FX Energy 10Q 2009 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, 2009

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

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

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

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 5, 2009, was 42,662,156.

FX ENERGY, INC. AND SUBSIDIARIES

Form 10-Q for the Three Months Ended September 30, 2009

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	16
3	Quantitative and Qualitative Disclosures about Market Risk	24
4	Controls and Procedures	25

	Part II—Other Information

1	Legal Proceedings	26
1A	Risk Factors	26
6	Exhibits	27
--	Signatures	27

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	September 30,		December 31,
	2009		2008
ASSETS

Current assets:
Cash and cash equivalents	$	2,508	$	16,588
Marketable securities		--		4,105
Receivables:
Accrued oil and gas sales		1,555		1,093
Other receivables		3,504		1,720
Input VAT receivable		629		2,514
Inventory		223		211
Other current assets		358		450
Total current assets		8,777		26,681

Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		31,684		28,600
Unproved		3,351		2,770
Other property and equipment		7,492		6,667
Gross property and equipment		42,527		38,037
Less accumulated depreciation, depletion and amortization		(11,014)		(11,164)
Net property and equipment		31,513		26,873

Other assets:
Certificates of deposit		406		406
Loan fees		827		842
Total other assets		1,233		1,248

Total assets	$	41,523	$	54,802

-Continued-

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

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands, except share data)

-Continued-

	September 30,		December 31,
	2009		2008
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	5,583	$	7,779
Accrued liabilities		501		4,937
Total current liabilities		6,084		12,716

Long-term liabilities:
Notes payable		25,000		25,000
Asset retirement obligation		2,192		1,932
Total long-term liabilities		27,192		26,932

Total liabilities		33,276		39,648

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized
as of September 30, 2009 and December 31, 2008; no shares
outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized
as of September 30, 2009 and December 31, 2008; 42,662,156
and 42,202,878 shares issued and outstanding as of September 30,
2009 and December 31, 2008, respectively		43		42
Additional paid-in capital		160,233		158,075
Cumulative translation adjustment		11,936		17,137
Accumulated deficit		(163,965)		(160,100)
Total stockholders’ equity		8,247		15,154

Total liabilities and stockholders’ equity	$	41,523	$	54,802

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

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,
	2009	2008	2009	2008
Revenues:
Oil and gas sales	$ 2,691	$ 3,885	$ 6,286	$ 11,354
Oilfield services	1,118	1,211	1,771	3,162
Total revenues	3,809	5,096	8,057	14,516

Operating costs and expenses:
Lease operating expenses	857	930	2,415	2,698
Exploration costs	686	3,683	4,071	9,960
Property impairment	1,864	--	1,864	--
Oilfield services costs	657	815	1,274	2,091
Depreciation, depletion and amortization	425	653	1,173	2,101
Accretion expense	8	21	24	63
Stock compensation	449	622	1,332	1,866
General and administrative	1,512	1,519	4,914	4,880
Total operating costs and expenses	6,458	8,243	17,067	23,659

Operating loss	(2,649)	(3,147)	(9,010)	(9,143)

Other income (expense):
Interest income (expense), net and
other income (expense)	(130)	(86)	(402)	13
Foreign exchange gain (loss)	12,227	(455)	5,547	(338)
Total other income (expense)	12,097	(541)	5,145	(325)
Net income (loss) Net loss	9,448	(3,688)	(3,865)	(9,468)

Other comprehensive income (loss)
Foreign currency translation adjustment	(9,579)	-	(5,201)	-
Increase in market value of
available for sale marketable securities	-	224	-	1
Comprehensive loss	$ (131)	$ (3,464)	$ (9,066)	$ (9,467)

Net income (loss) per common share
Basic	$ 0.22	$ (0.09)	$ (0.09)	$ (0.24)
Diluted	$ 0.22	$ (0.09)	$ (0.09)	$ (0.24)
Weighted average common shares outstanding
Basic	42,560	40,747	42,470	40,037
Dilutive effect of stock options	84	-	-	-
Diluted	42,644	40,747	42,470	40,037

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

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	For the Nine Months Ended
	September 30,
		2009		2008
Cash flows from operating activities:
Net loss	$	(3,865)	$	(9,468)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization		1,173		2,101
Property impairment		1,864		--
Accretion expense		24		63
Amortization of bank fees		137		137
Stock compensation		1,332		1,866
Foreign exchange gains		(6,756)		(338)
Common stock issued for services		739		665
Increase (decrease) from changes in working capital items:
Receivables		(861)		(3,330)
Inventory		(12)		(32)
Other current assets		48		(113)
Other assets		(122)		247
Accounts payable and accrued liabilities		(2,437)		(663)
Net cash used in operating activities		(8,736)		(8,865)

Cash flows from investing activities:
Additions to oil and gas properties		(6,680)		(16,941)
Additions to other property and equipment		(802)		(783)
Additions to marketable securities		(11)		(170)
Proceeds from maturities of marketable securities		4,661		9,815
Net cash used in investing activities		(2,832)		(8,079)

