FX ENERGY INC - FORM 10-Q - August 9, 2012

Attached files

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EX-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 - FX ENERGY INC	ex3202q063012.htm
EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3101q063012.htm
EX-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 - FX ENERGY INC	ex3201q063012.htm
EXCEL - IDEA: XBRL DOCUMENT - FX ENERGY INC	Financial_Report.xls
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3102q063012.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2012

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

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 August 3, 2012, was 52,926,098.

FX ENERGY, INC. AND SUBSIDIARIES

Form 10-Q for the Three Months Ended June 30, 2012

TABLE OF CONTENTS

Item		Page
	Part I—Financial Information

1	Financial Statements (Unaudited)
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations and Comprehensive Income (Loss)	5
	Consolidated Statements of Cash Flows	6
	Notes to the Consolidated Financial Statements	7
2	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	13
3	Quantitative and Qualitative Disclosures about Market Risk	23
4	Controls and Procedures	24

	Part II—Other Information

1A	Risk Factors	25
6	Exhibits	25
--	Signatures	26

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	June 30,		December 31,
	2012		2011
ASSETS

Current assets:
Cash and cash equivalents	$	45,914	$	50,859
Receivables:
Accrued oil and gas sales		3,109		3,446
Joint interest and other receivables		3,195		4,768
VAT receivable		--		389
Inventory		195		196
Other current assets		530		542
Total current assets		52,943		60,200

Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		56,904		49,388
Unproved		3,306		3,482
Other property and equipment		10,273		9,968
Gross property and equipment		70,483		62,838
Less accumulated depreciation, depletion and amortization		(16,731)		(14,942)
Net property and equipment		53,752		47,896

Other assets:
Certificates of deposit		406		406
Loan fees		1,494		1,722
Total other assets		1,900		2,128

Total assets	$	108,595	$	110,224

-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-

	June 30,		December 31,
	2012		2011
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	4,731	$	9,736
VAT payable		609		--
Accrued liabilities		430		677
Total current liabilities		5,770		10,413

Long-term liabilities:
Notes payable		40,000		40,000
Asset retirement obligation		1,221		1,184
Total long-term liabilities		41,221		41,184

Total liabilities		46,991		51,597

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized
as of June 30, 2012, and December 31, 2011; no shares
outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized
as of June 30, 2012, and December 31, 2011; 52,926,098
and 52,787,350 shares issued and outstanding as of
June 30, 2012, and December 31, 2011, respectively		53		53
Additional paid-in capital		221,290		219,522
Cumulative translation adjustment		27,608		28,964
Accumulated deficit		(187,347)		(189,912)
Total stockholders’ equity		61,604		58,627

Total liabilities and stockholders’ equity	$	108,595	$	110,224

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 June 30,				For the six months ended June 30,
	2012		2011		2012		2011
Revenues:
Oil and gas sales	$	7,885	$	7,789	$	15,807	$	14,912
Oilfield services		693		1,393		1,353		1,417
Total revenues		8,578		9,182		17,160		16,329

Operating costs and expenses:
Lease operating expenses		870		1,031		1,741		1,801
Exploration costs		1,987		4,054		4,951		6,931
Loss sale of assets		49		--		49		--
Oilfield services costs		455		1,200		1,094		1,341
Depreciation, depletion and amortization		863		931		1,790		1,668
Accretion expense		15		17		31		34
Stock compensation		551		356		1,102		711
General and administrative		2,363		2,161		4,254		4,123
Total operating costs and expenses		7,153		9,750		15,012		16,609

Operating income (loss)		1,425		(568)		2,148		(280)

Other income (expense):
Interest expense		(640)		(435)		(1,259)		(1,035)
Interest and other income		87		56		171		108
Foreign exchange gain (loss)		(12,987)		3,494		1,505		10,288
Total other income (expense)		(13,540)		3,115		417		9,361

Net income (loss)		(12,115)		2,547		2,565		9,081

Other comprehensive income (loss)
Foreign currency translation adjustment		8,212		(2,332)		(1,356)		(6,809)
Comprehensive income (loss)	$	(3,903)	$	215	$	1,209	$	2,272

Net income (loss) per common share
Basic	$	(0.23)	$	0.05	$	0.05	$	0.18
Diluted	$	(0.23)	$	0.05	$	0.05	$	0.18
Weighted average common shares outstanding
Basic		52,238		52,315		52,230		49,529
Dilutive effect of stock options		-		-		209		-
Diluted		52,238		52,315		52,439		49,529

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 Six Months Ended
	June 30,
	2012		2011
Cash flows from operating activities:
Net income	$	2,565	$	9,081
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		1,790		1,668
Accretion expense		31		34
Amortization of loan fees		250		289
Stock compensation		1,102		711
Loss on sale of assets		49		--
Unrealized foreign exchange gains		(1,509)		(10,298)
Common stock issued for services		666		712
Increase (decrease) from changes in working capital items:
Receivables		3,068		(12,053)
Inventory		1		1
Other current assets		(15)		114
Accounts payable and accrued liabilities		(3,534)		4,037
Net cash provided by (used in) operating activities		4,494		(5,704)

