FX ENERGY INC - FORM 10-Q - August 11, 2014

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - FX ENERGY INC	Financial_Report.xls
EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3101q063014.htm
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	ex3202q063014.htm
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3102q063014.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	ex3201q063014.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, 2014

¨	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. 001-35012

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. As of August 4, 2014, there were 54,076,416 and 800,000 shares outstanding of $0.001 par value common stock and 9.25% cumulative convertible preferred stock, respectively.

FX ENERGY, INC., AND SUBSIDIARIES

Form 10-Q for the Three Months Ended June 30, 2014

TABLE OF CONTENTS

Item		Page
	Part I—Financial Information

1	Financial Statements
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations and Comprehensive Income	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	15
3	Quantitative and Qualitative Disclosures about Market Risk	25
4	Controls and Procedures	26

	Part II—Other Information

1A	Risk Factors	27
6	Exhibits	27
--	Signatures	28

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	June 30,		December 31,
	2014		2013
ASSETS

Current assets:
Cash and cash equivalents	$	6,754	$	11,153
Receivables:
Accrued oil and gas sales		5,070		3,464
Joint interest and other receivables		2,580		5,029
VAT receivable		554		1,847
Inventory		99		100
Other current assets		283		234
Total current assets		15,340		21,827

Property and equipment, at cost:
Oil and gas properties (successful-efforts method):
Proved		91,455		85,244
Unproved		2,517		2,404
Other property and equipment		12,331		11,857
Gross property and equipment		106,303		99,505
Less accumulated depreciation, depletion, and amortization		(25,794)		(23,369)
Net property and equipment		80,509		76,136

Other assets:
Certificates of deposit		406		406
Loan fees		2,041		2,323
Total other assets		2,447		2,729

Total assets	$	98,296	$	100,692

-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,
	2014		2013
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	4,437	$	9,694
Accrued liabilities		463		833
Total current liabilities		4,900		10,527

Long-term liabilities:
Notes payable		50,000		45,000
Asset retirement obligation		1,740		1,620
Total long-term liabilities		51,740		46,620

Total liabilities		56,640		57,147

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized
as of June 30, 2014, and December 31, 2013; no shares
outstanding		--		--
Common stock, $0.001 par value, 100,000,000 shares authorized
as of June 30, 2014, and December 31, 2013; 54,076,416
and 53,733,398 shares issued and outstanding as of
June 30, 2014, and December 31, 2013, respectively		54		54
Additional paid-in capital		228,697		226,060
Cumulative translation adjustment		15,988		15,025
Accumulated deficit		(203,083)		(197,594)
Total stockholders’ equity		41,656		43,545

Total liabilities and stockholders’ equity	$	98,296	$	100,692

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

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income

(Unaudited)

(in thousands, except per-share amounts)

	For th three months ended June 30,				For the six months ended June 30,
	2014		2013		2014		2013
Revenues:
Oil and gas sales	$	8,802	$	8,183	$	18,310	$	17,629
Oilfield services		1,361		20		1,366		62
Total revenues		10,163		8,203		19,676		17,691

Operating costs and expenses:
Lease operating expenses		1,181		843		2,290		1,718
Exploration costs		3,591		4,034		6,911		10,198
Property impairments		3,689		5,426		3,735		5,633
Oilfield services costs		917		116		1,045		248
Depreciation, depletion and amortization		1,237		1,121		2,595		2,437
Accretion expense		23		22		47		45
Stock compensation		687		693		1,366		1,382
General and administrative		1,972		2,780		3,925		4,604
Total operating costs and expenses		13,297		15,035		21,914		26,265

Operating loss		(3,134)		(6,832)		(2,238)		(8,574)

Other expense:
Interest expense		(685)		(626)		(1,341)		(1,254)
Interest and other income		12		256		26		308
Foreign exchange loss		(720)		(3,427)		(1,936)		(12,552)
Total other expense		(1,393)		(3,797)		(3,251)		(13,498)

Net loss		(4,527)		(10,629)		(5,489)		(22,072)

Other comprehensive income
Foreign currency translation adjustment		357		2,389		963		8,265
Comprehensive loss	$	(4,170)	$	(8,240)	$	(4,526)	$	(13,807)

Net loss per common share
Basic	$	(0.08)	$	(0.20)	$	(0.10)	$	(0.42)
Diluted	$	(0.08)	$	(0.20)	$	(0.10)	$	(0.42)
Weighted average common shares outstanding
Basic		53,325		52,757		53,279		52,731
Dilutive effect of stock options		-		-		-		-
Diluted		53,325		52,757		53,279		52,731

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,
	2014		2013
Cash flows from operating activities:
Net loss	$	(5,489)	$	(22,072)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		2,595		2,437
Accretion expense		47		45
Amortization of loan fees		255		258
Stock compensation		1,366		1,382
Property impairments		3,694		5,633
Unrealized foreign exchange losses		1,929		12,519
Common stock issued for services		656		694
Increase (decrease) from changes in working capital items:
Receivables		2,010		6,226
Inventory		1		(1)
Other current assets		(49)		52
Accounts payable and accrued liabilities		(3,304)		(2,929)
Net cash provided by operating activities		3,711		4,244

