FX Energy (FXEN) 10-Q 2010 Q2 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 JUNE 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 re quirements 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 a ccelerated 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 August 4, 2010, was 43,262,456.

FX ENERGY, INC. AND SUBSIDIARIES

Form 10-Q for the Six Months Ended June 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	14
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	24
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)

	June 30,		December 31,
	2010		2009
ASSETS		& nbsp;
Current assets:
Cash and cash equivalents	$	7,069	$	4,225
Receivables:
Accrued oil and gas sales		2,265		2,875
Other receivables		358		918
Inventory		241		232
Other current assets		159		394
Total current assets		10,092		8,644
Property and equipment, at cost:
Oil and gas properties (successful efforts method)
Proved		27,584		32,700
Unproved		2,896		3,403
Other property and equipment		8,066		7,654
Gross property and equipment		38,546		43,757
Less accumulated depreciation, depletion and amortization		(10,662)		(11,466)
Net property and equipment		27,884		32,291
Other assets:
Certificates of deposit		406		406
Loan fees		602		729
Total other assets		1,008		1,135
Total assets	$	38,984	$	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-

	June 30,		December 31,
	2010		2009
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,108	$	3,569
VAT payable		391		575
Accrued liabilities		1,890		1,048
Total current liabilities		4,389		5,192
Long-term liabilities:
Notes payable		25,000		25,000
Asset retirement obligation		1,101		1,133
Total long-term liabilities		26,101		26,133
Total liabilities		30,490		31,325
Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized as of         June  3 0, 2010, and December 31, 2009; no shares outstanding		--		--
Common stock, $0.0 01 par value, 100,000,000 shares authorized as of         June 30, 2010, and December 31, 2009; 43,260,517 and 43,262,456         shares issued and outstanding as of June 30, 2010 and December 31,         2009, respectively		43		43
Additional paid-in capital		161,931		160,594
Cumulative translation adjustment		28,304		10,738
Accumulated deficit		(181,784)		(160,630)
Total stockholders’ equity		8,494		10,745
Total liabilities and stockholders’ equity	$	38,984	$	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 June 30,		For the six months ended June 30,
	2010	2009	2010		2009
Revenues:
Oil and gas sales	$ 5,515	$ 1,833	$ 11,543		$ 3,595
Oilfield services	578	633	722		653
Total revenues	6,093	2,466	12,265		4,248
Operating costs and expenses:
Lease operating expenses	797	811	1,678		1,558
Exploration costs	1,162	1,265	1,524	&n bsp;	3,385
Property impairment	515	--	515		--
Oilfield services costs	441	437	610		618
Depreciation, depletion and amortization	532	374	1,106		748
Accretion expense	19	8	39		16
Stock compensation	351	444	703		883
General and administrative	2,253	1,670	3,981		3,402
Total operating costs and expenses	6,070	5,009	10,156		10,610
Operating income (loss)	23	(2,543)	2,109		(6,362)
Other income (expense):
Interest income (expense), net and
other income (expense)	(145)	(137)	(296)		(272)
Foreign exchange gain (loss)	(21,961)	13,770	(22,967)		(6,680)
Total other income (expense)	(22,106)	13,633	(23,263)		(6,952)
Net income (loss)Net loss	(22,083)	11,090	(21,154)		(13,314)
Other comprehensive income (loss)
Foreign currency translation adjustment	16,808	(10,983)	17,566		4,378
Comprehensive income (loss)	$ (5,275)	$ 107	$ (3,588)		$ (8,936)
Net income (loss) per common share
Basic	$ (0.51)	$ 0.26	$ (0.49)		$ (0.31)
Diluted	$ (0.51)	$ 0.26	$ (0.49)		$ (0.31)
Weighted average common shares outstanding
Basic	43,260	42,451	43,238		42,424
Dilutive effect of stock options	-	153	-		-
Diluted	43,260	42,604	43,238		42,424

