FX ENERGY INC - FORM 10-Q - November 6, 2015

Attached files

file	filename
EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3101q093015.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	ex3202q093015.htm
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3102q093015.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	ex3201q093015.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, 2015

¨	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 November 5, 2015, there were 54,869,256 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 September 30, 2015

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	13
3	Quantitative and Qualitative Disclosures about Market Risk	26
4	Controls and Procedures	26

	Part II—Other Information

1A	Risk Factors	28
6	Exhibits	28
--	Signatures	29

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	September 30,		December 31,
	2015		2014
ASSETS

Current assets:
Cash and cash equivalents	$	8,738	$	11,232
Marketable securities		--		7,313
Receivables:
Accrued oil and gas sales		1,461		2,948
Joint interest and other receivables		562		551
VAT receivable		--		895
Inventory		99		97
Other current assets		252		415
Total current assets		11,112		23,451

Property and equipment, at cost:
Oil and gas properties (successful-efforts method):
Proved		65,103		65,621
Unproved		1,906		1,991
Other property and equipment		12,970		12,738
Gross property and equipment		79,979		80,350
Less accumulated depreciation, depletion, and amortization		(30,016)		(26,867)
Net property and equipment		49,963		53,483

Other assets:
Certificates of deposit		406		406
Loan fees		2,655		1,553
Total other assets		3,061		1,959

Total assets	$	64,136	$	78,893

-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,
	2015		2014
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	1,792	$	5,036
Accrued liabilities		544		821
VAT payable		240		--
Accrued dividends		463		463
Total current liabilities		3,039		6,320

Long-term liabilities:
Notes payable		50,659		50,000
Asset retirement obligation		2,008		1,989
Total long-term liabilities		52,667		51,989

Total liabilities		55,706		58,309

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized;
800,000 shares outstanding as of September 30, 2015, and
December 31, 2014, respectively		1		1
Common stock, $0.001 par value, 100,000,000 shares authorized;
54,869,256 and 54,401,967 shares issued and outstanding as of
September 30, 2015, and December 31, 2014, respectively		55		54
Additional paid-in capital		250,567		248,186
Cumulative translation adjustment		38,710		30,072
Accumulated other comprehensive loss		--		(67)
Accumulated deficit		(280,903)		(257,662)
Total stockholders’ equity		8,430		20,584

Total liabilities and stockholders’ equity	$	64,136	$	78,893

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 the three months ended September 30,				For the nine months ended September 30,
	2015		2014		2015		2014
Revenues:
Oil and gas sales	$	5,092	$	8,472	$	18,273	$	26,782
Oilfield services		12		1,722		44		3,088
Total revenues		5,104		10,194		18,317		29,870

Operating costs and expenses:
Lease operating expenses		824		1,213		2,770		3,502
Exploration costs		285		1,935		8,536		8,846
Property impairments		182		4,540		619		8,274
Oilfield services costs		123		941		354		1,987
Depreciation, depletion and amortization		1,289		1,264		4,305		3,859
Accretion expense		30		22		91		69
Stock compensation		556		650		1,653		2,016
General and administrative		1,980		1,869		6,316		5,794
Total operating costs and expenses		5,269		12,434		24,644		34,347

Operating loss		(165)		(2,240)		(6,327)		(4,477)

Other expense:
Interest expense		(897)		(802)		(2,200)		(2,143)
Interest and other income		65		22		111		48
Foreign exchange loss		(1,358)		(13,425)		(13,437)		(15,361)
Total other expense		(2,190)		(14,205)		(15,526)		(17,456)

Net loss		(2,355)		(16,445)		(21,853)		(21,933)

Other comprehensive income
Increase (decrease) in market value of available for sale marketable securities		--		(7)		67		(7)
Foreign currency translation adjustment		356		7,144		8,638		8,107
Comprehensive loss	$	(1,999)	$	(9,308)	$	$ (13,148)	$	(13,833)

Dividends on preferred stock		(462)		(385)		(1,388)		(385)
Net loss attributable to common stockholders	$	(2,817)	$	(16,830)	$	$ (23,241)	$	(22,318)

Net loss per common share
Basic	$	(0.05)	$	(0.31)	$	(0.43)	$	(0.42)
Diluted	$	(0.05)	$	(0.31)	$	(0.43)	$	(0.42)
Weighted average common shares outstanding
Basic		54,223		53,453		54,223		53,338
Dilutive effect of stock options		--		--		--		--
Diluted		54,223		53,453		54,223		53,338

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,
	2015		2014
Cash flows from operating activities:
Net loss	$	(21,853)	$	(21,933)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		4,305		3,859
Accretion expense		91		69
Amortization of loan fees		335		379
Stock compensation		1,653		2,016
Property impairments		395		8,232
Unrealized foreign exchange losses		13,420		15,340
Common stock issued for services		729		657
Increase (decrease) from changes in working capital items:
Receivables		2,373		5,340
Inventory		(2)		2
Other current assets		158		(112)
Accounts payable and accrued liabilities		(2,776)		(5,066)
Net cash (used in) provided by operating activities		(1,172)		8,783

Cash flows from investing activities:
Additions to oil and gas properties		(4,783)		(15,143)
Additions to other property and equipment		(469)		(730)
Sales (purchases) of marketable securities		7,380		(4,066)
Net cash provided by (used in) investing activities		2,128		(19,939)

Cash flows from financing activities:
Proceeds from common stock issuance		--		615
Proceeds from issuance of preferred stock, net of costs		--		18,361
Payment of preferred stock dividends		(1,388)		--
Payments on notes payable		(50,000)		--
Proceeds from notes payable		49,719		5,000
Payment of loan fees		(1,548)		--
Net cash (used in) provided by financing activities		(3,217)		23,976

Effect of exchange-rate changes on cash		(233)		(506)

Net (decrease) increase in cash		(2,494)		12,314
Cash and cash equivalents at beginning of year		11,232		11,153

Cash and cash equivalents at end of period	$	8,738	$	23,467

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 that 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 interim financial statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2014, and our quarterly reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015.

