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

Attached files

file	filename
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3102q063015.htm
EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INC	ex3101q063015.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	ex3201q063015.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	ex3202q063015.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, 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 August 5, 2015, there were 54,869,656 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, 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	23
4	Controls and Procedures	24

	Part II—Other Information

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

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FX ENERGY, INC., AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)

(in thousands)

	June 30,		December 31,
	2015		2014
ASSETS

Current assets:
Cash and cash equivalents	$	14,165	$	11,232
Marketable securities		--		7,313
Receivables:
Accrued oil and gas sales		2,548		2,948
Joint interest and other receivables		691		551
VAT receivable		--		895
Inventory		101		97
Other current assets		167		415
Total current assets		17,672		23,451

Property and equipment, at cost:
Oil and gas properties (successful-efforts method):
Proved		62,913		65,621
Unproved		1,912		1,991
Other property and equipment		12,846		12,738
Gross property and equipment		77,671		80,350
Less accumulated depreciation, depletion, and amortization		(28,771)		(26,867)
Net property and equipment		48,900		53,483

Other assets:
Certificates of deposit		406		406
Loan fees		1,241		1,553
Total other assets		1,647		1,959

Total assets	$	68,219	$	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-

	June 30,		December 31,
	2015		2014
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	4,760	$	5,036
Accrued liabilities		680		821
Accrued dividends		463		463
Total current liabilities		5,903		6,320

Long-term liabilities:
Notes payable		50,000		50,000
Asset retirement obligation		1,981		1,989
Total long-term liabilities		51,981		51,989

Total liabilities		57,884		58,309

Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized;
800,000 shares outstanding as of June 30, 2015, and December 31, 2014, respectively		1		1
Common stock, $0.001 par value, 100,000,000 shares authorized;
54,869,656 and 54,401,967 shares issued and outstanding as of
June 30, 2015, and December 31, 2014, respectively		55		54
Additional paid-in capital		250,011		248,186
Cumulative translation adjustment		38,354		30,072
Accumulated other comprehensive loss		--		(67)
Accumulated deficit		(278,086)		(257,662)
Total stockholders’ equity		10,335		20,584

Total liabilities and stockholders’ equity	$	68,219	$	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 June 30,				For the six months ended June 30,
	2015		2014		2015		2014
Revenues:
Oil and gas sales	$	6,547	$	8,802	$	13,181	$	18,310
Oilfield services		31		1,361		32		1,366
Total revenues		6,578		10,163		13,213		19,676

Operating costs and expenses:
Lease operating expenses		1,022		1,181		1,947		2,290
Exploration costs		3,254		3,591		8,251		6,911
Property impairments		67		3,689		437		3,735
Oilfield services costs		104		917		230		1,045
Depreciation, depletion and amortization		1,519		1,237		3,016		2,595
Accretion expense		31		23		61		47
Stock compensation		551		687		1,097		1,366
General and administrative		2,178		1,972		4,336		3,925
Total operating costs and expenses		8,726		13,297		19,375		21,914

Operating loss		(2,148)		(3,134)		(6,162)		(2,238)

Other expense:
Interest expense		(656)		(685)		(1,304)		(1,341)
Interest and other income		9		12		46		26
Foreign exchange loss		2,190		(720)		(12,079)		(1,936)
Total other expense		1,543		(1,393)		(13,337)		(3,251)

Net loss		(605)		(4,527)		(19,499)		(5,489)

Other comprehensive income
Increase (decrease) in market value of available for sale marketable securities		66		--		67		--
Foreign currency translation adjustment		(1,559)		357		8,282		963
Comprehensive loss	$	(2,098)	$	(4,170)	$	(11,150)	$	(4,526)
Dividends on preferred stock		(462)		--		(925)		-
Net loss attributable to common stockholders		(1,067)		(4,527)		(20,424)		(5,489)

