FX Energy (FXEN) 10-Q 2007 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007

Commission File No. 000-25386

FX ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada	87-0504461
(State or other jurisdiction of	(IRS Employer
incorporation or organization)	Identification No.)

3006 Highland Drive, Suite 206

Salt Lake City, Utah 84106

(Address of principal executive offices and zip code)

(801) 486-5555

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer x Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. The number of shares of $0.001 par value common stock outstanding as of November 2, 2007, was 37,784,007.

FX ENERGY, INC. AND SUBSIDIARIES

Form 10-Q for the Quarterly Period Ended September 30, 2007

TABLE OF CONTENTS

Item		Page
	Part I. Financial Information
1	Financial Statements
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations and Comprehensive     Income (Loss)	5
	Consolidated Statements of Cash Flows	6
	Notes to the Consolidated Financial Statements	7
2	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	12
3	Quantitative and Qualitative Disclosures about Market Risk	20
4	Controls and Procedures	21
	Part II. Other Information
1A	Risk Factors	21
6	Exhibits	22
--	Signatures	22

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands)

	September 30,	December 31,
	2007	2006
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$        6,447	$     4,644
Marketable securities	15,345	10,448
Accounts receivable:
Accrued oil and gas sales	2,143	1,615
Joint interest and other receivables	1,094	973
Inventory	175	206
Other current assets	479	322
Total current assets	25,683	18,208
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved	25,614	19,293
Unproved	1,177	2,912
Other property and equipment	5,352	4,624
Gross property and equipment	32,143	26,829
Less accumulated depreciation, depletion and amortization	(8,786)	(7,134)
Net property and equipment	23,357	19,695
Other assets:
Certificates of deposit	407	382
Loan fees	981	882
	1,388	1,264
Total assets	$    50,428	$    39,167

-- Continued --

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

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FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands, except share data)

-- Continued --

	September 30,	December 31,
	2007	2006
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$           3,545	$         5,234
Accrued liabilities	2,023	1,007
Total current liabilities	5,568	6,241
Long-term liabilities:
Asset retirement obligation	1,020	961
Total liabilities	6,588	7,202
Stockholders’ equity:
Preferred stock, $0.001 par value, 5,000,000 shares
authorized, no shares issued as of September 30, 2007 and
December 31, 2006	—	—
Common stock, $0.001 par value, 100,000,000 shares
authorized, 37,634,017 and 35,560,744 issued and
outstanding as of September 30, 2007 and
December 31, 2006 respectively	38	36
Additional paid-in capital	142,706	125,706
Accumulated other comprehensive loss	(58)	(72)
Accumulated deficit	(98,846)	(93,705)
Total stockholders’ equity	43,840	31,965
Total liabilities and stockholders’ equity	$        50,428	$       39,167

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

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FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

(in thousands, except per share amounts)

	For the three months ended September 30,		For the nine months ended September 30,
	2007	2006	2007	2006
Revenues:
Oil and gas sales	$         4,014	$    1,411	$       11,267	$    3,701
Oilfield services	1,229	431	2,665	1,362
Total revenues	5,243	1,842	13,932	5,063
Operating costs and expenses:
Lease operating expenses	903	596	2,711	1,881
Geological and geophysical costs	1,245	780	6,973	3,843
Oilfield services costs	648	251	1,680	964
Depreciation, depletion and     amortization (DD&A)	553	330	1,652	831
Accretion expense	20	12	59	35
Stock compensation (G&A)	657	712	2,132	2,115
General and administrative (G&A)	1,270	1,080	4,121	3,919
Total operating costs and expenses	5,296	3,761	19,328	13,588
Operating loss	(53)	(1,919)	(5,396)	(8,525)
Other income :
Interest income (net of interest expense) and     other income	219	191	255	553
Total other income	219	191	255	553
Net income (loss)	166	(1,728)	(5,141)	(7,972)
Other comprehensive income (loss)
Increase (decrease) in market value of available     for sale marketable securities	(56)	8	14	22
Comprehensive income (loss)	$           110	$  (1,720)	$      (5,127)	$   (7,950)
Basic and diluted net income (loss) per common     share	$           0.00	$     (0.05)	$        (0.14)	$     (0.23)
Basic weighted average number of     shares outstanding	37,522	35,162	36,313	35,139
Diluted weighted average number of shares     outstanding	43,741	35,162	36,313	35,139