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

5

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	For the Six Months Ended
	June 30,
	2010		2009
Cash flows from operating activities:
Net income (loss)	$	(21,154)	$	(13,314)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		1,106		748
Accretion expense		39		16
Amortization of bank fees		121  ;		92
Property impairment		515		--
Stock compensation		703		883
Foreign exchange losses		22,923		5,410
Common stock issued for services		635		724
Increase (decrease) from changes in working capital items:
Receivables		743		509
Inventory		(9)		(9)
&n bsp;    Other current assets		235		195
&nb sp;  Other assets		--		(122)
Accounts payable and accrued liabilities		(832)		(2,623)
Net cash provided by (used in) operating activities		5,025		(7,491)
Cash flows from investing activities:
Additions to oil and gas properties		(901)		(4,064)
Additions to other property and equipment		(543)		(545)
Additions to marketable securities		--		(10)
Proceeds from maturities of marketable securities		--		4,398
Net cash used in investing activities		(1,444)		(221)
Cash flows from financing activities:
Payments on loan related to auction rate securities		--		(2,709)
Net cash used in financing activities		--		(2,709)
Effect of exchange-rate changes on cash		(737)		4
Net increase (decrease) in cash		2,844		(10,417)
Cash and cash equivalents at beginning of year		4,225		16,588
Cash and cash equivalents at end of period	$	7,069	$	6,171

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

6

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 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, 2009 and our Form 10-Q for the quarter ended March 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 (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 three-month and six-month periods ended June 30, 2010, and in the six-month period ended June 30, 2009.  No options were included in the computation of diluted earnings per share for these periods because the effect would have been antidilutive.

Diluted earnings per share was computed for the three months ended June 30, 2009, by dividing the net income by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options.  Basic and diluted earnings per share were essentially the same for the three months ended June 30, 2009.

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

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
June 30, 2010	2,192,545	$0.00 - $10.65
June 30, 2009	2,600,847	$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 three and six-month periods ended June 30, 2010, and for the six-month period ended June 30, 2009.  No income tax expense was recognized for the three-month period ended June 30, 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.  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 six months ended June 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 wi thin 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 June 30, 2010, the six months ended June 30, 2010, and as of June 30, 2010, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended June 30, 2010:
Revenues	$ 995	$ 4,520	$ 578	$ --	$ 6,093
Net income (loss)(1)	400	2,281	(35)	(24,729)	(22,083)
Six months ended June 30, 2010:
Revenues	$ 2,079	$ 9,464	$ 722	$ --	$ 12,265
Net income (loss)(1)	883	6,175	(225)	(27,987)	(21,1 54)
As of June 30, 2010:
Identifiable net property and equipment	$ 906	$ 24,544	$ 2,357	$ 77	$ 27,884

_______________

(1)

Non - -segmented reconciling items for the second quarter include $2,253 of G&A costs, $351 of noncash stock compensation expense, $144 of other expense, $20 of corporate DD&A costs, and $21,961 of foreign exchange losses.  Non-segmented reconciling items for the first six months include $3,980 of G&A costs, $703 of noncash stock compensation expense, $296 of other expense, $41 of corporate DD&A costs, and $22,967 of foreign exchange losses.  

8

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

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended June 30, 2009:
Revenues	$ 793	$ 1,040	$ 633	$ --	$ 2,466
Net income (loss)(1)	19	(484)	48	11,507	11,090
Six months ended June 30, 2009:
Revenues	$ 1,319	$ 2,276	$ 653	$ --	$ 4,248
Net income (loss)(1)	(197)	(1,600)	(235)	(11,282)	(13,314)
As of June 30, 2009:
Identifiable net property and equipment	$ 282	$ 26,280	$ 2,075	$ 130	$ 28,767

_______________

(1)

Non-segmented reconciling items for the second quarter include $1,670 of G&A costs, $444 of noncash stock compensation expense, $137 of other expense, $12 of corporate DD&A costs, and $13,770 of foreign exchange gains.  Non-segmented reconciling items for the first six months include $3,402 of G&A costs, $883 of noncash stock compensation expense, $272 of other expense, $45 of corporate DD&A costs, and $6,680 of foreign exchange losses.  

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 six 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
Exerci sed	(12,000)	3.14
End of period	1,458,441	6.49	0.82
Exercisable at end of period	1,458,441	6.49	0.82	$16,380

The following table summarizes option activity for the first six 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
Cancelled	(75,000)	8.58
End of period	1,905,441	5.54	1.43
Exercisable at end of period	1,905,441	5.54	1.43	$651,240

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The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, bas ed on our stock price of $3.62 as of June 30, 2010, and $3.82 as of June 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 six months of 2010 totaled $172,154.  There were no shares of restricted stock issued during the first six months of 2010.  

