FX Energy (FXEN) 10-Q 2010 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010

Commission File No. 000-25386

FX ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada	87-0504461
(State or other jurisdiction of	(IRS Employer
incorporation or organization)	Identification No.)

3006 Highland Drive, Suite 206

Salt Lake City, Utah  84106

(Address of principal executive offices and zip code)

(801) 486-5555

(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.

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).

Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

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 November 4, 2010, was 43,411,027.

FX ENERGY, INC. AND SUBSIDIARIES

Form 10-Q for the Nine Months Ended September 30, 2010

TABLE OF CONTENTS

Item		Page
	Part I—Financial Information
1	Financial Statements
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations and Comprehensive Income (Loss)	5
	Consolidated Statements of Cash Flows	6
	Notes to the Consolidated Financial Statements	7
2	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	13
3	Quantitative and Qualitative Disclosures about Market Risk	22
4	Controls and Procedures	23
	Part II—Other Information
1	Legal Proceedings	23
1A	Risk Factors	23
6	Exhibits	24
--	Signatures	25

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PART I—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	September 30,		December 31,
	2010		2009
ASSETS
Current assets:
Cash and cash equivalents	$	7,253	$	4,225
Receivables:
Accrued oil and gas sales		1,675		2,875
Other receivables		3,207		918
Inventory		238		232
Other current assets		287		394
Total current assets		12,660		8,644
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		32,994		32,700
Unproved		3,362		3,403
Other property and equipment		8,286		7,654
Gross property and equipment		44,642		43,757
Less accumulated depreciation, depletion and amortization		(11,396)		(11,466)
Net property and equipment		33,246		32,291
Other assets:
Certificates of deposit		406		406
Loan fees		2,515		729
Total other assets		2,921		1,135
Total assets	$	48,827	$	42,070

-Continued-

The accompanying notes are an integral part of these consolidated financial statements.

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FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands, except share data)

-Continued-

	September 30,		December 31,
	2010		2009
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,758	$	3,569
VAT payable		767		575
Accrued liabilities		1,071		1,048
Total current liabilities		4,596		5,192
Long-term liabilities:
Notes payable		27,468		25,000
Asset retirement obligation		1,181		1,133
Total long-term liabilities		28,649		26,133
Total liabilities		33,245		31,325
Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized
as of September 30, 2010, and December 31, 2009; no shares
outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized
as of September 30, 2010, and December 31, 2009; 43,267,071
and 43,037,540 shares issued and outstanding as of September 30,
2010 and December 31, 2009, respectively		43		43
Additional paid-in capital		162,286		160,594
Cumulative translation adjustment		12,885		10,738
Accumulated deficit		(159,632)		(160,630)
Total stockholders’ equity		15,582		10,745
Total liabilities and stockholders’ equity	$	48,827	$	42,070

The accompanying notes are an integral part of these consolidated financial statements.

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FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

(in thousands, except per share amounts)

	For the three months ended September 30,				For the nine months ended September 30,
	2010		2009		2010		2009
Revenues:
Oil and gas sales	$	5,242	$	2,691	$	16,785	$	6,286
Oilfield services		1,406		1,118		2,128		1,771
Total revenues		6,648		3,809		18,913		8,057
Operating costs and expenses:
Lease operating expenses		824		857		2,502		2,415
Exploration costs		361		686		1,886		4,071
Property impairment		39		1,864		554		1,864
Oilfield services costs		764		657		1,375		1,274
Depreciation, depletion and amortization		524		425		1,629		1,173
Accretion expense		20		8		59		24
Stock compensation		354		449		1,057		1,332
General and administrative		1,496		1,512		5,476		4,914
Total operating costs and expenses		4,382		6,458		14,538		17,067
Operating income (loss)		2,266		(2,649)		4,375		(9,010)
Other income (expense):
Interest and other income (expense)		789		11		812		50
Interest expense		(990)		(141)		(1,310)		(452)
Foreign exchange gain (loss)		20,087		12,227		(2,879)		5,547
Total other income (expense)		19,886		12,097		(3,377)		5,145
Net income (loss)		22,152		9,448		998		(3,865)
Other comprehensive income (loss)
Foreign currency translation adjustment		(15,415)		(9,579)		2,151		(5,201)
Comprehensive income (loss)	$	6,737	$	(131)	$	3,149	$	(9,066)
Net income (loss) per common share
Basic	$	0.51	$	0.22	$	0.02	$	(0.09)
Diluted	$	0.51	$	0.22	$	0.02	$	(0.09)
Weighted average common shares outstanding
Basic		43,261		42,560		43,246		42,470
Dilutive effect of stock options		-		84		-		-
Diluted		43,261		42,644		43,246		42,470

The accompanying notes are an integral part of these consolidated financial statements.