Cash flows from financing activities:
Proceeds from notes payable		--		11,000
Proceeds from loan related to auction-rate securities		--		3,354
Payments on loan related to auction-rate securities		(2,808)		--
Proceeds from exercise of stock options and warrants		132		9,364
Net cash (used in) provided by financing activities		(2,676)		23,718

Effect of exchange rate changes on cash		164		--

Net increase (decrease) in cash		(14,080)		6,774
Cash and cash equivalents at beginning of year		16,588		4,262

Cash and cash equivalents at end of period	$	2,508	$	11,036

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

FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

(Unaudited)

Note 1: Basis of Presentation

We prepared the accompanying unaudited consolidated financial statements of FX Energy Inc., on the same basis as our annual audited financial statements, except as noted in the following footnotes.

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, 2008, and our Form 10-Q for the quarters ended March 31, 2009, and June 30, 2009.

We evaluated subsequent events through November 9, 2009, the date of our financial statement issuance.

New Accounting Pronouncements

In October 2008, the Financial Accounting Standards Board, or FASB, issued an amendment to the accounting and disclosure requirements regarding the determination of the fair value of a financial asset when the market for that asset is not active. This amendment was effective October 10, 2008. The application of this amendment did not have a material impact on our consolidated financial statements.

In December 2008, the Securities and Exchange Commission, or SEC, issued a final rule concerning the modernization of oil and gas reporting, which is effective January 1, 2010, for reporting 2009 reserve information. The new disclosure requirements permit the new use in SEC reports of technologies previously internationally well-accepted in the oil and gas industry to determine proved reserves through probabilistic methods that have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the prior 12 months rather than year-end prices. The new requirements also will allow companies to disclose their probable and possible reserves using both the previously SEC-accepted deterministic methods, as well as the newly SEC-accepted probabilistic methods. The new disclosure requirements also require companies to report the independence and qualifications of the reserves preparer or auditor. We will adopt the provisions of the final rule in connection with our December 31, 2009 Form 10-K filing and are currently evaluating the impact of the final rule.

On January 1, 2009, we adopted a new accounting standard regarding derivative instruments and hedging activities. The new standard requires enhanced disclosure about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The adoption of these new requirements did not have a material impact on our results of operations and financial condition.

In April 2009, the FASB issued three amendments to the accounting and disclosure requirements regarding fair value measurements and impairments of securities. These amendments provide guidelines for making fair value measurements more consistent with the principles presented in prior pronouncements, enhance consistency in financial reporting by increasing the frequency of fair value disclosures, and provide additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. We adopted these for the period ended June 30, 2009. The adoption of these amendments did not have a material impact on our financial position or results of operations.

In June 2009, the FASB issued the FASB Accounting Standards Codification (Codification). The Codification will become the single source for all authoritative GAAP recognized by the FASB to be applied for financial statements issued for periods ending after September 15, 2009. The adoption of the Codification does not change GAAP and did not have an effect on our financial position, results of operations, or liquidity.

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.

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. Diluted earnings per share was computed for the three months ended September 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, warrants, and convertible preferred stock or debt.

Outstanding options and unvested restricted stock as of September 30, 2009 and 2008, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
September 30, 2009	2,165,247	$0.00 - $10.65
September 30, 2008	3,745,009	$0.00 - $10.65

We had a net loss in each of the nine-month periods ended September 30, 2009 and 2008, and in the three-month period ended September 30, 2008. No options were included in the computation of diluted earnings per share for those periods because the effect would have been antidilutive.

Note 3: Income Taxes

We recognized no income tax benefit from the net loss generated in the nine-month periods ended September 30, 2009 and 2008, respectively, or for the three-month period ended September 30, 2008. No income tax expense was recognized for the three-month period ended 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 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, 2008. 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, 2009.

Note 4: Business Segments

We operate within two segments of the oil and gas industry: the exploration and production segment and the oilfield services segment. Direct revenues and costs, including exploration costs, depreciation, depletion and amortization costs (“DD&A”), general and administrative costs (“G&A”), and other income directly associated with their respective segments are detailed within the following discussion. Identifiable net property and equipment are reported by business segment for management reporting and reportable business segment disclosure purposes. Current assets, other assets, current liabilities, and long-term debt are not allocated to business segments for management reporting or business segment disclosure purposes.

Reportable business segment information for the three months ended 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, 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, and $5,547 of foreign exchange gains.