During 2008, we issued 367,000 shares of restricted stock resulting in unamortized compensation ex pense of $1,005,580, which is being amortized ratably over a three-year vesting period.  Expense recognized during the first six months of 2010 and 2009 totaled $166,217 and $166,230, 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 six months of 2010 and 2009 totaled $364,294 and $377,688, 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 six months of 2010 and 2009 totaled $0 and $339,443, respectively.

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

	Number of Shares
	2010	2009
Unvested restricted stock outstanding:
Beginning of year	739,535	714,421
Issued	--	--
Forfeited	(497)	(14,082)
Vested	(4,934)	(4,933)
End of period	734,104	695,406

Note 6:  Stockholders’ Equity

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.  

During the first six months of 2009, we i ssued 228,100 shares for our 2008 contribution to our employee benefit plan.  In addition, we issued 21,000 shares to consultants for services.  

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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 par ticipants 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.

·

Le vel 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 June 30, 2010, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first six 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.

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

	June 30,
	2010	Level 1(1)	Level 2(2)	Level 3(3)
Cash equivalents:
Money market funds	$   604	$   604	--	--

_______________

(1)

Quoted prices in active markets for identical assets.

(2)

Significant other observable inputs.

(3)

Significant unobservable inputs.

Note 8:  Notes Payable

We have a $25 Million Senior Facility Agreement (the Facility) with The Royal Bank of Scotland plc (RBS).  The Facility is provided to FX Energy Poland, a wholly owned subsidiary.  Funds from the Facility cover infrast ructure and development costs at a variety of our Polish gas projects and are collateralized by our commercial wells and production in Poland.  We made no principal payments during the quarter.  At June 30, 2010, we had drawn the full $25 million available under the Facility.  Amounts outstanding at June 30, 2010, approximate fair value due to the variable interest rate associated with the Facility.

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On August 5, 2010, we refinanced our existing Facility.  See Note 11 for more information.

Note 9:  Capitalized Exploratory Well Costs

At June 30, 2010, we had no capitalized costs related to exploratory wells.

Note 10:  Property Impairments

Second quarter 2010 remediation efforts at our Kleka well failed to restore commercial production.  Accordingly, we have impaired the remaining capital costs for the well of approximately $515,000.

Note 11:  Foreign Currency Translation and Risk

During the first half of 2010, we recorded foreign currency transaction losses of approximately $23.0 million.  This amount was attributable to increases in the amount of Polish zlotys necessary for FX Energy Pol and 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 Six Months
	Ended June 30, 2010
Balance at December 31, 2009	$ 10,738
Increase related to losses on intercompany loans	22,923
Decrease related to translation adjustments	(5,357)
Balance at June 30, 2010	$ 28,304

Future transaction gains or losses may be significant given the amount of intercompany loans and the volati lity 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.

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Note 12:  Liquidity

We have a history of operating losses and negative cash flow from operating activities.  From our inception in January 1989 through June 30, 2010, we have incurred cumulative net losses of approximately $182 million.  Our exploration and production activities may continue to result in net losses through 2010 and possibly beyond, 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, and operating activities provided net cash in our first half of 2010, we have reported negative cash flow from operating activities in each of the past three fiscal years. At June 30, 2010, we had working capital of approximately $5.7 million.  

With the establishment of proved reserves in Poland, in November 2006, we established the Facility with RBS.  As of June 30, 2010, we had drawn the full $25 million available under this Facility.  In August, 2010, we refinanced our existing Facility. See Note 13 for more information.

While we did not experience significant impacts from the economic crisis during 2009, the global economy continues to be unsteady.  Production from our Roszkow well should add significant, incremen tal revenues and cash flow during 2010, as we have seen in the first half of the year.  The fluctuation in the exchange rate of the Polish zloty against the U.S. dollar will also have an impact on our U.S. dollar-denominated future revenues and operating profit; conversely, any U.S. dollar-denominated capital, exploration, and operating costs in Poland will be impacted at the same rate.  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 matching capital spending with our discretionary cash flow, plus increased debt capacity if it becomes available.  We have the ability to control the timing and amount of most of our future capital and exploration costs.  As of June 30, 2010, we are moving ahead with new production facilities in Poland to be complete and ready for new production to begin in late 2010.  As of June 30, 2010, we are m oving 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 proceeds from our New Facility.  We had no other firm commitments for future capital and exploration costs at that date.  