Cash flows from investing activities:
Additions to oil and gas properties		(9,326)		(10,593)
Additions to other property and equipment		(303)		(775)
Proceeds from sale of assets		222		--
Net cash used in investing activities		(9,407)		(11,368)

Cash flows from financing activities:
Proceeds from stock option exercises		--		128
Proceeds from common stock offering, net		--		45,042
Payments made on credit facility		--		(35,000)
Net cash provided by in financing activities		--		10,170

Effect of exchange-rate changes on cash		(32)		652

Net decrease in cash		(4,945)		(6,250)
Cash and cash equivalents at beginning of year		50,859		19,740

Cash and cash equivalents at end of period	$	45,914	$	13,490

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

In the opinion of management, our financial statements reflect the adjustments, all of 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, 2011, and our Form 10-Q for the quarter ended March 31, 2012.

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. Diluted earnings per share was computed for the three- and six-month periods ended June 30, 2011, and the six-month period ended June 30, 2012, 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 each of these periods. As we had a net loss in the three-month period ended June 30, 2012, no options were included in the computation of diluted earnings per share for this period because the effect would have been antidilutive.

Outstanding options and unvested restricted stock as of June 30, 2012 and 2011, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
June 30, 2012	1,321,041	$0.00 - $5.06
June 30, 2011	1,560,608	$0.00 - $10.65

Note 3: Income Taxes

No income tax expense was recognized for the three- and six-month periods ended June 30, 2011, and the six-month period ended June 30, 2012, due to the reversal of valuation allowances that offset income tax expense for the period. We are required to provide a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of deferred tax assets will depend on the generation of future taxable income through profitable operations and the expansion of exploration and development activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided. We are subject to audit by the IRS and various states for the prior three years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months, nor has there been a change in our unrecognized tax positions since December 31, 2011. 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, 2012.

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 June 30, 2012, the six months ended June 30, 2012, and as of June 30, 2012, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non- Segmented	Total
	U.S.	Poland
Three months ended June 30, 2012:
Revenues	$ 971	$ 6,914	$ 693	$ --	$ 8,578
Net income (loss)	270	4,112	(36)	(16,461)(1)	(12,115)
Six months ended June 30, 2012:
Revenues	$ 2,123	$13,684	$ 1,353	$ --	$ 17,160
Net income (loss)	793	7,028	(302)	(4,954) (1)	2,565
As of June 30, 2012:
Identifiable net property and equipment	$ 3,577	$47,488	$ 2,646	$ 41	$ 53,752

_______________

(1)

Nonsegmented reconciling items for the second quarter include $2,363 of G&A costs, $551 of noncash stock compensation expense, $553 of other expense, $7 of corporate DD&A costs, and $12,987 of foreign exchange losses. Nonsegmented reconciling items for the first six months include $4,254 of G&A costs, $1,102 of noncash stock compensation expense, $1,088 of other expense, $15 of corporate DD&A costs, and $1,505 of foreign exchange gains.

Reportable business segment information for the three months ended June 30, 2011, the six months ended June 30, 2011, and as of June 30, 2011, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non- Segmented	Total
	U.S.	Poland
Three months ended June 30, 2011:
Revenues	$ 1,320	$ 6,469	$ 1,393	$ --	$ 9,182
Net income (loss)	426	1,577	(36)	580(1)	2,547
Six months ended June 30, 2011:
Revenues	$ 2,480	$12,432	$ 1,417	$ --	$ 16,329
Net income (loss)	880	4,079	(371)	4,493(1)	9,081
As of June 30, 2011:
Identifiable net property and equipment	$ 2,130	$43,535	$ 3,072	$ 24	$ 48,761

_______________

(1)

Nonsegmented reconciling items for the second quarter include $2,161 of G&A costs, $356 of noncash stock compensation expense, $380 of other expense, $17 of corporate DD&A costs, and $3,494 of foreign exchange gains. Nonsegmented reconciling items for the first six months include $4,123 of G&A costs, $711 of noncash stock compensation expense, $928 of other expense, $33 of corporate DD&A costs, and $10,288 of foreign exchange gains.

Note 5: Share-Based Compensation

We have several share-based incentive plans. Under these plans, options have been granted at an option price equal to the market value of the stock at the date of grant. The granted options have a term of ten years and vest in three equal annual installments from the date of grant. 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.