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FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	For the Nine Months Ended
	September 30,
	2010		2009
Cash flows from operating activities:
Net income (loss)	$	998	$	(3,865)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		1,629		1,173
Accretion expense		59		24
Amortization of bank fees		740		137
Property impairment		554		1,864
Stock compensation		1,057		1,332
Foreign exchange losses		2,769		(6,756)
Common stock issued for services		635		739
Increase (decrease) from changes in working capital items:
Receivables		(841)		(861)
Inventory		(6)		(12)
Other current assets		107		48
Other assets		(58)		(122)
Accounts payable and accrued liabilities		(1,422)		(2,437)
Net cash provided by (used in) operating activities		6,221		(8,736)
Cash flows from investing activities:
Additions to oil and gas properties		(2,483)		(6,680)
Additions to other property and equipment		(746)		(802)
Additions to marketable securities		--		(11)
Proceeds from maturities of marketable securities		--		4,661
Net cash used in investing activities		(3,229)		(2,832)
Cash flows from financing activities:
Proceeds from credit facility		27,468		--
Payments on credit facility		(25,000)		--
Payment of loan fees		(2,468)		--
Payments on loan related to auction rate securities		--		(2,808)
Proceeds from exercise of stock options and warrants		--		132
Net cash used in financing activities		--		(2,676)
Effect of exchange-rate changes on cash		36		164
Net increase (decrease) in cash		3,028		(14,080)
Cash and cash equivalents at beginning of year		4,225		16,588
Cash and cash equivalents at end of period	$	7,253	$	2,508

The accompanying notes are an integral part of these consolidated financial statements.

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FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

(Unaudited)

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 t his 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, 2009, and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 20, 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 (Loss) per Share

Basic earnings per share is computed by dividing the net income (loss) applicable to common shares by the weighted average number of common shares outstanding.  We had a net loss in the nine-month period ended September 30, 2009.  No options were included in the computation of diluted earnings per share for this period because the effect would have been antidilutive.

Diluted earnings per share was computed for the three months ended September 30, 2009, September 30, 2010, and the nine months ended September 30, 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.  There were no dilutive unexercised stock options in the three- and nine-month periods ended September 30, 2010.  Basic and diluted earnings per share were essentially the same for each of these periods.

Outstanding options and unvested restricted stock as of September 30, 2010 and 2009, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
September 30, 2010	2,151,660	$0.00 - $10.65
September 30, 2009	2,165,247	$0.00 - $10.65

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Note 3:  Income Taxes

No income tax benefit was recognized from the net loss generated in the nine-month period ended September 30, 2009.  No income tax expense was recognized for the three-month and nine-month periods ending September 30, 2010, and the three-month period ending September 30, 2009, 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 ass ociated 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.  There has been no change in our unrecognized tax positions since December 31, 2009.  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 nine months ended September 30, 2010.

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 (“DD&A”) costs, general and administrative (“G&A”) costs, 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 September 30, 2010, the nine months ended September 30, 2010, and as of September 30, 2010, is as follows (in thousands):

	Reportable Segments
	Exploration & Production				Oilfield Services		Non-Segmented		Total
	U.S.			Poland
Three months ended September 30, 2010:
Revenues	$	1,035	$	4,207	$	1,406	$	--	$	6,648
Net income (loss)(1)		286		3,324		443		18,099		22,152
Nine months ended September 30, 2010:
Revenues	$	3,114	$	13,671	$	2,128	$	--	$	18,913
Net income (loss)(1)		1,169		9,499		218		(9,888)		998
As of September 30, 2010:
Identifiable net property and equipment	$	1,075	$	29,749	$	2,360	$	62	$	33,246

_______________

(1) Non-segmented reconciling items for the third quarter include $1,496 of G&A costs, $354 of noncash stock compensation expense, $119 of other expense, $19 of corporate DD&A costs, and $20,087 of foreign exchange gains.  Non-segmented reconciling items for the first nine months include $5,476 of G&A costs, $1,057 of noncash stock compensation expense, $415 of other expense, $61 of corporate DD&A costs, and $2,879 of foreign exchange losses.