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

5

FX ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	For the Nine Months Ended September 30,
	2007	2006
Cash flows from operating activities:
Net loss	$    (5,141)	$    (7,972)
Adjustments to reconcile net loss to net cash used in
operating activities:
Accretion expense	59	35
Depreciation, depletion and amortization	1,652	831
Stock issued for services (G&A)	745	516
Stock compensation (G&A)	2,132	2,115
Increase (decrease) from changes in working capital items:
Accounts receivable	(649)	1,170
Inventory	31	1
Other current assets	(157)	(76)
Other assets	(124)	(102)
Accounts payable and accrued liabilities	1,686	(1,653)
Net cash provided by (used in) operating activities	234	(5,135)
Cash flows from investing activities:
Additions to oil and gas properties	(6,945)	(6,663)
Additions to other property and equipment	(728)	(248)
Additions to marketable securities	(9,325)	(542)
Proceeds from maturities of marketable securities	4,442	14,600
Net cash (used in) provided by investing activities	(12,556)	7,147
Cash flows from financing activities:
Proceeds from sale of common stock, net	12,436	—
Proceeds from exercise of stock options and warrants	1,689	—
Net cash provided by financing activities	14,125	—
Increase in cash and cash equivalents	1,803	2,012
Cash and cash equivalents at beginning of period	4,644	2,390
Cash and cash equivalents at end of period	$    6,447	$    4,402

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

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FX ENERGY, INC. AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

(Unaudited)

Note 1: Basis of Presentation

The interim financial data are unaudited; however, in the opinion of the management of FX Energy, Inc. and subsidiaries (“FX Energy” or the “Company”), the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim periods. The interim financial statements should be read in conjunction with FX Energy’s annual report on Form 10-K for the year ended December 31, 2006, and quarterly reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007, including the financial statements and notes thereto.

The consolidated financial statements include the accounts of FX Energy and its wholly owned subsidiaries and FX Energy’s undivided interests in Poland. All significant intercompany accounts and transactions have been eliminated in consolidation. At September 30, 2007, FX Energy owned 100% of the voting stock of all of its subsidiaries.

Note 2: Net Income (Loss) Per Share

Basic earnings per share is computed by dividing the net income or loss applicable to common shares by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing the net income or loss by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options, warrants, unvested restricted stock, and convertible preferred stock or debt.

Outstanding options, warrants and unvested restricted stock as of September 30, 2007 and 2006, were as follows:

	Options, Warrants and Unvested Restricted Stock	Price Range
Balance sheet date:
September 30, 2007	6,484,916	$0.00 - $10.65
September 30, 2006	8,776,277	$0.00 - $10.65

The Company had a net loss in each of the nine month periods ended September 30, 2007 and 2006. The above options, warrants and unvested restricted stock were not included in the computation of diluted earnings per share for the periods presented because the effect would have been antidilutive.

Note 3: Income Taxes

The Company adopted the provisions of Financial Accounting Standards Board, or FASB, Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109,” or FIN 48, effective January 1, 2007. The Company did not have any unrecognized tax benefits, and there was no effect on its financial condition or results of operations as a result of implementing FIN 48. The Company is subject to audit by the IRS and various states for the prior three years. The Company does not believe there will be any material changes in its unrecognized tax positions over the next 12 months. The Company’s policy is that it recognizes interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any tax-related interest expense recognized during the nine months ended September 30, 2007.

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FX Energy recognized no income tax benefit from the net loss generated in the nine months ended September 30, 2007 and 2006. Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. The Company’s ability to realize the benefit of its deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of exploration and development activities, resulting in the Company’s conclusion that a full valuation allowance be provided.

Note 4: Business Segments

FX Energy operates 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, or DD&A, general and administrative costs, or 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, 2007, the nine months ended September 30, 2007, and as of September 30, 2007, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended September 30, 2007:
Revenues	$ 1,116	$ 2,898	$1,229	$       —	$  5,243
Net income (loss)(1)	341	1,049	503	(1,727)	166
Nine months ended September 30, 2007:
Revenues	$ 2,958	$ 8,309	$2,665	$       —	$ 13,932
Net income (loss)(1)	410	(259)	802	(6,094)	(5,141)
As of September 30, 2007:
Identifiable net property and equipment(2)	2,978	19,201	1,108	70	23,357

_______________

(1) Non-segmented reconciling items for the third quarter include $1,270 of general and administrative costs, $657 of noncash stock compensation expense, $219 of other income, and $19 of corporate DD&A. Non-segmented reconciling items for the first nine months include $4,121 of general and administrative costs, $2,132 of noncash stock compensation expense, $255 of other income, and $96 of corporate DD&A.