Stock Options

The following table summarizes option activity for the first six months of 2012:

		Weighted	Weighted Average
		Average	Remaining	Aggregate
	Number of	Exercise	Contractual	Intrinsic
	Options	Price	Life (in years)	Value
Options outstanding:
Beginning of year	668,129	$5.31
Expired	(35,000)	9.89
End of period	633,129	5.06	9.22
Exercisable at end of period	--	--	--	$0

The following table summarizes option activity for the first six months of 2011:

		Weighted	Weighted Average
		Average	Remaining	Aggregate
	Number of	Exercise	Contractual	Intrinsic
	Options	Price	Life (in years)	Value
Options outstanding:
Beginning of year	832,332	$8.42
Exercised	(16,499)	7.79
End of period	815,833	8.44	0.20
Exercisable at end of period	815,833	8.44	0.20	$320,142

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $5.95 as of June 30, 2012, and $8.78 as of June 30, 2011, 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 second half of 2011, we issued 636,509 stock options, resulting in deferred compensation of $1,781,036, which will be amortized ratably over a three-year vesting period. Expense recognized during the first six months of 2012 totaled $293,917.

Restricted Stock

During the second half of 2011, we issued 318,252 shares of restricted stock, resulting in deferred compensation of $1,610,355, which will be amortized ratably over a three-year vesting period. Expense recognized during the first six months of 2012 totaled $265,750. There were no shares of restricted stock issued during the first six months of 2012.

During the second half of 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2,259,675, which will be amortized ratably over a three-year vesting period. Expense recognized during the first six months of 2012 and 2011 totaled $370,881 and $376,613, respectively.

During 2009, we issued 379,500 shares of restricted stock, resulting in unamortized compensation expense of $1,043,625, which will be amortized ratably over a three-year vesting period. Expense recognized during the first six months of 2012 and 2011 totaled $170,996 and $173,391, respectively.

During 2008, we issued 367,000 shares of restricted stock, resulting in unamortized compensation expense of $1,005,580, which will be amortized ratably over a three-year vesting period. Expense recognized during the first six months of 2012 and 2011 totaled $0 and $160,836, respectively.

The following table summarizes restricted stock activity during the first six months of 2012 and 2011:

	Number of Shares
	2012	2011
Unvested restricted stock outstanding:
Beginning of year	687,912	746,398
Issued	--	--
Forfeited	--	(1,623)
Vested	--	--
End of period	687,912	744,775

Note 6: Stockholders’ Equity

During the first six months of 2012, we issued 138,748 shares for the 2011 contribution to our employee benefit plan.

During the first six months of 2011, we sold 6,900,000 shares of common stock in a registered public offering at a price of $7.00 per share. After offering costs, the net proceeds from the offering were approximately $45.0 million, part of which was used to pay down our credit facility balance. See Note 8 for more information. Option holders exercised options to purchase 16,499 shares of common stock during the first half of 2011, which resulted in proceeds of approximately $128,000. Also during the first six months of 2011, we issued 106,301 shares for the 2010 contribution to our employee benefit plan and 9,500 shares to consultants for services.

Note 7: Fair Value Measurements

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

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

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

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

A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We did not have any significant nonfinancial assets or nonfinancial liabilities that would be recognized or disclosed at fair value on a recurring basis as of June 30, 2012, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first six months of 2012.

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 measured at fair value on a recurring basis consisted of the following as of June 30, 2012 (in thousands):

		Fair Value Measurements Using
		Quoted Prices
		in Active	Significant
		Markets for	Other	Significant
		Identical	Observable	Unobservable
	Carrying	Assets	Inputs	Inputs
	Amount	(Level 1)	(Level 2)	(Level 3)
Financial assets:
Money market funds	$1,975	$1,975	--	--

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of June 30, 2011 (in thousands):

		Fair Value Measurements Using
		Quoted Prices
		in Active	Significant
		Markets for	Other	Significant
		Identical	Observable	Unobservable
	Carrying	Assets	Inputs	Inputs
	Amount	(Level 1)	(Level 2)	(Level 3)
Financial assets:
Money market funds	$6,779	$6,779	--	--

Note 8: Notes Payable

FX Energy Poland has a $55 million Senior Reserve Base Lending Facility with the Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The credit facility calls for a periodic interest rate of LIBOR, plus an interest margin of 4.0%, and has a term of five years, with semiannual borrowing base reductions of $11 million each beginning on June 30, 2013. The credit facility is an interest-only facility until then. An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the expanded credit facility. We amortized approximately $250,000 of deferred financing costs associated with our existing credit facility to interest expense during the first six months of 2012. Payment of the credit facility is secured by our assets in Poland and guaranteed by FX Energy, Inc. We used proceeds from the offering described in Note 6 to repay all balances outstanding under the credit facility as of March 31, 2011. As of June 30, 2012, we had $40 million outstanding under the credit facility. Our notes payable is stated at book value, which approximated its fair value at June 30, 2012. Estimated fair values for notes payable have been determined based on borrowing rates currently available to us for bank loans with similar terms and maturities and are classified as Level 2 (significant observable inputs other than quoted prices) in the Financial Accounting Standards Board’s fair value hierarchy.