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 nine-month periods ended September 30, 2015 and 2014, 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 September 30, 2015 and 2014, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
September 30, 2015	3,196,405	$0.00 - $5.06
September 30, 2014	2,438,449	$0.00 - $5.06

Note 3: Income Taxes

No income tax expense was recognized for the three- and nine-month periods ended September 30, 2015 and 2014, due to net losses being incurred in both periods. We are subject to audit by the Internal Revenue Service and various states for the prior three years. There has not been a change in our unrecognized tax positions since December 31, 2014, 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 nine months ended September 30, 2015.

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, 2015, the nine months ended September 30, 2015, and as of September 30, 2015, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended September 30, 2015:
Revenues	$ 455	$ 4,637	$ 12	$ --	$ 5,104
Net income (loss)	(248)	2,992	(360)	(4,739)(1)	(2,355)
Nine months ended September 30, 2015:
Revenues	$1,420	$16,853	$ 44	$ --	$ 18,317
Net income (loss)	(806)	3,573	(1,079)	(23,541)(1)	(21,853)
As of September 30, 2015:
Identifiable net property and equipment	$ --	$47,772	$ 2,183	$ 8	$ 49,963

_______________

(1)

Nonsegmented reconciling items for the third quarter of 2015 include $1,980 of G&A costs, $556 of noncash stock compensation expense, $832 of other expense, $13 of corporate DD&A costs, and $1,358 of foreign exchange losses. Nonsegmented reconciling items for the first nine months include $6,316 of G&A costs, $1,653 of noncash stock compensation expense, $2,089 of other expense, $46 of corporate DD&A costs, and $13,437 of foreign exchange losses.

Reportable business segment information for the three months ended September 30, 2014, the nine months ended September 30, 2014, and as of September 30, 2014, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended September 30, 2014:
Revenues	$ 892	$ 7,580	$1,722	$ --	$ 10,194
Net income (loss)	(45)	(179)	521	(16,742)(1)	(16,445)
Nine months ended September 30, 2014:
Revenues	$2,816	$23,966	$3,088	$ --	$ 29,870
Net income (loss)	327	2,700	350	(25,310)(1)	(21,933)
As of September 30, 2014:
Identifiable net property and equipment	$2,762	$66,474	$2,584	$ 11	$ 71,831

_______________

(1)

Nonsegmented reconciling items for the third quarter of 2014 include $1,869 of G&A costs, $650 of noncash stock compensation expense, $780 of other expense, $18 of corporate DD&A costs, and $13,425 of foreign exchange losses. Nonsegmented reconciling items for the first nine months include $5,794 of G&A costs, $2,016 of noncash stock compensation expense, $2,095 of other expense, $44 of corporate DD&A costs, and $15,361 of foreign exchange losses.

Note 5: Share-Based Compensation

We have share-based incentive plans under which 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 share-based incentive plans, we may also issue restricted stock. Restricted stock awards vest in three equal annual installments from the date of grant.

The following table summarizes option activity for the first nine months of 2015:

		Weighted	Weighted Average
		Average	Remaining	Aggregate
	Number of	Exercise	Contractual	Intrinsic
	Options	Price	Life (in years)	Value
Options outstanding:
Beginning of year	2,561,169	$3.81
Issued	3,968	2.63
Forfeited	(15,256)	3.80
End of period	2,549,881	3.81	7.62
Exercisable at end of period	1,256,814	$4.50	6.72	$0

The following table summarizes option activity for the first nine months 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	(6,799)	4.25
End of period	1,905,073	4.22	8.09
Exercisable at end of period	838,323	$4.89	7.26	$0

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $0.95 as of September 30, 2015, and $3.04 as of September 30, 2014, 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 nine months of 2015 and 2014:

	Number of Shares
	2015	2014
Unvested restricted stock outstanding:
Beginning of year	648,511	640,056
Issued	1,984	--
Forfeited	(3,971)	(2,498)
Vested	--	(104,182)
End of period	646,524	533,376

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)	2015	2014
2014	330,033	$ 868	$216	$ --
2013	324,033	1,095	270	272
2012	321,086	1,365	333	336
2011	318,252	1,610	--	375
Total	1,293,404	$4,938	$819	$983

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)	2015	2014
2014	660,064	$ 885	$220	$ --
2013	648,058	1,084	267	270
2012	642,170	1,421	347	349
2011	636,509	1,781	--	414
Total	2,586,801	$5,171	$834	$1,033

Note 6: Stockholders’ Equity

Common Stock

We have a Stock Bonus Plan covering all of our employees under section 401(k) of the Internal Revenue Code. During the first nine months of 2015 and 2014, we made discretionary contributions of 465,276 and 171,879 shares of our stock, respectively, to employees under this plan for the prior year’s service and recorded $723,000 and $629,000 of expenses associated with these contributions for the years ended December 31, 2014 and 2013, respectively. During the first nine months of 2015 and 2014, we issued 4,000 and 7,500 shares of our stock, respectively, to Polish consultants, resulting in expense of $6,200 and $28,000 that is amortized monthly. During the first nine months of 2014, we sold 163,639 shares of common stock under our at-the-market agreement in connection with our then existing shelf registration statement. Net proceeds from the stock sale were approximately $615,000, after deducting associated costs of approximately $27,000.

Preferred Stock

During 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 Series B Preferred Stock has a liquidation preference of $25.00 per share. The Series B Preferred Stock ranks senior to our common stock in the payment of dividends and distribution of assets upon liquidation or dissolution. The Series B Preferred Stock has no stated maturity and is not subject to mandatory redemption.