(2) Identifiable net property and equipment not associated with a segment consists of $70 of corporate office equipment, hardware and software.

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            Reportable business segment information for the three months ended September 30, 2006, the nine months ended September 30, 2006, and as of September 30, 2006, is as follows (in thousands):

	Reportable Segments
	Exploration & Production		Oilfield Services	Non-Segmented	Total
	U.S.	Poland
Three months ended September 30, 2006:
Revenues	$ 1,187	$      224	$   431	$       —	$  1,842
Net income (loss)(1)	296	(517)	139	(1,646)	(1,728)
Nine months ended September 30, 2006:
Revenues	$ 3,344	$    357	$ 1,362	$       —	$  5,063
Net income (loss)(1)	679	(3,326)	288	(5,613)	(7,972)
As of September 30, 2006:
Identifiable net property and equipment(2)	3,397	15,787	479	259	19,922

_______________

(1) Non-segmented reconciling items for the third quarter include $1,080 of general and administrative costs, $712 of noncash stock compensation expense, $192 of other income, and $46 of corporate DD&A. Non-segmented reconciling items for the nine months include $3,919 of general and administrative costs, $2,115 of noncash stock compensation expense, $553 of other income, and $132 of corporate DD&A.

(2) Identifiable net property and equipment not associated with a segment consists of $259 of corporate office equipment, hardware and software.

Note 5: Share-Based Compensation

The Company maintains 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 ranging from five to seven years and vest over periods ranging from the date of grant to three years. Under terms of the stock option award plans, the Company may also issue restricted stock. Restricted stock awards vest in three equal annual installments from the date of grant.

Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, “Share-Based Payment” (“SFAS No. 123R”). Under SFAS No. 123R, share-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. The Company adopted SFAS No. 123R using the modified prospective transition method. Under this method, prior periods are not revised for comparative purposes. The provisions of SFAS No. 123R apply to new awards and to awards that are outstanding on the effective date that are subsequently modified or cancelled. Compensation expense for unvested awards at the effective date will be recognized over the remaining requisite service period using the compensation cost calculated for pro forma disclosure purposes under SFAS No. 123, “Accounting for Stock-Based Compensation.”

The following table summarizes option activity for the first nine months of 2007:

	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value
Options outstanding:
Beginning of year	2,836,833	$5.08
Exercised	(151,114)	4.27
Cancelled	(54,666)	8.42
End of period	2,631,053	$5.05	2.56
Exercisable at end of period	2,619,388	$5.03	2.56	$7,205,293

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The following table summarizes option activity for the first nine months of 2006:

	Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value
Options outstanding:
Beginning of year	3,193,333	$5.16
Expired	(20,000)	7.38
End of period	3,173,333	$5.15	3.18
Exercisable at end of period	2,582,685	$4.83	3.18	$3,038,504

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on the Company’s stock price of $7.45 as of September 30, 2007, and $5.10 as of September 30, 2006, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.

During the nine months ended September 30, 2007 and 2006, the Company recognized $830,760 and $1,343,392, respectively, in expense related to unvested stock options granted prior to the adoption of SFAS No. 123R. Total unamortized expense at September 30, 2007, related to unvested options was $27,021.

In December 2006 and February 2007, the Company issued 333,200 shares of restricted stock to employees resulting in deferred compensation of $2,166,308, which will be amortized ratably over a three-year vesting period. Expense recognized during the first nine months of 2007 totaled $534,888.

In November 2005, the Company issued 298,950 shares of restricted stock to employees resulting in deferred compensation of $3,109,080, which will be amortized ratably over the three-year vesting period. Expense recognized during the first nine months of 2007 and 2006 totaled $766,610 and $771,574, respectively.

Note 6: Stockholders’ Equity

In July 2007, the Company sold 1,500,000 shares of common stock to certain institutional investors in a registered direct offering. The offering price was $8.63 per share. After offering costs and expenses, the offering resulted in net proceeds to the Company of approximately $12.4 million.

During the nine months ended September 30, 2007, option holders exercised options for a total of 151,114 shares, resulting in proceeds of $644,990. During the same period, warrant holders exercised warrants for a total of 290,000 shares, resulting in proceeds of $1,044,000. No options or warrants were exercised during the nine months ended September 30, 2006. During the first nine months of 2007, the Company issued 96,756 shares for its 2006 contribution to the Company’s employee benefit plan. In addition, the Company issued 20,000 shares, with a total value of $149,800 for services, primarily to Polish consultants.