Cash flows from investing activities:
Additions to oil and gas properties		(13,091)		(13,067)
Additions to other property and equipment		(522)		(484)
Net cash used in investing activities		(13,613)		(13,551)

Cash flows from financing activities:
Proceeds from stock offering		615		--
Payment of loan fees		--		(53)
Proceeds from notes payable		5,000		--
Net cash provided by (used in) financing activities		5,615		(53)

Effect of exchange-rate changes on cash		(112)		(504)

Net decrease in cash		(4,399)		(9,864)
Cash and cash equivalents at beginning of year		11,153		33,990

Cash and cash equivalents at end of period	$	6,754	$	24,126

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 all adjustments, which are of a normal recurring nature, necessary for presentation of financial statements for interim periods in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions to Form 10-Q in Article 10 of SEC Regulation S-X. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates. As used in this report, the terms “we,” “us,” “our,” and the “Company” mean FX Energy, Inc., and its subsidiaries, unless the context indicates otherwise.

We condensed or omitted certain information and footnote disclosures normally included in our annual audited financial statements, which we prepared in accordance with GAAP. Our quarterly financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2013, and our Form 10-Q for the quarter ended March 31, 2014.

Note 2: Net Income per Share

Basic earnings per share is computed by dividing the net income applicable to common shares by the weighted average number of common shares outstanding. We recorded a net loss for each of the three- and six-month periods ended June 30, 2014 and 2013, so there are no diluted earnings per share calculated for those periods. Basic and diluted earnings per share were essentially the same for all periods presented.

Outstanding options and unvested restricted stock as of June 30, 2014 and 2013, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
June 30, 2014	2,550,125	$0.00 - $5.06
June 30, 2013	1,921,095	$0.00 - $5.06

Note 3: Income Taxes

No income tax expense was recognized for the three- and six-month periods ended June 30, 2014 and 2013, due to net losses being incurred in both periods. We are subject to audit by the IRS and various states for the prior three years. There has not been a change in our unrecognized tax positions since December 31, 2013, and we do not believe there will be any material changes in our unrecognized tax positions over the next 12 months. 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, and no interest expense related to unrecognized tax benefits was recognized during the six months ended June 30, 2014.

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, 2014, the six months ended June 30, 2014, and as of June 30, 2014, is as follows (in thousands):

	Reportable Segments
	Exploration &		Oilfield
	Production		Services	Nonsegmented		Total
	U.S.	Poland
Three months ended June 30, 2014:
Revenues	$1,003	$ 7,799	$1,361	$ --		$10,163
Net income (loss)(1)	260	(916)	196	(4,067	)	(4,527)
Six months ended June 30, 2014:
Revenues	$1,923	$16,387	$1,366	$ --		$19,676
Net income (loss)	371	2,879	(170)	(8,569	)(1)	(5,489)
As of June 30, 2014:
Identifiable net property and equipment	$2,778	$75,079	$2,636	$ 16		$80,509

_______________

(1)

Nonsegmented reconciling items for the second quarter include $1,972 of G&A, $687 of noncash stock compensation expense, $12 of other income, $685 of interest expense, $720 of foreign exchange losses, and $15 of corporate DD&A. Nonsegmented reconciling items for the first six months include $3,925 of G&A costs, $1,366 of noncash stock compensation expense, $27 of other income, $1,341 of interest expense, $26 of corporate DD&A costs, and $1,936 of foreign exchange losses.

Reportable business segment information for the three months ended June 30, 2013, the six months ended June 30, 2013, and as of June 30, 2013, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented		Total
	U.S.	Poland
Three months ended June 30, 2013:
Revenues	$ 952	$ 7,231	$ 20	$ --		$ 8,203
Net income (loss)	317	(3,131)	(334)	(7,481	)(1)	(10,629)
Six months ended June 30, 2013:
Revenues	$1,852	$15,777	$ 62	$ --		$ 17,691
Net income (loss)	617	(2,323)	(662)	(19,704	)(1)	(22,072)
As of June 30, 2013:
Identifiable net property and equipment	$2,532	$51,641	$2,518	$ 38		$ 56,729

_______________

(1)

Nonsegmented reconciling items for the second quarter include $2,780 of G&A costs, $693 of noncash stock compensation expense, $256 of other income, $626 of interest expense, $8 of corporate DD&A costs, and $3,426 of foreign exchange losses. Nonsegmented reconciling items for the first six months include $4,604 of G&A costs, $1,382 of noncash stock compensation expense, $308 of other income, $1,254 of interest expense, $15 of corporate DD&A costs, and $12,552 of foreign exchange losses.

Note 5: Share-Based Compensation

We have several share-based incentive plans. Under these plans, options have been granted at an option price equal to the market value of the stock at the date of grant. The granted options have terms 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.

