accepted accounting principles, or “GAAP,” when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method or determined the effect of the standard on our ongoing financial reporting.
F-12
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 financial position, cash flow, or current or future earnings or operations.
Foreign Operations
The functional currency of our Polish subsidiary is the Polish zloty. The functional currency for the Polish subsidiary affects the amounts reported for Polish assets, liabilities, revenues, and expenses as compared to those that would be reported if we used the U.S. dollar as the functional currency. The differences depend on changes in period-average and period-end exchange rates. Translation adjustments result from the process of translating the Polish subsidiary’s financial statements into the U.S. dollar reporting currency. Translation adjustments are not included in determining net income but are reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities of FX Energy Poland, our wholly owned subsidiary, is adjusted to reflect the difference between the exchange rate when the asset or liability was first recorded and the exchange rate on the date of the change. We record a cumulative translation adjustment (“CTA”) on our balance sheet to reflect those basis differences. At December 31, 2014 and 2013, the CTA balance was $30.1 million and $15.0 million, respectively. Because of the fluctuation in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.
During 2014, we recorded foreign currency transaction losses of approximately $26.2 million attributable to increases in the amount of 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 $11.1 million related to our other balance sheet accounts as discussed above. The total amount of outstanding intercompany loans and accrued interest at December 31, 2014, was approximately $60 million and $68 million, respectively.
During 2013, we recorded foreign currency transaction gains of approximately $5.0 million attributable to decreases in the amount of 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 debit to other comprehensive income for the gains attributable to the dollar-denominated loans, notes payable, and unpaid interest, which was then offset by translation adjustments of approximately $2.0 million related to our other balance sheet accounts as discussed above.
During 2013, we converted approximately $45 million of loans between FX Energy Poland and FX Energy, Inc., to equity. The conversion was necessary in order to make future interest payments from FX Energy Poland to FX Energy, Inc., tax deductible in Poland. The total amount of outstanding intercompany loans and accrued interest at December 31, 2013, was approximately $56 million and $63 million, respectively.
During 2012, we recorded foreign currency transaction gains of approximately $16.3 million attributable to decreases in the amount of 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 debit to other comprehensive income for the gains attributable to the dollar-denominated loans, notes payable, and unpaid interest, which was then offset by translation adjustments of approximately $5.4 million related to our other balance sheet accounts as discussed above. The total amount of outstanding intercompany loans and accrued interest at December 31, 2012, was approximately $106 million and $53 million, respectively.
F-13
The following table provides a summary of changes in CTA:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
||||
|
(in thousands)
|
|||||
|
Beginning balance
|
$
|
15,025
|
$
|
18,027
|
|
|
Increase (decrease) related to losses (gains)
|
|||||
|
on dollar-denominated loans and notes payable
|
26,149
|
(4,986)
|
|||
|
Increase (decrease) related to translation adjustments
|
(11,102)
|
1,984
|
|||
|
Ending balance
|
$
|
30,072
|
$
|
15,025
|
|
Future transaction gains or losses may be significant given the amount of dollar-denominated intercompany loans and notes payable and the volatility of exchange rates. Future translation adjustments will also vary in concert with changes in exchange rates. These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.
We enter into various operating agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. We do not use derivative financial instruments for trading or speculative purposes.
Use of Estimates
The preparation of the consolidated financial statements in conformity with GAAP 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 regarding 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 Income (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 income (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, 2014, 2013, and 2012, were as follows:
|
Options, Warrants, and
|
|||
|
Unvested Restricted Stock
|
Price Range
|
||
|
Balance sheet date:
|
|||
|
December 31, 2014
|
3,209,680
|
$0.00-$5.06
|
|
|
December 31, 2013
|
2,551,928
|
$0.00-$5.06
|
|
|
December 31, 2012
|
1,930,398
|
$0.00-$5.06
|
The above options, warrants, and unvested restricted stock were not included in the computation of diluted earnings per share for the years presented because the effect would have been antidilutive.
F-14
Note 2: Asset Retirement Obligation
We account for future site restoration costs by recording a liability for the fair value of asset retirement obligations 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 $96,000, $90,000, and $63,000 in 2014, 2013, and 2012, respectively.
Following is a reconciliation of the yearly changes in the asset retirement obligation:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
||||
|
(in thousands)
|
|||||
|
Asset retirement obligations:
|
|||||
|
Beginning balance
|
$
|
1,620
|
$
|
1,431
|
|
|
Current-year additions
|
127
|
164
|
|||
|
Current-year revisions
|
272
|
(64)
|
|||
|
Liabilities settled
|
--
|
(25)
|
|||
|
Foreign-exchange adjustments
|
(126)
|
24
|
|||
|
Accretion expense
|
96
|
90
|
|||
|
Ending balance
|
$
|
1,989
|
$
|
1,620
|
|
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 2014, the economic lives of our U.S. oil wells were decreased, as lower oil prices resulted in less economic barrels. During 2013, the economic lives of our U.S. oil wells were decreased due to higher than previously estimated production declines. This change resulted in an increase in the net present value of the retirement obligations.
Note 3: Other Assets
As of December 31, 2014 and 2013, we had reclamation bonds with federal and state agencies with face amounts of $821,000 and $639,000, respectively, which were partially collateralized by certificates of deposit totaling $406,500 for both periods.
Note 4: Accrued Liabilities
Our accrued liabilities were comprised of the following:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
||||
|
(in thousands)
|
|||||
|
Accrued liabilities:
|
|||||
|
Credit facility commitment fees
|
$
|
1
|
$
|
63
|
|
|
Compensation-related costs
|
815
|
701
|
|||
|
Interest expense
|
5
|
69
|
|||
|
Total
|
$
|
821
|
$
|
833
|
|
F-15
Note 5: Notes Payable
On July 8, 2013, we finalized a five-year, up to $100 Million Senior Reserve Based Lending Facility with BNP Paribas (Suisse) SA and ING Bank N.V. The initial commitment of the facility amounts to $65 million. We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism. Initial proceeds from the new facility were used to repay our previously existing facility. Payment of the credit facility is secured by our assets in Poland and guaranteed by us. In consideration of the new credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.2 million. These fees, along with approximately $399,000 associated with our previous facility, were capitalized as loan fees and will be amortized over the five-year term of the loan. By virtue of the refinance, we charged approximately $677,000 in unamortized loan fees associated with our previous facility to interest expense during the third quarter of 2013.