Net loss per common share
Basic	$	(0.02)	$	(0.08)	$	(0.38)	$	(0.10)
Diluted	$	(0.02)	$	(0.08)	$	(0.38)	$	(0.10)
Weighted average common shares outstanding
Basic		54,223		53,325		54,223		53,279
Dilutive effect of stock options		--		--		--		--
Diluted		54,223		53,325		54,223		53,279

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,
	2015		2014
Cash flows from operating activities:
Net loss	$	(19,499)	$	(5,489)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		3,016		2,595
Accretion expense		61		47
Amortization of loan fees		209		255
Stock compensation		1,097		1,366
Property impairments		395		3,694
Unrealized foreign exchange losses		12,063		1,929
Common stock issued for services		729		656
Increase (decrease) from changes in working capital items:
Receivables		1,219		2,010
Inventory		(5)		1
Other current assets		242		(49)
Accounts payable and accrued liabilities		(495)		(3,304)
Net cash (used in) provided by operating activities		(968)		3,711

Cash flows from investing activities:
Additions to oil and gas properties		(1,895)		(13,091)
Additions to other property and equipment		(344)		(522)
Sales of marketable securities		7,380		--
Net cash (used in) provided by investing activities		5,141		(13,613)

Cash flows from financing activities:
Proceeds from stock offering		--		615
Payment of preferred stock dividends		(925)		--
Proceeds from notes payable		--		5,000
Net cash (used in) provided by financing activities		(925)		5,615

Effect of exchange-rate changes on cash		(315)		(112)

Net increase (decrease) in cash		2,933		(4,399)
Cash and cash equivalents at beginning of year		11,232		11,153

Cash and cash equivalents at end of period	$	14,165	$	6,754

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 quarterly financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014, and our Form 10-Q for the quarter ended March 31, 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 six-month periods ended June 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 June 30, 2015 and 2014, were as follows:

	Options and
	Unvested Restricted Stock	Price Range
Balance sheet date:
June 30, 2015	3,202,396	$0.00 - $5.06
June 30, 2014	2,550,125	$0.00 - $5.06

Note 3: Income Taxes

No income tax expense was recognized for the three- and six-month periods ended June 30, 2015 and 2014, 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, 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 six months ended June 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 June 30, 2015, the six months ended June 30, 2015, and as of June 30, 2015, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Nonsegmented	Total
	U.S.	Poland
Three months ended June 30, 2015:
Revenues	$ 579	$ 5,968	$ 31	$ --	$ 6,578
Net income (loss)	(99)	1,028	(333)	(1,201)(1)	(605)
Six months ended June 30, 2015:
Revenues	$ 965	$12,216	$ 32	$ --	$ 13,213
Net income (loss)	(559)	580	(718)	(18,802)(1)	(19,499)
As of June 30, 2015:
Identifiable net property and equipment	$ --	$46,584	$2,307	$ 9	$ 48,900

_______________

(1)

Nonsegmented reconciling items for the second quarter include $2,178 of G&A costs, $551 of noncash stock compensation expense, $8 of other income, $655 of interest expense, $15 of corporate DD&A costs, and $2,190 of foreign exchange gains. Nonsegmented reconciling items for the first six months include $4,336 of G&A costs, $1,097 of noncash stock compensation expense, $46 of other income, $1,304 of interest expense, $32 of corporate DD&A costs, and $12,079 of foreign exchange losses.

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)(1)	(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 $3,927 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.

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 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	(9,665)	3.62
End of period	2,555,472	3.81	7.87
Exercisable at end of period	1,261,605	4.50	6.98	$0

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

			Weighted Average
	Number of	Weighted 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 aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $0.88 as of June 30, 2015, and $3.61 as of June 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 six 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	(3,571)	--
Vested	--	--
End of period	646,924	640,056

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	$143	$ --
2013	324,033	1,095	179	180
2012	321,086	1,365	221	223
2011	318,252	1,610	--	262
Total	1,293,404	$4,938	$543	$665

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	$ 146	$ --
2013	648,058	1,084	178	179
2012	642,170	1,421	230	232
2011	636,509	1,781	--	290
Total	2,586,801	$5,171	$554	$701

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 halves 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 halves 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 half 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.