The following table summarizes option activity for the first half of 2014:

		Weighted	Weighted Average
	Number of	Average	Remaining Contractual	Aggregate
	Options	Exercise Price	Life (in years)	Intrinsic Value
Options outstanding:
Beginning of year	1,911,872	$4.22
Expired	(1,803)	5.06
End of period	1,910,069	4.22	8.34
Exercisable at end of period	629,946	4.79	7.61	$0

The following table summarizes option activity for the first half 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	(6,214)	4.60
End of period	1,269,085	4.65	8.81
Exercisable at end of period	210,161	5.06	8.22	$0

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $3.61 as of June 30, 2014, and $3.21 as of June 30, 2013, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.

The following table summarizes restricted stock activity during the first six months of 2014 and 2013:

	Number of Shares
	2014	2013
Unvested restricted stock outstanding:
Beginning of year	640,056	655,099
Issued	--	--
Forfeited	--	(3,089)
Vested	--	--
End of period	640,056	652,010

Stock Compensation

The following table summarizes the quantity of restricted stock awards, total deferred compensation expense arising from those awards, and year-to-date compensation expense for each equity award that is included in stock compensation expense:

Year		Total Deferred	Stock Compensation Expense
Ended	Number of	Compensation	(thousands)
Dec. 31,	Shares	(thousands)	2014	2013
2013	324,033	$1,095	$180	$ --
2012	321,086	1,365	223	224
2011	318,252	1,610	262	264
2010	373,500	2,260	--	368
Total	1,336,871	$6,330	$665	$856

The following table summarizes the quantity of stock option awards, total deferred compensation expense arising from those awards, and year-to-date compensation expense for each equity award that is included in stock compensation expense:

Year		Total Deferred	Stock Compensation Expense
Ended	Number of	Compensation	(thousands)
Dec. 31,	Options	(thousands)	2014	2013
2013	648,058	$1,084	$179	$ -
2012	642,170	1,421	232	234
2011	636,509	1,781	290	292
Total	1,926,737	$4,286	$701	$526

Note 6: Stockholders’ Equity

We have a Stock Bonus Plan covering all of our employees under section 401(k) of the Internal Revenue Code. During the first halves of 2014 and 2013, we made discretionary contributions of 171,879 and 162,402 shares of our common stock, respectively, to employees under this Plan for the prior years’ service and recorded $629,000 and $667,000 of expenses associated with these contributions for the years ended December 31, 2013 and 2012, respectively. During the second quarter of 2014, we sold 163,639 shares of common stock under our at-the-market agreement in connection with our existing shelf registration. Net proceeds from the stock sale were approximately $615,000, after deducting associated costs of approximately $27,000. During 2014, we issued 7,500 shares of our stock to Polish consultants, resulting in expense of $28,000 that will be amortized monthly during 2014.

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, 2014, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first half of 2014.

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. Fair values of cash and cash equivalents approximate cost due to the short period of time to maturity.

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of June 30, 2014 (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	$391	$391	--	--

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of June 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	$1,029	$1,029	--	--

Note 8: Notes Payable

We maintain a 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, or expansion, mechanism. Initial proceeds from the 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 this credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.2 million during 2013. These fees, along with approximately $399,000 associated with our previous facility, have been capitalized as loan fees and will be amortized over the five-year term of the loan.

The credit facility calls for a periodic interest rate of three-, six-, or twelve-month-LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years. The facility 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 credit facility. There are no financial covenants associated with the credit facility. As of June 30, 2014, the total amount drawn under the credit facility was $50 million, and the interest rate was 3.90% per annum.

Our notes payable are stated at book value, which approximated their fair value at June 30, 2014. 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 based on Level 3 criteria in the Financial Accounting Standards Board’s fair value hierarchy.

Note 9: Capitalized Exploratory Well Costs

The following table shows the capitalized costs by well, at June 30, 2014, along with the year for which the costs of each well were incurred, for those costs that are capitalized, and included in proved property costs, pending the determination of proved reserves:

	Capitalized Costs						Total at June 30,
	2014(1)		2013		2012		2014
Well:
Tuchola-4K	$	9,192	$	290	$	--	$	9,482
Tuchola-3K		(97)		7,513		1,467		8,883
Gorka Duchowna-1		175		4,747		--		4,922
Frankowo-1		(54)		472		4,752		5,170
Total cost	$	9,216	$	13,022	$	6,219	$	28,457

_______________

(1)	Negative figures are associated with the effect of current-year exchange rate changes on costs incurred in prior years.

Note 10: Foreign Currency Translation and Risk

During the first half of 2014, we recorded foreign currency transaction losses of approximately $1.9 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 the gain 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, 2014
Balance at December 31, 2013	$15,025
Increase related to losses on intercompany loans	1,929
Decrease related to translation adjustments	(966)
Balance at June 30, 2014	$15,988

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. During 2013, we converted approximately $45 million of loans to FX Energy Poland from FX Energy, Inc., to equity. The conversion was necessary in order to make future interest payments from FX Energy Poland to FX Energy, Inc., tax deductible in Poland.

We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations. We do not use derivative financial instruments for trading or speculative purposes.

Note 11: Subsequent Event – Preferred Stock Offering

During July 2014, we closed an underwritten public offering of 800,000 shares of 9.25% Series B Cumulative Convertible Preferred Stock (the “Series B Preferred Stock”) at a public offering price of $25.00 per share. The Series B Preferred Stock ranks senior to all of our common stock, Series A Preferred Stock, and any other equity securities that we may issue in the future, the terms of which specifically provide that such equity securities rank junior to the Series B Preferred Stock, in each case with respect to payment of dividends and amounts upon liquidation, dissolution, or winding up.