We have access to $40 million under the credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells, or KSK wells, have been on production for 30 days, at which time the full $55 million becomes available. Full production at KSK began on June 28, 2012. We expect to have access to the remaining $15 million sometime during the third quarter. Proceeds from the credit facility are intended to support our development, production, and operating activities in Poland.

Note 9: Capitalized Exploratory Well Costs

We had $4.3 million, $6.7 million, and $2.6 million of capitalized costs related to our Plawce-2, Kutno, and Komorze-3 wells, respectively, which were being drilled at June 30, 2012. In addition, we had capitalized costs of approximately $1.5 million associated with three wells related to our Alberta Bakken project, pending further evaluation.

Note 10: Foreign Currency Translation and Risk

During the first six months of 2012, we recorded foreign currency transaction gains of approximately $1.5 million. This amount was attributable to decreases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany and other dollar-denominated loans and unpaid interest. There was a corresponding debit to other comprehensive income for gains 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, 2012
Balance at December 31, 2011	$ 28,964
Decrease related to gains on intercompany loans	(1,509)
Increase related to translation adjustments	153
Balance at June 30, 2012	$ 27,608

Future transaction gains or losses may be significant given the amount of intercompany loans and the volatility of the exchange rate. Future translation adjustments will also vary in concert with changes in exchange rates. These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.

We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Introduction

The majority of our operations are in Poland, and we have devoted most of our technical talent and capital expenditures in the last several years to our operations in that country. The decision to devote most of our available capital to this area drives our operating results and the changes to our balance sheet and liquidity. Our operations in Poland are a combination of existing production and substantial exploration. Oil and gas production, oil and gas revenues, cash flow, earnings, oil and gas reserves, and oil and gas expenditures have grown significantly over the last four years.

Our U.S. operations also have an impact. Our U.S. operations are smaller than those in Poland and do not present the same level of opportunities for expansion; however, our U.S. operations are a relatively stable source of cash flow. This, too, is reflected in our operating results.

Results of Operations by Business Segment

Quarter Ended June 30, 2012, Compared to the Same Period of 2011

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $6.9 million during the second quarter of 2012, compared to $6.5 million during the same quarter of 2011. Higher prices in the 2012 quarter led to the increase in natural gas revenues.

A summary of the amount and percentage change, as compared to the respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the quarters ended June 30, 2012 and 2011, is set forth in the following table:

	For the Quarter Ended June 30,
	2012	2011	Change
Gas revenues	$6,914,000	$6,469,000	+7%
Average price (per thousand cubic feet)	$6.86	$6.36	+8%
Production volumes (thousand cubic feet)	1,008,000	1,017,500	-1%

Our increased revenues were due entirely to higher prices during the 2012 quarter, as natural gas production in the second quarter of 2012 was essentially flat compared to the second quarter of 2011. Daily gas production for the second quarter of 2012 was 11.1 MMcfd, compared to 11.2 MMcfd during the same quarter of 2011. Production from our KSK wells increased by 145,000 Mcf over 2011 second quarter levels. We achieved full production at our KSK wells on June 28, 2012, following a successful resolution of a pipeline bottleneck. However, our Roszkow well was unexpectedly shut-in by the operator for maintenance and testing for 15 days during the quarter. Each of our natural gas wells in Poland is shut in for about two weeks every year for maintenance and testing. In the past, this has always occurred either late third quarter or early fourth quarter. Without the unexpected shut-in at Roszkow, our production rate for the second quarter of 2012 would have been approximately 12.0 MMcfd. At June 30, 2012, our net natural gas production rate was approximately 14.8 MMcfd.

During the third quarter of 2012, our three KSK wells are scheduled to be shut in for up to two weeks for annual maintenance and pressure testing, which will have an impact on our third quarter production and revenues.

Natural gas prices increased 8% quarter over quarter during the last 12 months. The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 32% higher during the second quarter of 2012, compared to the same quarter of 2011. The increase was a function of two price changes from 2011 second quarter-levels implemented by the Polish utility regulator. The first was a 12.5% increase that became effective for us on August 1, 2011; the second was a 16.9% increase that became effective for us on April 1, 2012. However, period-to-period strength in the U.S. dollar against the Polish zloty largely offset the higher prices. The average exchange rate during the second quarter of 2012 was 3.33 zlotys per U.S. dollar. The average exchange rate during the second quarter of 2011 was 2.75 zlotys per U.S. dollar, a change of approximately 21%.

Oil Revenues. Oil revenues were $971,000 for the second quarter of 2012, a 26% decrease from $1.3 million recognized during the second quarter of 2011. Production levels decreased approximately 9% from 2011 to 2012, due to normal production declines. The most significant factor in the decrease in oil revenues was the lower prices received during the second quarter of 2012. Our average oil price during the second quarter of 2012 was $72.64 per barrel, a 19% decrease from $89.95 per barrel received during the same quarter of 2011.

