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EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INCex3101q093011.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 INCex3201q093011.htm
EXCEL - IDEA: XBRL DOCUMENT - FX ENERGY INCFinancial_Report.xls
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INCex3102q093011.htm
EX-31.02 - 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 INCex3202q093011.htm
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2011
   
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______________ to _______________

Commission File No. 000-25386

FX ENERGY, INC.
(Exact name of registrant as specified in its charter)

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

3006 Highland Drive, Suite 206
Salt Lake City, Utah  84106
(Address of principal executive offices and zip code)

(801) 486-5555
(Registrant’s telephone number, including area code)

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

Yes
x
No
o

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
x
No
o

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
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 3, 2011, was 52,777,002.

 
 

 


FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Three Months Ended September 30, 2011



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
14
3
Quantitative and Qualitative Disclosures about Market Risk
23
4
Controls and Procedures
24
     
 
Part II—Other Information
 
     
1A
Risk Factors
25
6
Exhibits
25
--
Signatures
26

2

 
 

 

PART I—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
(in thousands)


 
September 30,
 
December 31,
 
2011
 
2010
ASSETS
         
           
Current assets:
         
Cash and cash equivalents
$
15,193 
 
$
19,740 
Receivables:
         
Accrued oil and gas sales
 
2,527 
   
2,617 
Joint interest and other receivables
 
3,009 
   
2,013 
VAT receivable
 
739 
   
392 
Inventory
 
270 
   
242 
Other current assets
 
329 
   
293 
Total current assets
 
22,067 
   
25,297 
           
Property and equipment, at cost:
         
Oil and gas properties (successful efforts method):
         
Proved
 
47,713 
   
38,528 
Unproved
 
3,417 
   
3,320 
Other property and equipment
 
9,845 
   
8,853 
Gross property and equipment
 
60,975 
   
50,701 
Less accumulated depreciation, depletion and amortization
 
(14,413)
   
(12,327)
Net property and equipment
 
46,562 
   
38,374 
           
Other assets:
         
Certificates of deposit
 
406 
   
406 
Loan fees
 
1,929 
   
2,527 
Total other assets
 
2,335 
   
2,933 
           
Total assets
$
70,964 
 
$
66,604 

 
-Continued-

The accompanying notes are an integral part of these consolidated financial statements.
 
3

 
 

 

FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
(in thousands, except share data)
-Continued-


 
September 30,
 
December 31,
 
2011
 
2010
LIABILITIES AND STOCKHOLDERS’ EQUITY
         
           
Current liabilities:
         
Accounts payable
$
6,043 
 
$
5,742 
Accrued liabilities
 
1,057 
   
1,343 
Total current liabilities
 
7,100 
   
7,085 
           
Long-term liabilities:
         
Notes payable
 
-- 
   
35,000 
Asset retirement obligation
 
940 
   
682 
Total long-term liabilities
 
940 
   
35,682 
           
Total liabilities
 
8,040 
   
42,767 
           
Stockholders’ equity:
         
Preferred stock, $0.001 par value, 5,000,000 shares authorized
         
as of September 30, 2011, and December 31, 2010; no shares
         
outstanding
 
-- 
   
-- 
Common stock, $0.001 par value, 100,000,000 shares authorized
         
as of September 30, 2011, and December 31, 2010; 52,777,002
         
and 45,284,527 shares issued and outstanding as of
         
September 30, 2011, and December 31, 2010, respectively
 
53 
   
45 
Additional paid-in capital
 
218,836 
   
171,167 
Cumulative translation adjustment
 
23,869 
   
14,013 
Accumulated deficit
 
(179,834)
   
(161,388)
Total stockholders’ equity
 
62,924 
   
23,837 
           
Total liabilities and stockholders’ equity
$
70,964 
 
$
66,604 

 

The accompanying notes are an integral part of these consolidated financial statements.
 
4

 
 

 

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,
 
2011
 
2010
 
2011
 
2010
Revenues:
             
Oil and gas sales
$  7,552
 
$   5,242
 
$ 22,463 
 
$ 16,785 
Oilfield services
2,568
 
1,406
 
3,986 
 
2,128 
Total revenues
10,120
 
6,648
 
26,449 
 
18,913 
               
Operating costs and expenses:
             
Lease operating expenses
1,064
 
824
 
2,865 
 
2,502 
Exploration costs
5,237
 
361
 
12,168 
 
1,886 
Property impairment
--
 
39
 
-- 
 
554 
Oilfield services costs
1,640
 
764
 
2,981 
 
1,375 
Depreciation, depletion and amortization
930
 
524
 
2,598 
 
1,629 
Accretion expense
21
 
20
 
55 
 
59 
Stock compensation
412
 
354
 
1,123 
 
1,057 
General and administrative
1,676
 
1,496
 
5,799 
 
5,476 
Total operating costs and expenses
10,980
 
4,382
 
27,589 
 
14,538 
               
Operating income (loss)
(860)
 
2,266
 
(1,140)
 
4,375 
               
Other income (expense):
             
Interest expense
(512)
 
(990)
 
(1,547)
 
(1,310)
Interest and other income
23
 
789
 
131 
 
812 
Foreign exchange gain (loss)
(26,178)
 
20,087
 
(15,890)
 
(2,879)
Total other income (expense)
(26,667)
 
19,886
 
(17,306)
 
(3,377)
               
Net income (loss)
(27,527)
 
22,152
 
(18,446)
 
998 
               
Other comprehensive income (loss)
             
Foreign currency translation adjustment
16,665
 
(15,415)
 
9,856 
 
2,151 
Comprehensive income (loss)
$ (10,862)
 
$   6,737
 
$  (8,590)
 
$   3,149 
               
Net income (loss) per common share
             
Basic
$   (0.53)
 
$      0.51 
  
$    (0.37)
 
$     0.02 
Diluted
$   (0.53)
 
$      0.51 
 
$    (0.37)
 
$     0.02 
Weighted average common shares outstanding
             
Basic
51,691
 
43,261
 
49,756 
 
43,246 
Dilutive effect of stock options
-
 
-
 
 
Diluted
51,691
 
43,261
 
49,756 
 
43,246 


 
The accompanying notes are an integral part of these consolidated financial statements.
 