Note 13:  Subsequent Events

On August 5, 2010, we refinanced our existing Facility 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 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 associated with our existing Facility will be charged to expense during the third quarter of 2010. Payment of the New Facility is secured by our assets in Poland and guaranteed by the Company.

We have access to $40 million under the New Facility until our KSK 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.

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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.

Results of Operations by Business Segment

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

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $4.5 million during the second quarter of 2010, compared to $1.0 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 June 30, 2010 and 2009, is set forth in the following table:

	For the Quarter Ended June 30,
	2010	2009	Change
Gas revenues	$4,520,000	$1,040,000	+335%
Average price (per thousand cubic feet)	$4.91	$4.44	+11%
Production volumes (thousand cubic feet)	920,000	234,000	+293%

We recognized an 11% increase in natural gas prices quarter over quarter.  At Roszkow, we receive approximately 95% of t he 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 5% lower during the second quarter of 2010 compared to the second quarter of 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 only decreased approximately 1% from the second quarter of 2009 to the second quarter of 2010.  The average exchange rate during the second quarter of 2010 was 3.16 zlotys per U.S. dollar.  The average exchange rate during the second qua rter of 2009 was 3.27 zlotys per U.S. dollar, a change of approximately 3%.  

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The Polish Energy Regulatory Office approved new gas tariffs effective July 1, 2010.  All tariffs are denominated in Polish zlotys.  The new tariff for low-methane gas, which applies to all of our production in Poland, increased by 6.7%.  

            During the third quarter of 2010, both our Roszkow and Zaniemysl wells will be shut in for two weeks for annual maintenance and pressure testing.  Accordingly, we expect third quarter production and gas revenues to be lower than second quarter levels.

Oil Revenues.  Oil revenues were $1.0 million for the second quarter of 2010, a 25% increase from $793,000 recognized during the second quarter of 2009.  Production levels decreased approximately 6% from 2009 to 2010.  The most significant factor in the increase in oil revenues was the higher prices received during the second quarter of 2010.  Our average oil price during the second quarter of 2010 was $67.12 per barrel, a 33% increase from $50.45 per barrel received during the same quarter 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 quarters ended June 30, 2010 and 2009, is set forth in the following table:

	For the Quarter Ended June 30,
	2010	2009	Change
Oil revenues	$994,000	$793,000	+25%
Average price (per barrel)	$67.12	$50.45	+33%
Production volumes (barrels)	14,800	15,700	-6%

Lease Operating Costs.  Lease operating costs of $797,000 during the second quarter of 2010 were essentially unchanged from the second quarter 2009 amount of $811,000.  Higher operating costs at our Roszkow property, which was not producing during the second quarter 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 $1.2 million during the second quarter of 2010, compared to $1.3 million during the same period of 2009, a decrease of 8%.  During the second quarter of 2010, $872,000 of costs associated with our Zakowo workover project incurred during the quarter were written off as dry-hole costs.  Second quarter 2010 geological and geophy sical costs were primarily associated with two-dimensional, or 2-D, seismic surveys on our 100%-owned acreage in Poland.  Second quarter 2009 exploration costs included approximately $1.0 million 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 at both existing and new Polish concessions.  

Property Impairment.  Second quarter 2010 remediation efforts at our Kleka well failed to restore commercial production.  Accordingly, we have impaired the remaining capital costs for the well of approximately $515,000.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $340,000 for the second quarter of 2010 , an increase of 60% compared to $213,000 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 $19,000 and $8,000 for the second quarter of 2010 and 2009, respectively.  Accretion expense is related entirely to our Asset Retirement Obligation associated with expected future plugging and abandonment costs.

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Oilfield Services Segment

Oilfield Services Revenues.  Oilfield services revenues were $578,000 during the second quarter of 2010, a decrease of 9% compared to $633,000 for the second quarter of 2009.  We drilled three wells for third parties during the second quarter of 2010, along with additional well service work.  During the second quarter of 2009, we drilled 14 wells for third parties; however, each of these was a shallow well, 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 Servi ces Costs.  Oilfield services costs were $441,000 during the second quarter of 2010, compared to $437,000 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 $173,000 during the second quarter of 2010, compared to $149,000 during the same period of 2009.  The quarter-to-quarter increase was primarily due to recent capital additions being depreciated.