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Note 7: Investments

The cost and estimated market value of marketable securities at September 30, 2007, are as follows (in thousands):

		Gross	Estimated
		Unrealized	Market
	Cost	Losses	Value
Marketable securities	$ 15,403	$ 58	$ 15,345

The marketable securities consist primarily of U.S. government agency bonds and notes, whose values fluctuate with changes in interest rates. The marketable securities decreased in value during the three months ended September 30, 2007. The Company believes the gross unrealized losses are temporary. The marketable securities have been classified as available-for-sale, and are reported at fair value with unrealized gains and losses, if any, recorded as a component of other comprehensive income or loss.

Note 8: Notes Payable

In November of 2006, the Company entered into a $25 million Senior Facility Agreement (the Facility) with The Royal Bank of Scotland plc. The Facility is provided to FX Energy Poland Sp. z o.o., a wholly owned subsidiary. Funds from the Facility will cover infrastructure and development costs at a variety of the Company’s Polish gas projects and are collateralized by its commercial wells and production in Poland.

Under the terms of the Facility, the initial commitment is for approximately $18.6 million, which is based solely on the proved reserve values of the Wilga, Zaniemysl and Kleka wells, and does not include Sroda-4, Winna Gora or Roszkow reserves. As of September 30, 2007, no amounts were outstanding under the Facility.

Note 9: Capitalized Exploratory Well Costs

At December 31, 2006, the Company had $2.4 million of capitalized costs related to two wells in progress at year-end, the Winna Gora and Roszkow wells. As of September 30, 2007, both wells were determined by the Company to be commercial.

Note 10: Reclassification

Certain amounts in the Consolidated Financial Statements for December 31, 2006, have been reclassified to conform to the 2007 presentation. These reclassifications had no impact on the Company’s net loss or cash flows.

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

Introduction

Our exploration efforts in Poland led to our first meaningful production commencing in 2006, as we began producing and selling gas from two of our five drilling successes, the Wilga and Zaniemysl wells. Production at our Wilga well, located southeast of Warsaw, officially commenced on September 19, 2006, and production began at our Zaniemysl well, located in western Poland, on October 12, 2006. Production from these wells enabled us to recognize record revenues and positive operating cash flow for the nine months ending September 30, 2007.

Our two major operating areas (the U.S. and Poland) have very different characteristics, which are reflected in the following discussion. Our U.S. operations, which include both oil production and oilfield services, are relatively mature, while our Polish operations are early in their initial development.

All oil and gas reservoirs are subject to natural production declines. In the United States, our mature oil fields have experienced, and will continue to experience, modest production declines from year to year.

Virtually all of our work in Poland, and all but one of our discoveries, are located in our Fences concessions in western Poland. Engineering and production histories of existing wells completed in the Rotliegend formation suggest that production from those gas wells should be fairly constant for the first three to four years, followed by a measured decline over another five to seven years. Our Zaniemsyl well appears to be following this trend.

Our Wilga well in eastern Poland is essentially unique with no comparable wells to model. It produces both gas and light crude oil, or LCO. Our production engineering data suggest that we may see a sharp decline in oil and gas production over the course of the next 12-18 months. We are currently evaluating alternative methods of sustaining production or slowing the anticipated decline; however, we expect oil and gas revenues in 2008 to be adversely impacted from 20% to 30% by lower Wilga production than that recorded in 2007.

In addition to the wells currently on production in Poland, we have three wells in our core area in western Poland that have been successfully drilled, and are waiting on production facilities. The Sroda-4, Winna Gora and Roszkow wells are expected to produce approximately 10 million cubic feet of natural gas per day net to our interest when they begin production. Plans are underway for the construction of the facilities, which should begin within the next six to twelve months. We expect production from these three wells to more than offset any production declines we may experience at our Wilga well. See “Results of Operations by Business Segment” below.

Results of Operations by Business Segment

We operate within two segments of the oil and gas industry: the exploration and production segment and the oilfield services segment. Depreciation, depletion and amortization expense, or DD&A, and general and administrative expense, or G&A, directly associated with their respective segments are detailed within the following discussion. G&A, interest and other income, and other costs that are not allocated to individual operating segments for management reporting or reportable business segment disclosure purposes are discussed in their entirety following the segment discussion. A comparison of the results of operations by business segment and the information regarding nonsegmented items for the three and nine months ended September 30, 2007 and 2006, follows.