5

 
 

 

FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)


 
For the Nine Months Ended
 
September 30,
 
2011
 
2010
Cash flows from operating activities:
         
Net income (loss)
$
(18,446)
 
$
998 
Adjustments to reconcile net loss to net cash
         
provided by (used in) operating activities:
         
Depreciation, depletion and amortization
 
2,598 
   
1,629 
Accretion expense
 
55 
   
59 
Amortization of bank fees
 
429 
   
740 
Property impairment
 
-- 
   
554 
Stock compensation
 
1,123 
   
1,057 
Foreign exchange (gains) losses
 
15,874 
   
2,769 
Common stock issued for services
 
711 
   
635 
Increase (decrease) from changes in working capital items:
         
Receivables
 
(2,581)
   
(841)
Inventory
 
(28)
   
(6)
Other current assets
 
(36)
   
107 
Other assets
 
-- 
   
(58)
Accounts payable and accrued liabilities
 
1,535 
   
(1,422)
Net cash provided by operating activities
 
1,234 
   
6,221 
           
Cash flows from investing activities:
         
Additions to oil and gas properties
 
(14,866)
   
(2,483)
Additions to other property and equipment
 
(1,015)
   
(746)
Net cash used in investing activities
 
(15,881)
   
(3,229)
           
Cash flows from financing activities:
         
Proceeds from stock option exercises
 
800 
   
-- 
Proceeds from common stock offering, net
 
45,042 
   
-- 
Proceeds from credit facility
 
-- 
   
27,468 
Payments made on credit facility
 
(35,000)
   
(25,000)
Payment of loan fees
 
-- 
   
(2,468)
Net cash provided by financing activities
 
10,842 
   
-- 
           
Effect of exchange-rate changes on cash
 
(742)
   
36 
           
Net decrease in cash
 
(4,547)
   
3,028 
Cash and cash equivalents at beginning of year
 
19,740 
   
4,225 
           
Cash and cash equivalents at end of period
$
15,193 
 
$
7,253 



The accompanying notes are an integral part of these consolidated financial statements.
 
6

 
 

 

FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
(Unaudited)



Note 1:  Basis of Presentation

In the opinion of management, our financial statements reflect the adjustments, all of which are of a normal recurring nature, necessary for presentation of financial statements for interim periods in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions to Form 10-Q in Article 10 of SEC Regulation S-X.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting periods.  Actual results could differ from those estimates.  As used in this report, the terms “we,” “us,” “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, 2010, and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2011.

We evaluated subsequent events through the date of our financial statement issuance.  In October 2011, we drew $40 million under our credit facility.  No other events were identified that had a material impact on the financial statements.

Note 2:  Net Income per Share

Basic earnings per share is computed by dividing the net income (loss) applicable to common shares by the weighted average number of common shares outstanding.  Diluted earnings per share was computed for the three- and nine-month periods ended September 30, 2010, by dividing the net income by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options.  Basic and diluted earnings per share were essentially the same for each of these periods.  We had a net loss in the three- and nine-month periods ended September 30, 2011.  No options were included in the computation of diluted earnings per share for this period because the effect would have been antidilutive.

Outstanding options and unvested restricted stock as of September 30, 2011 and 2010, were as follows:

 
Options and
   
 
Unvested Restricted Stock
 
Price Range
Balance sheet date:
     
September 30, 2011
1,732,211
 
$0.00 - $10.65
September 30, 2010
2,151,660
 
$0.00 - $10.65
 
7
 
 

 


Note 3:  Income Taxes

No income tax expense was recognized for the three- and nine-month periods ended September 30, 2011, due to the net losses recorded for each period.  No income tax expense was recognized for the three- and nine-month periods ended September 30, 2010, due to the valuation allowances that offset income tax expense for the period.  We are required to provide a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.  Our ability to realize the benefit of deferred tax assets will depend on the generation of future taxable income through profitable operations and the expansion of exploration and development activities.  The market and capital risks associated with achieving the above requirement are considerable, resulting in our conclusion that a full valuation allowance be provided.  We are subject to audit by the IRS and various states for the prior three years.  We do not believe there will be any material changes in our unrecognized tax positions over the next 12 months, nor has there been a change in our unrecognized tax positions since December 31, 2010.  Our policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense.  We do not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense related to unrecognized tax benefits recognized during the nine months ended September 30, 2011.

Note 4:  Business Segments

We operate within two segments of the oil and gas industry: the exploration and production segment and the oilfield services segment.  Direct revenues and costs, including exploration costs, depreciation, depletion and amortization costs (“DD&A”), general and administrative costs (“G&A”), and other income directly associated with their respective segments are detailed within the following discussion.  Identifiable net property and equipment are reported by business segment for management reporting and reportable business segment disclosure purposes.  Current assets, other assets, current liabilities, and long-term debt are not allocated to business segments for management reporting or business segment disclosure purposes.