Reportable business segment information for the three months ended September 30, 2008, the nine months ended September 30, 2008, and as of September 30, 2008, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended September 30, 2008:
Revenues	$ 1,826	$ 2,059	$ 1,211	$ --	$ 5,096
Net income (loss)⁽¹⁾	537	(1,818)	288	(2,695)	(3,688)
Nine months ended September 30, 2008:
Revenues	$ 4,959	$ 6,395	$ 3,162	$ --	$ 14,516
Net income (loss)⁽¹⁾	1,870	(4,972)	792	(7,158)	(9,468)
As of September 30, 2008:
Identifiable net property and equipment	$ 3,331	$ 33,887	$ 1,645	$ 112	$ 38,975

_______________

(1)

Non-segmented reconciling items for the third quarter include $1,519 of G&A costs, $621 of noncash stock compensation expense, $86 of other expense, $455 of foreign exchange loss, and $14 of corporate DD&A. Non-segmented reconciling items for the first nine months include $4,880 of G&A costs, $1,866 of noncash stock compensation expense, $13 of other income, $338 of foreign exchange loss, and $87 of corporate DD&A.

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 2009:

		Weighted	Weighted Average
	Number of	Average Exercise	Remaining Contractual	Aggregate Intrinsic
	Options	Price	Life (in years)	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 following table summarizes option activity for the first nine months of 2008:

		Weighted	Weighted Average
	Number of	Average Exercise	Remaining Contractual	Aggregate Intrinsic
	Options	Price	Life (in years)	Value
Options outstanding:
Beginning of year	2,315,441	$5.19
Exercised	--
End of period	2,315,441	5.19	2.15
Exercisable at end of period	2,315,441	5.19	2.15	$6,115,155

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $3.23 as of September 30, 2009, and $7.44 as of September 30, 2008, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.

During the nine months ended September 30, 2009 and 2008, we recognized $0 and $15,508, respectively, in expense related to unvested stock options. There was no unamortized expense related to unvested options at September 30, 2009.

Restricted Stock

During 2008, we issued 367,000 shares of restricted stock resulting in unamortized compensation expense of $1,005,580, which will be amortized ratably over the three-year vesting period. Expense recognized during the first nine months of 2009 totaled $250,722. There were no shares of restricted stock issued during the first nine months of 2009.

During 2007, we issued 370,925 shares of restricted stock resulting in unamortized compensation expense of $2,284,991, which will be amortized ratably over the three-year vesting period. Expense recognized during the first nine months of 2009 and 2008 totaled $569,669 and $570,278, respectively.

During 2006, we issued 318,400 shares of restricted stock resulting in unamortized compensation expense of $2,053,680, which will be amortized ratably over the three-year vesting period. Expense recognized during the first nine months of 2009 and 2008 totaled $511,978 and $512,483, respectively.

During 2005, we issued 298,950 shares of restricted stock to employees resulting in unamortized compensation expense of $3,109,080, which was amortized ratably over the three-year vesting period. Expense recognized during the first nine months of 2009 and 2008 totaled $0 and $768,023, respectively.

The following table summarizes restricted stock activity during the first nine months of 2009 and 2008:

	2009	2008
	Number of Shares	Number of Shares
Unvested restricted stock outstanding:
Beginning of year	714,421	679,788
Forfeited	(14,682)	(7,330)
Vested	(4,933)	(4,933)
End of period	694,806	667,525

Note 6: Stockholders’ Equity

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. During the first nine months of 2008, we issued 110,090 shares for a 2007 contribution to our employee benefit plan. In addition, we issued 7,000 shares to consultants for services.

In February 2008, warrant holders exercised a total of 1,960,000 outstanding warrants at a price of $3.60 per share and 615,593 outstanding warrants at a price of $3.75 per share, resulting in proceeds to us of $9,364,474. As of December 31, 2008, we had no warrants outstanding.

Note 7: Fair Value Measurements and Marketable Securities

On January 1, 2009, we adopted a newly issued accounting standard for fair value measurements of all nonfinancial assets and nonfinancial liabilities not recognized or disclosed at fair value in the financial statements on a recurring basis. The adoption of this accounting standard for those assets and liabilities did not have a material impact on our financial position, results of operations, or liquidity. 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, 2009.

The accounting standard for fair value measurements provides a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. Fair value is defined as the price that would be received for an asset or the exit price that would be paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date. The accounting standard established a fair value hierarchy that requires an entity to maximize the use of observable inputs, where available. The following summarizes the three levels of inputs required as well as the assets and liabilities that we value using those levels of inputs.

•

Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities.

•

Level 2: Observable inputs other than those included in Level 1. For example, quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in inactive markets.

•

Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. During the first six months of 2009, certain assets were classified as Level 3 assets. This classification primarily related to investments in auction-rate securities. We had no Level 3 assets as of September 30, 2009.

Recurring Fair Value

The following tables set forth the financial assets and liabilities that we measured at fair value on a recurring basis by level within the fair value hierarchy. We classify assets and liabilities measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 30, 2009 (in thousands):

	September 30,
	2009	Level 1⁽¹⁾	Level 2⁽²⁾	Level 3⁽³⁾

Cash equivalents:
Money market funds	$ 383	$ 383	--	--
Treasury bills	254	254	--	--

_______________

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

(2)	Significant other observable inputs.

(3)	Significant unobservable inputs.