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Quarter Ended September 30, 2007, Compared to the Same Period of 2006

Exploration and Production Segment

Gas Revenues. As discussed previously, we began gas production in Poland during 2006, and the related gas revenues have become the primary component of our revenue. Revenues from gas sales were $2.5 million during the third quarter of 2007, compared to $197,000 during the same quarter of 2006.

A summary of the amount and percentage change, as compared to the respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the quarters ended September 30, 2007 and 2006, is set forth in the following table:

	For the quarter ended September 30,
	2007	2006
Revenues	$2,501,185	$196,749
Percent change versus prior year	+1,170%	N/A
Average price (per thousand cubic feet of natural gas, or Mcf)	$5.37	$3.54
Percent change versus prior year	+52%	N/A
Production volumes (Mcf)	466,054	55,700
Percent change versus prior year	+737%	N/A

The substantial increase in production volumes is attributable to initiating production from wells drilled and completed in previous periods.

Gas revenue and production information for each of our three producing wells during the third quarter of 2007 was as follows:

	Volumes (Mcf)	Revenue	Price per Mcf
Wilga-2	208,234	$ 1,504,317	$ 7.22
Zaniemysl-3	227,542	940,959	4.14
Kleka 11	30,278	55,909	1.85

_______________

Note: Gas prices vary from property to property based primarily on the energy content of the gas, as well as the year in which the gas sales contract was consummated.

Oil Revenues. Oil revenues were $1.5 million for the third quarter of 2007, a 25% increase over the $1.2 million recognized during the third quarter of 2006. Included in 2007 revenues was approximately $397,000 related to the sale of a total of 4,840 barrels of LCO in Poland at an average price of $82.09 per barrel. All other oil revenues were derived from our producing properties in the United States. Oil revenues in the U.S. fluctuated primarily due to volatile oil prices and changing production rates that are a function of normal property declines. U.S. oil revenues in 2007 decreased from 2006 levels by a total of approximately $71,000. Higher oil prices increased revenues by approximately $79,000, while production declines decreased revenues by approximately $150,000.

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            A summary of the amount and percentage change, as compared to the respective prior-year period, for oil revenues, average oil prices, and oil production volumes for the quarters ended September 30, 2007 and 2006, is set forth in the following table:

	For the quarter ended September 30,
	2007	2006
Revenues	$1,513,672	$1,214,007
Percent change versus prior year	+25%	+14%
Average price (per barrel)	$68.74	$60.20
Percent change versus prior year	+14%	+8%
Production volumes (barrels)	22,021	20,166
Percent change versus prior year	+9%	+5%

Lease Operating Costs. Lease operating costs were $903,000 during the third quarter of 2007, an increase of $307,000, or 52%, compared to the same period of 2006. The higher operating costs are a direct result of our new production in Poland.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $1,245,000 during the third quarter of 2007, compared to $780,000 during the same period of 2006, an increase of 60%. Third quarter 2007 exploration costs included approximately $674,000 associated with our Sroda three-dimensional, or 3-D, seismic survey, approximately $439,000 associated with ongoing two-dimensional, or 2-D, seismic projects in the Fences concession area, and approximately $132,000 associated with 2-D seismic and other costs at our new concessions.

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $457,000 for the third quarter of 2007, an increase of 87% compared to $245,000 during the same period of 2006. With production commencing at our Zaniemysl and Wilga wells, we are now depleting the cost of those wells, which accounted for the majority of the year to year increase.

Accretion Expense. Accretion expense for the third quarter of 2007 reflects the increase in our asset retirement obligation under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). Accretion expense increased during the third quarter of 2007, as we began accreting property retirement obligations associated with our Zaniemysl and Wilga wells at the beginning of 2007.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $1,229,000 during the third quarter of 2007, an increase of $798,000 compared to $431,000 for the third quarter of 2006. We drilled five wells for third parties during the third quarter of 2007, along with additional well service work. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $648,000 during the third quarter of 2007, compared to $251,000 during the same period of 2006. The quarter to quarter increase was primarily due to our increased drilling activity as well as increased labor and material costs in 2007. Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

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DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $78,000 during the third quarter of 2007, compared to $40,000 during the same period of 2006. The quarter to quarter increase was primarily due to new capital additions in 2006 being depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $1,270,000 during the third quarter of 2007, compared to $1,080,000 during the third quarter of 2006, an increase of $190,000. Higher compensation and benefit costs and smaller foreign exchange gains were partially offset by lower accounting and investor relations costs. We also recognized $38,000 related to the amortization of stock options granted to consultants during 2007.