Reportable business segment information for the three months ended September 30, 2011, the nine months ended September 30, 2011, and as of September 30, 2011, is as follows (in thousands):

 
Reportable Segments
   
 
Exploration & Production
Oilfield Services
Non-Segmented
Total
 
U.S.
Poland
     
Three months ended September 30, 2011:
         
Revenues
$ 1,072
$  6,480
$ 2,568
$         --  
$ 10,120  
Net income (loss)(1)
311
266
668
(28,772)
(27,527)
Nine months ended September 30, 2011:
         
Revenues
$ 3,551
$18,912
$ 3,986
$         --  
$ 26,449
Net income (loss)(1)
1,191
4,345
296
(24,278)
(18,446)
As of September 30, 2011:
         
Identifiable net property and equipment
$ 2,677
$40,821
$ 3,035
$       29  
$ 46,562
_______________
 
(1)
Nonsegmented reconciling items for the third quarter include $1,676 of G&A costs, $412 of noncash stock compensation expense, $488 of other expense, $17 of corporate DD&A costs, and $26,179 of foreign exchange losses.  Nonsegmented reconciling items for the first nine months include $5,799 of G&A costs, $1,123 of noncash stock compensation expense, $1,415 of other expense, $51 of corporate DD&A costs, and $15,890 of foreign exchange losses.
 
8
 
 

 


Reportable business segment information for the three months ended September 30, 2010, the nine months ended September 30, 2010, and as of September 30, 2010, is as follows (in thousands):

 
Reportable Segments
   
 
Exploration & Production
Oilfield Services
Non-Segmented
Total
 
U.S.
Poland
     
Three months ended September 30, 2010:
         
Revenues
$ 1,035
$  4,207
$ 1,406
$         --  
$   6,648
Net income (loss)(1)
286
3,324
443
18,099  
22,152
Nine months ended September 30, 2010:
         
Revenues
$ 3,114
$13,671
$ 2,128
$         --  
$ 18,913
Net income (loss)(1)
1,169
9,499
218
(9,888)
998
As of September 30, 2010:
         
Identifiable net property and equipment
$ 1,075
$29,749
$ 2,360
$       62  
$ 33,246
_______________
 
(1)
Nonsegmented reconciling items for the third quarter include $1,496 of G&A costs, $354 of noncash stock compensation expense, $119 of other expense, $19 of corporate DD&A costs, and $20,087 of foreign exchange gains.  Nonsegmented reconciling items for the first nine months include $5,476 of G&A costs, $1,057 of noncash stock compensation expense, $415 of other expense, $61 of corporate DD&A costs, and $2,879 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 ranging from five to seven years and vest over periods ranging from the date of grant to three years.  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 nine months of 2011:

       
Weighted
 
Weighted Average
   
       
Average
 
Remaining
 
Aggregate
   
Number of
 
Exercise
 
Contractual
 
Intrinsic
   
Options
 
Price
 
Life (in years)
 
Value
Options outstanding:
               
Beginning of year
 
832,332
 
$8.42
       
Granted
 
636,509
 
5.06
       
Expired
 
(215,533)
 
8.37
       
Exercised
 
(581,799)
 
8.35
       
End of period
 
671,509
 
5.31
 
9.51
   
Exercisable at end of period
 
35,000
 
9.89
 
0.64
 
$0

During the third quarter of 2011, we issued 636,509 stock options with an exercise price of $5.06 per share, resulting in deferred compensation of $2,794,275, which will be amortized ratably over a three-year vesting period.  Expense recognized during the third quarter of 2011 totaled $35,726.
 
9

 
 

 


The following table summarizes option activity for the first nine months of 2010:

   
Weighted
Weighted Average
 
 
Number of
Average
Remaining Contractual
Aggregate
 
Options
Exercise Price
Life (in years)
Intrinsic Value
         
Options outstanding:
       
Beginning of year
1,470,441
$6.47
   
Exercised
(51,000)
  3.19
   
End of period
1,419,441
  6.58
0.84
 
Exercisable at end of period
1,419,441
  6.58
0.84
$93,937

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $4.13 as of September 30, 2011, and $4.14 as of September 30, 2010, which would have been received by stock option holders had all vested in-the-money stock options been exercised as of those dates.

Restricted Stock

During the third quarter of 2011, we issued 318,251 shares of restricted stock, resulting in deferred compensation of $1,610,352, which will be amortized ratably over a three-year vesting period.  Expense recognized during the third quarter of 2011 totaled $20,589.

During 2010, we issued 373,500 shares of restricted stock, resulting in deferred compensation of $2,259,675, which will be amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2011 totaled $564,918.

During 2009, we issued 379,500 shares of restricted stock, resulting in unamortized compensation expense of $1,043,625, which will be amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2011 and 2010 totaled $260,087 and $259,187, respectively.

During 2008, we issued 367,000 shares of restricted stock, resulting in unamortized compensation expense of $1,005,580, which will be amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2011 and 2010 totaled $241,254 and $250,249, respectively.

During 2007, we issued 370,925 shares of restricted stock, resulting in unamortized compensation expense of $2,284,991, which will be amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2010 totaled $547,718.

The following table summarizes restricted stock activity during the first nine months of 2011 and 2010:

 
Number of Shares
 
2011
 
2010
Unvested restricted stock outstanding:
     
Beginning of year
746,398
 
739,535
Issued
318,251
 
--
Forfeited
(3,947)
 
(2,382)
Vested
--
 
(4,934)
End of period
1,060,702
 
732,219
 
10
 
 

 

 
Note 6:  Stockholders’ Equity

During the first nine months of 2011, we sold 6,900,000 shares of common stock in a registered public offering at a price of $7.00 per share.  After offering costs, the net proceeds from the offering were approximately $45.0 million, part of which was used to pay down our credit facility balance.  See Note 8 for more information.  Option holders exercised options with cash to purchase 96,799 shares of common stock during the first nine months of 2011, which resulted in proceeds of approximately $800,000.  Option holders exercised an additional 485,000 outstanding options at a price of $8.37 per share by surrendering currently owned shares to pay the exercise price.  As a result of this exercise, we issued 65,571 incremental shares.  Also during the first nine months of 2011, we issued 106,301 shares for the 2010 contribution to our employee benefit plan and 9,500 shares to consultants for services.