The following table provides a summary of changes in fair value of our Level 3 marketable securities (in thousands):

	For the Nine Months
	Ended September 30, 2009
Balance at December 31, 2008	$ 4,650
Transfers in	--
Purchases, issuances and settlements	(4,650)
Balance at September 30, 2009	$ --

Marketable Securities

Marketable securities on the Consolidated Balance Sheets include investments we hold that are classified as trading securities as defined by accounting pronouncements.

As of December 31, 2008, we had certain auction-rate securities with a market value of $2,535,000 that were eligible to be “put” to UBS on January 2, 2009, and certain other auction-rate securities with a market value of $1,570,000 that were eligible to be “put” to UBS on June 30, 2010. During the first nine months of 2009, all of the auction-rate securities were redeemed at par value. A portion of the proceeds from the redemptions was used to satisfy loans relating to those securities at December 31, 2008, of $2,808,000.

Liabilities

At December 31, 2008, we had three outstanding zloty forward purchase contracts denominated in U.S. dollars as follows: $2,500,000 that matured January 30, 2009; $2,100,000 that matured February 27, 2009; and $1,100,000 that matured March 31, 2009. All contracts were settled on their maturity dates.

Note 8: Notes Payable

During 2006, we entered into a $25 Million Senior Facility Agreement (the Facility) with The Royal Bank of Scotland plc. The Facility is provided to FX Energy Poland, a wholly owned subsidiary. Funds from the Facility cover infrastructure 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 September 30, 2009, we had drawn the full $25 million available under the Facility. Amounts outstanding under the Facility at September 30, 2009, are stated at cost, which approximates fair value.

Interest on borrowed funds is accrued at LIBOR plus 1.25%. The average interest rate on the outstanding balance at September 30, 2009, was 1.49% per annum. The Facility is an interest-only facility until December 31, 2010, on which date the Facility’s principal amount is currently scheduled to be reduced to $20 million.

Note 9: Capitalized Exploratory Well Costs

At September 30, 2009, we had no capitalized costs related to exploratory wells in process.

Note 10: Foreign Currency Translation and Risk

Effective October 1, 2008, we changed the functional currency of our Polish subsidiary from the U.S. dollar to the Polish zloty. The change in functional currency for the Polish subsidiary will affect the amounts reported for Polish assets, liabilities, revenues, and expenses from those that would be reported had the U.S. dollar been maintained as the functional currency for our Polish operations. The differences will depend on changes in period-average and period-end exchange rates. Translation adjustments will result from the process of translating the Polish subsidiary’s financial statements into the U.S. dollar reporting currency. Translation adjustments will not be included in determining net income but shall be reported separately and accumulated in other comprehensive income. The accounting basis of the assets and liabilities of FX Energy Poland are adjusted to reflect the difference between the exchange rate when the asset or liability arose and the exchange rate on the date of the change. Upon the change in functional currency, we recorded a cumulative translation adjustment (“CTA”) of approximately $3.6 million. At December 31, 2008, the CTA had increased to approximately $17.1 million and decreased to $11.9 million at September 30, 2009. Because of the fluctuation in exchange rates between reporting periods and changes in certain account balances, the CTA will change from period to period.

During the third quarter of 2009, we recorded foreign currency transaction gains of approximately $12.227 million. Of this amount, approximately $12.166 million was attributable to decreases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. There was a corresponding debit to other comprehensive income for the gains attributable to the intercompany loans, which was then offset by translation adjustments related to our other balance sheet accounts as discussed above. The remaining $0.061 million was primarily attributable to the translation of period-end cash balances.

During the first nine months of 2009, we recorded foreign currency transaction gains of approximately $5.547 million. Of this amount, approximately $6.756 million was attributable to changes in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. There was a corresponding debit to other comprehensive income for the gain attributable to the intercompany loans, which was then offset by translation adjustments related to our other balance sheet accounts as discussed above. The difference of $1.209 million of foreign currency transaction losses was primarily attributable to losses on zloty purchase contracts that matured during the period and translation of period-end cash balances.

The following table provides a summary of changes in CTA (in thousands) for the three- and nine-month periods ended September 30, 2009:

	Three Months Ended	Nine Months Ended
	September 30, 2009	September 30, 2009
Beginning balance	$ 21,515	$ 17,137
Decrease related to gains on intercompany loans	(12,166)	(6,756)
Increase related to translation adjustments	2,587	1,555
Balance at September 30, 2009	$ 11,936	$ 11,936

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. We have used forward purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense are recognized in the consolidated financial statements. As of September 30, 2009, there were no outstanding zloty forward purchase contracts.

Note 11: Property Impairment

Production at our Wilga well, despite repeated workover attempts, ceased during the third quarter of 2009. We have impaired the remaining capitalized costs of $1.9 million at Wilga, and are planning to dismantle the production facility.

