FX ENERGY INC - FORM 10-Q - November 7, 2013

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EXCEL - IDEA: XBRL DOCUMENT - FX ENERGY INC	Financial_Report.xls
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	ex3202q093013.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	ex3201q093013.htm
EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3101q093013.htm
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3102q093013.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 September 30, 2013

¨	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 November 1, 2013, was 53,409,365.

FX ENERGY, INC. AND SUBSIDIARIES

Form 10-Q for the Three Months Ended September 30, 2013

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	14
3	Quantitative and Qualitative Disclosures about Market Risk	23
4	Controls and Procedures	24

	Part II—Other Information

1A	Risk Factors	24
6	Exhibits	25
--	Signatures	26

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	September 30,		December 31,
	2013		2012
ASSETS

Current assets:
Cash and cash equivalents	$	19,182	$	33,990
Receivables:
Accrued oil and gas sales		3,095		3,447
Joint interest and other receivables		1,290		7,733
VAT receivable		1,180		1,136
Inventory		206		199
Other current assets		309		614
Total current assets		25,262		47,119

Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved		72,473		63,821
Unproved		1,930		2,337
Other property and equipment		11,567		10,717
Gross property and equipment		85,970		76,875
Less accumulated depreciation, depletion, and amortization		(21,997)		(19,786)
Net property and equipment		63,973		57,089

Other assets:
Certificates of deposit		406		382
Loan fees		2,366		1,364
Total other assets		2,772		1,746

Total assets	$	92,007	$	105,954

-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,
	2013		2012
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	5,204	$	8,532
Accrued liabilities		634		1,192
Current portion of long-term debt		--		7,000
Total current liabilities		5,838		16,724

Long-term liabilities:
Notes payable		42,000		33,000
Asset retirement obligation		1,599		1,431
Total long-term liabilities		43,599		34,431

Total liabilities		49,437		51,155

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized
as of September 30, 2013, and December 31, 2012; no shares
outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized
as of September 30, 2013, and December 31, 2012; 53,409,365
and 53,246,620 shares issued and outstanding as of
September 30, 2013, and December 31, 2012, respectively		53		53
Additional paid-in capital		225,290		222,513
Cumulative translation adjustment		18,632		18,027
Accumulated deficit		(201,405)		(185,794)
Total stockholders’ equity		42,570		54,799

Total liabilities and stockholders’ equity	$	92,007	$	105,954

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,
	2013		2012		2013		2012
Revenues:
Oil and gas sales	$	8,034	$	9,008	$	25,663	$	24,816
Oilfield services		194		544		256		1,896
Total revenues		8,228		9,552		25,919		26,712

Operating costs and expenses:
Lease operating expenses		932		862		2,650		2,605
Exploration costs		7,158		10,923		17,355		15,874
Property impairments		--		2,000		5,633		2,000
Loss sale of assets		--		--		--		49
Oilfield services costs		164		387		412		1,481
Depreciation, depletion, and amortization		1,125		1,006		3,562		2,796
Accretion expense		22		16		67		46
Stock compensation		701		557		2,083		1,659
General and administrative		1,847		1,788		6,451		6,042
Total operating costs and expenses		11,949		17,539		38,213		32,552

Operating loss		(3,721)		(7,987)		(12,294)		(5,840)

Other income (expense):
Interest expense		(1,346)		(602)		(2,600)		(1,862)
Interest and other income		17		88		324		259
Foreign exchange gain (loss)		11,512		10,490		(1,041)		11,996
Total other income (expense)		10,183		9,976		(3,317)		10,393

Net income (loss)		6,462		1,989		(15,611)		4,553

Other comprehensive income (loss)
Foreign currency translation adjustment		(7,660)		(6,822)		605		(8,177)
Comprehensive loss	$	(1,198)	$	(4,833)	$	(15,006)	$	(3,624)

Net income (loss) per common share
Basic	$	0.12	$	0.04	$	(0.30)	$	0.09
Diluted	$	0.12	$	0.04	$	(0.30)	$	0.09
Weighted average common shares outstanding
Basic		52,778		52,255		52,748		52,244
Dilutive effect of stock options		958		391		-		329
Diluted		53,736		52,646		52,748		52,573