The credit facility calls for a periodic interest rate of one, three, six, or twelve month-LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years. The facility has a term of five years, with semiannual borrowing base reductions beginning on June 30, 2016. An unused commitment fee of 40% of the applicable interest margin is charged monthly based on the average daily unused portion of the credit facility. There are no financial covenants associated with the credit facility. As of December 31, 2014, the total amount drawn under the credit facility was $50 million, and the interest rate was 3.92% per annum.
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 2014, with the year-end 2014 borrowing base set at $55 million.
Our notes payable is stated at book value, which approximated its fair value at December 31, 2014. Estimated fair values for notes payable have been determined based on borrowing rates currently available to us for bank loans with similar terms and maturities and are based on Level 3 criteria in the FASB’s fair value hierarchy.
The following table provides a summary of changes in notes payable:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
||||
|
(in thousands)
|
|||||
|
Beginning balance
|
$
|
45,000
|
$
|
40,000
|
|
|
Payments of notes payable
|
-
|
(40,000)
|
|||
|
Proceeds from borrowing
|
5,000
|
45,000
|
|||
|
Ending balance
|
$
|
50,000
|
$
|
45,000
|
|
At December 31, 2014, the aggregate amounts of our contractually obligated principal payment commitments associated with our notes payable for the next four years are as follows:
|
Total
|
2015
|
2016
|
2017
|
2018
|
|||||
|
Credit facility principal
|
$50,000
|
$ --
|
$11,000
|
$26,000
|
$13,000
|
The principal payments shown in the table above represent those calculated under our most recent redetermination, and are subject to change at the next, and each succeeding, redetermination.
F-16
Note 6: Commitments and Contingencies
Due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. In our opinion, there are no material pending legal proceedings to which we are a party or of which any of our property is the subject. While the outcome of such legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations, or cash flows.
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 recorded as of December 31, 2014 or 2013.
Recurring Fair Value
The following tables set forth the financial assets that we measured at fair value on a recurring basis by level within the fair value hierarchy. We classify assets measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.
Assets measured at fair value on a recurring basis consisted of the following:
|
December 31,
|
|||||||
|
2014
|
Level 1(1)
|
Level 2(2)
|
Level 3(3)
|
||||
|
(in thousands)
|
|||||||
|
Marketable securities:
|
|||||||
|
Corporate and government bonds
|
$7,313
|
$7,313
|
$--
|
$--
|
|||
__________________
|
(1)
|
Quoted prices in active markets for identical assets.
|
|
(2)
|
Significant other observable inputs.
|
|
(3)
|
Significant unobservable inputs.
|
There were no assets measured at fair value on a recurring basis at December 31, 2013.
F-17
Note 8: Income Taxes
We recognized no income tax benefit from the losses generated during 2014, 2013, and 2012. The components of the net deferred tax asset are as follows:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
||||
|
(in thousands)
|
|||||
|
Deferred tax liability:
|
|||||
|
Property and equipment basis differences
|
$
|
(514)
|
$
|
(1,630)
|
|
|
Deferred tax asset:
|
|||||
|
Net operating loss carryforwards:
|
|||||
|
United States
|
37,898
|
24,799
|
|||
|
Poland
|
3,764
|
4,655
|
|||
|
Oil and gas properties
|
7,173
|
3,355
|
|||
|
Accrued interest expense
|
11,511
|
11,927
|
|||
|
Foreign exchange translation losses
|
8,239
|
4,013
|
|||
|
Options issued for services
|
1,408
|
831
|
|||
|
Asset retirement obligation
|
568
|
452
|
|||
|
Valuation allowance
|
(70,047)
|
(48,402)
|
|||
|
Total
|
$
|
--
|
$
|
--
|
|
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 generating future taxable income are considerable, resulting in our conclusion that a full valuation allowance be provided at December 31, 2014, 2013, and 2012. Due to the full valuation allowance, our effective income tax rate for all three years was zero percent.
During the year ended December 31, 2014, we increased our valuation allowance by $21.6 million. We increased our valuation allowance by $5.2 million and $3.0 million for the years ended December 31, 2013 and 2012, respectively.
The income tax provision differs from the amount computed by applying the U.S. federal income tax rate of 35% to net income (loss) before income taxes for the following reasons:
| Year Ended December 31, | ||||||||
| 2014 | 2013 | 2012 | ||||||
|
Effective Tax Rate Reconciliation:
|
(in thousands) | |||||||
|
Federal income tax provision (benefit) at statutory rates
|
$
|
(20,727)
|
$
|
(4,130)
|
$
|
1,441
|
||
|
Increase (decrease) due to stock-based compensation
|
34
|
240
|
(259)
|
|||||
|
Increase (decrease) due to differences in foreign tax rates
|
6,787
|
(2,200)
|
(3,586)
|
|||||
|
Decrease due to state and local taxes, net of federal benefit
|
(353)
|
(278)
|
(354)
|
|||||
|
Increase (decrease) due to the effect of exchange rate fluctuations
|
3,342
|
(1,728)
|
(2,118)
|
|||||
|
Increase (decrease) due to expiring and/or unavailable net operating losses
|
(10,728)
|
13,256
|
1,860
|
|||||
|
Change in valuation allowance
|
21,645
|
(5,160)
|
3,016
|
|||||
|
Total
|
$
|
--
|
$
|
--
|
$
|
--
|
||
United States NOL
At December 31, 2014, we had net operating loss (“NOL”) carryforwards in the United States of approximately $103 million available to offset future taxable income. The carryforwards begin to expire in 2018 and will fully expire in 2034. The application 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.