Holders of the Series B Preferred Stock are entitled to receive, when, as, and if declared by our board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 9.25% per annum of the $25.00 liquidation preference per share (equivalent to $2.3125 per annum per share). Dividends are payable quarterly in arrears on the last day of each January, April, July, and October, when, as, and if declared by our board. On September 19, 2015, the board declared a dividend of $0.58 per share, or a total of $462,500, accruing from July 1 through September 30, 2015.

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 establishes 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 September 30, 2015, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first nine months of 2015.

Recurring Fair Value

There were no assets measured at fair value on a recurring basis at September 30, 2015 and 2014.

Foreign Currency Exchange Rate Derivatives

In early 2015, we entered into two separate dollar/zloty hedge agreements. The agreements were in the form of costless collars, with floors of approximately 3.57 PLN/USD and ceilings of approximately 3.85 PLN/USD. One of the agreements, in the amount of $6.0 million, terminated on June 26, 2015, with no gain or loss recognized. The other agreement, in the amount of $6.5 million, was scheduled to terminate on December 29, 2015, but was terminated on July 1, 2015. As a result of the early termination, we recognized a gain of approximately $82,000, which was recorded as other income in financial statements for the three- and nine-month periods ended September 30, 2015.

Note 8: Notes Payable

In July 2015, we finalized a new, up to EUR90,000,000 Senior Reserve Base Lending Facility Agreement with BNP Paribas (Suisse) SA and ING Bank N.V., which refinanced and replaced our previously existing credit facility entered into in 2013. The initial commitment of the facility is EUR55 million. We can seek to increase the commitment up to EUR90 million under certain conditions via an embedded accordion mechanism. The credit facility calls for a periodic interest rate of EURIBOR, plus an interest margin of 4.75% for the first two years of the facility and 5.00% for the final three years. The facility has a term of five years, with scheduled semiannual borrowing-base reductions of 14.29% of the initial commitment amount beginning on September 30, 2017. Our initial borrowing base at closing was set at EUR45.1 million, equivalent on September 30, 2015, to $50.7 million. The facility also calls for us to segregate, on a monthly basis, certain amounts of cash in a debt service account, which is controlled by us. Any payments to the lenders from the debt service account will be made only if, at the next redetermination, the borrowing base is reduced, taking into consideration the current exchange rate and gas price environment and reserve additions since the prior redetermination. At September 30, 2015, approximately $3.0 million of our cash was in our debt service account.

In connection with the new credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $1.5 million during 2015. These fees, along with approximately $1,195,000 associated with our previous facility, have been capitalized as loan fees and will be amortized over the five-year term of the loan.

The borrowing base is redetermined twice a year, based on reserve volumes and values estimated by independent engineers as of the last day of the prior year. Our next redetermination is scheduled to be completed in December 2015.

Our note payable is stated at book value, which approximated its fair value at September 30, 2015. 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

At September 30, 2015, we had approximately $2.6 million of costs that were capitalized pending the determination of proved reserves, all of which are associated with our Miloslaw well that was in progress at that date.

Note 10: Foreign Currency Translation and Risk

During the first nine months of 2015, we recorded foreign currency transaction losses of approximately $13.4 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- and euro-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 Nine Months
	Ended September 30, 2015
Balance at December 31, 2014	$	30,072
Increase related to losses on intercompany loans		13,420
Decrease related to translation adjustments		(4,782)
Balance at September 30, 2015	$	38,710

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.

Note 11: Commitments and Contingencies

On October 13, 2015, we announced that we have entered into a definitive merger agreement (the “Merger Agreement”) pursuant to which ORLEN Upstream Sp. z o.o. will acquire all of the outstanding shares of common stock of FX Energy on the terms and subject to the conditions of the Merger Agreement. ORLEN Upstream is the wholly owned exploration and production subsidiary of PKN ORLEN SA (GPW: PKN). See “Operating Overview; and Merger Agreement with Orlen Upstream” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information.

Subsequent to our announcement, and as of a recent practicable date before filing of this document, five putative class action lawsuits on behalf of our shareholders were filed in various jurisdictions against us, each member of our board, ORLEN Upstream, and Kiwi Acquisition Corp. The lawsuits generally allege, among other things, that the members of our board breached their fiduciary duties of loyalty and care by agreeing to sell FX Energy without first taking steps to ensure that our shareholders would obtain adequate and fair consideration and by engineering the transaction to benefit themselves and or ORLEN Upstream without regard to our shareholders. The lawsuits further allege that the transaction is structured with deal protection devices that preclude other bidders from making successful competing offers. The lawsuits contend that we, ORLEN Upstream, and Kiwi Acquisition Corp. knowingly assisted the board in breaching its fiduciary duties. The lawsuits seek a declaration that the action is a proper class action and an order requiring the board to cooperate fully with any entity or person having a bona fide interest in proposing any alternative transactions and to ensure that no conflicts of interests exist between the directors’ own interests and their fiduciary duties. The lawsuits further seek an award of the plaintiffs’ damages, costs, and reasonable attorneys’ and experts’ fees and enjoinment of the acquisition of FX Energy by Kiwi Acquisition Corp. or, alternatively, rescission of the transaction in the event it is consummated.

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.

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 were a relatively stable source of cash flow until recent significant oil price declines. This, too, is reflected in our operating results.

Operating Overview; Merger Agreement with Orlen Upstream

The price we received for gas, denominated in dollars, declined materially during the first nine months of 2015 compared to the corresponding period in the previous year, due to the strength of the dollar relative to the zloty and the reduction in tariff prices on which our gas contracts are based. Oil prices for our domestic oil production declined by half compared to the corresponding periods in 2014. These factors materially reduced our revenues and cash flow from operations during 2015 and have adversely affected our liquidity and access to capital. As these trends emerged, we initiated a strategy to farm out our Edge concession area in order to obtain external capital to fund production facilities for our Tuchola discovery and further exploration and diversify risk. We also significantly curtailed our capital exploration expenditures in Poland, as compared to previous years. In July 2015, we refinanced our senior secured credit facility as further described below. See “Liquidity and Capital Resources.”