Nonsegmented Information

G&A Costs.  G&A costs were $2,253,000 during the second quarter of 2010, compared to $1,670,000 during the second quarter of 2009.  The increase is primarily due to higher compensation costs in 2010.  

Stock Compensation (G&A).  For the three-month periods ended June 30, 2010 and 2009, we recognized $351,000 and $444,000, 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 $17,000 during the second quarter of 2010, an increase of $9,000 compared to $8,000 during the same period of 2009.  The increase was a reflect ion of higher cash balances available for investment.  During the second quarter of 2010, we incurred $162,000 in interest expense, which included $61,000 of amortization of previously incurred loan fees.  During the second quarter of 2009, we incurred $145,000 in interest expense, which included $43,000 of amortization of previously incurred loan fees.  

Foreign Exchange Loss.  As discussed in Note 10 to the financial statements, during the second quarter of 2010, we recorded foreign currency transaction losses of approximately $21.9 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans.  We recorded foreign exchange gains of $13.8 million during the same quarter of 2009, which were also principally related to our intercompany loans.  During the second quarter of 2010, the zloty weakened by approximately 18% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction losses.  Conversely, during the second quarter of 2009, the zloty strengthened by approximately 10% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.

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Six Months Ended June 30, 2010, Compared to the Same Period of 2009

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $9.5 million during the first half of 2010, compared to $2.3 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.  Production at our Zaniemysl well was also slightly higher during the first six months of 2010, as it was shut-in for several days of maintenance during the first six months of 2009.  

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 six months ended June 30, 2010 and 2009, is set forth in the following table:

	For the Six Months Ended June 30,
	2010	2009	Change
Revenues	$9,464,000	$2,259,000	+319%
Average price (per thousand cubic feet)	$5.15	$4.38	+18%
Production volumes (thousand cubic feet)	1,837,500	516,100	+256%

We recognized an 18% increase in natural gas prices peri od 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 5% lower during the first six months of 2010 compared to the same period of 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 6% from the second quarter of 2009 to the second quarter of 2010.  The average exchange rate during the first half of 2010 was 3.02 zlotys per U.S. dollar.  The average exchange rate during the first half of 2009 was 3.36 zlotys per U.S. dollar, a change of approximately 10%.  

The Polish Energy Regulatory Office approved new gas tariffs effective July 1, 2010.  All tariffs are denominated in Polish zlotys.  The new tariff for low-methane gas, which applies to all of our production in Poland, increased by 6.7%.  

Oil Revenues.  Oil revenues were $2.1 million for the first half of 2010, a 58% increase from the $1.3 million recognized during the first half of 2009.  Production from our U.S. properties declined 2% during the first half of 2010.  The most significant factor in the increase in oil revenues was the higher prices received during the first half of 2010.  Our average oil price during the first half of 2010 was $67.59 per barrel, a 61% increase from $42.08 per barrel received during the same period 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 six months ended June 30, 2010 and 2009, is set forth in the following table:

	For the Six Months Ended June 30,
	2010	2009	Change
Revenues	$2,079,000	$1,319,000	+58%
Average price (per barrel)	$67.59	$42.08	+61%
Production volumes (barrels)	30,766	31,700	-3%

Lease Operating Costs.  Lease operating costs were $1.7 million during the first half of 2010, an increase of 8% 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 and Grabowka.  

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $1.5 million during the first half of 2010, compared to $3.4 million during the same period of 2009, a decrease of 55%.  The period-to-period decline is attributable to our lower level of 3-D seismic activity in 2010 compared to 2009.  First half 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 discussed earlier.  First half 2009 exploration costs included approximately $2.6 million associated with our ongoing Fences concession area 3-D seismic surveys, and the remainder was associated with 2-D seismic and other cos ts at both existing and new concessions.  

Property Impairment.  First half 2010 remediation efforts at our Kleka well failed to restore commercial production.  Accordingly, we have impaired the remaining capital costs for the well of approximately $515,000.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $729,000 for the first half of 2010, an increase of 69% compared to $432,000 million 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 Exp ense.  Accretion expense was $39,000 and $16,000 for the first half 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 $722,000 during the first half of 2010, an increase of 11%, compared to $653,000 for the first half of 2009.  We drilled four wells for third parties during the first half of 2010, along with additional well service work.  During the first half of 2009, we drilled 14 wells for third parties; however, each of these was a shallow well, 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, w eather, 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 $610,000 during the first half of 2010, compared to $618,000 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.