F-18
Polish NOL
As of December 31, 2014, we had NOL carryforwards in Poland totaling approximately $19.8 million. The NOL carryforwards will be fully expired in 2018. The normal carryforward period in Poland is five years. However, in any given year, no more than 50% of the NOL carryforward may be applied against Polish income in succeeding years.
The following table lists the years of expiration for our net operating losses:
|
United States
|
Poland
|
||
|
(in thousands)
|
|||
|
Year of NOL expiration:
|
|||
|
2018
|
$ 6,145
|
$19,810
|
|
|
2019
|
2,938
|
--
|
|
|
2020
|
2,717
|
--
|
|
|
2021
|
2,243
|
--
|
|
|
2022 and thereafter
|
88,916
|
--
|
|
The domestic and foreign components of our net income (loss) are as follows:
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
2012
|
|||
|
(in thousands)
|
|||||
|
Domestic
|
$ (10,964)
|
$ (9,223)
|
$ (9,963)
|
||
|
Foreign
|
(48,256)
|
(2,577)
|
14,081
|
||
|
Total
|
$(59,220)
|
$(11,800)
|
$ 4,118
|
||
No provision for deferred U.S. income taxes has been made for undistributed earnings of foreign subsidiaries because they were considered to be indefinitely reinvested outside the United States. The distribution of these earnings in the form of dividends or otherwise may subject the company to U.S. federal and state income taxes and, possibly, foreign withholding taxes. However, because of the complexities of U.S. taxation of foreign earnings, it is not practicable to estimate the amount of additional tax that might be payable on any eventual remittance of these earnings to the U.S. We are subject to U.S. federal, state and local income tax examinations by tax authorities for tax periods 2011 and forward, and similarly in Poland for tax periods 2009 and forward.
Note 9: Stockholders’ Equity
Common Stock
We have a Stock Bonus Plan under section 401(k) of the Internal Revenue Code covering all of our employees. We have made discretionary contributions of 171,879, 162,402, and 138,748 shares of our stock to employees under this Plan and have recorded $0.6 million, $0.7 million, and $0.7 million of expenses associated with these contributions for the years ended December 31, 2014, 2013, and 2012, respectively. We issued 7,500, 6,500, and 0 shares in 2014, 2013, and 2012, respectively, to consultants for services.
During 2014, we sold 163,639 shares of common stock under our at-the-market agreement in connection with our existing shelf registration. Net proceeds from the stock sale were approximately $0.6 million, after deducting associated costs.
Preferred Stock
During 2014, we closed an underwritten public offering of 800,000 shares of our 9.25% Series B Cumulative Convertible Preferred Stock (the “Series B Preferred Stock”) at a public offering price of $25.00 per share. The Series B Preferred Stock has a liquidation preference of $25.00 per share. Holders of Series B Preferred Stock may convert their shares, in whole or in part, into shares of our common stock at a conversion price of $5.00 per share. The Series B Preferred Stock ranks senior to our common stock in the payment of dividends and distribution of assets upon liquidation or dissolution. The Series B Preferred Stock has no stated maturity and is not subject to mandatory redemption.
F-19
The net proceeds from the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $18.4 million. We are using the net proceeds from the offering primarily to fund seismic and new drilling costs near our Tuchola discovery, which is located in the Edge license in north central Poland and other corporate costs.
Holders of the Series B Preferred Stock are entitled to receive, when, as, and if declared by our board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 9.25% per annum of the $25.00 liquidation preference per share (equivalent to $2.3125 per annum per share). Dividends are payable quarterly in arrears on the last day of each January, April, July, and October, commencing on October 31, 2014, when, as, and if declared by our board. During 2014, the board declared total dividends of $0.8 million, of which $0.5 million was payable at December 31, 2014.
We may cause conversion of the Series B Preferred Stock if the trading price of our common stock exceeds $6.00 for 20 trading days in any consecutive 30-day trading period. On or after July 17, 2017, we, at our option, may redeem the Series B Preferred Stock, in whole or in part, for cash at a redemption price of $25.00 per share, plus all accrued and unpaid dividends thereon to the date fixed for redemption, without interest. We may also redeem the Series B Preferred Stock following certain changes of control as defined in the Series B Preferred Stock designation, in whole or in part, within 90 days after the date on which the change of control has occurred, for cash at $25.00 per share, plus accumulated accrued and unpaid dividends to the date of redemption. If we elect not to exercise this option, the holders of the Series B Preferred Stock have the option to convert each share into common stock at a conversion price of $5.00 per share, subject to certain adjustments.
Except as required by law, holders of the Series B Preferred Stock will have no voting rights unless dividends fall into arrears for four or more quarterly periods (whether or not consecutive). In that event and until such dividends in arrears are paid in full, the holders will be entitled to elect two directors to the board, which will increase in size by that same number of directors.
Stockholder Rights Plan
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 an annual stock option and award plan that has 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 plan as of December 31, 2014:
|
Weighted
|
Number
|
||||
|
Number
|
Average
|
of Options
|
|||
|
of Shares
|
Exercise Price
|
Available
|
|||
|
Authorized
|
of Outstanding
|
for Future
|
|||
|
Under Plan
|
Options
|
Issuance
|
|||
|
Equity compensation plans approved by stockholders:
|
|||||
|
2011 Incentive Plan
|
4,447,962
|
$3.81
|
604,852
|
||
|
Total
|
4,447,962
|
$3.81
|
604,852
|
F-20
Our stock option and award plan is administered by the Board, on the recommendation of 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 nonqualified options to any employee, including officers. The granted options have a term of ten years and vest in three equal annual installments. Under terms of the stock option award plans, we may also issue restricted stock.