8

Reportable business segment information for the three months ended September 30, 2009, the nine months ended September 30, 2009, and as of September 30, 2009, is as follows (in thousands):

	Reportable Segments
	Exploration & Production				Oilfield Services		Non-Segmented		Total
	U.S.			Poland
Three months ended September 30, 2009:
Revenues	$	950	$	1,741	$	1,118	$	--	$	3,809
Net income (loss)(1)		123		(1,102)		306		10,121		9,448
Nine months ended September 30, 2009:
Revenues	$	2,269	$	4,017	$	1,771	$	--	$	8,057
Net income (loss)(1)		18		(2,788)		73		(1,168)		(3,865)
As of September 30, 2009:
Identifiable net property and equipment	$	297	$	28,984	$	2,122	$	110	$	31,513

_______________

(1) Non-segmented reconciling items for the third quarter include $1,512 of G&A costs, $449 of noncash stock compensation expense, $130 of other expense, $15 of corporate DD&A costs, and $12,227 of foreign exchange gains.  Non-segmented reconciling items for the first nine months include $4,914 of G&A costs, $1,332 of noncash stock compensation expense, $402 of other expense, $67 of corporate DD&A costs, and $5,547 of foreign exchange gains.

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 nine months of 2010:

		Weighted	Weighted Average
	Number of	Average	Remaining Contractual	Aggregate
	Options	Exercise Price	Life (in years)	Intrinsic Value
Options outstanding:
Beginning of year	1,470,441	$6.47
Exercised	(51,000)	3.19
End of period	1,419,441	6.58	0.84
Exercisable at end of period	1,419,441	6.58	0.84	$93,937

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The following table summarizes option activity for the first nine months of 2009:

		Weighted	Weighted Average
	Number of	Average	Remaining Contractual	Aggregate
	Options	Exercise Price	Life (in years)	Intrinsic Value
Options outstanding:
Beginning of year	1,980,441	$5.65
Exercised	(435,000)	2.40
Cancelled	(75,000)	8.58
End of period	1,470,441	6.47	1.56
Exercisable at end of period	1,470,441	6.47	1.56	$2,040

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $4.14 as of September 30, 2010, and $3.23 as of September 30, 2009, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.

Restricted Stock

During 2009, we issued 379,500 shares of restricted stock resulting in unamortized compensation expense of $1,043,625, which is being amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2010 totaled $259,187.  There were no shares of restricted stock issued during the first nine months of 2010.

During 2008, we issued 367,000 shares of restricted stock resulting in unamortized compensation expense of $1,005,580, which is being amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2010 and 2009 totaled $250,249 and $250,722, respectively.

During 2007, we issued 370,925 shares of restricted stock resulting in unamortized compensation expense of $2,284,991, which is being amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2010 and 2009 totaled $547,718 and $569,669, respectively.

During 2006, we issued 318,400 shares of restricted stock resulting in unamortized compensation expense of $2,053,680, which is being amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2010 and 2009 totaled $0 and $511,978, respectively.

The following table summarizes restricted stock activity during the first nine months of 2010 and 2009:

	Number of Shares
	2010	2009
Unvested restricted stock outstanding:
Beginning of year	739,535	714,421
Issued	--	--
Forfeited	(2,382)	(14,682)
Vested	(4,934)	(4,933)
End of period	732,219	694,806

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Note 6:  Stockholders’ Equity

In September of 2010, option holders exercised a total of 39,000 outstanding options at a price of $3.84 per share by surrendering currently owned shares to pay the exercise price.  As a result of this exercise, we issued 6,500 incremental shares.  In June of 2010, option holders exercised a total of 12,000 outstanding options at a price of $3.14 per share by surrendering currently owned shares to pay the exercise price.  As a result of this exercise, we issued 2,436 incremental shares.  In January 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.

In August 2009, option holders exercised a total of 55,000 outstanding options at a price of $2.40 per share, resulting in proceeds to us of $132,000.  Additionally, option holders exercised a total of 380,000 outstanding options at a price of $2.40 per share by surrendering currently owned shares to pay the exercise price.  As a result of this exercise, we issued 169,860 incremental shares.  During the first nine months of 2009, we issued 228,100 shares for a 2008 contribution to our employee benefit plan.  In addition, we issued 21,000 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, when 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 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 September 30, 2010, nor did we have any significant assets or liabilities measured at fair value on a nonrecurring basis to report in the first nine months of 2010.

Recurring Fair Value

The following table sets 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.

