FX Energy 10-Q 2011
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission File No. 000-25386
FX ENERGY, INC.
(Exact name of registrant as specified in its charter)
3006 Highland Drive, Suite 206
Salt Lake City, Utah 84106
(Address of principal executive offices and zip code)
(Registrant’s telephone number, including area code)
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.
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).
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. The number of shares of $0.001 par value common stock outstanding as of May 3, 2011, was 52,315,827.>
FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Three Months Ended March 31, 2011
TABLE OF CONTENTS
PART I—FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations and Comprehensive Income
(in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1: Basis of Presentation
In the opinion of management, our financial statements reflect all adjustments, which are of a normal recurring nature, necessary for presentation of financial statements for interim periods in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions to Form 10-Q in Article 10 of SEC Regulation S-X. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates. As used in this report, the terms “we,” “us,” “our,” and the “Company” mean FX Energy, Inc., and its subsidiaries, unless the context indicates otherwise.
We condensed or omitted certain information and footnote disclosures normally included in our annual audited financial statements, which we prepared in accordance with GAAP. Our quarterly financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010.
We evaluated subsequent events through the date of our financial statement issuance. No events were identified that had a material impact on the financial statements.
Note 2: Net Income per Share
Basic earnings per share was computed by dividing the net income applicable to common shares by the weighted average number of common shares outstanding. Diluted earnings per share was computed for the three months ended March 31, 2011 and 2010, by dividing the net income by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options and unvested restricted stock. Basic and diluted earnings per share were essentially the same for both periods presented.
Outstanding options and unvested restricted stock as of March 31, 2011 and 2010, were as follows:
Note 3: Income Taxes
No income tax expense was recognized for the three-month periods ended March 31, 2011 and 2010, due to the reversal of valuation allowances that offset income tax expense for the period. We are required to provide a valuation allowance 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 deferred tax assets will depend on the generation of future taxable income through profitable operations and the expansion of 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. We are subject to audit by the IRS and various states for the prior three years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months, nor has there been a change in our unrecognized tax positions since December 31, 2010. Our policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. We do not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense related to unrecognized tax benefits recognized during the three months ended March 31, 2011.
Note 4: Business Segments
We operate within two segments of the oil and gas industry: the exploration and production segment and the oilfield services segment. Direct revenues and costs, including exploration costs, depreciation, depletion and amortization costs (“DD&A”), general and administrative costs (“G&A”), and other income directly associated with their respective segments are detailed within the following discussion. Identifiable net property and equipment are reported by business segment for management reporting and reportable business segment disclosure purposes. Current assets, other assets, current liabilities, and long-term debt are not allocated to business segments for management reporting or business segment disclosure purposes.
Reportable business segment information for the three months ended March 31, 2011, and as of March 31, 2011, is as follows (in thousands):
Reportable business segment information for the three months ended March 31, 2010, and as of March 31, 2010, is as follows (in thousands):
Note 5: Share-Based Compensation
We have several share-based incentive plans. Under these plans, options have been granted at an option price equal to the market value of the stock at the date of grant. The granted options have terms ranging from five to seven years and vest over periods ranging from the date of grant to three years. Under the terms of the stock option award plans, we may also issue restricted stock. Restricted stock awards vest in three equal annual installments from the date of grant.
The following table summarizes option activity for the first quarter of 2011:
The following table summarizes option activity for the first quarter of 2010:
The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $8.36 as of March 31, 2011, and $3.43 as of March 31, 2010, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.
During 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2,259,675, which will be amortized ratably over a three-year vesting period. Expense recognized during the first quarter of 2011 totaled $188,306. There were no shares of restricted stock issued during the first three months of 2011.
During 2009, we issued 379,500 shares of restricted stock resulting in unamortized compensation expense of $1,043,625, which will be amortized ratably over a three-year vesting period. Expense recognized during the first quarter of 2011 and 2010 totaled $86,696 and $85,601, respectively.