During the first nine months of 2010, option holders exercised a total of 39,000 outstanding options at a price of $3.84 per share by surrendering currently owned shares to pay the exercise price.  As a result of this exercise, we issued 6,500 incremental shares.  In June of 2010, option holders exercised a total of 12,000 outstanding options at a price of $3.14 per share by surrendering currently owned shares to pay the exercise price.  As a result of this exercise, we issued 2,436 incremental shares.  In January of 2010, we issued 216,977 shares for the 2009 contribution to our employee benefit plan.  In addition, we issued 6,000 shares to consultants for services.

Note 7:  Fair Value Measurements

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

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

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

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

A review of fair value hierarchy classifications is conducted on a quarterly basis.  Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.  
 
We did not have any significant nonfinancial assets or nonfinancial liabilities that would be recognized or disclosed at fair value on a recurring basis as of September 30, 2011, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first nine months of 2011.

Recurring Fair Value

The following table sets forth the financial assets and liabilities that we measured at fair value on a recurring basis by level within the fair value hierarchy.  We classify assets and liabilities measured at fair value in their entirety based on the lowest level of input that is significant to their fair value measurement.
 
11
 
 

 
Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 30, 2011 (in thousands):

 
September 30,
           
 
2011
 
Level 1(1)
 
Level 2(2)
 
Level 3(3)
Cash equivalents:
             
Money market funds
$5,097
 
$5,097
 
--
 
--
_______________
 
(1)
Quoted prices in active markets for identical assets.
(2)
Significant other observable inputs.
(3)
Significant unobservable inputs.

Note 8:  Notes Payable

We have a $55 million Senior Reserve Base Lending Facility (the “Facility”) with the Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV.  The Facility calls for a periodic interest rate of LIBOR, plus an interest margin of 4.0%, and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on September 30, 2013.  The Facility is an interest-only facility until then.  An annual unused commitment fee of one-half of the applicable interest margin is charged quarterly based on the average daily unused portion of the expanded credit facility.  We amortized approximately $429,000 of deferred financing costs associated with our existing Facility to interest expense during the first nine months of 2011.  Payment of the Facility is secured by our assets in Poland and guaranteed by FX Energy, Inc.  We used proceeds from the offering described in Note 6 to repay all balances outstanding under the Facility.  As of September 30, 2011, we did not have any loans outstanding.  Subsequent to September 30, 2011, we drew the entire available balance of $40 million under the Facility.

We have access to an additional $15 million under the Facility as soon as our Kromolice-1, Sroda-4, and Kromolice-2 wells have been on production at the same time for 30 days.  Proceeds from the Facility are intended to support our development, production, and operating activities in Poland.

Note 9:  Capitalized Exploratory Well Costs

We had $3.7 million and $2.4 million of capitalized costs related to our Plawce-2 and Kutno wells, respectively, which were in progress at September 30, 2011.  In addition, we had capitalized costs of approximately $668,000 associated with two wells related to our Alberta Bakken project, pending further testing.  See Note 11 for more information.

Note 10:  Foreign Currency Translation and Risk

During the first nine months of 2011, we recorded foreign currency transaction losses of approximately $15.9 million.  This amount was attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany and other dollar-denominated loans and unpaid interest.  There was a corresponding credit to other comprehensive income for losses attributable to the intercompany loans, which was then offset by translation adjustments related to our other balance sheet accounts.
 
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The following table provides a summary of changes in cumulative translation adjustment (in thousands):

 
For the Nine Months
 
Ended September 30, 2011
Balance at December 31, 2010
$ 14,013 
Increase related to losses on intercompany loans
15,874 
Decrease related to translation adjustments
(6,018)
Balance at September 30, 2011
$ 23,869 

Future transaction gains or losses may be significant given the amount of intercompany loans and the volatility of the exchange rate.  Future translation adjustments will also vary in concert with changes in exchange rates.  These gains, losses, and adjustments are noncash items for U.S. reporting purposes and have no impact on our actual zloty-based revenues and expenditures in Poland.

We enter into various agreements in Poland denominated in the Polish zloty, which is subject to exchange-rate fluctuations.  Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues.  We do not use derivative financial instruments for trading or speculative purposes.

Note 11: Montana Joint Venture

During the second quarter of 2011, we entered into a joint venture with American Eagle Energy, Inc., and Big Sky Operating LLC, to jointly explore approximately 75,000 acres in the Alberta Bakken formation in Northwest Montana.  Our net interest in approximately 8,700 acres in the Southwest Cut Bank Sand Unit will be included in the joint exploration program and we will own a one-third interest in the overall project.  As part of our agreement, we have agreed to drill wells for the joint venture at customary retail rates.

As consideration for our one-third interest, we agreed to pay a purchase price of approximately $860,000 in land and associated costs to our partners.  The purchase price was reduced by approximately $349,000, which is the value attributed to the deeper rights in the acreage we contributed to the joint venture.

Through September of 2011, we have deepened one well in our Southwest Cut Bank Sand Unit and drilled a new test well in the newly acquired acreage.  While we have no current plans to complete the Cut Bank Sand Unit well in the deeper formation, both wells are undergoing further testing.  After eliminating all intercompany transactions, we capitalized our share of the cost of both projects, totaling approximately $668,000.

Note 12:  Contingencies

We may face financial sanctions as a result of an oil spill that occurred at our South West Cut Bank Sand Unit in Montana during June of 2011.  We are cooperating with the Blackfeet Tribe and the Environmental Protection Agency in completing clean-up, mitigation, and restoration pursuant to an approved plan.  Cleanup costs have exceeded the amount originally estimated by the cleanup contractor of approximately $150,000.  The total amount incurred through September 30, 2011, is approximately $311,000 and is included in operating costs.  We believe that we have satisfactorily completed the clean-up according to the specifications provided by the Blackfeet Tribe and the EPA.
 
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The majority of our operations are in Poland, and we have devoted most of our technical talent and capital expenditures in the last several years to our operations in that country.  Our operations in Poland, which are a combination of existing production and substantial exploration, have grown considerably.  Oil and gas production, oil and gas revenues, oil and gas reserves, and oil and gas expenditures in this area have grown significantly over the last three years.