Note 12: Liquidity

While we have not experienced significant impacts from the economic crisis through the first nine months of 2009, the global economy continues to contract. However, the strengthening of the Polish zloty against the U.S. dollar since February of this year will, if it continues, have a positive 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 increase at the same rate. In recognition of the current economic downturn, we plan to match future capital spending with our discretionary cash flow. As of September 30, 2009, we had firm commitments to spend approximately $600,000 of future capital and exploration costs, the bulk of which is not due to be paid until after December 31, 2009, and all of which will be paid from available cash or cash flow generated by our Polish production operations. Apart from those commitments, we have the ability to control the timing and amount of all other future capital and exploration costs.

For the short-term, the primary source of funds will be existing cash balances and cash flow from operations. We expect our Roszkow well in Poland to be a significant contributor to our future operating cash flows. Production commenced at Roszkow in late September of 2009, and the well generated approximately $1.4 million during October of 2009 in revenues net to us. We are also in discussions with the Royal Bank of Scotland to increase the size of our credit Facility, as well as to extend its maturity dates. Our expected discretionary cash flow combined with our cash resources should enable us to meet our anticipated operating and capital needs in Poland and the United States for more than the next 12 months.

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 early in their initial exploration and development. Our U.S. operations, which include both oil production and oilfield services, are relatively mature. See “Results of Operations by Business Segment” below.

Results of Operations by Business Segment

Quarter Ended September 30, 2009, Compared to the Same Period of 2008

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $1.7 million during the third quarter of 2009, compared to $2.0 million during the same quarter of 2008. Lower per-unit prices during the third quarter of 2009, which were caused primarily by weakness in the Polish zloty from the prior year’s quarter, offset higher production volumes. Production volumes were 33% higher during the third quarter of 2009 compared to the prior year’s third quarter.

Two new wells began production during the third quarter of 2009. Production commenced at our Roszkow well in late September. As of September 30, 2009, production at the well had reached its plateau of 15 million cubic feet of natural gas per day. We expect this production rate to be sustained for several years. We have a 49% interest in the well. Gas is being sold to the Polish Oil and Gas Company, or POGC, at a contracted rate equal to 95% of the published low-methane tariff. As of September 30, 2009, the net price for gas at the Roszkow well was $5.85 per million cubic feet.

Production also began during the third quarter of 2009 at our Grabowka well. PL Energia, a gas distribution company in Poland, is the purchaser of the gas from the Grabowka field. Under a three well re-entry program, gas will be sold at a fixed rate of approximately $1.62 per million cubic feet (approximately $2.70 per million British thermal units based on 60% methane content). This price, which is lower than the current market price, was agreed upon in order to compensate the buyer for taking on all of the cost and risk of re-entering, completing the wells, and paying for construction of the production facilities. Gas is being compressed and transported by truck. The combination of the purchaser-provided financing of all development costs and the lower than normal gas price effectively creates economic outcome and risk similar to a royalty interest for us.

Production at our Zaniemsyl well continues at approximately 10 million cubic feet of natural gas per day. We have a 24.5% interest in this well.

Production at our Wilga well, despite repeated workover attempts, ceased during the third quarter of 2009. We have impaired the remaining capitalized costs at Wilga, and are planning to dismantle the production facility.

Despite our higher production volumes, period-to-period weakness in the Polish zloty against the U.S. dollar resulted in lower U.S. dollar denominated gas revenues. Although the amount of Polish zlotys received per thousand cubic feet of production for each of our wells averaged about 6% higher during the third quarter of 2009 compared to the third quarter of 2008, average U.S. dollar denominated gas prices related to our Poland production decreased 34% from the third quarter of 2008 to the third quarter of 2009. The average exchange rate during the third quarter of 2008 was 2.20 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 34%.

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, 2009 and 2008, is set forth in the following table:

	For the Quarter Ended September 30,
	2009	2008	Change
Revenues	$1,728,000	$1,965,000	-12%
Average price (per thousand cubic feet)	$4.65	$7.00	-34%
Production volumes (thousand cubic feet)	371,800	280,600	+33%

Oil Revenues. Oil revenues were $962,000 for the third quarter of 2009, a 50% decrease from the $1.9 million recognized during the third quarter of 2008. Production from our U.S. properties declined 6% during the third quarter of 2009, and oil production in Poland, all of which came from our Wilga well, decreased by 78%. The most significant factor in the decline in oil revenues, however, was the lower prices received during the third quarter of 2009. Our average oil price during the third quarter of 2009 was $57.83 per barrel, a 45% decrease from $104.68 per barrel received during the same quarter of 2008.