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,
	2013		2012
Cash flows from operating activities:
Net income (loss)	$	(15,611)	$	4,553
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization		3,562		2,796
Accretion expense		67		46
Amortization of loan fees		1,055		374
Stock compensation		2,083		1,659
Property impairments		5,633		6,532
Loss on sale of assets		--		49
Unrealized foreign exchange losses (gains)		1,014		(11,993)
Common stock issued for services		694		669
Increase (decrease) from changes in working capital items:
Receivables		6,595		2,350
Inventory		(7)		2
Other current assets		295		(306)
Other assets		(25)		24
Accounts payable and accrued liabilities		(2,483)		(924)
Net cash provided by operating activities		2,872		5,831

Cash flows from investing activities:
Additions to oil and gas properties		(16,656)		(11,836)
Additions to other property and equipment		(869)		(464)
Proceeds from sale of assets		--		221
Net cash used in investing activities		(17,525)		(12,079)

Cash flows from financing activities:
Repayment of credit facility		(40,000)		--
Draws from credit facility		42,000		--
Payment of loan fees		(2,036)		--
Net cash used in financing activities		(36)		--

Effect of exchange-rate changes on cash		(119)		569

Net decrease in cash		(14,808)		(5,679)
Cash and cash equivalents at beginning of year		33,990		50,859

Cash and cash equivalents at end of period	$	19,182	$	45,180

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,” and “our” 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, 2012, and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2013.

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-month periods ended September 30, 2013 and 2012, and the nine-month period ended September 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 nine-month period ended September 30, 2013, no options were included in the computation of diluted earnings per share for those periods because the effect would have been antidilutive.

Outstanding options and unvested restricted stock as of September 30, 2013 and 2012, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
September 30, 2013	1,808,589	$0.00 - $5.06
September 30, 2012	1,321,041	$0.00 - $5.06

Note 3: Income Taxes

No income tax expense was recognized for the nine-month period ended September 30, 2013, 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, 2012. 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, 2013.

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, 2013, the nine months ended September 30, 2013, and as of September 30, 2013, is as follows (in thousands):

	Reportable Segments
	Exploration & Production				Oilfield Services		Non-Segmented		Total
	U.S.		Poland
Three months ended September 30, 2013:
Revenues	$	1,111	$	6,923	$	194	$	--	$	8,228
Net income (loss)		304		(1,260)		(207)		7,625(1)		6,462
Nine months ended September 30, 2013:
Revenues	$	2,963	$	22,700	$	256	$	--	$	25,919
Net income (loss)		921		(3,583)		(870)		(12,079)(1)		(15,611)
As of September 30, 2013:
Identifiable net property and equipment	$	2,624	$	58,701	$	2,616	$	32	$	63,973

_______________

(1)

Nonsegmented reconciling items for the third quarter 2013 include $1,847 of G&A costs, $701 of noncash stock compensation expense, $1,329 of other expense, $10 of corporate DD&A costs, and $11,512 of foreign exchange gains. Nonsegmented reconciling items for the first nine months include $6,451 of G&A costs, $2,083 of noncash stock compensation expense, $2,480 of other expense, $25 of corporate DD&A costs, and $1,040 of foreign exchange losses.

Reportable business segment information for the three months ended September 30, 2012, the nine months ended September 30, 2012, and as of September 30, 2012, is as follows (in thousands):

	Reportable Segments
	Exploration & Production				Oilfield Services		Non-Segmented		Total
	U.S.		Poland
Three months ended September 30, 2012:
Revenues	$	1,014	$	7,994	$	544	$	--	$	9,552
Net income (loss)		(974)		(4,543)		(117)		7,623(1)		1,989
Nine months ended September 30, 2012:
Revenues	$	3,137	$	21,679	$	1,896	$	--	$	26,712
Net income (loss)		(183)		2,484		(418)		2,670(1)		4,553
As of September 30, 2012:
Identifiable net property and equipment	$	2,260	$	46,327	$	2,515	$	55	$	51,157

_______________

(1)

Nonsegmented reconciling items for the third quarter 2012 include $1,788 of G&A costs, $557 of noncash stock compensation expense, $514 of other expense, $8 of corporate DD&A costs, and $10,490 of foreign exchange gains. Nonsegmented reconciling items for the first nine months include $6,042 of G&A costs, $1,659 of noncash stock compensation expense, $1,603 of other expense, $22 of corporate DD&A costs, and $11,996 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 nine months of 2013:

		Weighted	Weighted Average
		Average	Remaining	Aggregate
	Number of	Exercise	Contractual	Intrinsic
	Options	Price	Life (in years)	Value
Options outstanding:
Beginning of year	1,275,299	$4.65
Forfeited	(10,583)	4.46
End of period	1,264,716	4.65	8.55
Exercisable at end of period	421,205	5.06	7.97	$0

The following table summarizes option activity for the first nine 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	8.97
Exercisable at end of period	211,043	5.06	8.97	$504,393

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $3.43 as of September 30, 2013, and $7.45 as of September 30, 2012, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.