As we reached out to others respecting a farmout of our Edge concessions, we received indications from two companies of interest in a possible acquisition of our entire company. Based on this apparent interest, and in view of the continuing challenges faced by us in the current environment, we commenced our previously announced process to identify and engage with parties that had expressed interest or that might be interested in an acquisition of, or other transaction with, our company.

On October 13, 2015, we announced that we had entered into a definitive merger agreement (the “Merger Agreement”) with ORLEN Upstream Sp. z o.o. (“Orlen Upstream”) and its wholly owned subsidiary, Kiwi Acquisition Corp. (“Merger Sub”). ORLEN Upstream is the wholly owned exploration and production subsidiary of PKN ORLEN SA (GPW: PKN).

The Merger Agreement provides that, on the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will commence a tender offer (the “Offer”) to purchase all of the outstanding shares of our common stock (the “Common Stock”), at a price of $1.15 per share (the “Offer Price”), without interest and subject to any required withholding taxes. The Merger Agreement further provides that, on the terms and subject to the conditions set forth in the Merger Agreement, following completion of the Offer, Merger Sub will merge with and into the Company, with the Company continuing as the surviving corporation and as a wholly owned subsidiary of ORLEN Upstream (the “Merger”). In the Merger, each outstanding share of Common Stock (other than shares of Common Stock held by us, ORLEN Upstream, or Merger Sub and, if dissenters’ rights are available with respect to the Merger under Nevada law, shares of Common Stock held by stockholders who are entitled to assert, and who properly assert, such dissenters’ rights) will be converted into the right to receive cash in an amount equal to the Offer Price, subject to any required withholding of taxes and without interest.

Consummation of the Offer is subject to customary conditions set forth in the Merger Agreement, including, among others, that:

(i)

the number of shares of Common Stock validly tendered pursuant to the Offer and not validly withdrawn, together with the number of shares of Common Stock (if any) then owned by ORLEN Upstream or purchaser, represents a majority of the shares of Common Stock then outstanding (calculated on a fully diluted basis);

(ii)

any applicable filings or approvals or any mandatory waiting periods under antitrust laws that are required for the consummation of the Offer and the Merger have been made, obtained, or expired, as the case may be;

(iii)

no governmental authority has enacted any law or order that makes the Offer or the Merger illegal or otherwise prohibits the consummation of the Offer or the Merger, and there are no pending proceedings of any governmental authority challenging the consummation of the Offer or the Merger; and

(iv)

the Merger Agreement has not been terminated in accordance with its terms.

Merger Sub commenced the Offer on October 27, 2015. The Offer will expire at 12:01 a.m., Eastern Time, on Wednesday, November 25, 2015, unless extended in accordance with the terms of the Offer and the Merger Agreement and the applicable rules and regulations of the SEC.

Following the Offer, if ORLEN Upstream and Merger Sub own at least 90% of the outstanding shares of Common Stock, including through the exercise of a “top-up” option granted to Merger Sub, the Merger will be effected through a “short-form” merger without further action by our shareholders. We have granted Merger Sub a “top-up” option to acquire directly from us after completion of the Offer the number of shares required to effect the “short-form” merger at a price per share equal to the Offer Price, subject to the availability of sufficient authorized and unissued shares of Common Stock. If, after completion of the Offer, ORLEN Upstream and Merger Sub own less than 90% of the outstanding shares of Common Stock and the “top-up” option is not exercised, we will convene a meeting of the holders of our Common Stock to approve the Merger. ORLEN Upstream and Merger Sub have agreed that they will vote all shares of Common Stock owned by them in favor of approval of the Merger.

Completion of the Merger is subject to the conditions that: (i) ORLEN Upstream has accepted for payment and paid for all shares of Common Stock validly tendered and not withdrawn in the Offer; (ii) no governmental authority has enacted any law or order that makes the Merger illegal or otherwise prohibits the consummation of the Merger; and (iii) if approval of the Merger by the holders of Common Stock is required to complete the Merger under Nevada law, such approval has been obtained.

The Merger Agreement provides that, in the event the “top-up” option is not exercisable, ORLEN Upstream will have the right to appoint two individuals to serve on our board of directors and one individual to serve on each committee of our board of directors and the board of directors of our subsidiary, FX Energy Poland Sp. z o.o., subject to applicable NASDAQ independence rules.

The Merger Agreement provides that all outstanding shares of our 9.25% Series B Cumulative Convertible Preferred Stock will be redeemed following completion of the Offer at a redemption price of $25.00 per share, plus accrued and unpaid dividends to, but not including, the redemption date in accordance with the terms of the preferred stock.

The Merger Agreement contains customary representations and warranties by ORLEN Upstream, Merger Sub, and us. The Merger Agreement also contains customary covenants and agreements, including among others restrictions on the operation of the business of the Company and its subsidiaries between signing and closing and a covenant of the Company not to solicit alternative transactions or to provide information or enter into discussions with respect to alternative transactions, subject to certain exceptions.

The Merger Agreement may be terminated under certain circumstances, including in specified circumstances with respect to superior proposals, and provides that, upon termination of the Merger Agreement under specified circumstances, we will be required to pay Merger Sub a termination fee of $4 million.

A copy of the Merger Agreement was filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on October 14, 2015. The foregoing summary of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is subject to and qualified in its entirety by the full text of the Merger Agreement. The Merger Agreement was filed to provide investors and security holders with information regarding its terms. It is not intended to provide any other factual information about us, ORLEN Upstream, or Merger Sub or to modify or supplement any factual disclosures about us in our public reports filed with the SEC. The Merger Agreement includes representations, warranties, and covenants made by us, ORLEN Upstream, and Merger Sub made solely for purposes of the Merger Agreement and which may be subject to important qualifications and limitations agreed to by us, ORLEN Upstream, and Merger Sub in connection with the negotiated terms of the Merger Agreement. Moreover, some of those representations and warranties may not be accurate or complete as of any specified date, may be subject to a contractual standard of materiality different from those generally applicable to our SEC filings, or may have been used for purposes of allocating risk among the us, ORLEN Upstream, and Merger Sub rather than establishing matters as facts.