Holders of the Series B Preferred Stock will be entitled to receive, when and as declared by our board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at the rate of 9.25% per annum of the $25.00 per-share liquidation preference, equivalent to $2.3125 per annum per share. Dividends will be paid on the last day of each January, April, July, and October, commencing on October 31, 2014. If we have failed to pay dividends for any four consecutive or nonconsecutive quarters, then: (i) the annual dividend rate on the Series B Preferred Stock will be increased to 11.25%, equivalent to $2.8125 per annum, commencing on the first day after the dividend payment date on which such divide; and (ii) the holders of the Series B Preferred Stock will have the voting rights discussed below.

If and whenever either: (i) cash dividends on any outstanding Series B Preferred Stock have not been paid in full for any four consecutive or nonconsecutive quarterly periods, whether or not earned or declared; or (ii) we fail to maintain the listing of the Series B Preferred Stock on a registered national securities exchange for a period of at least 180 consecutive days, the number of directors then constituting our board of directors will increase by at least two (such exact number to be fixed by our board of directors in accordance with our bylaws), and the holders of Series B Preferred Stock, voting together as a class with the holders of any other equity securities that rank on par with the Series B Preferred Stock upon which like voting rights have been conferred, will have the right to elect two additional directors to serve on our board of directors (as long as such additional directors were not previously elected by the holders of other securities with similar voting rights).

Upon any voluntary or involuntary liquidation, dissolution, or winding up of our affairs, then, before any distribution or payment shall be made to the holders of any common stock or any other class or series in the distribution of assets upon any liquidation, dissolution, or winding up of our Company, the holders of Series B Preferred Stock shall be entitled to receive out of our assets legally available for distribution to stockholders, liquidating distributions in the amount of the liquidation preference, or $25.00 per share, plus an amount equal to all dividends (whether or not earned or declared) accrued and unpaid thereon.

On or after July 17, 2017, we, at our option, upon not less than 30 or more than 60 days’ written notice, may redeem the Series B Preferred Stock, in whole or in part, at any time or from time to time, for cash at a redemption price of $25.00 per share, plus all accrued and unpaid dividends thereon to the date fixed for redemption, without interest.

Following our change of control (as defined), we (or the acquiring entity) will have the option to redeem the Series B Preferred Stock, in whole but not in part, within 90 days after the date on which the change of control has occurred, for cash, at a redemption price of $25.00 per share, plus accumulated accrued and unpaid dividends to, but not including, the date of redemption. Notwithstanding the foregoing, holders shall always have the right, up to any applicable redemption date, to convert the Series B Preferred Stock into our common stock at a conversion price of $5.00 per share, as such conversion price may be adjusted.

Each outstanding share of Series B Preferred Stock shall be convertible at any time at the option of the holder into that number of whole shares of our common stock as is equal to $25.00 per share, plus accrued and unpaid dividends, divided by an initial conversion price of $5.00, as such conversion price may be adjusted.

Upon the occurrence of a change of control, each holder of Series B Preferred Stock will have the right (unless, prior to the change of control, we have provided or provide irrevocable notice of our election to redeem the Series B Preferred Stock, in which case, such holder will only have the right respecting the shares of Series B Preferred Stock not called for redemption to convert some or all of the Series B Preferred Stock held by such holder into a number of shares of our common stock per share of Series B Preferred Stock that is equal to the lesser of:

●	quotient obtained by dividing: (i) the sum of the $25.00 liquidation preference per preferred share, plus the amount of any accumulated and unpaid dividends by (ii) in general, the price at which our outstanding common stock is converted, valued, or quoted in the change in control transaction; and

●	14.925, subject to certain adjustments.

Notwithstanding the foregoing, holders shall always have the right, up to any applicable redemption date, to convert the Series B Preferred Stock into our common stock at a conversion price of $5.00 per share, as such conversion price may be adjusted.

We, at our option, may cause the Series B Preferred Stock to be converted in whole or in part, on a pro-rata basis, into that number of fully paid and nonassessable shares of common stock as is equal to $25.00 per share, plus accrued and unpaid dividends, divided by the conversion price if the trading price (as defined) of the common stock shall have equaled or exceeded $6.00, subject to adjustment, for at least 20 trading days in any 30 consecutive trading-day period ending three days prior to the date of notice of conversion.

So long as the Series B Preferred Stock has at least an aggregate of $5.0 million in liquidation amount outstanding, the affirmative vote of the holders of at least two-thirds of the Series B Preferred Stock at the time outstanding, the vote or consent shall be necessary for us to incur additional funded indebtedness in an aggregate amount greater than $1.0 million outstanding at any time if the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration to interest payments, after taking into account such additional funded indebtedness, shall be less than 2:1, on a pro forma basis, for the two most recently completed fiscal quarters for which financial statements have been filed with the Securities and Exchange Commission.