Stock Options
The following table summarizes option activity:
|
Year Ended December 31,
|
|||||||||||
|
2014
|
2013
|
2012
|
|||||||||
|
Weighted
|
Weighted
|
Weighted
|
|||||||||
|
Average
|
Average
|
Average
|
|||||||||
|
Number of
|
Exercise
|
Number of
|
Exercise
|
Number of
|
Exercise
|
||||||
|
Options
|
Price
|
Options
|
Price
|
Options
|
Price
|
||||||
|
Options outstanding:
|
|||||||||||
|
Beginning of year
|
1,911,872
|
$4.22
|
1,275,299
|
$4.65
|
668,129
|
$5.31
|
|||||
|
Granted
|
656,096
|
2.63
|
648,058
|
3.38
|
642,170
|
4.25
|
|||||
|
Exercised
|
--
|
--
|
--
|
--
|
--
|
--
|
|||||
|
Cancelled
|
(6,799)
|
4.25
|
(11,485)
|
4.50
|
--
|
--
|
|||||
|
Expired
|
--
|
--
|
--
|
--
|
(35,000)
|
9.89
|
|||||
|
End of year
|
2,561,169
|
3.81
|
1,911,872
|
4.22
|
1,275,299
|
4.65
|
|||||
|
Exercisable at year-end
|
1,264,126
|
$4.50
|
631,749
|
$4.79
|
211,063
|
$5.06
|
|||||
The following table summarizes information about stock options outstanding as of December 31, 2014:
|
Outstanding
|
Exercisable
|
|||||||||
|
Weighted
|
||||||||||
|
Average
|
Weighted
|
Weighted
|
||||||||
|
Number
|
Remaining
|
Average
|
Number
|
Average
|
||||||
|
Exercise
|
of Options
|
Contractual Life
|
Exercise
|
of Options
|
Exercise
|
|||||
|
Price Range
|
Outstanding
|
(in years)
|
Price
|
Exercisable
|
Price
|
|||||
|
$2.63 - $3.37
|
656,096
|
9.90
|
$2.63
|
--
|
$ --
|
|||||
|
3.38 - 4.24
|
645,566
|
8.88
|
3.38
|
215,205
|
3.38
|
|||||
|
4.25 - 5.05
|
632,630
|
7.87
|
4.25
|
422,044
|
4.25
|
|||||
|
5.06 - 5.06
|
626,877
|
6.70
|
5.06
|
626,877
|
5.06
|
|||||
|
Total
|
2,561,169
|
8.36
|
3.81
|
1,264,126
|
$4.50
|
|||||
The aggregate intrinsic value of outstanding stock options at December 31, 2014, was $0.
Restricted Stock
The following table summarizes restricted stock activity:
|
Number of Shares
|
|||||
|
Year Ended December 31,
|
|||||
|
2014
|
2013
|
2012
|
|||
|
Unvested restricted stock outstanding:
|
|||||
|
Beginning of year
|
640,056
|
655,099
|
687,912
|
||
|
Issued
|
328,049
|
324,033
|
321,086
|
||
|
Forfeited
|
(2,498)
|
(6,157)
|
(564)
|
||
|
Vested
|
(317,096)
|
(332,919)
|
(353,335)
|
||
|
End of year
|
648,511
|
640,056
|
655,099
|
||
F-21
The aggregate intrinsic value of unvested restricted stock at December 31, 2014, was $1.0 million. The aggregate intrinsic value represents the total pretax intrinsic value, based on our stock price of $1.55 as of December 31, 2014, which would have been received by the restricted stock award holders had all restricted stock awards been vested as of that date. The weighted average period over which stock compensation expense related to the restricted stock awards will be recognized is 2.22 years.
Stock Compensation Expense
The following tables summarize the quantity of restricted stock awards, total deferred compensation expense arising from those awards, and annual compensation expense for each annual equity award that is included in stock compensation expense:
|
Year
|
Total Deferred
|
Stock Compensation Expense
|
|||
|
Ended
|
Number of
|
Compensation
|
(thousands)
|
||
|
Dec. 31,
|
Shares
|
(thousands)
|
2014
|
2013
|
2012
|
|
2014
|
328,049
|
$ 863
|
$ 33
|
$ -
|
$ -
|
|
2013
|
324,033
|
1,095
|
364
|
47
|
-
|
|
2012
|
321,086
|
1,365
|
448
|
452
|
59
|
|
2011
|
318,252
|
1,610
|
375
|
531
|
534
|
|
2010
|
373,500
|
2,260
|
-
|
720
|
747
|
|
2009
|
379,500
|
1,044
|
-
|
-
|
334
|
|
Total
|
2,044,420
|
$8,237
|
$1,220
|
$1,750
|
$1,674
|
The following tables summarize the quantity of stock option awards, total deferred compensation expense arising from those awards, and annual compensation expense for each annual equity award that is included in stock compensation expense:
|
Year
|
Total Deferred
|
Stock Compensation Expense
|
|||
|
Ended
|
Number of
|
Compensation
|
(thousands)
|
||
|
Dec. 31,
|
Options
|
(thousands)
|
2014
|
2013
|
2012
|
|
2014
|
656,096
|
$ 880
|
$ 34
|
$ -
|
$ -
|
|
2013
|
648,058
|
1,084
|
360
|
45
|
-
|
|
2012
|
642,170
|
1,421
|
467
|
471
|
60
|
|
2011
|
636,509
|
1,781
|
414
|
587
|
591
|
|
Total
|
2,582,833
|
$5,166
|
$1,275
|
$1,103
|
$651
|
The following table summarizes the assumptions used in determining Black-Scholes valuations for stock option grants made:
|
Year
|
Calculated
|
||||
|
Ended
|
Expected Life
|
Expected
|
Risk Free
|
Stock Option
|
|
|
Dec. 31,
|
(Years)
|
Volatility
|
Dividend Yield
|
Interest Rate
|
Value per Share
|
|
2014
|
4.0
|
67%
|
0%
|
1.27%
|
$1.34
|
|
2013
|
4.0
|
65
|
0
|
1.01
|
1.67
|
|
2012
|
4.0
|
70
|
0
|
0.49
|
2.21
|
Note 11: Business Segments
We operate within two business segments of the oil and gas industry: exploration and production (“E&P”) and oilfield services. Revenues associated with our E&P activities are comprised of oil and gas sales from our producing properties in Poland and oil sales from our producing properties in the United States. During the last three years, essentially all sales of oil and gas in Poland were made to PGNiG or its affiliated companies. Over 95% of our oil sales in the United States were to Cenex during 2014, 2013, and 2012. Gas sales in Poland are pursuant to long-term sales contracts that obligate the buyer to purchase all gas produced. We believe the purchasers of our oil production in the United States could be replaced, if necessary, without a loss in revenue.