Our U.S. operations also have an impact.  Our U.S. operations are smaller than those in Poland and have not presented the same level of opportunities for expansion; however, we currently are initiating exploration of the Bakken shale in our area, which may warrant further exploration.  Our U.S. oil production is a relatively stable source of cash flow, while our domestic oilfield services provide varying amounts of cash flow depending on third-party drilling activities in the area.  This, too, is reflected in our operating results.

Results of Operations by Business Segment

Quarter Ended September 30, 2011, Compared to the Same Period of 2010

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $6.5 million during the third quarter of 2011, compared to $4.2 million during the same quarter of 2010.  New production at our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells was an important component in significantly increased 2011 third quarter natural gas production and revenues.

A summary of the amount and percentage change, as compared to the respective prior-year period, for gas revenues, average gas prices, and gas production volumes for the quarters ended September 30, 2011 and 2010, is set forth in the following table:

 
For the Quarter Ended September 30,
   
 
2011
 
2010
 
Change
Gas revenues
$6,480,000
 
$4,207,000
 
+54%
Average price (per thousand cubic feet)
$6.37
 
$5.30
 
+20%
Production volumes (thousand cubic feet)
1,017,000
 
794,000
 
+28%

As we discussed in our Form 10-Q for the period ended June 30, 2011, both our Roszkow and Zaniemysl wells were shut in for two weeks during September 2011 for annual maintenance and pressure testing.  Following the maintenance and pressure testing, the operator of both wells, the Polish Oil and Gas Company, or PGNiG, reduced the daily production at our Roszkow well by approximately 3%, while production at our Zaniemysl well resumed at prior levels.
 
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In addition to our increased production, three factors resulted in higher gas revenues during the 2011 quarter.  First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 12% higher during the third quarter of 2011 compared to the same quarter of 2010.  The increase was a function of price changes implemented by the Polish utility regulator during the second half of 2010 and the first nine months of 2011, including a 12.5% increase that became effective for us on August 1, 2011.  Second, period-to-period strength in the Polish zloty against the U.S. dollar increased our U.S. dollar-denominated gas prices.  The average exchange rate during the third quarter of 2011 was 2.94 zlotys per U.S. dollar.  The average exchange rate during the third quarter of 2010 was 3.10 zlotys per U.S. dollar, a change of approximately 5%.  Third, with the addition of production from our KSK wells, where we receive approximately 86% of the low-methane tariff, our weighted average price per thousand cubic feet of natural gas increased slightly.

Oil Revenues.  Oil revenues were $1.1 million for the third quarter of 2011, a 4% increase from $1.0 million recognized during the third quarter of 2010.  Production levels decreased, due to normal production declines, by approximately 12% from 2010 to 2011.  The decrease in production was more than offset by the higher prices received during the third quarter of 2011.  Our average oil price during the third quarter of 2011 was $77.26 per barrel, an 18% increase from $65.31 per barrel received during the same quarter of 2010.

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, 2011 and 2010, is set forth in the following table:

 
For the Quarter Ended September 30,
   
 
2011
 
2010
 
Change
Oil revenues
$1,072,000
 
$1,035,000
 
+4%
Average price (per barrel)
$77.26
 
$65.31
 
+18%
Production volumes (barrels)
13,900
 
15,800
 
-12%

Lease Operating Costs.  Lease operating costs of $1,064,000 during the third quarter of 2011 were 29% higher than the third quarter 2010 amount of $824,000.  Included in third quarter 2011 operating costs is approximately $161,000 associated with our Montana oil spill clean-up.  Without the clean-up costs, third quarter 2011 operating costs would have been 10% higher than third quarter 2010 operating costs.  Those additional operating costs are related to new production at our KSK wells.

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $5.2 million during the third quarter of 2011, compared to $361,000 during the same period of 2010.

Third quarter 2011 exploration costs included approximately $1.6 million associated with our Lisewo southeast three-dimensional, or 3-D, seismic survey, $2.6 million associated with new two-dimensional, or 2-D, seismic surveys at our 100%-owned concessions in Poland, and $1.0 million of dry-hole costs associated with our Machnatka well.  During the third quarter of 2011, we made the determination that our Machnatka well, which was being drilled in our Warsaw South concession, did not find commercial quantities of oil or gas.  Under the terms of a joint operating agreement, our partner agreed to pay 100% of the costs of the well to a depth of 3,558 meters.  After reaching that depth, the partners agreed to continue drilling to a depth of approximately 4,500 meters.  Our share of the dry-hole costs is equal to 51% of the incremental drilling costs incurred drilling the additional 952 meters.

Third quarter 2010 geological and geophysical costs were primarily associated with 2-D seismic surveys on our 100%-owned acreage in Poland.
 
15
 
 

 
Property Impairment.  There were no property impairments during 2011.  Third quarter 2010 property impairment costs include $39,000 of additional costs associated with our Kleka well, which ceased production in 2010, the capital costs of which were impaired during the second quarter.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $652,000 for the third quarter of 2011, an increase of 114% compared to $305,000 during the same period of 2010.  Higher DD&A expense in 2011 was due in part to new depreciation expense at our KSK wells, which we began to depreciate as production began in late 2010 and in mid-2011.  In addition, we recorded higher depreciation expense at our Roszkow well due to depreciating existing costs over a smaller reserve base because of year-end 2010 negative reserve revisions.