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, 2009 and 2008, is set forth in the following table:

	For the Quarter Ended September 30,
	2009	2008	Change
Revenues	$962,000	$1,920,000	-50%
Average price (per barrel)	$57.83	$104.68	-45%
Production volumes (barrels)	16,600	18,300	-9%

Lease Operating Costs. Lease operating costs were $857,000 during the third quarter of 2009, a decrease of $73,000, or 8%, compared to the same period of 2008. Lower operating costs in the United States resulted from lower production taxes due to lower oil prices. Higher operating costs in Poland, caused by increased workover expenses at our Wilga well, were largely offset by exchange rate differences in Poland from quarter to quarter.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $686,000 during the third quarter of 2009, compared to $3,683,000 during the same period of 2008, a decrease of 81%. Two factors contributed to the quarter-to-quarter decline. First, exchange rate differences reduced the amount of U.S. dollars required to fund 2009 Polish expenditures; second, our level of activity was lower in 2009 than in 2008. 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 associated with two-dimensional, or 2-D, seismic and other costs at both existing and new concessions. Third quarter 2008 exploration costs included approximately $1.6 million associated with 3-D seismic surveys, and approximately $1.5 million associated with ongoing 2-D seismic and other exploratory projects at our existing prospect areas in Poland. In addition, we also incurred $464,000 associated with two dry holes drilled in Montana.

Property Impairments. As discussed above, our Wilga well ceased production during the third quarter of 2009. Accordingly, we impaired the 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 $250,000 for the third quarter of 2009, a decrease of 53%, compared to $528,000 during the same period of 2008. The 2008 year-end negative reserve revision due to low year-end oil prices, and subsequent impairment of capital costs, at our U.S. properties resulted in lower DD&A costs, as the bulk of the capital costs in the U.S. were removed from our depletion base.

Accretion Expense. Accretion expense was $8,000 and $21,000 for the third quarter of 2009 and 2008, respectively. Accretion expense is related entirely to our Asset Retirement Obligation.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $1.1 million during the third quarter of 2009, a decrease of 8%, compared to $1.2 million for the third quarter of 2008. We drilled seven wells for third parties during the third quarter of 2008, along with additional well service work. During the third quarter of 2009, we drilled 11 wells for third parties; however, nine of these were shallow wells that 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 and type 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 $657,000 during the third quarter of 2009, compared to $815,000 during the same period of 2008. The quarter-to-quarter decrease was primarily due to the nature of our drilling activity in 2009 discussed above. Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number and type 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 $155,000 during the third quarter of 2009, compared to $107,000 during the same period of 2008. The quarter-to-quarter increase was primarily due to new capital additions in 2008 being depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $1.5 million during the third quarter of 2009, compared to $1.5 million during the third quarter of 2008.

Stock Compensation (G&A). For the three-month periods ended September 30, 2009 and 2008, we recognized $449,000 and $622,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock.

Interest and Other Income. Interest and other income was $11,000 during the third quarter of 2009, a decrease of $41,000, compared to $52,000 during the same period of 2008. The decrease was a reflection of lower cash balances available for investment. During the third quarter of 2009, we incurred $141,000 in interest expense, which included $46,000 of amortization of previously incurred loan fees. During the third quarter of 2008, we incurred $138,000 in interest expense, which included $31,000 in quarterly commitment fees in connection with securing the Facility and $46,000 of amortization of loan fees.

Foreign Exchange Gain. As discussed in footnote 10 to the financial statements, during the third quarter of 2009 we recorded foreign currency transaction gains of approximately $12.2 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.

Nine Months Ended September 30, 2009, Compared to the Same Period of 2008

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $4.0 million during the first nine months of 2009, compared to $6.0 million during the same period of 2008. Production at our Wilga well continued to decline, with the first nine months of 2009 of production 80% lower than production during the same period of 2008. Lower per-unit prices during the first nine months of 2009, which were caused primarily by weakness in the Polish zloty from the prior year’s nine months, combined with lower production volumes to result in lower revenues. Despite the decline at Wilga, production volumes were only 3% lower during the first nine months of 2009 compared to the prior year’s first nine months.

Two new wells began production during the third quarter of 2009. Production commenced at our Roszkow well in late September. As of September 30, 2009, production at the well had reached its plateau of 15 million cubic feet of natural gas per day. We expect this production rate to be sustained for several years. We have a 49% interest in the well. Gas is being sold to POGC at a contracted rate equal to 95% of the published low-methane tariff. As of September 30, 2009, the net price for gas at the Roszkow well was $5.85 per million cubic feet.

In addition to our lower year-to-date production volumes in 2009, period-to-period weakness in the Polish zloty against the U.S. dollar resulted in lower U.S. dollar denominated gas revenues. Although the amount of Polish zlotys received per thousand cubic feet of production for each of our wells averaged more than 13% higher during the first nine months of 2009, compared to the first nine months of 2008, average U.S. dollar denominated gas prices related to our Poland production decreased 31% from the first nine months of 2008 to the first nine months of 2009. The average exchange rate during the first nine months of 2008 was 2.26 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 42%.