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Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 30, 2010 (in thousands):

	September 30,
	2010	Level 1(1)	Level 2(2)	Level 3(3)
Cash equivalents:
Money market funds	$   764	$   764	--	--

_______________

(1) Quoted prices in active markets for identical assets.

(2) Significant other observable inputs.

(3) Significant unobservable inputs.

Note 8:  Notes Payable

On August 5, 2010, we refinanced our existing $25 million Senior Facility Agreement (the “Facility”) with The Royal Bank of Scotland plc by executing a new, $55 million Senior Reserve Base Lending Facility (the “New Facility”) between the Company and the Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV.  The New 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 New Facility is an interest-only facility until then.  Unamortized deferred financing costs of approximately $577,000 associated with our existing Facility wer e charged to interest expense during the third quarter of 2010.  Payment of the New Facility is secured by our assets in Poland and guaranteed by the Company.  As of September 30, 2010, the total amount drawn under the New Facility was $27.5 million.

We have access to $40 million under the New 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 New Facility are intended to support our development, production, and operating activities in Poland.

In consideration for the New Facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.5 million.  These fees, which were paid by increasing the amount of debt drawn under the New Facility, have been capitalized as deferred financing costs and are being amortized over the five-year term of the loan, beginning in the third quarter of 2010.  An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the New Facility.  There are no financial covenants associated with the New Facility.

Note 9:  Capitalized Exploratory Well Costs

We had $637,000 of capitalized costs related to our Lisewo-1 well, which was being drilled at September 30, 2010.

Note 10:  Property Impairments

Our 2010 remediation efforts at our Kleka well failed to restore commercial production.  Accordingly, we impaired the remaining capital costs related to the well of approximately $554,000.

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Note 11:  Foreign Currency Translation and Risk

During the first nine months of 2010, we recorded foreign currency transaction losses of approximately $2.9 million.  This amount was attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.  There was a corresponding credit to other comprehensive income for the 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):

	For the Nine Months
	Ended September 30, 2010
Balance at December 31, 2009	$	10,738
Increase related to losses on intercompany loans	2,769
Decrease related to translation adjustments	(622)
Balance at September 30, 2010	$	12,885

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

Introduction

Our two major operating areas (Poland and the U.S.) have very different characteristics, which are reflected in the following discussion.  Our Polish operations are progressing in their exploration and development.  These assets are a combination of existing oil and gas production, completed wells that we expect to be brought into production, and wildcat exploration opportunities.  These assets, in total, have a relatively high risk/reward profile compared to our U.S. assets.  Our U.S. operations, which include both oil production and oilfield services, are relatively mature.

Before 2007, most of our revenues were from our U.S. operations.  However, since that time, our Polish gas production and revenues have become substantially larger than our U.S. revenues.  In particular, the natural gas production added by our Zaniemysl well in late 2006 and our Roszkow well in late 2009 has been very significant.  We expect this trend toward a greater percentage of our revenues being from Poland will continue in the immediately foreseeable future.

See “Results of Operations by Business Segment” below.

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Results of Operations by Business Segment

Quarter Ended September 30, 2010, Compared to the Same Period of 2009

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $4.2 million during the third quarter of 2010, compared to $1.7 million during the same quarter of 2009.  Production at our Roszkow well, which began producing in September 2009, was the primary driver in the quarter-over-quarter increase.

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 September 30, 2010 and 2009, is set forth in the following table:

	For the Quarter Ended September 30,
	2010	2009	Change
Gas revenues	$4,207,000	$1,728,000	+143%
Average price (per thousand cubic feet)	$5.30	$4.65	+14%
Production volumes (thousand cubic feet)	794,000	372,000	+113%

As we discussed in our Form 10-Q for the period ended June 30, 2010, both our Roszkow and Zaniemysl wells were shut in for two weeks during September 2010 for annual maintenance and pressure testing.  Accordingly, third quarter 2010 production volumes and gas revenues were lower than second quarter 2010 levels.  Following the maintenance and pressure testing, the operator of both wells, the Polish Oil and Gas Company, or POGC, reduced the daily production at each well by approximately 7%.  We are discussing with POGC the rationale for the reductions; however, at this time, we cannot assure that POGC will agree to restore the production rates to their pre-maintenance levels.

The effect of anticipated production declines will be mitigated, to some extent, by the second tariff increase in 2010.  In late September, the Polish energy regulator approved a tariff increase of approximately 6.4%.  All tariffs are denominated in Polish zlotys.  The increase becomes effective for us beginning November 1, 2010.