Accretion Expense.  Accretion expense was $21,000 and $20,000 for the third quarter of 2011 and 2010, 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 $2.6 million during the third quarter of 2011, an increase of 83% compared to $1.4 million for the third quarter of 2010.  We drilled five wells for third parties, including those drilled for our Alberta Bakken joint venture, during the third quarter of 2011, along with additional well service work.  During the third quarter of 2010, we drilled three wells for third parties.  Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

Oilfield Services Costs.  Oilfield services costs were $1,640,000 during the third quarter of 2011, compared to $764,000 during the same period of 2010.  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 $261,000 during the third quarter of 2011, compared to $199,000 during the same period of 2010.  The quarter-to-quarter increase was primarily due to depreciation on recent capital additions.

Nonsegmented Information

G&A Costs.  G&A costs were $1.7 million during the third quarter of 2011, up 12% from third quarter of 2010 levels.  The increase is primarily due to higher compensation, legal and travel costs in 2011.

Stock Compensation (G&A).  For the three-month periods ended September 30, 2011 and 2010, we recognized $412,000 and $354,000, respectively, of stock compensation expense related to the amortization of deferred compensation related to stock option and restricted stock grants.

Interest and Other Income (Expense).  Interest and other income was $23,000 during the third quarter of 2011, compared to $789,000 during the same period of 2010.  Included in the 2010 amount was a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008.
 
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During the third quarter of 2011, we incurred $512,000 in interest expense, which included $139,000 of amortization of loan fees and $373,000 in unused commitment fees.  During the third quarter of 2010, we incurred $990,000 in interest expense.  In connection with our new credit facility, we charged $577,000 of previously unamortized loan fees associated with our prior credit facility to interest expense during the third quarter of 2010.  We also recorded $122,000 of amortization of loan fees and $87,000 in unused commitment fees during that quarter.

Foreign Exchange Gain (Loss).  During the third quarter of 2011, we recorded foreign currency transaction losses of approximately $26.2 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans.  We recorded foreign exchange gains of $20.1 million during the same quarter of 2010, which were also principally related to our intercompany loans.  During the third quarter of 2011, the zloty weakened by approximately 18% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction losses.  During the third quarter of 2010, the zloty strengthened by approximately 14% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.

Nine Months Ended September 30, 2011, Compared to the Same Period of 2010

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $18.9 million during the first nine months of 2011, compared to $13.7 million during the same period of 2010.  New production at our KSK wells was an important component in significantly increased 2011 third quarter natural gas production and 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 nine months ended September 30, 2011 and 2010, is set forth in the following table:

 
For the Nine Months
Ended September 30,
   
 
2011
 
2010
 
Change
Revenues
$18,912,000
 
$13,670,000
 
+38%
Average price (per thousand cubic feet)
$6.28
 
$5.19
 
+21%
Production volumes (thousand cubic feet)
3,009,000
 
2,632,000
 
+14%

In addition to our increased production, three factors discussed earlier resulted in higher gas revenues during the first nine months of 2011.  First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 10.5% higher during the first nine months of 2011 compared to the same period of 2010.  The increase was a function of price changes implemented by the Polish utility regulator during the second half of 2010 and the first nine months of 2011, including a 12.5% increase that became effective for us on August 1, 2011.  Second, period-to-period strength in the Polish zloty against the U.S. dollar increased our U.S. dollar-denominated gas prices.  The average exchange rate during the first nine months of 2011 was 2.86 zlotys per U.S. dollar.  The average exchange rate during the same period of 2010 was 3.05 zlotys per U.S. dollar, a change of approximately 6%.  Third, with the addition of production from our KSK wells, where we receive approximately 86% of the low-methane tariff, our weighted average price per thousand cubic feet of natural gas increased slightly.
 
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Oil Revenues.  Oil revenues were $3.6 million for the first nine months of 2011, a 14% increase from the $3.1 million recognized during the first nine months of 2010.  Production from our U.S. properties declined 8% during the first nine months of 2011 due to regular production declines.  The most significant factor in the increase in oil revenues was the higher prices received during the first nine months of 2011.  Our average oil price during the first nine months of 2011 was $83.09 per barrel, a 24% increase from $66.81 per barrel received during the same period of 2010.

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, 2011 and 2010, is set forth in the following table:

 
For the Nine Months
Ended September 30,
   
 
2011
 
2010
 
Change
Revenues
$3,551,000
 
$3,114,000
 
+14%
Average price (per barrel)
$83.09
 
$66.81
 
+24%
Production volumes (barrels)
42,700
 
46,600
 
-8%

Lease Operating Costs.  Lease operating costs were $2.9 million during the first nine months of 2011, an increase of 15% compared to the same period of 2010.  Included in our nine-month 2011 operating costs is approximately $311,000 associated with our Montana oil spill clean-up.  Without the clean-up costs, nine-month 2011 operating costs would have been only 4% higher than nine-month 2010 operating costs.  Those additional operating costs are related to new production at our KSK wells.

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $12.2 million during the first nine months of 2011, compared to $1.9 million during the same period of 2010.  Our 2011 exploration costs do not include approximately $11 million that were spent by our partner to earn a 50% working interest in our Warsaw South concession.  The period-to-period increase is attributable primarily to our higher level of seismic activity in 2011 compared to 2010.  Nine-month 2011 exploration costs included approximately $3.0 million associated with our Lisewo southeast 3-D seismic survey, $7.9 million associated with new 2-D seismic surveys at our 100%-owned concessions in Poland, and $1.3 million of dry-hole costs associated with our Machnatka well.  First nine months 2010 geological and geophysical costs were primarily associated with 2-D seismic surveys of approximately $1.0 million on our 100%-owned acreage in Poland and $872,000 of dry-hole costs associated with our Zakowo project.

Property Impairment.  We had no property impairments during the first nine months of 2011.  During 2010, remediation efforts at our Kleka well failed to restore commercial production.  Accordingly, we impaired the remaining capital costs for the well of approximately $554,000 during the first nine months of 2010.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $1.8 million for the first nine months of 2011, an increase of 80% compared to $1.0 million during the same period of 2010.  Higher DD&A expense in 2011 was due in part to new depreciation expense at our KSK wells.  In addition, we recorded higher depreciation expense at our Roszkow well due to depreciating existing costs over a smaller reserve base because of year-end 2010 negative reserve revisions.