Restricted Stock

The following table summarizes restricted stock activity during the first nine months of 2013 and 2012:

	Number of Shares
	2013	2012
Unvested restricted stock outstanding:
Beginning of year	655,099	687,912
Vested	(105,069)	(105,538)
Forfeited	(6,157)	--
End of period	543,873	582,374

Stock Compensation

There were no stock options issued during the first nine months of 2013. During 2012, we issued 642,170 stock options, resulting in deferred compensation of $1.4 million, which will be amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2013 totaled $353,000.

There were no shares of restricted stock issued during the first nine months of 2013. During 2012, we issued 321,086 shares of restricted stock, resulting in deferred compensation of $1.4 million, which will be amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2013 totaled $339,000.

During 2011, we issued 636,509 stock options, resulting in deferred compensation of $1.8 million, which is being amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2013 and 2012 totaled $440,000 and $442,000, respectively.

During 2011, we issued 318,252 shares of restricted stock, resulting in deferred compensation of $1.6 million, which will be amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2013 and 2012 totaled $397,000 and $400,000, respectively.

During 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2.3 million, which will be amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2013 and 2012 totaled $554,000 and $559,000, respectively.

During 2009, we issued 379,500 shares of restricted stock, resulting in unamortized compensation expense of $1.0 million, which will be amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2013 and 2012 totaled $0 and $258,000, respectively.

Note 6: Stockholders’ Equity

We have a Stock Bonus Plan covering all of our employees under section 401(k) of the Internal Revenue Code. We have made discretionary contributions of 162,402 and 138,748 shares of our stock to employees under this Plan and have recorded $667,000 and $666,000 of expenses associated with these contributions for the nine-month periods ended September 30, 2013 and 2012, respectively.

Note 7: Fair Value Measurements

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

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

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

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

A review of fair value hierarchy classifications is conducted on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We did not have any significant nonfinancial assets or nonfinancial liabilities that would be recognized or disclosed at fair value on a recurring basis as of September 30, 2013, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first nine months of 2013.

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, 2013 (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	$279	$279	--	--

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 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	$1,926	$1,926	--	--

Note 8: Notes Payable

On July 8, 2013, we finalized a new, five-year, up to $100 Million Senior Reserve Based Lending Facility with BNP Paribas (Suisse) SA and ING Bank N.V. The initial commitment of the facility amounts to $65 million. We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism. Initial proceeds from the new facility were used to repay our previously existing facility. Payment of the credit facility is secured by our assets in Poland and guaranteed by us.

In consideration of the new credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.0 million. These fees, along with approximately $385,000 associated with our previous facility, have been capitalized as loan fees and will be amortized over the five-year term of the loan, beginning in the third quarter of 2013. By virtue of the refinance, we charged approximately $677,000 in unamortized loan fees associated with our previous facility to interest expense during the third quarter of 2013.

The credit facility calls for a periodic interest rate of LIBOR, plus an interest margin of 3.75%, and has a term of five years, with semiannual borrowing base reductions beginning on June 30, 2016. An unused commitment fee of 40% of the applicable interest margin is charged monthly based on the average daily unused portion of the new credit facility. There are no financial covenants associated with the new credit facility. As of September 30, 2013, the total amount drawn under the credit facility was $42 million, and the interest rate was 3.93% per annum.

Our previous facility was a $55 million reserve-based agreement with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV. The previous facility called for a periodic interest rate of LIBOR, plus an interest margin of 4.0%, and had a term of five years, with semiannual borrowing base reductions of $11 million each beginning on June 30, 2013. Accordingly, our borrowing base was reduced to $44 million on that date. Loan fees of approximately $257,000 associated with our existing credit facility were amortized and charged to interest expense during the first half of 2013.

Our notes payable is stated at book value, which approximated its fair value at September 30, 2013. 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 Standard Board’s fair value hierarchy.