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 June 19, 2015, the board declared a dividend of $0.58 per share, or a total of $462,500, accruing from April 1 through June 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 June 30, 2015, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first half of 2015.

Recurring Fair Value

There were no assets measured at fair value on a recurring basis at June 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, in fact, terminated on July 1, 2015. As a result of the early termination, we recognized a gain of approximately $82,000, which will be recorded as other income in our third quarter financial statements.

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 is $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, 2015, the total amount drawn under the credit facility was $50 million, and the interest rate was 3.94% per annum.

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 last redetermination was completed in December 2014, with the year-end 2014 borrowing base set at $55 million.

Our notes payable is stated at book value, which approximated its fair value at June 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.

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 replaces our 2013 credit facility. 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 LIBOR, 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. Our initial borrowing base at closing was set at EUR45 million, which is approximately equal to $50 million, our outstanding balance at June 30, 2015.

Note 9: Capitalized Exploratory Well Costs

At June 30, 2015, we had approximately $0.8 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 half of 2015, we recorded foreign currency transaction losses of approximately $12.1 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, 2015
Balance at December 31, 2014	$30,072
Increase related to losses on intercompany loans	12,063
Decrease related to translation adjustments	(3,781)
Balance at June 30, 2015	$38,354

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

Due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. In our opinion, there are no material pending legal proceedings to which we are a party, of which any of our property is the subject, or for which an outcome adverse to us would have a material adverse effect on our financial condition, results of operations, or cash flows.

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 and Strategic Alternatives

The price we received for gas, denominated in dollars, declined materially during the second quarter and first half of 2015 compared to the corresponding periods 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 almost half compared to the corresponding periods in 2014. These factors materially reduced our revenues and cash flow from operations during 2015. 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 significantly curtailed our capital exploration expenditures in Poland, as compared to previous years. We recently also revised our senior secured credit facility to better align our capital needs, timing, and repayment schedule with this new operating environment.

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. Although these unsolicited indications of interest did not constitute binding offers, and may have been prompted by the decline in trading prices of our common stock, our board of directors believed that these approaches reflected bona fide interest in pursuing a transaction. Based on this apparent interest, we commenced a thorough process to identify and engage with additional parties that have expressed interest or that might be interested in an acquisition of, or other transaction with, our company. We have engaged Evercore Group L.L.C. as our financial adviser to assist us with the process.

Our board’s goal is to explore such a transaction on a competitive basis as a potential avenue for delivering value to our holders of common stock, including value that may not be reflected in current trading prices of our common stock, and to ensure that any such transaction that we ultimately pursue would be the best available transaction for us and our constituents based on all relevant facts and circumstances.

We caution that there are no assurances that the current process will result in a transaction or as to the structure, terms, or timing of any such transaction. Although we and our advisers are actively pursuing the process, there is no definitive schedule for completion of the process.

Results of Operations by Business Segment

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

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $6.0 million during the second quarter of 2015, compared to $7.8 million during the same quarter of 2014. Lower 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 respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the quarters ended June 30, 2015 and 2014, is set forth in the following table:

	For the Quarter Ended June 30,
	2015	2014	Change
Gas revenues	$5,968,000	$7,799,000	-23%
Average price (per thousand cubic feet)	$5.76	$7.56	-24%
Production volumes (thousand cubic feet)	1,036,000	1,031,000	+0%

Daily gas production was 11.4 million cubic feet of natural gas per day, or MMcfd, in the second quarter of 2015, compared to 11.3 MMcfd in the second quarter of 2014. At June 30, 2015, our daily production was 11.3 MMcfd. We expect production to begin at our Karmin well in the first quarter of next year.