Trading of the Series B Preferred Stock, under the symbol “FXENP,” has begun on the NASDAQ Global Select Market. The offering was made pursuant to our existing effective shelf registration statement, previously filed with the Securities and Exchange Commission.

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 most of 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 several years.

Our U.S. operations also have an impact. Our U.S. operations are smaller than our operations 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, 2014, Compared to the Same Period of 2013

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $7.8 million during the second quarter of 2014, compared to $7.2 million during the same quarter of 2013. Higher prices in the 2014 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, 2014 and 2013, is set forth in the following table:

	For the Quarter Ended June 30,
	2014	2013	Change
Gas revenues	$7,799,000	$7,231,000	+8%
Average price (per thousand cubic feet)	$7.56	$6.97	+9%
Production volumes (thousand cubic feet)	1,031,000	1,038,000	-1%

Daily gas production was 11.3 million cubic feet of natural gas per day, or MMcfd, in the second quarter of 2014, compared to 11.4 MMcfd in the second quarter of 2013. Production declines at our Roszkow and Zaniemysl wells were mostly offset by increases at our Winna Gora and Lisewo-1 wells. Our Winna Gora well was shut-in for two weeks for annual maintenance and pressure testing. In addition, production was stopped for 40 days at our Kromolice-1 well for some unexpected flow line repairs, now completed, which reduced our quarterly production by approximately 900,000 cubic feet per day. At June 30, 2014, our daily production was 12.3 MMcfd. We expect production to begin at our Lisewo-2 well in the fourth quarter of this year.

Natural gas prices were higher during the 2014 second quarter. Two factors contributed to the increase in average prices. First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 3.1% higher during the second quarter of 2014. Second, period-to-period weakness in the U.S. dollar against the Polish zloty increased our dollar-denominated gas prices. The average exchange rate during the second quarter of 2014 was 3.04 zlotys per dollar. The average exchange rate during the second quarter of 2013 was 3.21 zlotys per dollar, a change of approximately 5%.

Oil Revenues. Oil revenues were $1.0 million for the second quarter of 2014, a 5% increase from $952,000 received during the second quarter of 2013. Production levels decreased approximately 3% from 2013 to 2014, due to normal production declines. Higher oil prices in the second quarter of 2014 offset the production decline. Our average oil price during the second quarter of 2014 was $83.62 per barrel, an 8% increase from $77.30 per barrel received during the same quarter of 2013.

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, 2014 and 2013, is set forth in the following table:

	For the Quarter Ended June 30,
	2014	2013	Change
Oil revenues	$1,003,000	$952,000	+5%
Average price (per barrel)	$83.62	$77.30	+8%
Production volumes (barrels)	11,997	12,315	-3%

Lease Operating Costs. Lease operating costs increased $338,000, or 40%, from the second quarter of 2013 to 2014. Poland operating costs increased approximately $233,000, or 78%, from quarter to quarter, with a portion of the increase attributable to new production at our Lisewo-1 and Komorze-3K wells, along with workover costs at our Komorze and Winna Gora wells. Operating costs and production taxes in the United States increased by approximately $105,000, or 19%, from 2013 to 2014 as we performed extensive workovers at our Montana properties, with a view to increasing production.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $3.6 million during the second quarter of 2014, compared to $4.0 million during the same period of 2013, a decrease of 11%. Second quarter 2014 exploration costs included approximately $2.9 million of dry-hole costs, primarily associated with our Szymanowice well, which was plugged during the quarter following an unsuccessful workover, and $700,000 associated with three-dimensional, or 3-D, and two-dimensional, or 2-D, seismic surveys at both our Fences and Edge project areas in Poland.

Second quarter 2013 exploration costs included approximately $2.2 million of dry-hole costs, including $736,000 associated with our Mieczewo well, which was plugged at the end of the first quarter of the year, $1.3 million associated with the unsuccessful fracture stimulation of our Plawce-2 well, and $200,000 associated with a dry-hole drilled at the Dry Lake prospect in Nevada. In addition, we spent $1.8 million associated with 3-D and 2-D seismic surveys and other costs at our various project areas in Poland.

Property Impairments. During the second quarter of 2014, we recorded property impairment costs of $3.7 million, essentially all of which were prior-year costs associated with our Szymanowice well, which was plugged during the quarter following an unsuccessful sidetrack operation. During the second quarter of 2013, we recorded property impairment costs of $5.4 million. We impaired $4.7 million of prior-year costs associated with our Plawce-2 well, following its unsuccessful fracture stimulation. In addition, our Zaniemysl-3 well ceased production during the quarter, 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 determined to cease all exploration efforts.

DD&A Expense – Exploration and Production. DD&A expense for producing properties was $975,000 for the second quarter of 2014, an increase of 11%, compared to $875,000 during the same period of 2013. Higher DD&A expense in 2014 was due to increased depreciation expense at our Lisewo-1 and Komorze-3K, reflecting higher and new production in 2014.