Note 9: Capitalized Exploratory Well Costs

We had $8.7 million and $5.0 million of capitalized costs related to our Tuchola-3K and Frankowo wells, respectively, which were being evaluated for future reserve potential at September 30, 2013. In addition, we had $473,000 and $1.4 million of capitalized costs associated with our Lisewo-2 and Gorka-Duchowna-1 wells, respectively, which we were drilling at September 30, 3013.

Note 10: Foreign Currency Translation and Risk

During the first nine months of 2013, we recorded foreign currency transaction losses of approximately $1.0 million. This amount was attributable to increases 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 credit 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 Nine Months
	Ended September 30, 2013
Balance at December 31, 2012	$	18,027
Increase related to losses on intercompany loans		1,014
Decrease related to translation adjustments		(409)
Balance at September 30, 2013	$	18,632

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. Our operations in Poland, which are a combination of existing production and substantial exploration, have grown considerably. Oil and gas production, oil and gas revenues, oil and gas reserves, and oil and gas expenditures in this area have grown significantly over the last three years.

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

Results of Operations by Business Segment

Quarter Ended September 30, 2013, Compared to the Same Period of 2012

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $6.9 million during the third quarter of 2013, compared to $8.0 million during the same quarter of 2012. Lower production in the 2013 quarter led to the decrease 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 September 30, 2013 and 2012, is set forth in the following table:

	For the Quarter Ended September 30,
	2013	2012	Change
Gas revenues	$6,923,000	$7,994,000	-13%
Average price (per thousand cubic feet)	$7.02	$7.05	-0%
Production volumes (thousand cubic feet)	986,000	1,135,000	-13%

Daily gas production decreased to 10.7 million cubic feet of natural gas per day, or MMcfd, in the third quarter of 2013, compared to 12.3 MMcfd in the third quarter of 2012, a decrease of 13%. Production from our Zaniemysl and Roszkow wells decreased by 243,000 thousand cubic feet of natural gas, or Mcf, over 2012 third quarter levels, due to normal production declines. New production at our Winna Gora well of 96,000 Mcf partially offset the production declines at our other wells.

Natural gas prices were essentially unchanged during the 2013 quarter. The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 3% lower during the third quarter of 2013 than the same quarter of 2012, due to a tariff decrease that became effective for us on January 1, 2013. However, mild period-to-period weakness in the U.S. dollar against the Polish zloty increased our U.S. dollar-denominated gas prices. The average exchange rate during the third quarter of 2013 was 3.21 zlotys per U.S. dollar. The average exchange rate during the third quarter of 2012 was 3.31 zlotys per U.S. dollar, also a change of approximately 3%.

During the third quarter of 2013, our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells were shut in for two weeks for annual maintenance and pressure testing. Production at our Lisewo-1 well is expected to begin in November 2013.

Oil Revenues. Oil revenues were $1.1 million for the third quarter of 2013, a 10% increase from $1.0 million recognized during the third quarter of 2012. Production levels decreased, due to normal production declines, by approximately 8% from 2012 to 2013. The decrease in production was offset by higher prices received during the third quarter of 2013. Our average oil price during the third quarter of 2013 was $88.14 per barrel, a 19% increase from $74.30 per barrel received during the same quarter of 2012.

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, 2013 and 2012, is set forth in the following table:

	For the Quarter Ended September 30,
	2013	2012	Change
Oil revenues	$1,111,000	$1,014,000	+10%
Average price (per barrel)	$88.14	$74.30	+19%
Production volumes (barrels)	12,600	13,700	-8%

Lease Operating Costs. Lease operating costs of $932,000 during the third quarter of 2013 were 8% higher than the third quarter of 2012 amount of $862,000. Poland operating costs increased approximately 9% from quarter to quarter, with the bulk of the increase attributable to new production at Winna Gora. In addition, operating costs and production taxes in the U.S. increased by approximately 7% from 2012 to 2013, due to higher production taxes and workover costs. The net effect of these changes was an increase in total operating costs of $70,000 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 $7.2 million during the third quarter of 2013, compared to $10.9 million during the same period of 2012.