StockCompensation (G&A). As discussed above, we adopted the provisions of SFAS No. 123R effective January 1, 2006, using the modified prospective transition method. For the three-month periods ended September 30, 2007 and 2006, we recognized $657,000 and $712,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock purchase rights.

Interest Income (Expense) and Other Income. Interest and other income was $219,000 during the third quarter of 2007, an increase of $28,000 compared to $191,000 during the same period of 2006. The increase was a reflection of higher cash balances available for investment. At the beginning of 2007, we began paying a quarterly commitment fee in connection with securing our Senior Facility Agreement, resulting in a charge to interest expense of approximately $39,000 during the third quarter. We also began amortizing the previously capitalized fees associated with the Facility, which added $38,000 of additional interest expense to the third quarter of 2007.

Comparison of the First Nine Months of 2007 to the First Nine Months of 2006

Exploration and Production Segment

Gas Revenues. Revenues from gas sales were $7.1 million during the first nine months of 2007, compared to $330,000 during the same period of 2006.

A summary of the amount and percentage change, as compared to the respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the nine months ended September 30, 2007 and 2006, is set forth in the following table:

	For the nine months ended September 30,
	2007	2006
Revenues	$7,050,072	$329,812
Percent change versus prior year	+2038%	N/A
Average price (per Mcf )	$5.16	$2.58
Percent change versus prior year	+100%	N/A
Production volumes (Mcf)	1,365,769	127,700
Percent change versus prior year	+970%	N/A

The substantial increase in production volumes is attributable to initiating production from wells drilled and completed in previous periods.

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            Gas revenue and production information for each of our three producing wells during the first nine months of 2007 was as follows:

	Volumes (Mcf)	Revenue	Price per Mcf
Wilga-2	605,108	$ 4,216,339	$ 6.97
Zaniemysl-3	665,829	2,657,954	3.99
Kleka 11	94,832	175,779	1.85

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Note: Gas prices vary from property to property based primarily on the energy content of the gas, as well as the year in which the gas sales contract was consummated.

Oil Revenues. Oil revenues were $4.2 million for the first nine months of 2007, a 25% increase over the $3.3 million recognized during the first nine months of 2006. Included in 2007 revenues was approximately $1,258,000 related to the sale of a total of 18,193 barrels of LCO in Poland at an average price of $69.17 per barrel. All other oil revenues were derived from our producing properties in the United States. Oil revenues in the U.S. fluctuated primarily due to volatile oil prices and changing production rates that are a function of normal property declines. U.S. oil revenues in 2007 decreased from 2006 levels by a total of approximately $385,000. Of this decrease, $123,000 was due to lower oil prices and approximately $262,000 was due to production declines.

A summary of the amount and percentage change, as compared to the respective prior-year period, for oil revenues, average oil prices, and oil production volumes for the nine months ended September 30, 2007 and 2006, is set forth in the following table:

	For the Nine Months Ended September 30,
	2007	2006
Revenues	$4,216,867	$3,371,033
Percent change versus prior year	+25%	+20%
Average price (per barrel)	$60.02	$58.08
Percent change versus prior year	+3%	+22%
Production volumes (barrels)	70,261	58,080
Percent change versus prior year	+21%	-2%

Lease Operating Costs. Lease operating costs were $2,711,000 during the first nine months of 2007, an increase of $830,000, or 44%, compared to the same period of 2006. The higher operating costs are a direct result of our new production in Poland.

Exploration Costs. Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes. Exploration costs were $6,973,000 during the first nine months of 2007, compared to $3,843,000 during the same period of 2006, an increase of 81%. First nine months 2007 exploration costs included approximately $4.0 million associated with our Sroda 3-D seismic survey, approximately $1.8 million associated with ongoing 2-D seismic projects in the Fences concession area, and approximately $1.2 million associated with 2-D seismic and other costs at our new concessions

DD&A Expense - Exploration and Production. DD&A expense for producing properties was $1,373,000 for the first nine months of 2007, an increase of 133% compared to $590,000 during the same period of 2006. With production commencing at our Zaniemysl and Wilga wells, we are now depleting the cost of those wells, which accounted for the bulk of the year to year increase.

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Accretion Expense. Accretion expense for the first nine months of 2007 reflects the increase in our asset retirement obligation under SFAS No. 143. Accretion expense increased during the first nine months of 2007, as we began accreting property retirement obligations associated with our Zaniemysl and Wilga wells.