Results of Operations by Business Segment

Quarter Ended September 30, 2015, Compared to the Same Period of 2014

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $4.6 million during the third quarter of 2015, compared to $7.6 million during the same quarter of 2014. Lower production and prices in the 2015 quarter led to the decrease in natural gas revenues.

A summary of the amount and percentage change, as compared to the prior year, for gas revenues, average gas prices, and gas production volumes is set forth in the following table:

	For the Quarter Ended September 30,
	2015	2014	Change
Gas revenues	$4,637,000	$7,580,000	-39%
Average price (per thousand cubic feet)	$5.48	$7.26	-25%
Production volumes (thousand cubic feet)	846,000	1,045,000	-19%

Daily gas production was 9.2 million cubic feet of natural gas per day, or MMcfd, in the third quarter of 2015, compared to 11.3 MMcfd in the third quarter of 2014. Production was shut-in for two weeks for annual maintenance and pressure testing at six of our producing wells during the third quarter of 2015, while only one of our wells incurred its annual maintenance period during the third quarter of 2014. Following the third quarter 2015 customary maintenance and testing period, production resumed at all wells at a daily rate of approximately 11.0 MMcfd. In addition, production from our Roszkow and Komorze wells continued to decline.

Natural gas prices were lower during the 2015 third quarter. Two factors contributed to the decrease in average prices. First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 10.9% lower during the third quarter of 2015, compared to the same quarter of 2015. Second, period-to-period strength in the dollar against the zloty decreased our dollar-denominated gas prices. The average exchange rate during the third quarter of 2015 was 3.77 zlotys per dollar. The average exchange rate during the third quarter of 2014 was 3.15 zlotys per dollar, a change of approximately 20%.

Oil Revenues. Oil revenues were $0.5 million for the third quarter of 2015, a 49% decrease from $0.9 million recognized during the third quarter of 2014. Production levels increased slightly, due to a number of successful well workovers during earlier periods, by approximately 11% from 2014 to 2015. The increase in production was offset by lower prices received during the third quarter of 2015. Our average oil price during the third quarter of 2015 was $35.74 per barrel, a 54% decrease from $78.18 per barrel received during the same quarter of 2014.

A summary of the amount and percentage change, as compared to the prior year, for oil revenues, average oil prices, and oil production volumes is set forth in the following table:

	For the Quarter Ended September 30,
	2015	2014	Change
Oil revenues	$455,000	$892,000	-49%
Average price (per barrel)	$35.74	$78.18	-54%
Production volumes (barrels)	12,700	11,400	+11%

Lease Operating Costs. Lease operating costs of $0.8 million during the third quarter of 2015 were 32% lower than the third quarter of 2014 amount of $1.2 million. The primary cause of the quarter to quarter decline in operating costs was the effect of foreign exchange rates in Poland. As discussed above, the zloty weakened by some 20% during the 2015 quarter compared to the 2014 quarter. Absent any changes in the nature and zloty cost of operations, costs should have decreased by approximately 20% from 2014 to 2015. During the 2014 quarter, Poland operating costs included approximately $0.3 million associated with the startup of new production at our Lisewo-1 and Komorze-3K wells, along with workover costs at our Komorze and Winna Gora wells, which were not repeated during 2015. Operating costs and production taxes in the United States decreased from 2014 to 2015 as value-based production taxes dropped due to lower oil prices.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $0.3 million during the third quarter of 2015, compared to $1.9 million during the same period of 2014.

Third quarter 2015 exploration costs included approximately $0.1 million associated with three-dimensional, or 3-D, and two-dimensional, or 2-D, seismic surveys at both our Fences area and our 100%-owned concessions in Poland and $0.2 million of dry-hole costs associated primarily with the unsuccessful sidetrack operation at our Zaniemysl well. Third quarter 2014 exploration costs included approximately $0.9 million in period-to-date dry-hole costs associated with our Baraniec well, $0.7 million associated with 3-D and 2-D seismic surveys at both our Fences area and our 100%-owned concessions in Poland, and $0.4 million of current period dry-hole costs associated primarily with our Gorka-Duchowna well.

Property Impairment. During the third quarter of 2015, we recorded property impairment costs of $0.2 million, the majority of which represent capital costs incurred at our Montana properties, which we impaired due to uneconomic reserves caused by low oil prices. During the third quarter of 2014, we recorded property impairment costs of $4.5 million, essentially all of which were prior-year costs associated with our Gorka Duchowna well.

DD&A Expense–Exploration and Production. DD&A expense for producing properties was $1.0 million for the third quarter of 2015, compared to $1.0 million during the same period of 2014.

Accretion Expense. Accretion expense was $30,000 and $22,000 for the third quarters of 2015 and 2014, 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. during the third quarter of 2015, compared to $1.7 million for the third quarter of 2014. During the third quarter of 2015, we performed only minimal well service work for third parties. During the third quarter of 2014, we drilled five 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 $0.1 million during the third quarter of 2015, compared to $0.9 million during the same period of 2014. 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 $0.2 million during the third quarter of 2015, compared to $0.3 million during the same period of 2014.

Nonsegmented Information

G&A Costs. G&A costs were $2.0 million during the third quarter of 2015, compared to $1.9 million during the third quarter of 2014. Legal costs incurred relating to our pending sale caused the increase from 2014 to 2015.

Stock Compensation (G&A). We recognized $0.6 million and $0.7 million of stock compensation expense related to the amortization of deferred compensation associated with stock option and restricted stock grants for the three-month periods ended September 30, 2015 and 2014, respectively.