F-22
E&P operating costs are comprised of: (1) exploration costs (geological and geophysical costs, exploratory dry holes, and proved property and nonproducing 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 particular 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 is summarized as follows:
|
Year Ended December 31, 2014
|
|||||||||||
|
(in thousands)
|
|||||||||||
|
Oilfield
|
|||||||||||
|
Exploration & Production
|
Services
|
Total
|
|||||||||
|
U.S.
|
Poland
|
||||||||||
|
Operations summary:
|
|||||||||||
|
Revenues
|
$
|
3,469
|
$
|
30,796
|
$
|
3,761
|
$
|
38,026
|
|||
|
Lease operating expense
|
(2,894)
|
(1,851)
|
--
|
(4,745)
|
|||||||
|
Oilfield services costs
|
--
|
--
|
(2,486)
|
(2,486)
|
|||||||
|
Exploration expense
|
(15)
|
(21,158)
|
--
|
(21,173)
|
|||||||
|
Impairment expense
|
(2,899)
|
(20,394)
|
--
|
(23,293)
|
|||||||
|
Accretion expense
|
(57)
|
(39)
|
--
|
(96)
|
|||||||
|
DD&A expense
|
(350)
|
(4,109)
|
(1,010)
|
(5,469)
|
|||||||
|
Operating income (loss)
|
$
|
(2,746)
|
$
|
(16,755)
|
$
|
265
|
$
|
(19,236)
|
|||
|
Identifiable net property and equipment:
|
|||||||||||
|
Unproved properties
|
$
|
--
|
$
|
1,991
|
$
|
--
|
$
|
1,991
|
|||
|
Proved properties
|
--
|
48,877
|
--
|
48,877
|
|||||||
|
Equipment and other
|
--
|
115
|
2,483
|
2,598
|
|||||||
|
Total
|
$
|
--
|
$
|
50,983
|
$
|
2,483
|
$
|
53,466
|
|||
|
Net Capital Expenditures:
|
|||||||||||
|
Property and equipment
|
$
|
535
|
$
|
17,381
|
$
|
840
|
$
|
18,756
|
|||
|
Total
|
$
|
535
|
$
|
17,381
|
$
|
840
|
$
|
18,756
|
|||
F-23
|
Year Ended December 31, 2013
|
|||||||||||
|
(in thousands)
|
|||||||||||
|
Oilfield
|
|||||||||||
|
Exploration & Production
|
Services
|
Total
|
|||||||||
|
U.S.
|
Poland
|
||||||||||
|
Operations summary:
|
|||||||||||
|
Revenues
|
$
|
3,861
|
$
|
29,450
|
$
|
1,218
|
$
|
34,529
|
|||
|
Lease operating expense
|
(2,314)
|
(1,366)
|
--
|
(3,680)
|
|||||||
|
Oilfield services costs
|
--
|
--
|
(1,179)
|
(1,179)
|
|||||||
|
Exploration expense
|
(303)
|
(20,489)
|
--
|
(20,792)
|
|||||||
|
Impairment expense
|
(24)
|
(6,105)
|
--
|
(6,129)
|
|||||||
|
Accretion expense
|
(55)
|
(35)
|
--
|
(90)
|
|||||||
|
DD&A expense
|
(236)
|
(3,344)
|
(956)
|
(4,536)
|
|||||||
|
Operating income (loss)
|
$
|
929
|
$
|
(1,889)
|
$
|
(917)
|
$
|
(1,877)
|
|||
|
Identifiable net property and equipment:
|
|||||||||||
|
Unproved properties
|
$
|
--
|
$
|
2,404
|
$
|
--
|
$
|
2,404
|
|||
|
Proved properties
|
2,713
|
68,286
|
--
|
70,999
|
|||||||
|
Equipment and other
|
--
|
49
|
2,657
|
2,706
|
|||||||
|
Total
|
$
|
2,713
|
$
|
70,739
|
$
|
2,657
|
$
|
76,109
|
|||
|
Net Capital Expenditures:
|
|||||||||||
|
Property and equipment
|
$
|
819
|
$
|
27,207
|
$
|
1,083
|
$
|
29,109
|
|||
|
Total
|
$
|
819
|
$
|
27,207
|
$
|
1,083
|
$
|
29,109
|
|||
|
Year Ended December 31, 2012
|
|||||||||||
|
(in thousands)
|
|||||||||||
|
Oilfield
|
|||||||||||
|
Exploration & Production
|
Services
|
Total
|
|||||||||
|
U.S.