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, 2009 and 2008, is set forth in the following table:

	For the Nine Months Ended September 30,
	2009	2008	Change
Revenues	$3,988,000	$6,017,000	-34%
Average price (per thousand cubic feet)	$4.49	$6.54	-31%
Production volumes (thousand cubic feet)	888,000	920,000	-3%

Oil Revenues. Oil revenues were $2.3 million for the first nine months of 2009, a 57% decrease from the $5.3 million recognized during the first nine months of 2008. Production from our U.S. properties declined 3% during the first nine months of 2009, and oil production in Poland, all of which came from our Wilga well, decreased by 85%. The most significant factor in the decline in oil revenues, however, was the lower prices received during the first nine months of 2009. Our average oil price during the first nine months of 2009 was $47.50 per barrel, a 53% decrease from $101.10 per barrel received during the same period of 2008.

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, 2009 and 2008, is set forth in the following table:

	For the Nine Months Ended September 30,
	2009	2008	Change
Revenues	$2,298,000	$5,337,000	-57%
Average price (per barrel)	$47.50	$101.10	-53%
Production volumes (barrels)	48,400	52,800	-8%

Lease Operating Costs. Lease operating costs were $2.4 million during the first nine months of 2009, a decrease of $283,000, or 10%, compared to the same period of 2008. Lower operating costs in the United States resulted from lower production taxes due to lower oil prices. Higher operating costs in Poland, caused by increased workover expenses at our Wilga well, were largely offset by exchange rate differences in Poland from year to year.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $4.1 million during the first nine months of 2009, compared to $10.0 million during the same period of 2008, a decrease of 59%. Two factors contributed to the year-to-year decline. First, exchange rate differences reduced the amount of U.S. dollars required to fund 2009 Polish expenditures; second, our level of activity was lower in 2009 than in 2008. 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 associated with 2-D seismic and other costs at both existing and new concessions. First nine months 2008 exploration costs included approximately $4.5 million associated with seismic surveys on our 100% owned acreage, approximately $3.0 million associated with 3-D seismic surveys, and approximately $2.0 million associated with ongoing 2-D seismic and other exploratory projects at our existing prospect areas in Poland. In addition, we also incurred $464,000 associated with two dry holes drilled in Montana.

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $681,000 for the first nine months of 2009, a decrease of 61%, compared to $1.7 million during the same period of 2008. The 2008 year-end negative reserve revision due to low year-end oil prices, and subsequent impairment of capital costs, at our U.S. properties resulted in lower DD&A costs, as the bulk of the capital costs in the U.S. were removed from our depletion base. In addition, lower production at our Wilga well in 2009 contributed to the decline.

Accretion Expense. Accretion expense was $24,000 and $63,000 for the first nine months of 2009 and 2008, respectively. Accretion expense is related entirely to our Asset Retirement Obligation.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $1.8 million during the first nine months of 2009, a decrease of 44%, compared to $3.2 million for the first nine months of 2008. We drilled 20 wells for third parties during the first nine months of 2008, along with additional well service work, compared to 25 wells during the same period of 2009. All but two of the wells drilled in 2009 were shallow wells that can be drilled in two to three days. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number and type 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 $1.3 million during the first nine months of 2009, compared to $2.1 million during the same period of 2008. The year-to-year decrease was primarily due to the nature of our drilling activity in 2009 discussed above. Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number and type 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 $428,000 during the first nine months of 2009, compared to $282,000 during the same period of 2008. The year-to-year increase was primarily due to new capital additions in 2008 being depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $4.9 million during the first nine months of 2009, compared to $4.9 million during the first nine months of 2008.

Stock Compensation (G&A). For the nine months ended September 30, 2009 and 2008, we recognized $1.3 million and $1.9 million, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock.

Interest and Other Income. Interest and other income was $50,000 during the first nine months of 2009, a decrease of $277,000, compared to $327,000 during the same period of 2008. The decrease was a reflection of lower cash balances available for investment. During the first nine months of 2009, we incurred $452,000 in interest expense, which included $134,000 of amortization of previously incurred loan fees. During the first nine months of 2008, we incurred $314,000 in interest expense, which included $111,000 in quarterly commitment fees and $137,000 related to the amortization of capitalized fees, all of which are associated with our credit Facility.

Foreign Exchange Gain. As discussed in footnote 10 to the financial statements, during the first nine months of 2009 we recorded foreign currency transaction gains of approximately $5.5 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.

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. With the establishment of proved reserves in Poland, in November 2006, we established a $25.0 million Senior Credit Facility with The Royal Bank of Scotland to fund infrastructure and development costs in Poland. As of December 31, 2008, we had drawn down the full $25.0 million available under this Facility. In addition, cash flows from our operations have been providing a portion of our overhead and capital needs for the past 24 months.

While we have not experienced significant impacts from the economic crisis through the first nine months of 2009, the global economy continues to contract. However, the strengthening of the Polish zloty against the U.S. dollar over the past few months will, if it continues, have a positive 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 increase 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 match future capital spending with our discretionary cash flow. As of September 30, 2009, we had firm commitments to spend approximately $600,000 of future capital and exploration costs, the bulk of which is not due to be paid until after December 31, 2009, and all of which will be paid from available cash or cash flow generated by our Polish production operations. Apart from those commitments, we have the ability to control the timing and amount of all other future capital and exploration costs.