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DD&A Expense – Oilfield Services.  DD&A expense for oilfield services was $336,000 during the first half of 2010, compared to $271,000 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 $3,981,000 during the first half of 2010, compared to $3,402,000 during the first half of 2009, an increase of $579,000.  The increase is primarily due to higher compensation costs in 2010.  

Stock Compensation (G& A).  For the six-month periods ended June 30, 2010 and 2009, we recognized $703,000 and $883,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock purchase rights.  

Interest and Other Income.  Interest and other income was $22,000 during the first half of 2010, a decrease of $15,000, compared to $38,000 during the same period of 2009.  During the first half of 2010, we incurred $318,000 in interest expense, which included $123,000 of amortization of previously incurred loan fees.  During the first half of 2009, we incurred $310,000 in interest expense, which included $88,000 of amortization of previously incurred loan fees.

Foreign Exchange Loss.  As discusse d in Note 10 to the financial statements, during the first half of 2010, we recorded foreign currency transaction losses of approximately $22.9 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 losses during the first half of 2009 were $6.7 million.  During the first half of 2010, the zloty weakened by approximately 19% against the US dollar from the beginning to the end of the period, which caused us to recognized foreign currency transaction losses.  During the first half of 2009, the zloty weakened by approximately 7% against the US dollar from the beginning to the end of the period, which caused us to recognized foreign currency transaction losses.

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 US production, our internally generated cash flow has become a more significant source of operations financing.  Additionally, with the establishment of proved reserves in Poland, in November 2006, we established a $25.0 million Senior Credit Facility (Facility) with the Royal Bank of Scotland plc (RBS).  As of December 31, 2008, we had drawn down the full $25.0 million available under this facility.  

On August 5, 2010 , we refinanced our existing Facility 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 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 KSK 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.

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At June 30, 2010, we had working capital of approximately $5.7 million.  Cash flow from our production operations has been providing a portion of our capital needs for the past two and one-half years.

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.  Base d 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 half 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 June 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 proceeds from our New Facility.  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 June 30, 2010, was $5.7 million, an increase of $2.2 million from our working capital at December 31, 2009, of $3.5 million.  As of June 30, 2010, our cash and cash equivalents totaled approximately $7.1 million.  

Operating Activities.  Net cash provided by operating activities was $5.0 million during the first six months of 2010, compared to net cash used in operating activities of $7.5 million during the first six months of 2009.  The increase was primarily due to increases in oil and gas revenues.

Investing Activities.  During the first six months of 2010, we used cash of $1.4 million from investing activities.  We used $305,000 for current-year capital additions in Poland and $245,000 related to our proved properties i n the United States, used $352,000 to pay accounts payable related to prior-year capital costs, and used $542,000 for capital additions in our office and drilling equipment.  During the first six months of 2009, we used cash of $221,000 in investing activities.  We received proceeds of $4.4 million from maturities of marketable securities, purchased marketable securities of $10,000, used $2.2 million for current-year capital additions in Poland and $246,000 related to our proved properties in the United States, used $1.6 million to pay accounts payable related to prior-year capital costs, and used $545,000 for capital additions in our office and drilling equipment.

Financing Activities.  During the first half of 2009, we paid $2.7 million toward loans related to auction-rate securities.  There were no similar transactions during the first six 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, exce pt 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 those 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 a ccounting 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 t o 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 respectin g 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 Pola nd 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 the Polish Oil and Gas Company, or 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, 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 POGC.  We expect that the prices we receive in the short term for gas we p roduce 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.

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Foreign Currency Risk

We ente r 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 are recognized in our consolidated financial statements.  As of June 30, 2010 and 2009, we had no outstanding zloty forward-purchase contr acts.

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 evalu ated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of June 30, 2010, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of June 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.

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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.  

ITEM 6.  EXHIBITS

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

Exhibit Number*	Title of Document	Location
Item 3	Articles of Incorporation and Bylaws
3.05	Bylaws of FX Energy, Inc., as amended May 24, 2010	Incorporated by reference from the current report on Form 8-K filed June 8, 2010
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	Certificati on 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	Certifi cation 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

_______________

*

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:  August 9, 2010	By:	/s/ David N. Pierce
		David N. Pierce, President, Chief Executive Officer
Date:  August 9, 2010	By:	/s/ Clay Newton
		Clay Newton, Principal Financial Officer

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