|
Poland
|
||||||||||
|
Operations summary:
|
|||||||||||
|
Revenues
|
$
|
4,117
|
$
|
30,344
|
$
|
2,137
|
$
|
36,598
|
|||
|
Lease operating expense
|
(2,403)
|
(1,228)
|
--
|
(3,631)
|
|||||||
|
Oilfield services costs
|
--
|
--
|
(1,610)
|
(1,610)
|
|||||||
|
Exploration expense
|
(475)
|
(23,320)
|
--
|
(23,795)
|
|||||||
|
Impairment expense
|
(1,775)
|
(787)
|
--
|
(2,562)
|
|||||||
|
Accretion expense
|
(39)
|
(24)
|
--
|
(63)
|
|||||||
|
Loss on asset sale
|
(49)
|
--
|
--
|
(49)
|
|||||||
|
DD&A expense
|
(146)
|
(2,954)
|
(1,109)
|
(4,209)
|
|||||||
|
Operating income (loss)
|
$
|
(770)
|
$
|
2,031
|
$
|
(582)
|
$
|
679
|
|||
|
Identifiable net property and equipment:
|
|||||||||||
|
Unproved properties
|
$
|
24
|
$
|
2,313
|
$
|
--
|
$
|
2,337
|
|||
|
Proved properties
|
2,330
|
49,852
|
--
|
52,182
|
|||||||
|
Equipment and other
|
--
|
10
|
2,510
|
2,520
|
|||||||
|
Total
|
$
|
2,354
|
$
|
52,175
|
$
|
2,510
|
$
|
57,039
|
|||
|
Net Capital Expenditures:
|
|||||||||||
|
Property and equipment
|
$
|
967
|
$
|
23,402
|
$
|
693
|
$
|
25,062
|
|||
|
Total
|
$
|
967
|
$
|
23,402
|
$
|
693
|
$
|
25,062
|
|||
F-24
A reconciliation of the segment information to the consolidated totals follows:
|
Year Ended December 31,
|
||||||||
|
2014
|
2013
|
2012
|
||||||
|
(in thousands)
|
||||||||
|
Revenues:
|
||||||||
|
Reportable segments
|
$
|
38,026
|
$
|
34,529
|
$
|
36,598
|
||
|
Non reportable segments
|
--
|
--
|
--
|
|||||
|
Total revenues
|
$
|
38,026
|
$
|
34,529
|
$
|
36,598
|
||
|
Net loss:
|
||||||||
|
Operating income (loss), reportable segments
|
$
|
(19,236)
|
$
|
(1,877)
|
$
|
679
|
||
|
Expense or (revenue) adjustments:
|
||||||||
|
Corporate DD&A expense
|
(62)
|
(37)
|
(30)
|
|||||
|
General and administrative costs (G&A)
|
(8,500)
|
(8,836)
|
(8,369)
|
|||||
|
Stock compensation (G&A)
|
(2,495)
|
(2,853)
|
(2,325)
|
|||||
|
Total net operating loss
|
(30,293)
|
(13,603)
|
(10,045)
|
|||||
|
Non operating income:
|
||||||||
|
Interest income (net of interest expense) and other income
|
(2,749)
|
(3,164)
|
(2,129)
|
|||||
|
Foreign exchange gain (loss)
|
(26,178)
|
4,967
|
16,292
|
|||||
|
Net (loss) income
|
$
|
(59,220)
|
$
|
(11,800)
|
$
|
4,118
|
||
|
Net property and equipment:
|
||||||||
|
Reportable segments
|
$
|
53,466
|
$
|
76,109
|
$
|
57,039
|
||
|
Corporate assets
|
17
|
27
|
50
|
|||||
|
Net property and equipment
|
$
|
53,483
|
$
|
76,136
|
$
|
57,089
|
||
|
Property and equipment capital expenditures:
|
||||||||
|
Reportable segments
|
$
|
18,756
|
$
|
29,109
|
$
|
25,062
|
||
|
Corporate assets
|
10
|
--
|
42
|
|||||
|
Total property and equipment capital expenditures
|
$
|
18,766
|
$
|
29,109
|
$
|
25,104
|
||
Note 12: Quarterly Financial Data (Unaudited)
Summary quarterly information for 2014 and 2013 is as follows:
|
Quarter Ended
|
|||||||||||
|
December 31
|
September 30
|
June 30
|
March 31
|
||||||||
|
(in thousands, except per share amounts)
|
|||||||||||
|
2014:
|
|||||||||||
|
Revenues
|
$
|
8,156
|
$
|
10,194
|
$
|
10,163
|
$
|
9,513
|
|||
|
Net operating loss
|
(25,816)
|
(2,240)
|
(3,134)
|
896
|
|||||||
|
Net loss
|
(37,286)
|
(16,445)
|
(4,527)
|
(962)
|
|||||||
|
Basic and diluted net loss per common share
|
$
|
(0.71)
|
$
|
(0.31)
|
$
|
(0.08)
|
$
|
(0.02)
|
|||
|
2013:
|
|||||||||||
|
Revenues
|
$
|
8,610
|
$
|
8,228
|
$
|
8,203
|
$
|
9,488
|
|||
|
Net operating loss
|
(1,308)
|
(3,721)
|
(6,832)
|
(1,742)
|
|||||||
|
Net income (loss)
|
3,810
|
6,462
|
(10,629)
|
(11,443)
|
|||||||
|
Basic and diluted net income (loss) per common share
|
$
|
0.07
|
$
|
0.12
|
$
|
(0.20)
|
$
|
(0.22)
|
|||
F-25
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 are summarized as follows:
| United States | Poland |
Total
|
||||||
| (in thousands) | ||||||||
|
Year Ended December 31, 2014:
|
||||||||
|
Proved properties
|
$
|
4,237
|
$
|
61,384
|
$
|
65,621
|
||
|
Unproved properties
|
--
|
1,991
|
1,991
|
|||||
|
Total gross properties
|
4,237
|
63,375
|
67,612
|
|||||
|
Less accumulated depreciation, depletion, and amortization
|
(4,237)
|
(12,507)
|
(16,744)
|
|||||
|
$
|
--
|
$
|
50,868
|
$
|
50,868
|
|||
|
Year Ended December 31, 2013:
|
||||||||
|
Proved properties
|
$
|
6,600
|
$
|
78,644
|
$
|
85,244
|
||
|
Unproved properties
|
--
|
2,404
|
2,404
|
|||||
|
Total gross properties
|
6,600
|
81,048
|
87,648
|
|||||
|
Less accumulated depreciation, depletion, and amortization
|
(3,887)
|
(10,358)
|
(14,245)
|
|||||
|
$
|
2,713
|
$
|
70,690
|
$
|
73,403
|
|||
Results of Operations
Results of operations are reflected in Note 11, 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 2014, 2013, and 2012 were $4,745, $3,680, and $3,631, respectively.