During 2008, we issued 367,000 shares of restricted stock resulting in unamortized compensation expense of $1,005,580, which will be amortized ratably over a three-year vesting period. Expense recognized during the first quarter of 2010 totaled $80,418.
During 2007, we issued 370,925 shares of restricted stock resulting in unamortized compensation expense of $2,284,991, which will be amortized ratably over a three-year vesting period. Expense recognized during the first quarter of 2010 totaled $0.
The following table summarizes restricted stock activity during the first three months of 2011 and 2010:
Note 6: Stockholders’ Equity
During the first three months of 2011, we sold 6,900,000 shares of common stock in a registered public offering at a price of $7.00 per share. After offering costs, the net proceeds from the offering were approximately $45.2 million. Option holders exercised 16,499 options during the quarter, which resulted in proceeds of approximately $128,000. Also during the first three months of 2011, we issued 106,301 shares for the 2010 contribution to our employee benefit plan. In addition, we issued 8,500 shares to consultants for services.
During the first three months of 2010, we issued 216,977 shares for the 2009 contribution to our employee benefit plan. In addition, we issued 6,000 shares to consultants for services.
Note 7: Fair Value Measurements
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.
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 did not have any significant nonfinancial assets or nonfinancial liabilities that would be recognized or disclosed at fair value on a recurring basis as of March 31, 2011, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first quarter of 2011.
Recurring Fair Value
The following tables set forth the financial assets and liabilities that we measured at fair value on a recurring basis by level within the fair value hierarchy. We classify assets and liabilities measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.
Assets and liabilities measured at fair value on a recurring basis consisted of the following as of March 31, 2011 (in thousands):
Note 8: Notes Payable
We have a $55 million Senior Reserve Base Lending Facility (the “Facility”) with the Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The Facility calls for a periodic interest rate of LIBOR, plus an interest margin of 4.0%, and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on June 30, 2013. The Facility is an interest-only facility until then. An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the expanded credit facility. Deferred financing costs of approximately $142,000 associated with our existing Facility were amortized and charged to interest expense during the first quarter of 2011. Payment of the Facility is secured by our assets in Poland and guaranteed by the Company. We used proceeds from the offering described in note 6 to repay all balances outstanding under the Facility. As of March 31, 2011, we did not have any loans outstanding.
We have access to $40 million under the Facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been on production for 30 days, at which time the full $55 million becomes available. Proceeds from the Facility are intended to support our development, production, and operating activities in Poland.
Note 9: Capitalized Exploratory Well Costs
At March 31, 2011, we had no capitalized costs related to exploratory wells.
Note 10: Foreign Currency Translation and Risk
During the first quarter of 2011, we recorded foreign currency transaction gains of approximately $6.8 million. This amount was attributable to decreases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany and other dollar-denominated loans and unpaid interest. There was a corresponding debit to other comprehensive income for gain loss attributable to the intercompany loans, which was then offset by translation adjustments related to our other balance sheet accounts.
The following table provides a summary of changes in cumulative translation adjustment (in thousands):
Future transaction gains or losses may be significant given the amount of intercompany loans and the volatility of the exchange rate. Future translation adjustments will also vary in concert with changes in exchange rates. These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.
We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The majority of our operations are in Poland, and we have devoted most of our technical talent and capital expenditures in the last several years to our operations in that country. The decision to devote most of our available capital to this area drives our operating results and the changes to our balance sheet and liquidity. Our operations in Poland, which are a combination of existing production and substantial exploration, have grown considerably. Oil and gas production, oil and gas revenues, cash flow, earnings, oil and gas reserves, and oil and gas expenditures in this area have grown significantly over the last three years.
Our U.S. operations also have an impact. Our U.S. operations are smaller than those in Poland and do not present the same level of opportunities for expansion; however, our U.S. operations are a relatively stable source of cash flow. This, too, is reflected in our operating results.