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, 2012 and 2011, is set forth in the following table:

	For the Quarter Ended June 30,
	2012	2011	Change
Oil revenues	$971,000	$1,320,000	-26%
Average price (per barrel)	$72.64	$89.95	-19%
Production volumes (barrels)	13,370	14,680	-9%

Lease Operating Costs. Lease operating costs of $870,000 during the second quarter of 2012 were 16% lower than the second quarter 2011 amount of $1.0 million. During the second quarter of 2011, we had a small oil leak in our Southwest Cut Bank Sand Unit in Montana. Cleanup costs were then estimated to be approximately $150,000, and we accrued those costs as of June 30, 2011. There were no similar costs in 2012. In addition, lower oil prices in the United States resulted in lower value-based production taxes. These decreases in the United States were partially offset by higher operating costs in Poland associated with higher production at our Kromolice-1 and -2 wells.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $2.0 million during the second quarter of 2012, compared to $4.1 million during the same period of 2011, a decrease of 51%. Second quarter 2012 geological and geophysical costs included approximately $1.2 million associated with new two-dimensional, or 2-D, seismic surveys on our Warsaw South acreage, $0.7 million associated with 2-D seismic surveys on our 100%-owned acreage, and $0.1 million associated with our three-dimensional, or 3-D, seismic survey at our Lisewo southeast project. Second quarter 2011 exploration costs included approximately $1.5 million associated with our Lisewo southeast 3-D seismic survey and $2.0 million associated with 2-D seismic surveys at other project areas in Poland. Subsequent to June 30, 2011, we determined that our Machnatka well, which was being drilled in our Warsaw South concession, did not find commercial quantities of oil or gas. Accordingly, we charged to exploration expense our share of dry-hole costs incurred through June 30, 2011, of $232,000.

Loss on Sale of Assets. During the second quarter of 2012, we sold certain leases in Montana associated with our Bakken exploration project, resulting in a loss of approximately $49,000. There was no corresponding transaction during 2011.

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $582,000 for the second quarter of 2012, a decrease of 15%, compared to $685,000 during the same period of 2011. Lower DD&A expense in 2012 was due primarily to changes in Polish zloty and U.S. dollar exchange rates, along with lower production at our Roszkow well.

Accretion Expense. Accretion expense was $15,000 and $17,000 for the second quarter of 2012 and 2011, respectively. Accretion expense is related entirely to our asset retirement obligation associated with expected future plugging and abandonment costs.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $693,000 during the second quarter of 2012, a decrease of 50%, compared to $1.4 million for the second quarter of 2011. During the second quarter of 2012, we drilled two wells for third parties. We drilled three wells for third parties, including two drilled for our Alberta Bakken joint venture, during the second quarter of 2011, along with additional well service work. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $455,000 during the second quarter of 2012, compared to $1.2 million during the same period of 2011. 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 $274,000 during the second quarter of 2012, compared to $229,000 during the same period of 2011. The period-to-period increase was primarily due to new depreciation from capital additions in 2011 and 2012.

Nonsegmented Information

G&A Costs. G&A costs were $2.4 million during the second quarter of 2012, compared to $2.2 million during the second quarter of 2011. The increase is primarily due to higher compensation costs, which were partially offset by lower legal costs.

Stock Compensation (G&A). For the three-month periods ended June 30, 2012 and 2011, we recognized $551,000 and $356,000, 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 $87,000 during the second quarter of 2012, an increase of $31,000, compared to $56,000 during the same period of 2011. The increase was a reflection of higher cash balances available for investment. During the second quarter of 2012, we incurred $640,000 in interest expense, which included $123,000 of amortization of previously incurred loan fees and $75,000 in commitment fees. During the second quarter of 2011, we incurred $435,000 in interest expense, which included $148,000 of amortization of previously incurred loan fees and $173,000 in commitment fees.

Foreign Exchange Gain (Loss). During the second quarter of 2012, we recorded foreign currency transaction losses of approximately $13.0 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 approximately $3.5 million during the same quarter of 2011, which were also principally related to our intercompany loans. During the second quarter of 2012, the U.S. dollar strengthened against the zloty by approximately 9% from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction losses. Conversely, during the second quarter of 2011, the zloty strengthened by approximately 3% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.

Six Months Ended June 30, 2012, Compared to the Same Period of 2011

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $13.7 million during the first half of 2012, compared to $12.4 million during the same period of 2011. Higher natural gas prices combined with higher production from our Kromolice-1 and -2 wells to produce the higher revenues.