Property Acquisition, Exploration, and Development Activities
Costs incurred in property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:
| United States | Poland | Total | ||||||
| (in thousands) | ||||||||
|
Year ended December 31, 2014:
|
||||||||
|
Acquisition of unproved properties
|
$
|
--
|
$
|
163
|
$
|
163
|
||
|
Exploration costs
|
15
|
32,107
|
32,122
|
|||||
|
Development costs
|
536
|
1,466
|
2,002
|
|||||
|
Total
|
$
|
551
|
$
|
33,736
|
$
|
34,287
|
||
|
Year ended December 31, 2013:
|
||||||||
|
Acquisition of unproved properties
|
$
|
--
|
$
|
1,043
|
$
|
1,043
|
||
|
Exploration costs
|
303
|
37,697
|
38,000
|
|||||
|
Development costs
|
864
|
8,902
|
9,766
|
|||||
|
Total
|
$
|
1,167
|
$
|
47,642
|
$
|
48,809
|
||
|
Year ended December 31, 2012:
|
||||||||
|
Acquisition of unproved properties
|
$
|
134
|
$
|
1
|
$
|
135
|
||
|
Exploration costs
|
405
|
31,976
|
32,381
|
|||||
|
Development costs
|
903
|
2,300
|
3,203
|
|||||
|
Total
|
$
|
1,442
|
$
|
34,277
|
$
|
35,719
|
||
F-26
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:
|
2014
|
2013
|
2012
|
|
|
(in thousands)
|
|||
|
Impairment of properties
|
$23,293
|
$6,129
|
$2,562
|
Exploratory Dry Hole Costs
Total dry-hole costs of $10.4 million in 2014 were principally related with our Polish Baraniec-1 and Angowice-2 wells, along with some costs associated with an unsuccessful recompletion at our Szymanowice well that was drilled in 2013. Dry-hole costs of $6.7 million in 2013 were principally related to the Mieczewo-1K and Plawce-2 wells in Poland. Dry-hole costs of $12.7 million in 2012 were principally related to the Kutno-2 well drilled in Poland and one Alberta Bakken well drilled in Montana.
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 GAAP 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.
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.
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.
F-27
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
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, including annual beginning and ending volumes by year, represents estimates only and should not be construed as exact:
|
Crude Oil
|
Natural Gas
|
||||||
|
United States
|
Poland
|
United States
|
Poland
|
||||
|
(in thousand barrels of oil)
|
(in million cubic feet)
|
||||||
|
December 31, 2014:
|
|||||||
|
Beginning of year
|
461
|
--
|
--
|
41,219
|
|||
|
End of year
|
357
|
--
|
--
|
23,271
|
|||
|
December 31, 2013:
|
|||||||
|
Beginning of year
|
594
|
--
|
--
|
22,367
|
|||
|
End of year
|
461
|
--
|
--
|
41,219
|
|||
|
December 31, 2012:
|
|||||||
|
Beginning of year
|
639
|
--
|
--
|
31,987
|
|||
|
End of year
|
594
|
--
|
--
|
22,367
|
|||
Proved Undeveloped Reserves:
The following unaudited summary of proved undeveloped reserve quantity information, including annual beginning and ending volumes by year, represents estimates only and should not be construed as exact:
|
Crude Oil
|
Natural Gas
|
||||||
|
United States
|
Poland
|
United States
|
Poland
|
||||
|
(in thousand barrels of oil)
|
(in million cubic feet)
|
||||||
|
December 31, 2014:
|
|||||||
|
Beginning of year
|
--
|
--
|
--
|
793
|
|||
|
End of year
|
--
|
--
|
--
|
14,118
|
|||
|
December 31, 2013:
|
|||||||
|
Beginning of year
|
--
|
--
|
--
|
21,754
|
|||
|
End of year
|
--
|
--
|
--
|
793
|
|||
|
December 31, 2012:
|
|||||||
|
Beginning of year
|
--
|
--
|
--
|
17,649
|
|||
|
End of year
|
--
|
--
|
--
|
21,754
|
|||
F-28
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
Total Proved Reserves:
The following unaudited summary of proved reserve quantity information represents estimates only and should not be construed as exact:
|
Crude Oil
|
Natural Gas
|
||||||
|
United States
|
Poland
|
United States
|
Poland
|
||||
|
(in thousand barrels of oil)
|
(in million cubic feet)
|
||||||
|
December 31, 2014:
|
|||||||
|
Beginning of year
|
461
|
--
|
--
|
42,012
|
|||
|
Extensions or discoveries(1)
|
--
|
--
|
--
|
13,315
|
|||
|
Revisions of previous estimates(2)
|
(57)
|
--
|
--
|
(13,703)
|
|||
|
Production
|
(47)
|
--
|
--
|
(4,235)
|
|||
|
End of year
|
357
|
--
|
--
|
37,389
|
|||
|
December 31, 2013:
|
|||||||
|
Beginning of year
|
594
|
--
|
--
|
44,121
|
|||
|
Extensions or discoveries(3)
|
--
|
--
|
--
|
3,947
|
|||
|
Revisions of previous estimates(4)
|
(84)
|
--
|
--
|
(1,909)
|
|||
|
Production
|
(49)
|
--
|
--
|
(4,147)
|
|||
|
End of year
|
461
|
--
|
--
|
42,012
|
|||
|
December 31, 2012:
|
|||||||
|
Beginning of year
|
639
|
--
|
--
|
49,636
|
|||
|
Extensions or discoveries(5)
|
--
|
--
|
--
|
2,313
|
|||
|
Revisions of previous estimates(6)
|
9
|
--
|
--
|
(3,371)
|
|||
|
Production
|
(54)
|
--
|
--
|
(4,457)
|
|||
|
End of year
|
594
|
--
|
--
|
44,121
|
|||
_______________
|
(1)
|
Volume increase in Poland attributable to new Karmin-1 and Tuchola-3K and Tuchola-4K wells.