Results of Operations by Business Segment
Quarter Ended March 31, 2011, Compared to the Same Period of 2010
Exploration and Production Segment
Gas Revenues. Revenues from gas sales were approximately $6.0 million during the first quarter of 2011, compared to $4.9 million during the same quarter of 2010. New production at our Sroda-4 well, which began production in late December 2010, was an important component in significantly increased 2011 first quarter natural gas production and revenues.
A summary of the amount and percentage change, as compared to the respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the quarters ended March 31, 2011 and 2010, is set forth in the following table:
In addition to our increased production, two factors resulted in higher gas revenues during the 2011 quarter. First, the price we receive for our Roszkow production is higher than the prices we receive for our other Polish production. At Roszkow, we receive approximately 95% of the published low-methane tariff. At Sroda-4, we receive approximately 86% of the tariff, and at Zaniemysl, we receive approximately 70% of the same tariff. With production at Roszkow dominating Company-wide production, we expect, assuming stable exchange rates, our U.S. dollar-denominated average prices to remain higher compared to pre-Roszkow average prices. Second, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 10% higher during the first quarter of 2011 compared to the same quarter of 2010. The increase was a function of two separate price increases by the Polish utility regulator during the second half of 2010.
Exchange-rate fluctuations had no measurable impact on gas prices or revenues from quarter to quarter. The average exchange rate during the first quarter of both 2011 and 2010 was 2.88 zlotys per U.S. dollar.
Oil Revenues. Oil revenues were approximately $1.2 million for the first quarter of 2011, a 7% increase from $1.1 million recognized during the first quarter of 2010. Production levels were down 13% from quarter to quarter. The most significant factor in the increase in oil revenues was the higher prices received during the first quarter of 2011. Our average oil price during the first quarter of 2011 was $81.69 per barrel, a 20% increase from $68.02 per barrel received during the same quarter of 2010.
A summary of the amount and percentage change, as compared to the respective prior-year period, for oil revenues, average oil prices, and oil production volumes for the quarters ended March 31, 2011 and 2010, is set forth in the following table:
Lease Operating Costs. Lease operating costs were $770,000 during the first quarter of 2011, a decrease of $111,000, or 13%, compared to the same period of 2010. Included in first quarter 2010 operating costs was approximately $108,000 attributable to our Wilga and Kleka wells, both of which are no longer in production.
Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $2.9 million during the first quarter of 2011, compared to $363,000 during the same period of 2010, an almost seven-fold increase, reflecting our significantly higher level of exploration in 2011 than in 2010. First quarter 2011 exploration costs included approximately $2.5 million associated with a two-dimensional, or 2-D, seismic project at our Warsaw South concession, and the remainder associated with 2-D seismic and other costs at other existing Polish concessions. The Polish Oil and Gas Company, or PGNiG, has an option to join our Warsaw South concession for a 49% interest by paying for, among other things, 273 kilometers of 2-D seismic data. Should PGNiG exercise its option, we would recover the funds spent on 2-D seismic data on that concession. First quarter 2010 exploration costs were primarily associated with 2-D seismic surveys on our 100% owned acreage in Poland.
DD&A Expense - Exploration and Production. DD&A expense for producing properties was $502,000 for the first quarter of 2011, an increase of 29%, compared to $389,000 during the same period of 2011. Higher DD&A expense in 2011 was due in part to new depreciation expense at our Sroda-4 property, which we began to depreciate when production began in December 2010. In addition, we recorded higher depreciation expense at our Roszkow well due to depreciating existing costs over a smaller reserve base because of year-end 2010 negative reserve revisions.
Accretion Expense. Accretion expense was $17,000 and $20,000 for the first quarter of 2011 and 2010, respectively. Accretion expense is related entirely to our Asset Retirement Obligation associated with expected future plugging and abandonment costs.
Oilfield Services Segment
Oilfield Services Revenues. Oilfield services revenues were $25,000 during the first quarter of 2011, a decrease of 83%, compared to $143,000 for the first quarter of 2010. During the first quarter of 2011, we performed only minimal well service work for third parties. We drilled one well for third parties during the first quarter of 2010, 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 utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.