Oilfield Services Segment

Oilfield Services Revenues. Oilfield services revenues were $2,665,000 during the first nine months of 2007, an increase of 96% compared to $1,362,000 for the first nine months of 2006. We drilled twelve wells for third parties during the first nine months of 2007, along with additional well service work. Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

Oilfield Services Costs. Oilfield services costs were $1,680,000 during the first nine months of 2007, compared to $964,000 during the same period of 2006. The year to year increase was primarily due to increased drilling activity in 2007, as well as higher labor and material costs. Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

DD&A Expense – Oilfield Services. DD&A expense for oilfield services was $182,000 during the first nine months of 2007, compared to $110,000 during the same period of 2006. The year to year increase was primarily due to new capital additions in 2006 being depreciated.

Nonsegmented Information

G&A Costs. G&A costs were $4,121,000 during the first nine months of 2007, compared to $3,919,000 during the first nine months of 2006, an increase of $202,000. Higher compensation and benefit costs were partially offset by foreign exchange gains and lower accounting and investor relations costs. We also recognized $113,000 related to the amortization of stock options granted to consultants during 2007.

StockCompensation (G&A). As discussed above, we adopted the provisions of SFAS No. 123R on January 1, 2006, using the modified prospective transition method. For the nine-month periods ended September 30, 2007 and 2006, we recognized $2,132,000 and $2,115,000, respectively, of stock compensation expense related to the amortization of unexercised options and restricted stock purchase rights.

Interest Income (Expense) and Other Income. Interest and other income was $255,000 during the first nine months of 2007, a decrease of $298,000 compared to $553,000 during the same period of 2006. At the beginning of 2007, we began paying a quarterly commitment fee in connection with securing our Senior Facility Agreement, resulting in a charge to interest expense of approximately $158,000. We also began amortizing the previously capitalized fees associated with the Facility, which added $115,000 of additional interest expense to the first nine months of 2007.

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Liquidity and Capital Resources

To date, we have financed our operations principally through the sale of equity securities, issuance of debt securities, and agreements with industry participants that funded our share of costs in certain exploratory activities in return for an interest in our properties. Our cash resources and marketable securities at September 30, 2007, together with anticipated revenues in 2007 and availability under our $25 million Senior Facility Agreement, are sufficient to cover our planned exploration program and ongoing operations in the United States and Poland for the next 12 months.

We may seek to obtain additional funds for future capital investments from the sale of additional securities, project financing to help finance the completion of successful wells, sale of partial property interests, or other arrangements, all of which may dilute the interest of our existing stockholders or our interest in the specific project financed. We will allocate our existing capital as well as funds we may obtain in the future among our various projects at our discretion. We may change the allocation of capital among the categories of anticipated expenditures depending upon future events. For example, we may change the allocation of our expenditures based on the actual results and costs of future exploration, appraisal, development, production, property acquisition and other activities. In addition, we may have to change our anticipated expenditures if costs of placing any particular well or group of wells into production are higher, if the field is smaller, or if the commencement of production takes longer than expected.

Working Capital (current assets less current liabilities). Our working capital was $20,115,000 as of September 30, 2007, an increase of $8,148,000 from our working capital at December 31, 2006, of $11,967,000. As of September 30, 2007, our cash and cash equivalents and marketable securities totaled approximately $21.8 million. We have no long-term debt.

Operating Activities. Net cash provided by operating activities was $234,000 during the first nine months of 2007, compared to $5,135,000 in net cash used in operating activities during the same period of 2006. The 2007 improvement was due primarily to our higher oil and gas revenues in 2007.

Investing Activities. During the first nine months of 2007, we used $12,556,000 in investing activities. We received proceeds of $4,442,000 from maturities of marketable securities, purchased marketable securities of $9,325,000, used $4,309,000 for current year capital additions in Poland and $277,000 related to our proved properties in the United States, used $2,359,000 to pay accounts payable related to prior-year capital costs, and used $728,000 for capital additions in our drilling and office equipment. During the first nine months of 2006, $7,147,000 was provided by investing activities. We received proceeds of $14,600,000 from the maturities of marketable securities, purchased marketable securities of $542,000, used $798,000 to pay accounts payable related to prior-year capital costs, used $5,175,000 for current year capital additions in Poland and $546,000 related to our proved properties in the United States, $140,000 for Polish concession costs, $248,000 for office and drilling equipment, and $4,000 for undeveloped leasehold costs in the United States.