For the quarter, we recognized a 14% increase in natural gas prices.  At Roszkow, we receive approximately 95% of the published low-methane tariff.  At Zaniemysl, we receive approximately 70% of the same tariff.  With production at Roszkow now dominating Company-wide production, we expect average zloty-based prices to remain higher compared to pre-Roszkow average prices.  Also during the quarter, period-to-period strength in the Polish zloty against the U.S. dollar, combined with an increase in Polish gas tariffs, resulted in higher quarter-to-quarter gas prices.  The average exchange rate during the third quarter of 2010 was 3.10 zlotys per U.S. dollar.  The average exchange rate during the third quarter of 2009 was 2.94 zlotys per U.S. dollar, a change of approximately 5%.  Should the zloty continue to appreciate against the U.S. dollar, our dollar-denominated gas prices will likewise increase.  Effective July 1, 2010, gas tariffs in Poland were increased by 6.8% from their previous levels.

Oil Revenues.  Oil revenues were $1.0 million for the third quarter of 2010, an 8% increase from $962,000 recognized during the third quarter of 2009.  Production levels decreased, due to normal production declines, by approximately 5% from 2009 to 2010.  The decrease in production was more than offset by the higher prices received during the third quarter of 2010.  Our average oil price during the third quarter of 2010 was $65.31 per barrel, a 13% increase from $57.83 per barrel received during the same quarter of 2009.

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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 September 30, 2010 and 2009, is set forth in the following table:

	For the Quarter Ended September 30,
	2010	2009	Change
Oil revenues	$1,035,000	$962,000	+8%
Average price (per barrel)	$65.31	$57.83	+13%
Production volumes (barrels)	15,800	16,600	-5%

Lease Operating Costs.  Lease operating costs of $824,000 during the third quarter of 2010 were slightly less than the third quarter 2009 amount of $857,000.  The additional operating costs at our Roszkow property, which began producing during September of 2009, were offset by a reduction in costs at our U.S. properties.

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $361,000 during the third quarter of 2010, compared to $686,000 during the same period of 2009, a decrease of 47%.  Third quarter 2010 geological and geophysical costs were primarily associated with two-dimensional, or 2-D, seismic surveys on our 100%-owned acreage in Poland.  Third quarter 2009 exploration costs included approximately $300,000 associated with our ongoing Fences concession area three-dimensional, or 3-D, seismic surveys, and the remainder was associated with 2-D seismic and other costs.

Property Impairment.  During the third quarter of 2009, our Wilga well ceased production.  Accordingly, we impaired the then-remaining capital costs of approximately $1.9 million as of September 30, 2009.  Third quarter 2010 property impairment costs include $39,000 of additional costs associated with our Kleka well, which ceased production earlier in 2010, the capital costs of which were impaired during the second quarter.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $305,000 for the third quarter of 2010, an increase of 22% compared to $250,000 during the same period of 2009.  Higher DD&A expense in 2010 was due to incremental depreciation expense at our Roszkow property, which we began to depreciate when production started in September 2009.

Accretion Expense.  Accretion expense was $20,000 and $8,000 for the third quarter of 2010 and 2009, respectively.  Accretion expense is related entirely to our Asset Retirement Obligation associated with expected future plugging and abandonment costs.

Oilfield Services Segment

Oilfield Services Revenues.  Oilfield services revenues were $1.4 million during the third quarter of 2010, an increase of 26% compared to $1.1 million for the third quarter of 2009.  We drilled three wells for third parties during the third quarter of 2010, along with additional well service work.  During the third quarter of 2009, we drilled 11 wells for third parties; however, most of these were shallow wells, which can be drilled in only two to three days.  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 equipm ent on our Company-owned properties, and other factors.

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Oilfield Services Costs.  Oilfield services costs were $764,000 during the third quarter of 2010, compared to $657,000 during the same period of 2009.  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 $199,000 during the third quarter of 2010, compared to $155,000 during the same period of 2009.  The quarter-to-quarter increase was primarily due to depreciation on recent capital additions.

Nonsegmented Information

G&A Costs.  G&A costs were $1.5 million during the third quarter of 2010, down 1% from third quarter of 2009 levels.

Stock Compensation (G&A).  For the three-month periods ended September 30, 2010 and 2009, we recognized $354,000 and $449,000, respectively, of stock compensation expense related to the amortization of restricted stock grants.

Interest and Other Income (Expense).  Interest and other income was $789,000 during the third quarter of 2010, compared to $11,000 during the same period of 2009.  Included in the 2010 amount was a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008.