Oilfield Services Costs. Oilfield services costs were $141,000 during the first quarter of 2011, compared to $169,000 during the same period of 2010. The quarter-to-quarter decrease was primarily due to the lack of third-party drilling activities during the 2011 quarter compared to the 2010 quarter. Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.
DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $219,000 during the first quarter of 2011, compared to $169,000 during the same period of 2009. The quarter-to-quarter increase was primarily due to recent capital additions being depreciated.
G&A Costs. G&A costs were $1,961,000 during the first quarter of 2011, compared to $1,728,000 during the first quarter of 2010, an increase of $233,000. Increased costs in 2011 were due to higher legal and accounting fees, as well as higher employee costs as we increased headcount in our Poland offices.
Stock Compensation (G&A). For the three-month periods ended March 31, 2011 and 2010, we recognized $356,000 and $352,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock.
Interest and Other Income (Expense). Interest and other income was $53,000 during the first quarter of 2011, an increase of $47,000, compared to $6,000 during the same period of 2010. The increase was a reflection of higher cash balances available for investment. During the first quarter of 2011, we incurred $600,000 in interest expense, which included $142,000 of amortization of previously incurred loan fees. During the first quarter of 2010, we incurred $157,000 in interest expense, which included $62,000 of amortization of previously incurred loan fees. Interest expense increased in the 2011 quarter to due higher interest rates on our outstanding credit facility balances.
Foreign Exchange Gains and Losses. As discussed in note 10 to the financial statements, during the first quarter of 2011, we recorded foreign currency transaction gains of approximately $6.8 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany and other dollar-denominated loans. We recorded foreign exchange losses of $1.0 million during the same quarter of 2010, which were also principally related to our intercompany loans. Exchange-rate fluctuation from year-end 2010 to March 31, 2011, of 5% was greater than the exchange-rate fluctuation from year-end 2009 to March 31, 2010, of 1%. The increase in volatility resulted in a higher foreign exchange impact in 2011 compared to 2010.
Liquidity and Capital Resources
For much of our history, we have financed our operations principally through the sale of equity securities, bank borrowings, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. However, as our oil and gas production has increased in Poland in the last several years and as higher oil prices have improved the profitability of our U.S. production, our internally generated cash flow has become a significant source of operations financing.
Following a registered public offering of 6.9 million shares of common stock, which resulted in net proceeds to us of approximately $45.2 million, in March of 2011 we paid off all amounts previously outstanding under our credit facility. As of March 31, 2011, we had cash and cash equivalents of $29.6 million.
2011 Liquidity and Capital
Working Capital (current assets less current liabilities). Our working capital was $27.7 million as of March 31, 2011, an increase of $9.5 million from December 31, 2010. Our current assets at March 31, 2011, included approximately $3.1 million in accrued oil and gas sales from both the United States and Poland. Our current liabilities at quarter-end included approximately $3.3 million in costs related to capital and exploration projects in Poland.
Operating Activities. Net cash provided by operating activities was $4.7 million during the first three months of 2011, compared to $2.5 million during the first three months of 2010. Higher revenues in 2011, associated with our increased levels of gas production in Poland, were the primary factor in our improved 2011 results.
Investing Activities. During the first three months of 2011, we used cash of $5.6 million in investing activities. We used $5.4 million for current year capital additions in Poland and $188,000 for capital additions in our office and drilling equipment. During the first three months of 2010, we used cash of $658,000 in investing activities. We used $142,000 for capital additions in Poland and $72,000 related to our proved properties in the United States, used $273,000 to pay accounts payable related to prior-year capital costs, and used $171,000 for capital additions in our office and drilling equipment.
Financing Activities. During the first quarter of 2011, we issued 6.9 million shares of common stock in a registered public offering, which resulted in net proceeds to us, after offering costs, of approximately $45.2 million. We used $35.0 million of those proceeds to repay amounts outstanding under our credit facility. We also received proceeds of $128,000 from the exercise of stock options. There were no similar transactions during the first quarter of 2010.