A summary of the amount and percentage change, as compared to the respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the six months ended June 30, 2012 and 2011, is set forth in the following table:

	For the Six Months Ended June 30,
	2012	2011	Change
Revenues	$13,684,000	$12,432,000	+10%
Average price (per thousand cubic feet)	$6.42	$6.24	+3%
Production volumes (thousand cubic feet)	2,130,400	1,992,400	+7%

We recognized a 3% increase in natural gas prices period over period. The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 22% higher during the first half of 2012, compared to the same quarter of 2011. The increase was primarily a function of a 16.9% price increase by the Polish utility regulator that became effective for us on April 1, 2012. However, period-to-period strength in the U.S. dollar against the Polish zloty decreased our U.S. dollar-denominated gas prices. The average exchange rate during the first half of 2011 was 2.82 zlotys per U.S. dollar. The average exchange rate during the first half of 2012 was 3.27 zlotys per U.S. dollar, a change of approximately 16%.

Daily gas production for the first half of 2012 was 11.7 MMcfd, compared to 11.0 MMcfd during the same period of 2011. Production from our KSK wells increased by 300,000 Mcf over 2011 second quarter levels. We achieved full production at our KSK wells on June 28, 2012, following a successful resolution of a pipeline bottleneck. However, our Roszkow well was unexpectedly shut-in by the operator for maintenance and testing for 15 days during the quarter. Each of our natural gas wells in Poland is shut in for about two weeks every year for maintenance and testing. In the past, this has always occurred either late third quarter or early fourth quarter. Without the unexpected shut-in at Roszkow, our production rate for the first half of 2012 would have been approximately 12.1 MMcfd.

During the third quarter of 2012, all of our producing wells, except for Roszkow, are scheduled to be shut in for up to two weeks for annual maintenance and pressure testing, which will have an impact on our third quarter and nine-month production and revenues.

Oil Revenues. Oil revenues were $2.1 million for the first half of 2012, a 14% decrease from the $2.5 million recognized during the first half of 2011. Production from our U.S. properties declined 7% during the first half of 2012, due to normal production declines. The other important factor in the decrease in oil revenues was the lower prices received during the first half of 2012. Our average oil price during the first half of 2012 was $78.85 per barrel, an 8% decrease from $85.89 per barrel received during the same period of 2011.

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, 2012 and 2011, is set forth in the following table:

	For the Six Months Ended June 30,
	2012	2011	Change
Revenues	$2,123,000	$2,480,000	-14%
Average price (per barrel)	$78.85	$85.89	-8%
Production volumes (barrels)	26,923	28,865	-7%

Lease Operating Costs. Lease operating costs were $1.7 million during the first half of 2012, compared to $1.8 million during the first half of 2011. During the second quarter of 2011, we had a small oil leak at our Southwest Cut Bank Sand Unit in Montana. Cleanup costs were then estimated to be approximately $150,000, and those costs were accrued as of June 30, 2011.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $5.0 million during the first half of 2012, compared to $6.9 million during the same period of 2011, a decrease of 29%.

First half 2012 exploration costs included approximately $500,000 associated with our Lisewo southeast 3-D seismic survey in our Fences concession, $3.9 million associated with 2-D seismic projects at our other existing Polish concessions, and approximately $470,000 in dry-hole costs associated with a Bakken test well in Montana. First half 2011 exploration costs included approximately $1.5 million associated with our Lisewo southeast 3-D seismic survey, $4.5 million associated with new 2-D seismic surveys at other project areas in Poland, and approximately $600,000 associated with other geological and geophysical studies. Subsequent to June 30, 2011, we determined that our Machnatka well, which was drilled in our Warsaw South concession, did not find commercial quantities of oil or gas. Accordingly, we charged to exploration expense our share of dry-hole costs incurred through June 30, 2011, of $232,000.

Loss on Sale of Assets. During the first half of 2012, we sold certain leases in Montana associated with our Bakken exploration project, resulting in a loss of approximately $49,000. There was no corresponding transaction during 2011.

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $1.2 million for the first half of 2012, unchanged from $1.2 million during the same period of 2011. Higher zloty-based DD&A expenses during the first half of 2012 were offset by changes in the Polish zloty and U.S. dollar exchange rates.

Accretion Expense. Accretion expense was $31,000 and $34,000 for the first half of 2012 and 2011, respectively. Accretion expense is related entirely to our asset retirement obligation.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were just under $1.4 million during the first half of 2012, a decrease of 5%, compared to just over $1.4 million for the first half of 2011. We drilled five wells for third parties, including one drilled for our Alberta Bakken joint venture, during the first half of 2012, along with additional well service work. During the first half of 2011, we drilled four wells for third parties, including those drilled for our Alberta Bakken joint venture. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $1.1 million during the first half of 2012, compared to $1.3 million during the same period of 2011. 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 $560,000 during the first half of 2012, compared to $448,000 during the same period of 2011. The period-to-period increase was primarily due to new depreciation from capital additions in 2011 and 2012.