|
|
(2)
|
Downward oil revisions in the United States attributable to lower oil prices. Downward gas revisions in Poland due to the reduction of proved reserves calculated at the Lisewo and Komorze wells based on new pressure data and at the Szymanowice well that was plugged following an unsuccessful sidetrack.
|
|
(3)
|
Volume increase in Poland attributable to new Szymanowice-1 well drilled during 2013.
|
|
(4)
|
Downward oil revisions in the United States attributable to higher than previously estimated production declines. Downward gas revisions in Poland due to the reduction of proved reserves calculated at the Lisewo-1 well based on new pressure data and at the Grabowka wells due to lower than anticipated production.
|
|
(5)
|
Volume increase in Poland attributable to Komorze-3K well drilled during 2012.
|
|
(6)
|
Upward oil revisions in the United States attributable to lower average operating costs during 2012 compared to 2011 operating costs. Downward gas revisions in Poland due to the reduction of proved reserves calculated at the Zaniemysl and Kromolice-1, Sroda-4, and Kromolice-2 wells based on new pressure data.
|
Standardized Measure of Discounted Future Net Cash Flows (“SMOG”) and Changes Therein Relating to Proved Oil Reserves (Unaudited)
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute the proved reserve valuation do not necessarily reflect our expectations of actual revenues to be derived from those reserves or their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rates also could result directly or indirectly from factors outside our control, such as unintentional delays in development, environmental concerns, and changes in prices or regulatory controls. The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations also could affect the amount of cash eventually realized. Future development and production costs are computed by estimating expenditures to be incurred in developing and producing the proved oil reserves at the end of the period, based on period-end costs and assuming continuation of existing economic conditions. A discount rate of 10% per year was used to reflect the timing of the future net cash flows. The future net cash flows for our Polish reserves are based on gas sales contracts we have with PGNiG. The average prices used to calculate year-end reserve values were $7.75 and $6.82 per Mcf and $74.94 and $78.18 per barrel for 2014 and 2013, respectively.
F-29
FX ENERGY, INC. AND SUBSIDIARIES
Supplemental Information
--continued--
The components of SMOG are detailed below:
|
United States
|
Poland
|
Total
|
||||||
|
(in thousands)
|
||||||||
|
December 31, 2014:
|
||||||||
|
Future cash flows
|
$
|
26,770
|
$
|
289,640
|
$
|
316,410
|
||
|
Future production costs
|
(16,688)
|
(42,900)
|
(59,588)
|
|||||
|
Future development costs
|
--
|
(43,580)
|
(43,580)
|
|||||
|
Future income tax expense
|
--
|
(5,642)
|
(5,642)
|
|||||
|
Future net cash flows
|
10,082
|
197,518
|
207,600
|
|||||
|
10% annual discount for estimated timing of cash flows
|
(5,452)
|
(68,520)
|
(73,972)
|
|||||
|
Discounted net future cash flows
|
$
|
4,630
|
$
|
128,998
|
$
|
133,628
|
||
|
December 31, 2013:
|
||||||||
|
Future cash flows
|
$
|
36,077
|
$
|
286,680
|
$
|
322,757
|
||
|
Future production costs
|
(22,113)
|
(33,660)
|
(55,773)
|
|||||
|
Future development costs
|
--
|
(17,830)
|
(17,830)
|
|||||
|
Future income tax expense
|
--
|
(11,300)
|
(11,300)
|
|||||
|
Future net cash flows
|
13,964
|
223,890
|
237,854
|
|||||
|
10% annual discount for estimated timing of cash flows
|
(5,760)
|
(80,292)
|
(86,052)
|
|||||
|
Discounted net future cash flows
|
$
|
8,204
|
$
|
143,598
|
$
|
151,802
|
||
|
December 31, 2012:
|
||||||||
|
Future cash flows
|
$
|
46,449
|
$
|
291,160
|
$
|
337,609
|
||
|
Future production costs
|
(28,171)
|
(21,020)
|
(49,191)
|
|||||
|
Future development costs
|
--
|
(25,620)
|
(25,620)
|
|||||
|
Future income tax expense
|
--
|
(30,570)
|
(30,570)
|
|||||
|
Future net cash flows
|
18,278
|
213,950
|
232,228
|
|||||
|
10% annual discount for estimated timing of cash flows
|
(7,848)
|
(66,777)
|
(74,625)
|
|||||
|
Discounted net future cash flows
|
$
|
10,430
|
$
|
147,173
|
$
|
157,603
|
||
The principal sources of changes in SMOG are detailed below:
|
Year Ended December 31,
|
||||||||
|
2014
|
2013
|
2012
|
||||||
|
(in thousands)
|
||||||||
|
SMOG sources:
|
||||||||
|
Balance, beginning of year
|
$
|
151,802
|
$
|
157,603
|
$
|
169,567
|
||
|
Sale of oil and gas produced, net of production costs
|
(29,520)
|
(29,631)
|
(30,830)
|
|||||
|
Net changes in prices and production costs
|
2,019
|
(2,456)
|
4,385
|
|||||
|
Acquisition of minerals in place
|
--
|
--
|
--
|
|||||
|
Extensions and discoveries, net of future costs
|
62,580
|
6,020
|
4,570
|
|||||
|
Changes in estimated future development costs
|
(17,651)
|
(773)
|
(7,358)
|
|||||
|
Previously estimated development costs incurred during the year
|
1,399
|
8,902
|
2,277
|
|||||
|
Revisions in previous quantity estimates
|
(54,926)
|
(9,210)
|
(13,508)
|
|||||
|
Accretion of discount
|
15,180
|
15,760
|
16,957
|
|||||
|
Net change in income taxes
|
3,580
|
13,495
|
5,769
|
|||||
|
Changes in rates of production and other
|
(835)
|
(7,908)
|
5,774
|
|||||
|
Balance, end of year
|
$
|
133,628
|
$
|
151,802
|
$
|
157,603
|
||
F-30