For the short-term, the primary source of funds will be existing cash balances and cash flow from operations. We expect our Roszkow well in Poland to be a significant contributor to our future operating cash flows. Production commenced at Roszkow in late September of 2009. At current prices, exchange rates, and production rates, we expect the Roszkow well to generate approximately $1.3 million a month in revenues net to us. We are also in discussions with the Royal Bank of Scotland to increase the size of our credit Facility, as well as to extend its maturity dates. Our expected discretionary cash flow combined with our cash resources should enable us to meet our anticipated operating and capital needs in Poland and the United States for more than 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, 2009, was $2,693,000, a decrease of $11,272,000 from our working capital at December 31, 2008, of $13,965,000. As of September 30, 2009, our cash, cash equivalents, and marketable securities totaled approximately $2.5 million.

Operating Activities. Net cash used in operating activities was $8,736,000 during the first nine months of 2009, compared to net cash used in operating activities of $8,865,000 during the first nine months of 2008.

Investing Activities. During the first nine months of 2009, we used net cash of $2,832,000 in investing activities. We received proceeds of $4,661,000 from maturities of marketable securities, purchased marketable securities of $11,000, used $4,671,000 for current year capital additions in Poland and $386,000 related to our proved properties in the United States, used $1,623,000 to pay accounts payable related to prior-year capital costs, and used $802,000 for capital additions in our office and drilling equipment. During the first nine months of 2008, we used $8,079,000 from investing activities. We received proceeds of $9,815,000 from maturities of marketable securities, purchased marketable securities of $170,000, used $15,614,000 for current year capital additions in Poland and $899,000 related to our proved properties in the United States, used $428,000 to pay accounts payable related to prior-year capital costs, and used $783,000 for capital additions in our office and drilling equipment.

Financing Activities. During the first nine months of 2009, we paid $2,808,000 toward loans related to auction-rate securities. In addition, option holders exercised 55,000 options that resulted in proceeds to us of $132,000. During the first nine months of 2008, warrant holders exercised warrants for a total of 2,575,593 shares, resulting in proceeds of approximately $9,364,000. As discussed previously, we also borrowed $11 million during this time period under our credit Facility.

New Accounting Pronouncements

As discussed in Note 11 to the financial statements, we have reviewed all 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, 2008. 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.

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; fluctuations in the currency exchange rates between U.S. dollars and the Polish zlotys; the timing of exchange-rate sensitive transactions; 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, Wilga, 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 produce will be lower than would be the case in an unregulated setting and may be lower than prevailing western European prices. We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.

We currently do not engage in any hedging activities to protect ourselves against market risks associated with oil and gas price fluctuations, although we may elect to do so in the future.

Foreign Currency Risk

We enter into various agreements in Poland denominated in the Polish zloty. The Polish zloty is subject to exchange-rate fluctuations that are beyond our control. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes. We have used forward purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense are recognized in our consolidated financial statements. As of September 30, 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 SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified by the SEC’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, 2009, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2009, 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

On June 26, 2009, the court dismissed all claims against all defendants for failure to state a claim upon which relief could be granted in the consolidated single matter, In re FX Energy, Inc., Securities Litigation, United States District Court, District of Utah, case no. 2:07-cv-00874. The time for filing an appeal has now expired without an appeal being filed by plaintiffs. (See Current Report on Form 8-K filed July 1, 2009.)

The action dismissed was based on a consolidated complaint alleging that the defendants violated the antifraud provisions of Section 10(b) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder by making material misrepresentations and omissions regarding our Sroda-5 and Lugi-1 projects between January 20, 2005, and January 5, 2006. The consolidated actions had not been certified to proceed as a class action.

Another pending action filed in the United States District Court for the District of Utah entitled Leilani York, derivatively on behalf of nominal defendant FX Energy, Inc., plaintiff, v. David N. Pierce, Dennis B. Goldstein, Arnold S. Grundvig, Jr., Richard Hardman, Tom Lovejoy, Jerzy Maciolek, Clay Newton, Andrew W. Pierce, and David Worrell, defendants, and FX Energy, Inc., nominal defendant, case no. 2:08-cv-00143, asserting derivative claims on our behalf against certain of our current and former directors and certain of our current and former executive officers and arising out of the same set of facts, had been stayed pending final resolution of the In re FX Energy, Inc., Securities Litigation. Based on the recent dismissal and the expiration of the appeal period in the FX Energy, Inc., Securities Litigation, we have requested that the plaintiffs in the derivative action stipulate to a dismissal of that action as well. Absent such stipulation, we intend to move the court for dismissal.

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, 2008. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2008, 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 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

_______________

*	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.

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, 2009	By:	s/ David N. Pierce
		David N. Pierce, President,
		Chief Executive Officer


Date: November 9, 2009	By:	/s/ Clay Newton
		Clay Newton, Principal Financial Officer

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FX Energy (FXEN) Inactive 10-Q2009 Q3 Quarterly report

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