Interest and Other Income (Expense). During the third quarter of 2015, we incurred $0.9 million in interest expense, which included amortization of loan fees and unused commitment and other fees totaling $0.3 million. During the third quarter of 2014, we incurred $0.8 million in interest expense, which included amortization of loan fees and unused commitment and other fees totaling $0.3 million.

Foreign Exchange Gain (Loss). During the third quarter of 2015, we recorded noncash foreign currency transaction losses of approximately $1.4 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans. During the third quarter of 2014, we recorded noncash foreign currency transaction losses of approximately $13.4 million, also principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans. During the third quarter of 2015, the zloty weakened by less than 1% against the dollar from the beginning to the end of the quarter, which caused us to recognize minimal foreign currency transaction losses. During the third quarter of 2014, the zloty weakened by approximately 8% against the dollar from the beginning to the end of the quarter, which caused us to recognize larger foreign currency transaction losses.

Nine Months Ended September 30, 2015, Compared to the Same Period of 2014

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $16.9 million during the first nine months of 2015, compared to $24.0 million during the same period of 2014.

A summary of the amount and percentage change, as compared to the prior year, for gas revenues, average gas prices, and gas production volumes is set forth in the following table:

	For the Nine Months Ended September 30,
	2015	2014	Change
Revenues	$16,853,000	$23,966,000	-30%
Average price (per thousand cubic feet)	$5.75	$7.41	-22%
Production volumes (thousand cubic feet)	2,930,000	3,233,000	-9%

Daily gas production for the first nine months of 2015 was 10.7 MMcfd, compared to 11.8 MMcfd during the same period of 2014. Production was shut-in for two weeks for annual maintenance and pressure testing at all seven of our producing wells during the first nine months of 2015, while only four of our wells incurred their annual maintenance period during the same period of 2014. Production also declined at our Roszkow and Komorze wells.

Natural gas prices were lower during the 2015 nine months. Two factors contributed to the decrease in average prices. First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 8.4% lower in 2015 compared to 2014. Second, period-to-period strength in the dollar against the zloty decreased our dollar-denominated gas prices. The average exchange rate during the first nine months of 2015 was 3.73 zlotys per dollar. The average exchange rate during the first nine months of 2014 was 3.08 zlotys per dollar, a change of approximately 21%.

Oil Revenues. Oil revenues were $1.4 million for the first nine months of 2015, a 50% decrease from the $2.8 million recognized during the first nine months of 2014. Production levels increased slightly, due to a number of successful well workovers during earlier periods, by approximately 1% from 2014 to 2015. The increase in production was offset by lower prices received during the first nine months of 2015. Our average oil price during the first nine months of 2015 was $39.57 per barrel, a 50% decrease from $79.60 per barrel received during the same period of 2014.

A summary of the amount and percentage change, as compared to the prior year, for oil revenues, average oil prices, and oil production volumes is set forth in the following table:

	For the Nine Months Ended September 30,
	2015	2014	Change
Revenues	$1,420,000	$2,816,000	-50%
Average price (per barrel)	$39.57	$79.60	-50%
Production volumes (barrels)	35,900	35,400	+1%

Lease Operating Costs. Lease operating costs were $2.8 million during the first nine months of 2015, a decrease of 21% compared to the same period of 2014. The primary cause of the year-to-year decline in operating costs was the effect of foreign exchange rates in Poland. As discussed above, the zloty weakened by some 21% during the 2015 nine months compared to the 2014 nine months. Absent any changes in the nature and zloty cost of operations, costs should have decreased by approximately 21% from 2014 to 2015. Operating costs and production taxes in the United States also decreased from 2014 to 2015 as we incurred less workover costs at our Montana properties, and value-based production taxes declined with the reduction in oil prices.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $8.5 million during the first nine months of 2015, compared to $8.8 million during the same period of 2014. Nine-month 2015 exploration costs included approximately $7.5 million associated with 3-D and 2-D seismic surveys at both our Fences and Edge project areas in Poland and approximately $1.0 million in dry-hole costs associated with the unsuccessful sidetrack operation at our Zaniemysl well.

Nine-month 2014 exploration costs included approximately $0.9 million in period-to-date dry-hole costs associated with our Baraniec well, $3.2 million of dry-hole costs primarily associated with our Szymanowice well, which was plugged following an unsuccessful workover, and $4.8 million associated with 3-D and 2-D seismic surveys at both our Fences and Edge project areas in Poland.

Property Impairment. During the first nine months of 2015, we recorded property impairment costs of $0.6 million, the majority of which represent capital costs incurred at our Montana properties, which we impaired due to uneconomic reserves caused by low oil prices. During the first nine months of 2014, we recorded property impairment costs of $8.3 million. Approximately $4.5 million was associated with prior-year costs at our Gorka Duchowna well. In addition, we impaired $3.7 million of prior-year costs associated with our Szymanowice well, which was plugged during the first half of 2015.

DD&A Expense–Exploration and Production. DD&A expense for producing properties was $3.5 million for the first nine months of 2015, compared to $3.1 million during the same period of 2014. Higher DD&A expense in 2015 was due to increased depreciation expense in Poland caused by negative proved reserve revisions at year-end 2014.

Accretion Expense. Accretion expense was $91,000 and $69,000 for the first nine months of 2015 and 2014, respectively. Accretion expense is related entirely to our asset retirement obligation.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $0 during the first nine months of 2015, compared to $3.1 million for the first nine months of 2014. During the first nine months of 2015, we performed only minimal well service work for third parties, reflecting the general downtime in oil exploration and development due to substantially low oil prices. We drilled nine wells for third parties during the first nine months of 2014, 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 2015, compared to $2.0 million during the same period of 2014. 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 $0.8 million during the first nine months of both 2015 and 2014.

Nonsegmented Information

G&A Costs. G&A costs were $6.3 million during the first nine months of 2015, compared to $5.8 million during the first nine months of 2014, an increase of $0.5 million. The increase is primarily due to higher legal and accounting costs, including costs associated with the contemplated sale of the Company.