Third quarter of 2013 exploration costs included approximately $5.3 million associated with three-dimensional, or 3-D, seismic surveys at both our Fences area and our 100%-owned concessions in Poland, $478,000 associated with new two-dimensional, or 2-D, seismic surveys and other costs at our other project areas in Poland, and $1.4 million of dry-hole costs associated primarily with the unsuccessful fracture stimulation of our Plawce-2 well. Third quarter 2012 exploration costs included our share of dry-hole costs at the Kutno-2 well incurred through September 30, 2012, of approximately $9.0 million. In addition, the remaining third quarter 2012 geological and geophysical costs were primarily associated with 2-D seismic surveys on our 100%-owned acreage in Poland.

Property Impairment. There were no property impairments during the third quarter of 2013. Third quarter 2012 property impairment costs totaled $2.0 million. In the United States, we impaired all of the drilling costs associated with our Montana Bakken project, totaling approximately $1.3 million. In addition, in Poland, we impaired the costs of our Kutno concessions and certain of our Warsaw South concessions that either expired during the quarter or were deemed to be non-prospective for hydrocarbon potential. The impairments in Poland totaled approximately $700,000.

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $878,000 for the third quarter of 2013, an increase of 21% compared to $725,000 during the same period of 2012. Higher DD&A expense in 2013 was due to increased depreciation expense at our KSK and Winna Gora wells, reflecting higher and new production in 2013.

Accretion Expense. Accretion expense was $22,000 and $16,000 for the third quarter of 2013 and 2012, 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 $0.2 million during the third quarter of 2013, a decrease of 60% compared to $0.5 million for the third quarter of 2012. During the third quarter of 2013, we drilled one well for third parties, along with additional well service work. During the third quarter of 2012, we drilled two wells for third parties, 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 own properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $0.2 million during the third quarter of 2013, compared to $0.4 million during the same period of 2012. 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 own properties, and other factors.

DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $237,000 during the third quarter of 2013, compared to $273,000 during the same period of 2012. The quarter-to-quarter decrease was primarily due to prior-year capital additions becoming fully depreciated during 2012.

Nonsegmented Information

G&A Costs. G&A costs were $1.8 million during the third quarter of 2013, compared to $1.8 million during the third quarter of 2012.

Stock Compensation (G&A). For the three-month periods ended September 30, 2013 and 2012, we recognized $701,000 and $557,000, respectively, of stock compensation expense related to the amortization of deferred compensation related to stock option and restricted stock grants.

Interest and Other Income (Expense). During the third quarter of 2013, we incurred $1.4 million in interest expense. We recorded $797,000 of amortization of loan fees, including $677,000 related to our prior credit facility that was charged to interest expense by virtue of our refinance, and $72,000 in unused commitment fees during the quarter. During the third quarter of 2012, we incurred $602,000 in interest expense, which included $124,000 of amortization of loan fees and $104,000 in unused commitment fees.

Foreign Exchange Gain. During the third quarter of 2013, we recorded foreign currency transaction gains of approximately $11.5 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans. We recorded foreign exchange gains of $10.5 million during the same quarter of 2012, which were also principally related to our intercompany loans. During the third quarter of 2013 and 2012, the zloty strengthened by approximately 6% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.

Nine Months Ended September 30, 2013, Compared to the Same Period of 2012

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $22.7 million during the first nine months of 2013, compared to $21.7 million during the same period of 2012.

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, 2013 and 2012, is set forth in the following table:

	For the Nine Months Ended September 30,
	2013	2012	Change
Revenues	$22,700,000	$21,679,000	+5%
Average price (per thousand cubic feet)	$7.06	$6.64	+6%
Production volumes (thousand cubic feet)	3,213,000	3,265,000	-2%

Daily gas production for the first nine months of 2013 was 11.8 MMcfd, compared to 11.9 MMcfd during the same period of 2012. Production from our KSK wells increased by 471,000 Mcf over 2012 nine-month levels. Production from our Winna Gora well added another 219,000 Mcf during 2013. These increases mostly offset normal production declines at our Zaniemysl-3 and Roszkow wells.

We recognized a 6% increase in natural gas prices period over period. The Polish low-methane tariff was 2% higher during the first nine months of 2013, compared to the same period of 2012. However, period-to-period weakness in the U.S. dollar against the Polish zloty increased our U.S. dollar-denominated gas prices. The average exchange rate during the first nine months of 2013 was 3.19 zlotys per U.S. dollar. The average exchange rate during the first nine months of 2012 was 3.29 zlotys per U.S. dollar, a change of approximately 3%. In addition, production declines at Zaniemysl-3 were replaced by production gains at both KSK and Winna Gora, where our average price per Mcf is approximately 20% higher than at Zaniemysl-3.