During the third quarter of 2010, we incurred $995,000 in interest expense.  In connection with our new credit facility, we charged $577,000 of previously unamortized loan fees associated with our prior credit facility to interest expense during this quarter.  We also recorded $122,000 of amortization of loan fees and $87,000 in unused commitment fees.  During the third quarter of 2009, we incurred $141,000 in interest expense, which included $46,000 of amortization of previously incurred loan fees.

Foreign Exchange Gain (Loss).  During the third quarter of 2010, we recorded foreign currency transaction gains of approximately $20.1 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans.  We recorded foreign exchange gains of $12.2 million during the same quarter of 2009, which were also principally related to our intercompany loans.  During the third quarter of 2010, the zloty strengthened by approximately 14% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.  During the third quarter of 2009, the zloty strength ened by approximately 9% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.

Nine Months Ended September 30, 2010, Compared to the Same Period of 2009

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $13.7 million during the first nine months of 2010, compared to $4.0 million during the same period of 2009.  Production at our Roszkow well, which began producing in September 2009, was the primary driver in the period-over-period increase.

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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 nine months ended September 30, 2010 and 2009, is set forth in the following table:

	For the Nine Months Ended September 30,
	2010	2009	Change
Revenues	$13,670,000	$3,988,000	+243%
Average price (per thousand cubic feet)	$5.19	$4.49	+16%
Production volumes (thousand cubic feet)	2,632,000	888,000	+196%

We recognized a 16% increase in natural gas prices period over period.  As discussed previously, at Roszkow, we receive approximately 95% of the published low-methane tariff.  At Zaniemysl, we receive approximately 70% of the same tariff.  With production at Roszkow now dominating Company-wide production, we expect average zloty-based prices to remain higher compared to pre-Roszkow average prices.  Also during the quarter, period-to-period strength in the Polish zloty against the U.S. dollar helped offset a decline in gas tariffs for our legacy Poland production.  Although the amount of Polish zlotys received per thousand cubic feet of production was approximately 3% lower during the first nine months of 2010 compared to the same period o f 2009, due to a tariff reduction that was effective June 1, 2009, average U.S. dollar-denominated gas prices related to our legacy Poland production increased approximately 16% from the first nine months of 2009 to the same period of 2010.  The average exchange rate during the first nine months of 2010 was 3.05 zlotys per U.S. dollar.  The average exchange rate during the first nine months of 2009 was 3.22 zlotys per U.S. dollar, a change of approximately 5%.

As discussed previously, the Polish Energy Regulatory Office approved two gas tariff increases during the first nine months of 2010.  The first tariff increase, effective on July 1, 2010, was for 6.8%.  The second increase, effective November 1, 2010, was for 6.4%.  All tariffs are denominated in Polish zlotys.

Oil Revenues.  Oil revenues were $3.1 million for the first nine months of 2010, a 36% increase from the $2.3 million recognized during the first nine months of 2009.  Production from our U.S. properties declined 3% during the first nine months of 2010 due to regular production declines.  The most significant factor in the increase in oil revenues was the higher prices received during the first nine months of 2010.  Our average oil price during the first nine months of 2010 was $66.81 per barrel, a 41% increase from $47.50 per barrel received during the same period of 2009.

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 nine months ended September 30, 2010 and 2009, is set forth in the following table:

	For the Nine Months Ended September 30,
	2010	2009	Change
Revenues	$3,114,000	$2,298,000	+36%
Average price (per barrel)	$66.81	$47.50	+41%
Production volumes (barrels)	46,600	48,400	-4%

Lease Operating Costs.  Lease operating costs were $2.5 million during the first nine months of 2010, an increase of 4% compared to the same period of 2009.  Higher operating costs in 2010 were due primarily to production beginning at the end of 2009 at Roszkow, offset by lower costs at our U.S. properties.

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Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $1.9 million during the first nine months of 2010, compared to $4.1 million during the same period of 2009, a decrease of 54%.  The period-to-period decline is attributable to our lower level of 3-D seismic activity in 2010 compared to 2009.  First nine months 2010 geological and geophysical costs were primarily associated with 2-D seismic surveys on our 100%-owned acreage in Poland and $872,000 of dry-hole costs associated with our Zakowo project.  First nine months 2009 exploration costs included approximately $2.8 million associated with our ongoing Fences concession area 3-D seismic surveys, and the remainder was associated with 2-D seismic and other costs at both existing and new concessions.