Natural gas prices were lower during the 2015 second 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 8.3% lower during the second 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 second quarter of 2015 was 3.70 zlotys per dollar. The average exchange rate during the second quarter of 2014 was 3.04 zlotys per dollar, a change of approximately 22%.

Oil Revenues. Oil revenues were $0.6 million for the second quarter of 2015, a 42% decrease from $1.0 million received during the second quarter of 2014. Production levels rose approximately 1% from 2014 to 2015 due to a number of successful well workovers during earlier periods. Our average oil price during the second quarter of 2015 was $47.69 per barrel, a 43% decrease from $83.62 per barrel received during the same quarter of 2014.

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, 2015 and 2014, is set forth in the following table:

	For the Quarter Ended June 30,
	2015	2014	Change
Oil revenues	$579,000	$1,003,000	-42%
Average price (per barrel)	$47.69	$83.62	-43%
Production volumes (barrels)	12,136	11,997	+1%

Lease Operating Costs. Lease operating costs decreased from $1.2 million during the second quarter of 2014 to $1 million during the same quarter of 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.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $3.3 million during the second quarter of 2015, compared to $3.6 million during the same period of 2014, a decrease of 9%. Second quarter 2015 exploration costs were primarily associated with three-dimensional, or 3-D, and two-dimensional, or 2-D, seismic surveys and other costs at our various project areas in Poland. There were no dry-hole costs incurred during the 2015 quarter.

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 3-D and 2-D seismic surveys at both our Fences and Edge 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. Property impairments during the second quarter of 2015 totaled approximately $0.1 million.

DD&A Expense–Exploration and Production. DD&A expense for producing properties was $1.2 million for the second quarter of 2015, compared to $975,000 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 $31,000 and $23,000 for the second 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 $31,000 during the second quarter of 2015, compared to $1.4 million during the second quarter of 2014. During the second quarter of 2015, our drilling rig was largely inactive as reduced oil prices significantly depressed drilling activity in this area. 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 (which is significantly affected by oil prices), 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 $104,000 during the second quarter of 2015, compared to $917,000 during the same period of 2014. Oilfield services costs will also continue to fluctuate period to period based on market demand (which is significantly affected by oil prices), 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 $259,000 during the second quarter of 2015, compared to $247,000 during the same period of 2014. DD&A expense increased from quarter to quarter as new assets began to be depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $2.2 million during the second quarter of 2015, compared to $2.0 million during the second quarter of 2014. Higher figures in 2015 were due primarily to higher legal and accounting costs.

Stock Compensation (G&A). For the three-month periods ended June 30, 2015 and 2014, we recognized $551,000 and $687,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock.

Interest and Other Income (Expense). During the second quarter of 2015, we incurred $656,000 in interest expense, which included $105,000 of amortization of previously incurred loan fees and $59,000 in commitment fees. 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. Interest and other income was $9,000 during the second quarter of 2015, compared to $12,000 during the same period of 2014.

Foreign Exchange Gain (Loss). During the second quarter of 2015, we recorded foreign currency transaction gains of approximately $2.2 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans. We recorded foreign exchange losses of approximately $0.7 million during the same quarter of 2014, which were also principally related to our intercompany loans. The foreign exchange gains during the 2015 quarter were due entirely to changes in exchange rates. At June 30, 2015, the exchange rate was 3.76 zlotys per dollar, compared to 3.81 zlotys per dollar at March 31, 2015, a strengthening in the zloty of 1.3%. For comparative purposes, the exchange rate at June 30, 2014, was 3.05 zlotys per dollar, a year-over-year change of 23% in the value of the dollar versus the zloty.