Accretion Expense. Accretion expense was $23,000 and $22,000 for the second quarters of 2014 and 2013, respectively. Accretion expense is related entirely to our asset retirement obligation associated with expected future plugging and abandonment costs.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $1.4 million during the second quarter of 2014, compared to $20,000 for the second quarter of 2013. During the second quarter of 2013, our drilling rig was largely inactive. During the second quarter of 2014, we drilled four wells for third parties. 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 $917,000 during the second quarter of 2014, compared to $116,000 during the same period of 2013. 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 $247,000 during the second quarter of 2014, compared to $238,000 during the same period of 2013. DD&A expense increased from quarter to quarter as new assets began to be depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $2.0 million during the second quarter of 2014, compared to $2.8 million during the second quarter of 2013. The decrease is primarily due to lower compensation costs. During the second quarter of 2013, compensation costs included the payment of incentive awards totaling approximately $852,000, of which approximately $500,000 related to 2008, which had been deferred until the Company met certain performance benchmarks. There were no incentive compensation payments made during the second quarter of 2014.

Stock Compensation (G&A). For the three-month periods ended June 30, 2014 and 2013, we recognized $687,000 and $693,000, 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 $12,000 during the second quarter of 2014, a decrease of $244,000, compared to $256,000 during the same period of 2013. The decrease was due to the recognition of $204,000 in insurance proceeds during the second quarter of 2013, combined with lower cash balances available for investment. During the second quarter of 2014, we incurred $685,000 in interest expense, which included $128,000 of amortization of previously incurred loan fees and $61,000 in commitment fees. During the second quarter of 2013, we incurred $626,000 in interest expense, which included $127,000 of amortization of previously incurred loan fees and $74,000 in commitment fees.

Foreign Exchange Gain (Loss). During the second quarter of 2014, we recorded foreign currency transaction losses of approximately $720,000, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans. We recorded foreign exchange losses of approximately $3.4 million during the same quarter of 2013, which were also principally related to our intercompany loans. Two factors contributed to the lower foreign exchange loss during the 2014 quarter. First, during 2013, we converted approximately $45 million of loans to FX Energy Poland from FX Energy, Inc., to equity. The conversion was necessary in order to make future interest payments from FX Energy Poland to FX Energy, Inc., tax deductible in Poland. Second, exchange-rate fluctuation from March 31 to June 30, 2014, of 1% was less than the exchange-rate fluctuation during the same period of 2013 of 2%. The lower amounts of intercompany loans outstanding and the decrease in exchange-rate volatility resulted in a lower foreign exchange impact in 2014 compared to 2013, a trend that is likely to continue for the balance of 2014.

Six Months Ended June 30, 2014, Compared to the Same Period of 2013

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $16.4 million during the first half of 2014, compared to $15.8 million during the same period of 2013. Higher natural gas prices offset a slight production decline 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, 2014 and 2013, is set forth in the following table:

	For the Six Months Ended June 30,
	2014	2013	Change
Revenues	$16,387,000	$15,777,000	+4%
Average price (per thousand cubic feet)	$7.49	$7.08	+6%
Production volumes (thousand cubic feet)	2,188,000	2,228,000	-2%

Daily gas production for the first half of 2014 was 12.1 MMcfd, compared to 12.3 MMcfd during the same period of 2013. New and full period production from our Lisewo-1, Winna Gora, and Komorze-3K wells added 497,000 cubic feet of natural gas over 2013 first half levels. These increases helped offset production declines at our Zaniemysl-3 and Roszkow wells. In addition, production was stopped for 40 days at our Kromolice-1 well for some unexpected flow line repairs, now completed, which reduced our first half production by approximately 466,000 cubic feet per day.

Natural gas prices were higher during the 2014 first half. Two factors contributed to the increase in average prices. First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 3.1% higher beginning in February of 2014. Second, period-to-period weakness in the U.S. dollar against the Polish zloty increased our dollar-denominated gas prices. The average exchange rate during the first half of 2014 was 3.05 zlotys per dollar. The average exchange rate during the first half of 2013 was 3.18 zlotys per dollar, a change of approximately 4%.

During the third quarter of 2014, our Kromolice-1, Sroda-4, and Kromolice-2 wells are scheduled to be shut-in for up to two weeks for annual maintenance and pressure testing, which will reduce our third-quarter and nine-month production and revenues.

Oil Revenues. Oil revenues were just over $1.9 million for the first half of 2014, a 4% increase from the oil revenues received during the first half of 2013. Production from our U.S. properties declined 1% during the first half of 2014, due to normal production declines. The decline in production was more than offset by higher oil prices received during the first half of 2014. Our average oil price during the first half of 2014 was $80.27 per barrel, a 4% increase from $76.89 per barrel received during the same period of 2013.

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, 2014 and 2013, is set forth in the following table:

	For the Six Months Ended June 30,
	2014	2013	Change
Revenues	$1,923,000	$1,852,000	+4%
Average price (per barrel)	$80.27	$76.89	+4%
Production volumes (barrels)	23,962	24,087	-1%

Lease Operating Costs. Lease operating costs increased $572,000, or 33%, from the first half of 2013 to 2014. Poland operating costs increased approximately $289,000, or 46%, from year to year, with a portion of the increase attributable to new production at our Lisewo-1 and Komorze-3K wells, along with workover costs at our Komorze and Winna Gora wells. Operating costs and production taxes in the United States increased by approximately $283,000, or 26%, from 2013 to 2014 as we performed extensive workovers at our Montana properties, with a view to increasing production.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $6.9 million during the first half of 2014, compared to $10.2 million during the same period of 2013, a decrease of 32%. First half 2014 exploration costs included approximately $2.9 million of dry-hole costs, primarily associated with our Szymanowice well, which was plugged following an unsuccessful workover, and $4.0 million associated with 3-D and 2-D seismic surveys at both our Fences and Edge project areas in Poland.