Property Impairment.  Remediation efforts at our Kleka well earlier in 2010 failed to restore commercial production.  Accordingly, we have impaired the remaining capital costs for the well of approximately $554,000.  During the first nine months of 2009, our Wilga well ceased production.  Accordingly, we impaired the then-remaining capital costs of approximately $1.9 million as of September 30, 2009.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $1.0 million for the first nine months of 2010, an increase of 52% compared to $681,000 during the same period of 2009.  The increase is primarily due to new depreciation expense at our Roszkow property, which we began to depreciate when production began in September 2009.

Accretion Expense.  Accretion expense was $59,000 and $24,000 for the first nine months of 2010 and 2009, respectively.  Accretion expense is related entirely to our Asset Retirement Obligation.

Oilfield Services Segment

Oilfield Services Revenues.  Oilfield services revenues were $2.1 million during the first nine months of 2010, an increase of 20%, compared to $1.8 million for the first nine months of 2009.  We drilled seven wells for third parties during the first nine months of 2010, along with additional well service work.  During the first nine months of 2009, we drilled 25 wells for third parties; however, most of these were shallow wells, which can be drilled in only two to three days.  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 $1.4 million during the first nine months of 2010, compared to $1.3 million during the same period of 2009.  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 $535,000 during the first nine months of 2010, compared to $428,000 during the same period of 2009.  The period-to-period increase was primarily due to new depreciation from capital additions in 2009 and 2010.

Nonsegmented Information

G&A Costs.  G&A costs were $5.5 million during the first nine months of 2010, compared to $4.9 million during the first nine months of 2009, an increase of $562,000.  The increase is primarily due to higher compensation costs in 2010.

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Stock Compensation (G&A).  For the nine-month periods ended September 30, 2010 and 2009, we recognized $1.1 million and $1.3 million, respectively, of stock compensation expense related to the amortization of restricted stock purchase grants.

Interest and Other Income.  Interest and other income was $812,000 during the first nine months of 2010, compared to $50,000 during the same period of 2009.  Included in the 2010 amount was a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008.

During the first nine months of 2010, we incurred $1.3 million in interest expense.  In connection with our new credit facility, we charged $577,000 of previously unamortized loan fees associated with our prior credit facility to interest expense during this period.  We also recorded $245,000 of amortization of loan fees and $87,000 in unused commitment fees.  During the same period of 2009, we incurred $452,000 in interest expense, which included $134,000 of amortization of previously incurred loan fees.

Foreign Exchange Gain (Loss).  As discussed in Note 11 to the financial statements, during the first nine months of 2010, we recorded foreign currency transaction losses of approximately $2.9 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.  Foreign currency transaction gains during the first nine months of 2009 were $5.5 million.  During the first nine months of 2010, the zloty weakened by approximately 3% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses.  During the firs t nine months of 2009, the zloty strengthened by approximately 3% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction gains.

Liquidity and Capital Resources

To date, we have financed our operations principally through the sale of equity securities, issuance of debt securities, 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.

On August 5, 2010, we refinanced our existing Facility by executing a New Facility between the Company and the Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV.  The New 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 New Facility is an interest-only facility until then.

We have access to $40 million under the New 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 New Facility are intended to support our operating activities in Poland.  As of September 30, 2010, we had drawn $27.5 million under the New Facility.

At September 30, 2010, we had working capital of approximately $8.1 million.  Cash flow from our production operations has been providing a portion of our capital needs for the past two and one-half years.

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While we have not experienced significant impacts from the current economic crisis, the global economy continues to be unsteady.  In particular, liquidity and capital needs of banks globally and rather underwhelming equity markets have the potential to restrict our access to capital.

Production from our Roszkow well has added significant, incremental revenues and cash flow during 2010.  Based on current conditions, we presently expect our exploration and development programs will continue in spite of the economic downturn; however, in recognition of the downturn, we plan to continue, as we did throughout 2009 and the first nine months of 2010, matching capital spending with our discretionary cash flow, plus increased debt capacity.  We have the ability to control the timing and amount of most of our future capital and exploration costs.  As of September 30, 2010, we are moving ahead with new production facilities in Poland expected to be complete and ready for new production in late 2010.  We will pay for the facilities using p roceeds from our New Facility.  We were also in the process of drilling the Lisewo-1 well in our Fences concession and have committed to a $4.5 million 2-D seismic project in our Warsaw South concession.  We had no other firm commitments for future capital and exploration costs at that date.  Our operating cash flow combined with our cash resources should more than enable us to meet our other capital needs in Poland and the United States for the next 12 months.