Six Months Ended June 30, 2015, Compared to the Same Period of 2014

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $12.2 million during the first half of 2015, compared to $16.4 million during the same period of 2014. Lower natural gas prices combined with a decline in production to produce the lower 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, 2015 and 2014, is set forth in the following table:

	For the Six Months Ended June 30,
	2015	2014	Change
Revenues	$12,216,000	$16,387,000	-25%
Average price (per thousand cubic feet)	$5.86	$7.49	-22%
Production volumes (thousand cubic feet)	2,085,000	2,188,000	-5%

Daily gas production for the first half of 2015 was 11.5 MMcfd, compared to 12.1 MMcfd during the same period of 2014. Production declines at our Roszkow and Komorze wells were mostly offset by increases at our Lisewo wells. Natural gas prices were lower during the 2015 first half. 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 7.5% 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 half of 2015 was 3.72 zlotys per dollar. The average exchange rate during the first half of 2014 was 3.05 zlotys per dollar, a change of approximately 22%.

During the third quarter of 2015, 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 $0.9 million for the first half of 2015, a 50% decrease from the oil revenues received during the first half of 2014. Production from our U.S. properties declined 3% during the first half of 2015 due to normal production declines. Our average oil price during the first half of 2015 was $41.68 per barrel, a 48% decrease from $80.27 per barrel received during the same period of 2014.

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, 2015 and 2014, is set forth in the following table:

	For the Six Months Ended June 30,
	2015	2014	Change
Revenues	$965,000	$1,923,000	-50%
Average price (per barrel)	$41.68	$80.27	-48%
Production volumes (barrels)	23,157	23,962	-3%

Lease Operating Costs. Lease operating costs decreased $0.3 million, or 15%, from the first half of 2014 to 2015. Poland operating costs in 2014 included $0.3 million associated with new production at our Lisewo-1 and Komorze-3K wells, along with workover costs at our Komorze and Winna Gora wells.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $8.3 million during the first half of 2015, compared to $6.9 million during the same period of 2014, an increase of 19%. First half 2015 exploration costs included approximately $7.4 million associated with 3-D and 2-D seismic surveys and other costs at our various project areas in Poland, along with approximately $0.9 million in dry-hole costs associated with the unsuccessful sidetrack of our Zaniemysl well in Poland.

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.

Property Impairments. During the first half of 2015, we impaired approximately $0.4 million of current year capital costs associated with our producing oil wells in the United States, where the majority of our reserves, measured at current prices, remain uneconomic due to the recent decline in these prices. 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 following an unsuccessful sidetrack operation.

DD&A Expense–Exploration and Production. DD&A expense for producing properties was $2.5 million for the first half of 2015, compared to $2.1 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 $61,000 and $47,000 for the first half 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 $32,000 during the first half of 2015, compared to $1.4 million for the first half of 2014. During the first half of 2015, 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 (which is significantly affected by oil prices), 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 $230,000 during the first half of 2015, compared to $1.0 million during the same period of 2014. Oilfield services costs will also continue to fluctuate period to period based on market demand (which is significantly affected by oil prices), 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 $520,000 during the first half of 2015, compared to $491,000 during the same period of 2014. DD&A expense increased from quarter to quarter as new assets began to be depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $4.3 million during the first half of 2015, compared to $3.9 million during the first half of 2014. The increase is primarily due to higher legal and accounting costs.

Stock Compensation (G&A). For the six-month periods ended June 30, 2015 and 2014, we recognized $1.1 million and $1.4 million, respectively, 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 $46,000 during the first half of 2015, compared to $26,000 during the same period of 2014. During the first half of 2015, we incurred $1.3 million in interest expense, which included $209,000 of amortization of previously incurred loan fees and $113,000 in commitment fees. 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.

Foreign Exchange Loss. As discussed in Note 10 to the financial statements, during the first half of 2015, we recorded foreign currency transaction losses of approximately $12.1 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 half of 2015, the dollar strengthened by approximately 22% against the zloty from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses. During the first half of 2014, the dollar strengthened by approximately 1% against the zloty from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses of $1.9 million.