Stock Compensation (G&A). For the nine-month periods ended September 30, 2015 and 2014, we recognized $1.7 million and $2.0 million, respectively, of stock compensation expense for the amortization of deferred compensation related to stock option and restricted stock grants.

Interest and Other Income (Expense). Interest and other income was $0.1 million during the first nine months of 2015, compared to $0 during the same period in 2014. During the first nine months of 2015, we incurred $2.2 million in interest expense. We recorded $0.6 million of amortization of loan fees and unused commitment fees. During the first nine months of 2014, we incurred $2.1 million in interest expense, which included $0.4 million of amortization of previously incurred loan fees and $0.3 million in commitment and other fees.

Foreign Exchange Gain (Loss). As discussed in Note 10 to the financial statements, during the first nine months of 2015, we recorded noncash foreign currency transaction losses of approximately $13.4 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany U.S. dollar-denominated loans and unpaid interest to FX Energy, Inc. During the first nine months of 2015, the zloty weakened by approximately 8% against the dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses. During the first nine months of 2014, we recorded noncash foreign currency transaction losses of approximately $15.4 million, principally attributable to increases in the amount of zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc. During the first nine months of 2014, the zloty weakened by approximately 9% against the dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses.

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, primarily as a result of higher gas production in Poland over the last several years, our internally generated cash flow has become an important source of operations financing. Until the recent significant decline in oil prices, favorable oil prices from our U.S. production also provided cash flow.

2015 Liquidity and Capital

Working Capital (current assets less current liabilities). Our working capital was $8.1 million as of September 30, 2015, down from $17.1 million at December 31, 2014. The primary cause of the decrease is lower oil and gas revenues.

Our current assets at September 30, 2015, included approximately $8.7 million in cash and cash equivalents, $1.5 million in accrued oil and gas sales from both the United States and Poland, and $0.6 million in receivables from our joint interest partners in both the United States and Poland. At the same date, $4.3 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.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for the remainder of 2015 include our working capital of $8.1 million at September 30, 2015, credit that may become available under our credit facility, and cash available from our operations.

In July 2015, we finalized a new, up to EUR90,000,000 Senior Reserve Base Lending Facility Agreement with BNP Paribas (Suisse) SA and ING Bank N.V., which refinanced and replaced our previously existing credit facility entered into in 2013. The initial commitment of the facility is EUR55 million. We can seek to increase the commitment up to EUR90 million under certain conditions via an embedded accordion mechanism. The facility calls for a periodic interest rate of EURIBOR, plus an interest margin of 4.75% for the first two years of the facility and 5.00% for the final three years. The facility has a term of five years, with scheduled semiannual borrowing-base reductions of 14.29% of the initial commitment amount beginning on June 30, 2017. We believe the new euro-denominated facility may help to dampen adverse effects of currency exchange-rate fluctuations and may better align our borrowing capability with our capital needs, timing, and repayment schedule in the current operating environment.

The facility also calls for us to segregate, on a monthly basis, certain amounts of cash in a debt service account, which is controlled by us. Any payments to the lenders from the debt service account will be made only if, at the next redetermination, the borrowing base is reduced, taking into consideration the current exchange rate and gas price environment and reserve additions since the prior redetermination. In early October 2015, we announced the successful completion of our Miloslaw 4-K well, which we expect to begin production in late 2016. The reserves and future cash flows from this well should have a positive effect on our next redetermination. At September 30, 2015, approximately $3.0 million of our cash was in our debt service account.

Operating Activities. Net cash used in operating activities was $1.2 million during the first nine months of 2015, compared to net cash provided by operating activities of $8.8 million during the first nine months of 2014. The reduction in cash provided by operating activities was directly related to sharply lower oil and gas revenues, caused by the factors described above.

Investing Activities. During the first nine months of 2015 cash provided by investing activities was $2.1 million. We used $4.8 million for capital additions in Poland and $0.5 million for capital additions in our office and drilling equipment. We also sold $7.4 million of marketable securities. During the first nine months of 2014, we used cash of $15.9 million in investing activities. We used $15.1 million for capital additions in Poland and $0.7 million for capital additions in our office and drilling equipment. Following our preferred stock offering, we purchased $4.1 million of marketable securities.

Financing Activities. As discussed above, during the first nine months of 2015, we refinanced our existing credit facility. As a consequence, we repaid $50.0 million for our then-existing facility, received proceeds of $49.9 million from our new facility, and paid $1.5 million in new loan fees. Also during the first nine months of 2015, we paid preferred stock dividends of $1.4 million. During the first nine months of 2014, we increased our outstanding debt by $5.0 million and sold $0.6 million in common stock under the terms of our at-the-market agreement. As described above, we also sold 800,000 shares of Series B Preferred Stock during 2014. After associated offering costs, the net proceeds from the offering were approximately $18.4 million.

We expect to generate cash from our operating activities in Poland to meet any debt repayment obligations and to help fund our reduced exploration and development activities in 2015. We expect that our full-year 2015 production will approximate or be slightly lower than our 2014 production with the addition of production at our Lisewo-2 well. The amount of revenue from our production will depend on applicable gas sales prices and prevailing currency exchange rates. If current exchange rates and gas prices continue for the balance of 2015, we would expect our natural gas revenues in 2015 to be lower than 2014, despite our level of production.

We have an effective universal shelf registration statement under the Securities Act of 1933 under which we may sell up to $200 million of equity or debt securities of various kinds until August 2018. The $200 million of securities 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.

As of September 30, 2015, we had partially completed four 3-D seismic surveys in our Fences and Edge concessions. Total remaining 2015 costs for these projects are expected to be approximately $0.7 million. In addition, we have begun the design and construction process for production facilities at our Karmin-1 well. Total remaining costs are expected to be approximately $1.9 million. We had no other firm commitments for future capital and exploration costs at quarter end.