We may seek to obtain additional funds for future capital expenditures from the sale of additional securities, project financing, sale of partial property interests, 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.

Working Capital (current assets less current liabilities).  Our working capital at September 30, 2010, was $8.1 million, an increase of $4.6 million from our working capital at December 31, 2009, of $3.5 million.  As of September 30, 2010, our cash and cash equivalents totaled approximately $7.3 million.

Operating Activities.  Net cash provided by operating activities was $6.2 million during the first nine months of 2010, compared to net cash used in operating activities of $8.7 million during the first nine months of 2009.  The increase was primarily due to increases in oil and gas revenues.

Investing Activities.  During the first nine months of 2010, we used cash of $3.2 million from investing activities.  We used $1.7 million for current-year capital additions in Poland and $443,000 related to our proved properties in the United States, used $324,000 to pay accounts payable related to prior-year capital costs, and used $744,000 for capital additions in our office and drilling equipment.  During the first nine months of 2009, we used cash of $2.8 million in investing activities.  We received proceeds of $4.7 million from maturities of marketable securities, purchased marketable securities of $11,000, used $4.7 million for capital additions in Poland and $386,000 related to our p roved properties in the United States, used $1.6 million to pay accounts payable related to prior-year capital costs, and used $802,000 for capital additions in our office and drilling equipment.

Financing Activities.  As discussed in Note 8, we refinanced our credit facility during the third quarter of 2010.  In connection with that refinance, we repaid our original Facility of $25.0 million, drew $27.5 million under our New Facility, and paid $2.5 million in various fees associated with the New Facility.  During the first nine months of 2009, we paid $2.8 million toward loans related to auction-rate securities.  There were no similar transactions during the first nine months of 2010.

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New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board issued new standards intended to improve disclosures about fair value measurements.  The new standards require details of transfers in and out of Level 1 and 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward.  The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements.  We adopted these new rules effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward, which is effective for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within th ose years.  The adoption had no impact on our consolidated financial statements.

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, 2009.  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.

Forward-Looking Statements

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.

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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

Price 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 to POGC or its subsidiaries under contracts that extend for the life of each field.  Prices are determined contractually and, in the case of our Roszkow and Zaniemysl 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 POGC.  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 Po land 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.

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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 va lue of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense are recognized in our consolidated financial statements.  As of September 30, 2010 and 2009, 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 September 30, 2010, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2010, 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 1.  LEGAL PROCEEDINGS

There have been no material developments this fiscal year in any pending legal proceedings to which we are a party.

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, 2009.  The risks described in our Annual Report on Form 10-K for the year ended December 31, 2009, 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.

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ITEM 6.  EXHIBITS

The following exhibits are filed as a part of this report:

Exhibit Number*	Title of Document	Location
Item 10	Material Contracts
10.95	USD 55,000,000 Senior Reserve Base Lending Facility Agreement among FX Energy Poland Sp. z o.o., FX Energy, Inc., FX Energy Netherlands Partnership C.V., FX Energy Netherlands B.V., The Royal Bank of Scotland Plc, ING Bank N.V., and KBC Bank NV dated August 5, 2010	Incorporated by reference from the current report on Form 8-K filed August 11, 2010
10.96	Intercreditor Deed among FX Energy Poland Sp. z o.o, The Royal Bank Of Scotland Plc, and the subordinated lenders dated August 5, 2010	Incorporated by reference from the current report on Form 8-K filed August 11, 2010
10.97	Deed of Pledge of Registered Shares among Frontier Exploration Company and FX Drilling Company, Inc., in their capacity of general partners of FX Energy Netherlands Partnership C.V.; The Royal Bank of Scotland Plc; and FX Energy Netherlands B.V., dated August 6, 2010	Incorporated by reference from the current report on Form 8-K filed August 11, 2010
Item 31	Rule 13a-14(a)/15d-14(a) Certifications
31.01	Certification of Chief Executive Officer Pursuant to Rule 13a-14	Attached
31.02	Certification of Principal Financial Officer Pursuant to Rule 13a-14	Attached
Item 32	Section 1350 Certifications
32.01	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Attached
32.02	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Attached

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* 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.

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SIGNATURES

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.

	FX ENERGY, INC.
	(Registrant)
Date:  November 9, 2010	By:	/s/ David N. Pierce
		David N. Pierce, President, Chief Executive Officer
Date:  November 9, 2010	By:	/s/ Clay Newton
		Clay Newton, Principal Financial Officer

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