During the third quarter of 2013, our KSK wells were shut in for two weeks for annual maintenance and pressure testing. Production at our Lisewo-1 well is expected to begin in November, 2013.

Oil Revenues. Oil revenues were $3.0 million for the first nine months of 2013, a 6% decrease from the $3.1 million recognized during the first nine months of 2012. Production from our U.S. properties declined 10% during the first nine months of 2013 due to regular production declines. The decline in production was partially offset by higher prices received during the first nine months of 2013. Our average oil price during the first nine months of 2013 was $80.75 per barrel, a 4% increase from $77.32 per barrel received during the same period of 2012.

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, 2013 and 2012, is set forth in the following table:

	For the Nine Months Ended September 30,
	2013	2012	Change
Revenues	$2,963,000	$3,137,000	-6%
Average price (per barrel)	$80.75	$77.32	+4%
Production volumes (barrels)	36,700	40,600	-10%

Lease Operating Costs. Lease operating costs were $2.7 million during the first nine months of 2013, an increase of 2% compared to the same period of 2012. Poland operating costs increased approximately 10% from year to year, with the bulk of the increase attributable to new production at Winna Gora. Conversely, operating costs and production taxes in the U.S. declined by approximately 2% from 2012 to 2013, due to lower production taxes and workover costs. The net effect of these changes was an increase in total operating costs of $45,000 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 $17.4 million during the first nine months of 2013, compared to $15.9 million during the same period of 2012.

Our 2013 exploration costs included approximately $6.6 million of dry-hole costs, including approximately $3.8 million associated with our Mieczewo well, which was plugged at the end of the first quarter of the year, and approximately $2.4 million associated with the unsuccessful fracture stimulation of our Plawce-2 well. In addition, we spent approximately $9.0 million associated with 3-D seismic surveys at both our Fences area and our 100%-owned concessions in Poland, and $1.7 million associated with new 2-D seismic surveys and other costs at our other project areas in Poland. Nine-month 2012 exploration costs included our share of dry-hole costs at the Kutno-2 well incurred through September 30, 2012, of approximately $9.0 million. In addition, the remaining 2012 exploration costs included approximately $560,000 associated with our Lisewo southeast 3-D seismic survey in our Fences concession, $5.8 million associated with 2-D seismic projects at our other existing Polish concessions, and approximately $485,000 in dry-hole costs associated with a Bakken test well in Montana.

Property Impairment. During the first nine months of 2013, we recorded property impairment costs of $5.6 million. We impaired approximately $4.6 million of prior-year costs associated with our Plawce-2 well following its unsuccessful fracture stimulation, along with approximately $200,000 of prior-year costs associated with our Mieczewo well. In addition, our Zaniemysl-3 well ceased production during 2013, causing us to charge its remaining net book value of $366,000 to impairment expense. Finally, we recorded an impairment charge of $474,000 related to concession costs in our Northwest project area, where we have made the determination to cease all exploration efforts. Our first nine months of 2012 property impairment costs totaled $2.0 million. In the United States, we impaired all of the capitalized drilling costs associated with our Montana Bakken project, totaling approximately $1.3 million. In addition, in Poland, we impaired the costs of our Kutno concessions and certain of our Warsaw South concessions that either expired during 2012 or were deemed to be non-prospective for hydrocarbon potential. The impairments in Poland totaled approximately $700,000.

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $2.8 million for the first nine months of 2013, an increase of 46% compared to $1.9 million during the same period of 2012. Higher DD&A expense in 2013 was due to increased depreciation expense at our KSK and Winna Gora wells, reflecting higher and new production in 2013.

Accretion Expense. Accretion expense was $67,000 and $46,000 for the first nine months of 2013 and 2012, respectively. Accretion expense is related entirely to our asset retirement obligation.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $0.3 million during the first nine months of 2013, compared to $1.9 million for the first nine months of 2012. We drilled one well for third parties during the first nine months of 2013, along with additional well service work. We drilled seven wells for third parties, including one drilled for our Alberta Bakken joint venture, during the first nine months of 2012, 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 own properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $0.4 million during the first nine months of 2013, compared to $1.5 million during the same period of 2012. 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 own properties, and other factors.

DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $714,000 during the first nine months of 2013, compared to $834,000 during the same period of 2012. The year-to-year decrease was primarily due to prior-year capital additions becoming fully depreciated during 2012.

Nonsegmented Information

G&A Costs. G&A costs were $6.5 million during the first nine months of 2013, compared to $6.0 million during the first nine months of 2012, an increase of $409,000. The increase is primarily due to higher compensation costs, including the payment of a company-wide incentive award of approximately $500,000 related to 2008, which had been deferred until we met certain performance benchmarks, which were met in 2013.

Stock Compensation (G&A). For the nine-month periods ended September 30, 2013 and 2012, we recognized $2.1 million and $1.7 million, respectively, of stock compensation expense related to the amortization of deferred compensation related to stock option and restricted stock grants.

Interest and Other Income (Expense). During the first nine months of 2013, we incurred $2.6 million in interest expense. We recorded $1.1 million of amortization of loan fees, including $677,000 related to our prior credit facility that was charged to interest expense by virtue of our refinance, and $226,000 in unused commitment fees. During the first nine months of 2012, we incurred $1.9 million in interest expense. We recorded $374,000 of amortization of loan fees and $256,000 in unused commitment fees.

Foreign Exchange Gain (Loss). As discussed in Note 10 to the financial statements, during the first nine months of 2013, we recorded foreign currency transaction losses of approximately $1.0 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. During the first nine months of 2013, the zloty weakened by approximately 1% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses. Foreign currency transaction gains during the first nine months of 2012 were $12.0 million. During the first nine months of 2012, the zloty strengthened by approximately 7% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction gains.

Liquidity and Capital Resources

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

2013 Liquidity and Capital

Working Capital (current assets less current liabilities). Our working capital was $19.4 million as of September 30, 2013, down $11.0 million from December 31, 2012. Our current assets at September 30, 2013, included approximately $3.1 million in accrued oil and gas sales from both the United States and Poland. Our current liabilities at September 30, 2013, included approximately $4.3 million in costs related to capital and exploration projects in Poland. Our total outstanding long-term debt at September 30, 2013, was $42.0 million. Our cash and cash equivalents at September 30, 2013, totaled $19.2 million, $17.0 million of which was held in Poland at ING Bank N.V. We have not historically repatriated any cash held in Poland to the United States nor do we plan to do so in the foreseeable future. Consequently, there will be no repatriation taxes incurred.

Operating Activities. Net cash provided by operating activities was $2.9 million during the first nine months of 2013, down 51% from the $5.8 million during the first nine months of 2012. The 2013 decrease was due primarily to higher exploration expenses and a reduction of current liabilities.

Investing Activities. During the first nine months of 2013, we used cash of $17.5 million in investing activities. We used $16.7 million for capital additions at our producing properties and $869,000 for capital additions in our office and drilling equipment. During the first nine months of 2012, we used cash of $12.1 million in investing activities. We used $11.8 million for capital additions in Poland and $464,000 for capital additions in our office and drilling equipment, offset by $221,000 in proceeds from the sale of assets.

Financing Activities. During the first nine months of 2013, we paid $2.0 million in fees for our new credit facility that closed in July of this year. We used proceeds of $42.0 million from our new facility to repay the prior facility, as well as to pay for the new facility fees. These fees have been capitalized as loan fees and are being amortized over the life of the new facility, beginning in the third quarter of 2013. There were no financing transactions during the first nine months of 2012.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2013 include our working capital of $19.4 million at September 30, 2013, available credit under our expanded credit facility, and cash available from future operations.

In consideration of the new credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.0 million. These fees, along with approximately $400,000 associated with our previous facility, have been capitalized as loan fees and will be amortized over the five-year term of the loan, beginning in the third quarter of 2013. By virtue of the refinance, we charged approximately $677,000 in unamortized loan fees associated with our existing facility to interest expense during the third quarter of 2013.

We expect that our 2013 production will be slightly lower than our 2012 production with the addition of production at our Winna Gora-1 and Lisewo-1 wells, as well as full production from our KSK wells, which mostly offset production declines at some of our older wells. Production began at Winna Gora-1 in late January of 2013. Production is expected to begin at Lisewo-1 during November 2013 and at Komorze-3K in early 2014. We have contracts in place that call for us to receive 86% of the published low-methane tariff, adjusted for energy content, for the Winna Gora-1 and Lisewo-1 wells, and expect to receive similar pricing for the Komorze-3K well. The amount of revenue from this new production will depend on applicable gas sales prices and prevailing currency exchange rates.