First half 2013 exploration costs included approximately $5.2 million of dry-hole costs, including approximately $3.7 million associated with our Mieczewo well, which was plugged at the end of the first quarter of the year, approximately $1.3 million associated with the unsuccessful fracture stimulation of our Plawce-2 well, and $200,000 associated with a dry hole drilled at the Dry Lake prospect in Nevada. In addition, we spent $5.0 million associated 3-D and 2-D seismic surveys and other costs at our various project areas in Poland.

Property Impairments. During the first half of 2014, we recorded property impairment costs of $3.7 million, essentially all of which were prior-year costs associated with our Szymanowice well, which was plugged during the first half following an unsuccessful sidetrack operation. During the first half of 2013, we recorded property impairment costs of $5.6 million. We impaired $4.7 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 the second quarter of 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 determined to cease all exploration efforts.

DD&A Expense – Exploration and Production. DD&A expense for producing properties was $2.1 million for the first half of 2014, compared to $1.9 million during the same period of 2013. Higher DD&A expense in 2014 was due to increased depreciation expense at our Lisewo-1 and Komorze-3K, reflecting higher and new production in 2014.

Accretion Expense. Accretion expense was $47,000 and $45,000 for the first half of 2014 and 2013, respectively. Accretion expense is related entirely to our asset retirement obligation.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $1.4 million during the first half of 2014, compared to $62,000 for the first half of 2013. During the first half of 2013, we performed limited services for third parties. During the first half of 2014, we drilled four 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 Company-owned properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $1.0 million during the first half of 2014, compared to $248,000 during the same period of 2013. 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 $491,000 during the first half of 2014, compared to $476,000 during the same period of 2013. DD&A expense increased from quarter to quarter as new assets began to be depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $3.9 million during the first half of 2014, compared to $4.6 million during the first half of 2013, a decrease of $678,000. The decrease is primarily due to lower compensation costs. During the first half of 2013, compensation costs included the payment of incentive awards totaling approximately $852,000, of which approximately $500,000 related to 2008, which had been deferred until the Company met certain performance benchmarks. There were no incentive compensation payments made during the first half of 2014. We do not expect to make any further incentive payments related to our 2013 performance.

Stock Compensation (G&A). For the six-month periods ended June 30, 2014 and 2013, we recognized $1.4 million for both periods 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 $26,000 during the first half of 2014, a decrease of $282,000, compared to $308,000 during the same period of 2013. The decrease was due to the recognition of $204,000 in insurance proceeds during the first half of 2013 combined with lower cash balances available for investment. During the first half of 2014, we incurred $1.3 million in interest expense, which included $255,000 of amortization of previously incurred loan fees and $165,000 in commitment fees. During the first half of 2013, we incurred $1.3 million in interest expense, which included $257,000 of amortization of previously incurred loan fees and $154,000 in commitment fees.

Foreign Exchange Loss. As discussed in Note 10 to the financial statements, during the first half of 2014, we recorded foreign currency transaction losses of approximately $1.9 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. During the first half of 2014, the U.S. dollar strengthened by approximately 1% against the Polish zloty from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses. During the first half of 2013, the U.S. dollar strengthened by approximately 7% against the Polish zloty from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses of $12.6 million. During 2013, we converted approximately $45 million of loans to FX Energy Poland from FX Energy, Inc., to equity. The conversion was necessary in order to make future interest payments from FX Energy Poland to FX Energy, Inc., tax deductible in Poland. The lower amounts of intercompany loans outstanding and the decrease in exchange-rate volatility resulted in a lower foreign exchange impact in 2014 compared to 2013, a trend that is likely to continue for the balance of 2014.

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.

2014 Liquidity and Capital

Working Capital (current assets less current liabilities). Our working capital was $10.4 million as of June 30, 2014, down from $11.3 million at December 31, 2013.

Our current assets at June 30, 2014, included approximately $6.8 million in cash and cash equivalents, $5.1 million in accrued oil and gas sales from both the United States and Poland, and $2.6 million in receivables from our joint interest partners in both the United States and Poland. At June 30, 2014, $4.1 million of our cash and cash equivalents were held in Poland at ING Bank N.V. We have not historically repatriated, and do not plan in the foreseeable future to repatriate, any cash held in Poland to the United States. Consequently, we do not expect to incur repatriation taxes in the foreseeable future. Most of the joint interest receivables at June 30, 2014, was due from Polskie Górnictwo Naftowe i Gazownictwo, or PGNiG, all of which are related to joint projects in which we act as the operator. Our current liabilities at quarter-end included approximately $3.3 million payable by us for various drilling and development operations in Poland. Our total outstanding long-term debt at quarter-end was $50 million.