Liquidity and Capital Resources

For much of our history, we have financed our operations principally through the sale of equity securities, bank borrowings, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. However, 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 $11.8 million as of June 30, 2015, a decrease of $5.3 million from December 31, 2014. The primary cause of the decrease is lower oil and gas revenues.

Our current assets at June 30, 2015, included approximately $14.2 million in cash and cash equivalents, $2.5 million in accrued oil and gas sales from both the United States and Poland, and $0.7 million in receivables from our joint interest partners in both the United States and Poland. At the same date, $6.9 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 $11.8 million at June 30, 2015, credit that may become available under our Senior Secured 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 replaces our 2013 facility. 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 LIBOR, 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.

Operating Activities. Net cash used in operating activities was $1.0 million during the first six months of 2015, compared to net cash provided by operating activities of $3.7 million during the first six 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, along with higher exploration spending.

Investing Activities. During the first six months of 2015 cash provided by investing activities was $5.1 million. We used $1.9 million for capital additions in Poland and $0.3 million for capital additions in our office and drilling equipment. We also sold $7.4 million of marketable securities. 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 $0.5 million for capital additions in our office and drilling equipment.

Financing Activities. During the first half of 2015, we paid preferred stock dividends of $0.9 million. During the first half 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.

We expect to generate cash from our operating activities in Poland to help fund our exploration and development activities in 2015. We expect that our full-year 2015 production will approximate or be higher 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.

On July 30, 2015, we filed a universal shelf registration statement under the Securities Act of 1933 under which we may sell up to $200 million of equity or debt securities of various kinds. This filing replaces the prior shelf registration statement, which expired. We may continue to sell securities under the previous registration statement for six months unless the new registration statement is declared effective for a new three-year term. 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 June 30, 2015, we had partially completed two 3-D seismic surveys in our Fences and Edge concession. Total remaining 2015 costs for these projects are expected to be approximately $2.5 million. We had no other firm commitments for future capital and exploration costs at quarter end. In addition to these projects, we are in the process of designing and permitting production facilities at our Karmin-1, Tuchola-3K, and Tuchola-4K wells.

As mentioned earlier, we decided to 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 had implemented a strategy to seek to farm out our Edge concessions to obtain external capital for planned Tuchola discovery development and further exploration, which has led to a process to identify and engage with parties that have expressed interest or that might be interested in an acquisition of, or other transaction with, our company. See “Operating Activities and Strategic Alternatives”.

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 projected 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 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 June 30, 2015, we have incurred cumulative net losses of approximately $278 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.

We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements such as those negotiated in prior years for our Kutno and Warsaw South project areas in which industry participants are bearing 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.

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 Accounting Standard Update, or 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, 2018. 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 above 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 results of our exploration of strategic alternatives being undertaken, 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 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, 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 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, 2015, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of June 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 3	Articles of Incorporation and Bylaws
3.07	Form of Certificate of Withdrawal of Certificate of Designation	Incorporated by reference from the Current Report on Form 8-K filed June 17, 2015

Item 4	Instruments Defining the Rights of Security Holders
4.06	Revised Rights Agreement dated as of April 24, 2015, between FX Energy, Inc., and Fidelity Transfer Company, as Rights Agent	Incorporated by reference from the Current Report on Form 8-K filed April 30, 2015

Item 10	Material Contracts
10.113	FX Energy, Inc., 2015 Performance Incentive Plan	Incorporated by reference from the Definitive Proxy Statement Pursuant to Section 14(a) filed April 30, 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

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 Files
101.01	XBRL Instance Document	Attached

101.02	XBRL Taxonomy Extension Schema	Attached

101.03	XBRL Taxonomy Extension Calculation	Attached

101.04	XBRL Taxonomy Extension Linkbase	Attached

101.05	XBRL Taxonomy Extension Presentation Linkbase	Attached

101.06	XBRL Taxonomy Extension Definition Linkbase	Attached

_______________

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	FX ENERGY, INC.
	(Registrant)


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


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

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