As mentioned above, we decided to significantly reduce our exploration and development activities in Poland during 2015 to accommodate the impact of current exchange rates and gas prices in Poland. As also noted above, we began to pursue a farmout of our Edge concessions to obtain external capital for planned Tuchola discovery development and further exploration, which efforts contributed to the commencement of the process that ultimately led to our entering into the Merger Agreement, as described above under Operating Overview; Merger Agreement with Orlen Upstream.

We may 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 the initial 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.

The actual amount of our expenditures will depend on ongoing exploration results; the pace at which Polskie Górnictwo Naftowe i Gazownictwo, 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 enable us to meet our significantly reduced projected capital needs in Poland and the United States for the next 12 months and meet anticipated debt repayment obligations. We have the ability to control the timing and amount of most of our future capital and exploration costs. However, our ability to access capital from external sources may be significantly impaired in the current environment, and we expect it is likely that we will be required to use our future cash flow principally to repay indebtedness under our credit facility. Factors that could affect our ability to raise additional capital include: (i) the adverse effects of the current commodity price environment on the availability of debt financing for oil and gas exploration and production companies; (ii) the potentially dilutive effects on our existing stockholders of the issuance of additional equity, particularly given the depressed trading prices of our common stock and the equity of companies engaged in the exploration and production business generally; and (iii) the limited number of potential strategic partners to fund or jointly explore or develop our assets in Poland.

We have a history of operating losses, and we may continue to incur operating losses in future periods as we continue to fund substantial exploration and development in Poland. From our inception in January 1989 through September 30, 2015, we have incurred cumulative net losses of approximately $281 million. Despite our 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.

If the transactions contemplated by the Merger Agreement are not completed for any reason, we anticipate that we will continue to restrict our expenditures for exploration and development in Poland to assure that we can meet our debt service obligations under our senior secured credit facility. We will renew our efforts to seek external funding for exploration and development in Poland through any means available, to the extent feasible in view of current commodity prices, currency exchange rates, and low trading prices for our equity securities. We will also substantially reduce our exploration staff and administrative and executive overhead. Further, we may also seek to dispose of our Montana and Nevada oil producing properties, which currently operate at a loss due to low oil prices, or possibly shut in less productive wells to the extent economically feasible in view of plugging, abandoning, and reclamation costs.

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 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, 2014. 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 “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements involve significant risks and uncertainties. All statements contained in this report, other than statements of historical fact, are statements that could be deemed forward-looking statements, including: any statements regarding the anticipated timing of filings and approvals relating to the Offer and the Merger; any statements regarding the expected timing of the completion of the Offer and the Merger; any statements regarding the ability to complete the Offer or the Merger considering the various closing conditions, including that Merger Sub must have accepted for payment all shares of Common Stock that Merger Sub becomes obligated to purchase pursuant to the Offer; any statements of expectation or belief; any statement regarding our future financial or operating performance; and any statements of assumptions underlying any of the foregoing. Forward-looking statements speak only as of the date they were made, and except to the extent required by law, we undertake no obligation to update or review any forward-looking statement because of new information, future events, or other factors. The words “anticipate,” “believe,” “can,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “will,” “plan,” “project,” “seek,” “should,” “target,” “would,” and similar expressions are intended to identify forward-looking statements. We have based these forward-looking statements largely on management’s current expectations, estimates, and assumptions about future events. These forward-looking statements are subject to a number of risks, uncertainties, and assumptions that may cause actual performance or achievements to be materially different from any future results, performance, or achievements expressed or implied by those statements. Such risks and uncertainties include those related to the Offer and the Merger, including: uncertainties as to the timing of the Offer and the Merger; uncertainties as to how many of the holders of shares of Common Stock will tender their shares into the Offer; the possibility that various closing conditions for the Offer or the Merger may not be satisfied or waived, including that a governmental entity may prohibit, delay, or refuse to grant approval for the consummation of the Offer or the Merger; the effects of disruption from the Offer and the Merger making it more difficult for us to maintain relationships with employees (including potential difficulties in employee retention), collaboration parties, other business partners, or governmental entities; legal proceedings that are instituted against us and others following announcement of the Merger Agreement; other business effects, including the effects of industrial, economic, or political conditions outside of our control; transaction costs; and actual or contingent liabilities. Such risks and uncertainties also include those related to our business and operations described in this report and other documents filed with the SEC by us, 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; the possible impairment of capitalized drilling costs if no recoverable reserves are established; 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.

It is not possible for our management to predict all risks, nor can we assess the impact of all factors or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements we make in this report. In light of these risks and uncertainties, the future events discussed in this report may not occur, or if any of them do, when they will occur or what impact they will have on us cannot presently be ascertained. Actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements. Because of these uncertainties, investors should not place undue reliance on these forward-looking statements.

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, KSK, Winna Gora, Komorze, 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 zloty is subject to exchange-rate fluctuations that are beyond our control. We do not use derivative financial instruments for hedging, 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, 2015, 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, 2015, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2015, 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, 2014. The risks described in our annual report on Form 10-K for the year ended December 31, 2014, 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
10.114	Up To EUR90,000,000 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 28, 2015	Incorporated by reference from the Current Report on Form 8-K filed August 3, 2015

10.115	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 28, 2015	Incorporated by reference from the Current Report on Form 8-K filed August 3, 2015

10.116	Deed of Pledge of Registered Shares of FX Energy Netherlands B.V. 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 29, 2015	Incorporated by reference from the Current Report on Form 8-K filed August 3, 2015

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

Exhibit Number*	Title of Document	Location

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: November 6, 2015	By:	/s/ David N. Pierce
		David N. Pierce, President, Chief Executive Officer


Date: November 6, 2015	By:	/s/ Clay Newton
		Clay Newton, Principal Financial and Principal Accounting Officer

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