Operating Activities. Net cash provided by operating activities was $3.7 million during the first six months of 2014, compared to $4.2 million during the first six months of 2013.

Investing Activities. During the first six months of 2014, we used cash of $13.6 million in investing activities. We used $13.1 million for capital additions in Poland and $522,000 for capital additions in our office and drilling equipment. During the first six months of 2013, we used cash of $13.6 million in investing activities. We used $13.1 million for capital additions in Poland and $484,000 for capital additions in our office and drilling equipment.

Financing Activities. During the first half of 2014, we increased our outstanding debt by $5.0 million. We also sold 163,639 shares of common stock under our at-the-market agreement, in connection with our existing shelf registration. Net proceeds from the stock sale were approximately $615,000, after deducting associated costs of approximately $27,000. There were no financing transactions during the first half of 2013.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2014 include our working capital of $10.4 million at June 30, 2014, available credit under our credit facility, and cash available from our operations.

In July 2014, we closed an underwritten public offering of 800,000 shares of our 9.25% Series B Cumulative Convertible Preferred Stock (the “Series B Preferred Stock”) at a public offering price of 25.00 per share. The aggregate gross proceeds from the offering were $20 million, with net proceeds after deducting estimated underwriting discounts and commissions and offering expenses, of approximately $18.4 million. Cumulative dividends of 9.25%, or $1.9 million per year are payable out of funds legally available therefor. We intend to use funds available to accelerate exploration efforts in our Edge concession in Poland and for general corporate purposes, including declaring and paying dividends on our Series B Preferred Stock.

In July 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 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.

The credit facility calls for a periodic interest rate of LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years. The facility has a term of five years, with semiannual borrowing base reductions of $13 million beginning on June 30, 2016. There are no financial covenants associated with the new credit facility. As of June 30, 2014, we had $50 million outstanding under the facility and $15 million of available credit.

We expect to generate cash from our operating activities as well to help fund our exploration and development activities in 2014. We expect that our 2014 production will approximate or be higher than our 2013 production with the addition of production at our Lisewo-2 and Komorze-3K wells. Production began at Komorze-3K in late February of 2014. Production is expected to begin at Lisewo-2 during the second half of 2014. We currently expect to receive 86% of the published low-methane tariff, adjusted for energy content, for each of the two new wells. The amount of revenue from this increased 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. As discussed above, we closed a $20 million preferred stock offering in July 2014, which was made under the shelf registration. Any additional stock issued to cover over-allotments will also be issued under the shelf registration.

In June 2012, we entered into an agreement to possibly sell up to $50 million in common stock in at-the-market transactions. During the first half of 2014, we sold approximately $0.7 million of common stock under that agreement. Currently, we have approximately $179.3 million of securities available for sale at any time under the registration statement, $49.3 million of which is covered by the at-the-market facility. Future issuances of stock under the shelf registration to finance our exploration and development plans in Poland and for other corporate purposes are subject to market conditions and our ability to access the capital markets.

At June 30, 2014, we were in the process of constructing pipeline and production facilities at our Lisewo-2 well. Total remaining costs for these facilities and the well once production begins and drilling is completed are expected to be approximately $1.0 million. We had no other firm commitments for future capital and exploration costs at June 30, 2014.

We expect our primary use of cash for 2014 will be for our exploration and development activities in Poland. Our board of directors has approved projects whose costs are expected to range from $50 million to $60 million for production facilities for existing discoveries, exploration and development wells, capital additions for our drilling rigs, 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 2014, but we do expect to start work on all of them during 2014. In 2013, we approved a capital budget of similar size. Our actual costs in 2013 were approximately $50.0 million.

The actual amount of our expenditures will 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 pace at which we explore our 100%-owned concessions following our recent discovery, 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 June 30, 2014, we have incurred cumulative net losses of approximately $203 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.

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 agreed to bear specified exploration costs to earn an interest in the project or other arrangements, all of which may dilute the interests 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

On May 28, 2014, the Financial Accounting Standards Board issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method or determined the effect of the standard on our ongoing financial reporting.

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, 2013. 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

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 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 zloty is subject to exchange-rate fluctuations that are beyond our control. 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, 2014, 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 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, 2014, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of June 30, 2014, 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, 2013. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2013, 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 1	Underwriting Agreement
1.02	Underwriting Agreement dated July 10, 2014, between and among FX Energy, Inc., and MLV & Co. LLC and Euro Pacific Capital, Inc., for themselves and as representatives of the underwriters named in Schedule II thereto	Incorporated by reference from the current report on Form 8-K filed July 14, 2014.

Item 3	Articles of Incorporation and Bylaws
3.06	Amendment to the Articles of Incorporation Designating Rights, Privileges, and Preferences of 9.25% Series B Cumulative Convertible Preferred Stock dated July 11, 2014	Incorporated by reference from the current report on Form 8-K filed July 14, 2014.

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.

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 11, 2014	By:	/s/ David N. Pierce
		David N. Pierce, President, Chief Executive Officer


Date: August 11, 2014	By:	/s/ Clay Newton
		Clay Newton, Principal Financial and Principal Accounting Officer

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