Our Capital Resources and Future Expenditures
Our anticipated sources of liquidity and capital for 2011 include our working capital of $27.7 million at March 31, 2011, available credit of $55 million under our credit facility when we meet the benchmarks discussed below, cash available from our operations, and proceeds from the possible sale of securities.
We currently have a $55 million credit facility with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The credit facility calls for a periodic interest rate of LIBOR plus 4.0% and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on June 30, 2013. The credit facility is an interest-only facility until June 2013. As of March 31, 2011, we had no amounts outstanding under the credit facility. We have access to $40 million under the credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been in production for 30 days, at which time the full $55 million becomes available. We expect to reach this benchmark in the second quarter of 2011. Proceeds from the credit facility are intended to support our operating activities in Poland. Further, we believe our total credit line could be expanded, even without including our recent 2011 Lisewo-1 discovery, in a revised credit facility.
As of March 31, 2011, we were producing gas from three wells in Poland. We expect production from our two Kromolice wells to commence shortly as new production facilities are completed in the second quarter of 2011. We expect production from these new wells to increase funds available for exploration and development over 2010 levels. Our Winna Gora well is expected to begin production in 2012. In addition, in early 2011, we drilled and completed the successful Lisewo-1 well in our Fences concession, which we expect to further increase revenue in 2013.
We have an effective universal shelf registration statement under the Securities Act of 1933 under which we may sell up to $200 million of equity or debt securities of various kinds. In December 2010, we sold 1.5 million shares of stock for $9.0 million in a registered public offering, which resulted in net proceeds to us of approximately $8.4 million. Also in December 2010, we entered into an agreement to possibly sell up to $50 million in common stock during the next two years in at-the-market transactions. Through the date of this filing, we have not sold any stock under that agreement. As discussed above, in March 2011, we sold 6.9 million shares of stock for $48.3 million, which resulted in net proceeds to us of approximately $45.2 million. The remaining $92.7 million balance of securities available for sale under the registration statement is available for sale at any time, subject to market conditions and our ability to access the capital markets, to further finance our exploration and development plans in Poland and for other corporate purposes.
We expect our primary use of cash for 2011 will be for our exploration and development activities, most of which will be in Poland. We expect the cost of these activities to range from $60 to $70 million for 2-D and 3-D seismic data acquisition and analysis, production facilities for existing discoveries, and additional exploration drilling. The actual amount of our expenditures will depend on ongoing exploration results; the pace at which PGNiG, our operating partner in the Fences project area, determines to participate; the availability of drilling and other exploration resources; and the amount of capital we obtain from the various sources discussed above. Our various sources of liquidity and capital outlined above should more than enable us to meet our capital needs in Poland and the United States for the next 12 months.
Based on current conditions, we presently expect our exploration and development programs will continue in spite of uncertain global economic conditions; however, in recognition of the ongoing economic downturn, we plan to continue, as we have in prior years, matching capital spending with our cash on hand, expected discretionary cash flow, increased debt capacity, and proceeds from the sale of securities. We have the ability to control the timing and amount of most of our future capital and exploration costs.
We may incur operating losses in future periods, and we continue to fund substantial exploration and development in Poland. We have a history of operating losses. From our inception in January 1989 through March 31, 2011, we have incurred cumulative net losses of approximately $155 million. Despite our recent and expected future increases in production and revenues, our exploration and production activities may continue to result in net losses in future years, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses. While revenues from our operations exceed our fixed operating and overhead costs, we reported negative cash flow from operating activities as recently as 2009.
We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements such as those recently negotiated for our Kutno and Warsaw South project areas, in which industry participants are bearing the initial exploration costs to earn an interest in the project or other arrangements, all of which may dilute the interest of our existing stockholders or our interest in the specific project financed.