We have an effective Securities Act universal shelf registration statement under which we may sell up to $200 million of equity or debt securities of various kinds. In June 2012, we entered into an agreement to possibly sell up to $50 million in common stock during the next two years in at-the-market transactions. Through the date of this filing, we have not sold any stock under that agreement. Assuming all $50 million of common stock covered by the at-the-market facility were sold, the remaining $150 million balance of securities available for sale under the registration statement is available for sale at any time, subject to market conditions and our ability to access the capital markets, to further finance our exploration and development plans in Poland and for other corporate purposes.

At September 30, 2013, we were in the process of building pipelines and production facilities at our Lisewo and Komorze-3K wells and were drilling the Lisewo-2 well in the Fences area and the Gorka-Duchowna well in Block 246. On October 5, 2013, we began drilling the Szymanowice-1 well, also in the Fences area. In addition, we had various seismic projects underway at September 30, 2013. We had no other firm commitments for future capital and exploration costs at September 30, 2013.

We expect our primary use of cash for 2013 will be for our exploration and development activities in Poland. Our board of directors has approved projects whose costs are expected to range from $60 million to $70 million for production facilities for existing discoveries, exploration and development wells, and 2-D and 3-D seismic data acquisition and analysis, including those items noted above. All of the approved projects may not be completed during 2013, but we do expect to start work on all of them during 2013.

The actual amount of our expenditures will depend on ongoing exploration results; the pace at which Polskie Górnictwo Naftowe i Gazownictwo S.A., or 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 various sources of liquidity and capital outlined above should more than enable us to meet our capital needs in Poland and the United States for the next 12 months. We have the ability to control the timing and amount of most of our future capital and exploration costs.

We may continue to 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 September 30, 2013, we have incurred cumulative net losses of approximately $201 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 as we seek to increase reserves, 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.

We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements, such as those negotiated in prior years for our Kutno and Warsaw South project areas, in which industry participants are bearing agreed exploration costs to earn an interest in the project or other arrangements, all of which may dilute the interest of our existing stockholders or our interest in the specific project financed.

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

New Accounting Pronouncements

We have reviewed all other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position, and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.

Critical Accounting Policies

A summary of our significant accounting policies is included in Note 1 of our Consolidated Financial Statements contained in our annual report on Form 10-K for the year ended December 31, 2012. 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 GAAP 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

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-3, KSK, Winna Gora, and Lisewo 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.

Realized pricing for our oil production in the United States 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.

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 September 30, 2013, we had no outstanding zloty forward-purchase contracts.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2013, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2013, 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, 2012. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2012, 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 10	Material Contracts
10.108	Up to USD 100,000,000 Senior Reserve Base Lending Facility Agreement among FX Energy Poland Sp. z o.o., FX Energy, Inc., FX Energy Netherlands Partnership C.V., FX Energy Netherlands B.V., BNP Paribas (Suisse) SA and ING Bank N.V. dated July 3, 2013	Incorporated by reference from the current report on Form 8-K filed July 17, 2013.

10.109	Intercreditor Deed among FX Energy Poland Sp. z o.o, BNP Paribas (Suisse) SA, ING Bank N.V., BNP Paribas SA, and the subordinated lenders dated July 3, 2013	Incorporated by reference from the current report on Form 8-K filed July 17, 2013.

10.110	Deed of Pledge of Registered Shares among Frontier Exploration Company and FX Drilling Company, Inc., in their capacity of general partners of FX Energy Netherlands Partnership C.V.; BNP Paribas (Suisse) SA; and FX Energy Netherlands B.V., dated July 5, 2013	Incorporated by reference from the current report on Form 8-K filed July 17, 2013.

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

Item 101	Interactive Data File
101	Interactive Data File	Attached

_______________

*	All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601 and the number following the decimal indicating the sequence of the particular document. Omitted numbers in the sequence refer to documents previously filed as an exhibit.

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 7, 2013	By:	/s/ David N. Pierce
		David N. Pierce, President, Chief Executive Officer


Date: November 7, 2013	By:	/s/ Clay Newton
		Clay Newton, Principal Financial and Principal Accounting Officer

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