Financing Activities. During the first nine months of 2007, option and warrant holders exercised options and warrants for a total of 441,114 shares, resulting in proceeds of $1,689,000. No options or warrants were exercised during the first nine months of 2006. In July 2007, we sold 1,500,000 shares of common stock to certain institutional investors in a registered direct offering at an offering price of $8.63 per share, resulting in net proceeds to us of approximately $12.4 million.

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New Accounting Pronouncements

We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109,” or FIN 48, on January 1, 2007. We did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing FIN 48. We are subject to audit by the IRS and various states for the prior three years. We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months. Our policy is that we recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter ended September 30, 2007.

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

Critical Accounting Policies and Accounting Estimates

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, 2006. We believe the application of these accounting policies on a consistent basis enables us to provide financial statement users with useful, reliable and timely information about our earnings results, financial condition and cash flows.

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make judgments, estimates and assumptions regarding uncertainties that affect the reported amounts presented and disclosed in the financial statements. Our management reviews these estimates and assumptions, which are based on historical experience, changes in business conditions and other relevant factors that it believes to be reasonable under the circumstances. In any given reporting period, actual results could differ from the estimates and assumptions used in preparing our financial statements.

Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgment due to a high degree of uncertainty at the time the estimate is made. Our senior management has discussed the development and selection of our accounting policies, related accounting estimates and the disclosures set forth below with the Audit Committee of our Board of Directors. We believe our critical accounting policies include those addressing the recoverability and useful lives of assets, the retirement obligations associated with those assets, and the estimates of oil and gas reserves.

Forward-Looking Statements

This report contains statements about the future, sometimes referred to as “forward-looking” statements. Forward-looking statements are typically identified by the use of the words “believe,” “may,” “could,” “should,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “intend” and similar words and expressions. We intend that the forward-looking statements will be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements that describe our future strategic plans, goals or objectives are also forward-looking statements.

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            Readers of this report are cautioned that any forward-looking statements, including those regarding us or our management’s current beliefs, expectations, anticipations, estimations, projections, proposals, plans or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as the future timing and results of drilling individual wells and other exploration and development activities; future variations in well performance as compared to initial test data; future events that may result in the need for additional capital; the prices at which we may be able to sell oil or gas; fluctuations in prevailing prices for oil and gas; 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.

Our gas in Poland is sold to the Polish Oil and Gas Company, or POGC, or its subsidiaries under contracts that extend for the life of each field. Prices are determined contractually and, in the case of our Wilga and Zaniemysl wells, are tied to published tariffs. Gas sold at Kleka is sold at a fixed price without regard to any published tariff or index. The currently limited volumes and sources of our gas production mean we cannot assure uninterruptible production or production in amounts that would be meaningful to industrial users, which may depress the price we may be able to obtain by limiting our market for potential customers. POGC is the primary purchaser of domestic gas in Poland. We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in a more competitive setting and may be lower than prevailing western European prices, at least until a fully competitive market develops in Poland.

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 in the future.

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Foreign Currency Risk

We have entered into various agreements in Poland denominated in the Polish zloty. The Polish zloty is subject to exchange rate fluctuations that are beyond our control. We do not currently engage in hedging transactions to protect ourselves against foreign currency risks, nor do we intend to do so in the immediate future; our policy is to use zloty-based revenues generated in Poland to pay for all zloty-based invoices, supplemented as needed by transferring US dollars to Poland to cover invoices that exceed the generated revenues.

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, 2007, pursuant to Rule 13a-15(b) under the Securities Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2007, 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, 2006. There have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2006, 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.

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ITEM 6. EXHIBITS

The following exhibits are filed as a part of this report:

Exhibit Number*	Title of Document	Location
Item 10	Material Contracts
10.83	Form of Stock Purchase Agreement	Incorporated by reference from the current report on Form 8-K filed July 5, 2007
Item 31	Rule 13a-14(a)/15d-14(a) Certifications
31.01	Certification of Chief Executive Officer Pursuant to Rule 13a-14	Attached
31.02	Certification of Principal Financial Officer Pursuant to Rule 13a-14	Attached
Item 32	Section 1350 Certifications
32.01	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Attached
32.02	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Attached

__________________

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

SIGNATURES

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

FX ENERGY, INC.

(Registrant)

Date: November 8, 2007 By: /s/ David N. Pierce

David N. Pierce, President, Chief Executive Officer

Date: November 8, 2007 By: /s/ Clay Newton

Clay Newton, Principal Financial Officer

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