We will allocate our existing capital, as well as funds we may obtain in the future, among our various projects at our discretion. We may change the allocation of capital among the categories of anticipated expenditures depending upon future events. For example, we may change the allocation of our expenditures based on the actual results and costs of future exploration, appraisal, development, production, property acquisition, and other activities. In addition, we may have to change our anticipated expenditures if costs of placing any particular discovery into production are higher, if the field is smaller, or if the commencement of production takes longer than expected.
New Accounting Pronouncements
We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position, and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.
Critical Accounting Policies
A summary of our significant accounting policies is included in Note 1 of our Consolidated Financial Statements contained in our annual report on Form 10-K for the year ended December 31, 2010. We believe the application of these accounting policies on a consistent basis enables us to provide financial statement users with useful, reliable, and timely information about our earnings results, financial condition, and cash flows.
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make judgments, estimates, and assumptions regarding uncertainties that affect the reported amounts presented and disclosed in the financial statements. Our management reviews these estimates and assumptions, which are based on historical experience, changes in business conditions, and other relevant factors that it believes to be reasonable under the circumstances. In any given reporting period, actual results could differ from the estimates and assumptions used in preparing our financial statements.
Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgment due to a high degree of uncertainty at the time the estimate is made. Our senior management has discussed the development and selection of our accounting policies, related accounting estimates, and the disclosures set forth below with the Audit Committee of our Board of Directors. We believe our critical accounting policies include those addressing the recoverability and useful lives of assets, the retirement obligations associated with those assets, and the estimates of oil and gas reserves.
This report contains statements about the future, sometimes referred to as “forward-looking” statements. 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. 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. Statements that describe our future strategic plans, goals, or objectives are also forward-looking statements.
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, proposals, plans, or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as the future timing and results of drilling individual wells and other exploration and development activities; future variations in well performance as compared to initial test data; future events that may result in the need for additional capital; the prices at which we may be able to sell oil or gas; fluctuations in prevailing prices for oil and gas; our ability to complete the acquisition of targeted new or expanded exploration or development prospects; uncertainties of certain terms to be determined in the future relating to our oil and gas interests, including exploitation fees, royalty rates, and other matters; future drilling and other exploration schedules and sequences for various wells and other activities; uncertainties regarding future political, economic, regulatory, fiscal, taxation, and other policies in Poland; the cost of additional capital that we may require and possible related restrictions on our future operating or financing flexibility; our future ability to attract strategic participants to share the costs of exploration, exploitation, development, and acquisition activities; and future plans and the financial and technical resources of strategic participants.
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 as a result of various factors. The forward-looking statements included in this report are made only as of the date of this report. We disclaim any obligation to update any forward-looking statements whether as a result of new information, future events, or otherwise.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Realized pricing for our oil production in the United States and Poland 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.
Substantially all of our gas in Poland is sold PGNiG or its subsidiaries under contracts that extend for the life of each field. Prices are determined contractually and, in the case of our Roszkow, Zaniemysl, and Kleka wells, are tied to published tariffs. The tariffs are set from time to time by the public utility regulator in Poland. Although we are not directly subject to such tariffs, we have elected to link our price to these tariffs in our contracts with PGNiG. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in an unregulated setting and may be lower than prevailing western European prices. We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.
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 Polish zloty is subject to exchange-rate fluctuations that are beyond our control. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes. We have used forward-purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense is recognized in our consolidated financial statements. As of March 31, 2011, we had no outstanding zloty forward-purchase contracts.
ITEM 4. 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 time 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 March 31, 2011, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of March 31, 2011, our disclosure controls and procedures were effective.
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.
PART II—OTHER INFORMATION
ITEM 1A. RISK FACTORS
Information regarding risk factors appears in “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Forward-Looking Statements,” in Part I — Item 2 of this Form 10-Q and in Part I — Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2010, are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially and adversely affect our business, financial condition, or operating results.
ITEM 6. EXHIBITS
The following exhibits are filed as a part of this report:
Pursuant to the requirements 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.