Accretion Expense.  Accretion expense was $55,000 and $59,000 for the first nine months of 2011 and 2010, respectively.  Accretion expense is related entirely to our Asset Retirement Obligation.
 
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Oilfield Services Segment

Oilfield Services Revenues.  Oilfield services revenues were $4.0 million during the first nine months of 2011, an increase of 87% compared to $2.1 million for the first nine months of 2010.  We drilled nine wells for third parties during the first nine months of 2011, along with additional well service work.  During the first nine months of 2010, we drilled seven wells for third parties.  Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our Company-owned properties, and other factors.

Oilfield Services Costs.  Oilfield services costs were $3.0 million during the first nine months of 2011, compared to $1.4 million during the same period of 2010.  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 $709,000 during the first nine months of 2011, compared to $535,000 during the same period of 2010.  The period-to-period increase was primarily due to new depreciation from capital additions in 2010 and 2011.

Nonsegmented Information

G&A Costs.  G&A costs were $5.8 million during the first nine months of 2011, compared to $5.5 million during the first nine months of 2010, an increase of $323,000.  Higher legal, investor relations, and travel costs were mostly offset by lower compensation costs in the first nine months of 2011.

Stock Compensation (G&A).  For the nine-month periods ended September 30, 2011 and 2010, we recognized $1.1 million and $1.1 million, respectively, of stock compensation expense related to the amortization of deferred compensation related to stock option and restricted stock grants.

Interest and Other Income.  Interest and other income was $131,000 during the first nine months of 2011, compared to $812,000 during the same period of 2010.  Included in the 2010 amount was a gain of approximately $772,000 attributable to the sale of tubing associated with our Grundy-1 well, which was drilled and abandoned during 2008.

During the first nine months of 2011, we incurred $1.5 million in interest expense.  We recorded $429,000 of amortization of loan fees and $80,000 in unused commitment fees.  During the first nine months of 2010, we incurred $1.3 million in interest expense.  In connection with our new credit facility, we charged $577,000 of previously unamortized loan fees associated with our prior credit facility to interest expense during the period.  We also recorded $245,000 of amortization of loan fees and $87,000 in unused commitment fees.

Foreign Exchange Gain (Loss).  As discussed in Note 11 to the financial statements, during the first nine months of 2011, we recorded foreign currency transaction losses of approximately $15.9 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.  Foreign currency transaction losses during the first nine months of 2010 were $2.9 million.  During the first nine months of 2011, the zloty weakened by approximately 9% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses.  During the first nine months of 2010, the zloty weakened by approximately 3% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses.
 
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Liquidity and Capital Resources

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

Following a registered public offering of 6.9 million shares of common stock, which resulted in net proceeds to us of approximately $45.0 million, in March of 2011 we paid off all amounts previously outstanding under our credit facility.  As of September 30, 2011, we had cash and cash equivalents of $15.1 million and working capital of $15.0 million.

2011 Liquidity and Capital

Working Capital (current assets less current liabilities).  Our working capital was $15.0 million as of September 30, 2011, a decrease of $3.2 million from December 31, 2010.  Our current assets at September 30, 2011, included $2.5 million in accrued oil and gas sales from both the United States and Poland.  Our current liabilities at quarter-end included approximately $3.8 million in costs related to capital and exploration projects in Poland.

Operating Activities.  Net cash provided by operating activities was $1.2 million during the first nine months of 2011, compared to net cash provided by operating activities of $6.2 million during the first nine months of 2010.  Higher revenues in 2011 were offset by increases in exploration spending.

Investing Activities.  During the first nine months of 2011, we used cash of $15.9 million in investing activities.  We used $10.2 million for current-year capital additions in Poland, $1.6 million for current-year capital additions in the United States, $1.0 million for capital additions in our office and drilling equipment, and $3.1 million to pay accounts payable related to prior-year capital costs.  During the first nine months of 2010, we used cash of $3.2 million from investing activities.  We used $1.7 million for current-year capital additions in Poland and $443,000 related to our proved properties in the United States, used $324,000 to pay accounts payable related to prior-year capital costs, and used $744,000 for capital additions in our office and drilling equipment.

Financing Activities.  During the first nine months of 2011, we issued 6.9 million shares of common stock in a registered public offering, which resulted in net proceeds to us, after offering costs, of approximately $45.0 million.  We used $35.0 million of those proceeds to repay amounts outstanding under our credit facility.  We also received proceeds of $800,000 from the exercise of stock options.  There were no similar transactions during the first nine months of 2010.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2011 include our working capital of $15.0 million at September 30, 2011, available credit of $55 million as of such date under our credit facility when we meet the benchmarks discussed below, cash available from our operations, and proceeds from the possible sale of securities.
 
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We currently have a $55 million credit facility with The Royal Bank of Scotland, ING Bank N.V., and KBC Bank NV.  The credit facility calls for a periodic interest rate of LIBOR plus 4.0% and has a term of five years, with semi-annual borrowing base reductions of $11 million each beginning on June 30, 2013.  The credit facility is an interest-only facility until June 2013.  As of September 30, 2011, we had no amounts outstanding under the credit facility.  As of September 30, 2011, we had access to $40 million under the credit facility until our Kromolice-1, Sroda-4, and Kromolice-2 wells have been in production at the same time for 30 days, at which time the full $55 million becomes available.  We expect to reach this benchmark in the fourth quarter of 2011.  Proceeds from the credit facility are intended to support our operating activities in Poland.  Further, we believe our total credit line could be expanded, even without including our recent 2011 Lisewo-1 discovery, in a revised credit facility.