Nonsegmented Information

G&A Costs. G&A costs were $4.3 million during the first half of 2012, compared to $4.1 million during the first half of 2011, an increase of $131,000. Higher compensation costs were partially offset by lower legal costs in the first half of 2012.

Stock Compensation (G&A). For the six-month periods ended June 30, 2012 and 2011, we recognized $1.1 million and $711,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock purchase rights.

Interest and Other Income (Expense). Interest and other income was $171,000 during the first half of 2012, an increase of $63,000, compared to $108,000 during the same period of 2011. The increase was a reflection of higher cash balances available for investment. During the first half of 2012, we incurred $1.3 million in interest expense, which included $250,000 of amortization of previously incurred loan fees and $152,000 in commitment fees. During the first half of 2011, we incurred $1.0 million in interest expense, which included $290,000 of amortization of previously incurred loan fees and $291,000 in commitment fees.

Foreign Exchange Loss. As discussed in Note 10 to the financial statements, during the first half of 2012, we recorded foreign currency transaction gains of approximately $1.5 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. During the first half of 2012, the zloty strengthened by approximately 1% against the U.S. dollar from the beginning to the end of the period, which caused us to recognized foreign currency transaction gains. During the first half of 2011, the zloty strengthened by approximately 7% against the U.S. dollar from the beginning to the end of the period, which caused us to recognized foreign currency transaction gains of $10.3 million.

Liquidity and Capital Resources

For much of our history, we have financed our operations principally through the sale of equity securities, bank borrowings, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. However, in the last several years, as our gas production and prices have increased in Poland and as oil prices have generally increased the profitability of our U.S. production, our internally generated cash flow has become a significant source of operations financing.

2012 Liquidity and Capital

Working Capital (current assets less current liabilities). Our working capital was $47.2 million as of June 30, 2012, down from $49.8 million from December 31, 2011. Our current assets at June 30, 2012, included approximately $3.1 million in accrued oil and gas sales from both the United States and Poland. Our current liabilities at quarter-end included approximately $3.7 million in costs related to capital and exploration projects in Poland. Our outstanding long-term debt at June 30, 2012, was $40 million, with no payments due during the next twelve months.

Operating Activities. Net cash provided by operating activities was $4.5 million during the first half of 2012, compared to net cash used by operating activities of $5.7 million during the first half of 2011. Lower exploration costs in 2012 combined with positive changes in working capital items to account for the improved results.

Investing Activities. During the first half of 2012, we used cash of $9.6 million in investing activities. We used $9.3 million for current-year capital additions related to our ongoing exploration and production activities and $303,000 for capital additions in our office and drilling equipment. During the first half of 2011, we used cash of $11.4 million in investing activities. We used $10.6 million for 2011 capital additions related to our ongoing exploration and production activities and $775,000 for capital additions in our office and drilling equipment.

Financing Activities. During the first half of 2011, we issued 6.9 million shares of common stock in a registered public offering, which resulted in net proceeds to us, after offering costs, of approximately $45.0 million. We used $35.0 million of those proceeds to repay amounts outstanding under our credit facility. We also received proceeds of $128,000 from the exercise of stock options. There were no financing activities during the first half of 2012.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2012 include our working capital of $47.2 million at June 30, 2012, available credit of $15 million under our credit facility when we meet the benchmarks discussed below, and cash available from our operations. Possible additional proceeds may be available from the sale of securities, increased debt capacity, or asset sales.

We currently have a $55 million credit facility with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The credit facility calls for a periodic interest rate of LIBOR plus 4.0% and has a term of five years, with semiannual borrowing base reductions of $11 million each beginning on June 30, 2013. The credit facility is an interest-only facility until June 2013. As of June 30, 2012, we had $40 million outstanding under the credit facility. We have access to $40 million under the credit facility until our KSK wells have been in full production for 30 days, at which time the full $55 million becomes available. Full production at KSK began on June 28, 2012. We expect to have access to the remaining $15 million sometime during the third quarter. Proceeds from the credit facility are intended to support our operating activities in Poland. Further, we believe our total credit line could be expanded, even without including our 2011 Lisewo-1 discovery, in a revised credit facility.

As of June 30, 2012, we were producing gas from six wells in Poland, including our Sroda-4 and two Kromolice wells. We expect our increased production to increase funds available for exploration and development over 2011 levels. Our Winna Gora well is expected to begin production in the fourth quarter of 2012. In addition, in 2011, we drilled and completed the successful Lisewo-1 well in our Fences concession, which we expect to further increase production and revenue in 2013.

On June 22, 2012, we filed a universal shelf registration statement under the Securities Act of 1933 under which we may sell up to $200 million of equity or debt securities of various kinds. This filing replaces the prior shelf registration statement, which expired. The registration statement became effective August 1, 2012. The $200 million of securities available for sale under the registration statement is available for sale at any time, subject to market conditions and our ability to access the capital markets, to further finance our exploration and development plans in Poland and for other corporate purposes.

We expect our primary use of cash for 2012 will be for our exploration and development activities in Poland. At June 30, 2012, we were in the process of drilling the Kutno-2 well, having incurred total costs of $2.2 million during this year. Our total costs for this well, once drilling is completed, are expected to be approximately $10 million. We were also drilling our Komorze 3-K well at a total cost through June 30, 2012 of $2.6 million. We have agreed with the Polish Oil and Gas Company, or PGNiG, to conduct a fracture stimulation test at the Plawce-2 well during the third quarter of 2012. We were also building production facilities at our Winna Gora well. We have signed tender documents in preparation of drilling our Frankowo well, which should begin drilling during August of 2012. We had no other firm commitments for future capital and exploration costs at June 30, 2012. However, while not currently committed, our plans call for drilling operations to begin during the second half of the year at our Mieczewo, Tuchola, and Lisewo-2 wells. In addition, we also plan additional 2-D and 3-D seismic data acquisition and analysis.

We expect the cost of these 2012 activities to range from $50 million to $60 million. During 2010 and 2011, the exchange rate between the Polish zloty and the U.S. dollar averaged approximately 3.0 zlotys per U.S. dollar. Due to the strength of the U.S. dollar, the exchange rate has averaged approximately 3.3 zlotys per U.S. dollar through June 30, 2012. Accordingly, the actual amount of our U.S. dollar denominated expenditures will depend on exchange rates between the U.S. dollar and the Polish zloty. In addition, our expenditures also depend on ongoing exploration results; the pace at which PGNiG, our operating partner in the Fences project area, wishes to proceed or the extent it wishes to continue to participate with us in concessions we operate; the availability of drilling and other exploration services; and the amount of capital we obtain from the various sources discussed above. Our sources of liquidity and capital outlined above should more than enable us to meet our capital needs in Poland and the United States for the next 12 months.

Based on current conditions, we presently expect our exploration and development programs will continue in spite of uncertain global economic conditions; however, in recognition of the ongoing economic downturn, we plan to continue, as we have in prior years, matching capital spending with our cash on hand, expected discretionary cash flow, increased debt capacity, and proceeds from the sale of securities. We have the ability to control the timing and amount of most of our future capital and exploration costs.

We may incur operating losses in future periods, and we continue to fund substantial exploration and development in Poland. We have a history of operating losses. From our inception in January 1989 through June 30, 2012, we have incurred cumulative net losses of approximately $187 million. Despite our recent and expected future increases in production and revenues, our exploration and production activities may continue to result in net losses in future years, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses. While revenues from our operations exceed our fixed operating and overhead costs, we reported negative cash flow from operating activities as recently as 2011.

We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements in which industry participants bear the initial exploration costs to earn an interest in the project or other arrangements, all of which may dilute the interest of our existing stockholders or our interest in the specific project financed.

We will allocate our existing capital, as well as funds we may obtain in the future, among our various projects at our discretion. We may change the allocation of capital among the categories of anticipated expenditures depending upon future events. For example, we may change the allocation of our expenditures based on the actual results and costs of future exploration, appraisal, development, production, property acquisition, and other activities. In addition, we may have to change our anticipated expenditures if costs of placing any particular discovery into production are higher, if the field is smaller, or if the commencement of production takes longer than expected.

New Accounting Pronouncements

We have reviewed all 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, 2011. 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; 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 PGNiG or its subsidiaries under contracts that extend for the life of each field. Prices are determined contractually and, in the case of our Roszkow, Zaniemysl, and KSK wells, are tied to published tariffs. The tariffs are set from time to time by the public utility regulator in Poland. Although we are not directly subject to such tariffs, we have elected to link our price to these tariffs in our contracts with PGNiG. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in an unregulated setting and may be lower than prevailing western European prices. We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.

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

Foreign Currency Risk

We enter into various agreements in Poland denominated in the Polish zloty. The Polish zloty is subject to exchange-rate fluctuations that are beyond our control. Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues. We do not use derivative financial instruments for trading or speculative purposes. We have used forward-purchase contracts to buy zlotys at specified exchange rates. The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense is recognized in our consolidated financial statements. As of June 30, 2012, we had no outstanding zloty forward-purchase contracts.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of June 30, 2012, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of June 30, 2012, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

ITEM 1A. RISK FACTORS

Information regarding risk factors appears in “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Forward-Looking Statements,” in Part I — Item 2 of this Form 10-Q and in Part I — Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2011, 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 Principal 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: August 9, 2012	By:	/s/ David N. Pierce
		David N. Pierce, President, Chief Executive Officer


Date: August 9, 2012	By:	/s/ Clay Newton
		Clay Newton, Principal Financial Officer

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