Subsequent to September 30, 2011, we drew $40 million under this facility.  Although all three banks that participate in our Facility successfully passed the recent European bank stress tests, in view of the unsettled circumstances surrounding the secondary credit crisis in Europe, signs of deteriorating sovereign debt conditions in Europe and the uncertain success of efforts to resolve the Euro crisis, we felt it prudent to access these funds to ensure their availability to finance our future capital programs.  Our access to the remaining $15 under our credit facility, when it becomes available, may be adversely affected by the capital stability of our lenders and European credit and economic conditions generally,

We expect production from our KSK wells to increase funds available for exploration and development over 2010 levels.  Our Winna Gora well is expected to begin production in 2012.  In addition, in early 2011, we drilled and completed the successful Lisewo-1 well in our Fences concession, which we expect to further increase revenue in 2013.

We have an effective universal shelf registration statement under the Securities Act of 1933 under which we may sell up to $200 million of equity or debt securities of various kinds.  In December 2010, we sold 1.5 million shares of stock for $9.0 million in a registered public offering, which resulted in net proceeds to us of approximately $8.4 million.  Also in December 2010, we entered into an agreement to possibly sell up to $50 million in common stock during the next two years in at-the-market transactions.  Through the date of this filing, we have not sold any stock under that agreement.  As discussed above, in March 2011, we sold 6.9 million shares of stock for $48.3 million, which resulted in net proceeds to us of approximately $45.0 million.  Assuming all $50 million of common stock covered by the at-the-market facility were sold, the remaining $92.7 million balance of securities available for sale under the registration statement is available for sale at any time, subject to market conditions and our ability to access the capital markets, to further finance our exploration and development plans in Poland and for other corporate purposes.

We use cash primarily for exploration and development activities, most of which are in Poland.  The amount we budgeted earlier in the year for our 2011 planned expenditures was reduced by $11 million invested by our partner, PGNiG, during the first nine months of 2011 to earn an interest in our Warsaw South concession.  In addition to our own expenditures during the first nine months of 2011, we have budgeted about $20 million to complete planned activities, consisting principally of 2-D and 3-D seismic data acquisition and analysis, production facilities for existing discoveries, and additional exploration drilling, during the balance of this year and early 2012.  The actual amount of our expenditures will depend on ongoing exploration results; the pace at which PGNiG, our operating partner in the Fences project area, determines to participate; the availability of drilling and other exploration resources; and the amount of capital we obtain from the various sources discussed above.  Our various sources of liquidity and capital outlined above should more than enable us to meet our capital needs in Poland and the United States for the next 12 months.
 
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Based on current conditions, we presently expect our exploration and development programs will continue in spite of uncertain global economic conditions; however, in recognition of the ongoing economic downturn, we plan to continue, as we have in prior years, matching capital spending with our cash on hand, expected discretionary cash flow, increased debt capacity, and proceeds from the sale of securities.  We have the ability to control the timing and amount of most of our future capital and exploration costs.

We may incur operating losses in future periods, and we continue to fund substantial exploration and development in Poland.  We have a history of operating losses.  From our inception in January 1989 through September 30, 2011, we have incurred cumulative net losses of approximately $180 million.  Despite our recent and expected future increases in production and revenues, our exploration and production activities may continue to result in net losses in future years, depending on the success of our drilling activities in Poland and the United States and whether we generate sufficient revenues to cover related operating expenses.

We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements such as those recently negotiated 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 interest of our existing stockholders or our interest in the specific project financed.

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

New Accounting Pronouncements

We have reviewed all 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 disclosure, 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, 2010.  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.
 
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Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgment due to a high degree of uncertainty at the time the estimate is made.  Our senior management has discussed the development and selection of our accounting policies, related accounting estimates, and the disclosures set forth below with the Audit Committee of our Board of Directors.  We believe our critical accounting policies include those addressing the recoverability and useful lives of assets, the retirement obligations associated with those assets, and the estimates of oil and gas reserves.

Forward-Looking Statements

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

Readers of this report are cautioned that any forward-looking statements, including those regarding us or our management’s current beliefs, expectations, anticipations, estimations, projections, proposals, plans, or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as the future timing and results of drilling individual wells and other exploration and development activities; future variations in well performance as compared to initial test data; future events that may result in the need for additional capital; the prices at which we may be able to sell oil or gas; fluctuations in prevailing prices for oil and gas; our ability to complete the acquisition of targeted new or expanded exploration or development prospects; uncertainties of certain terms to be determined in the future relating to our oil and gas interests, including exploitation fees, royalty rates, and other matters; future drilling and other exploration schedules and sequences for various wells and other activities; uncertainties regarding future political, economic, regulatory, fiscal, taxation, and other policies in Poland; the cost of additional capital that we may require and possible related restrictions on our future operating or financing flexibility; our future ability to attract strategic participants to share the costs of exploration, exploitation, development, and acquisition activities; and future plans and the financial and technical resources of strategic participants.

The forward-looking information is based on present circumstances and on our predictions respecting events that have not occurred, that may not occur, or that may occur with different consequences from those now assumed or anticipated.  Actual events or results may differ materially from those discussed in the forward-looking statements as a result of various factors.  The forward-looking statements included in this report are made only as of the date of this report.  We disclaim any obligation to update any forward-looking statements whether as a result of new information, future events, or otherwise.


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Price Risk

Realized pricing for our oil production in the United States and Poland is primarily driven by the prevailing worldwide price of oil, subject to gravity and other adjustments for the actual oil sold.  Historically, oil prices have been volatile and unpredictable.  Price volatility relating to our oil production is expected to continue in the foreseeable future.
 
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Substantially all of our gas in Poland is sold to PGNiG or its subsidiaries under contracts that extend for the life of each field.  Prices are determined contractually and in the case of our Roszkow, Zaniemysl, Sroda, and Kromolice wells are tied to published tariffs.  The tariffs are set from time to time by the public utility regulator in Poland.  Although we are not directly subject to such tariffs, we have elected to link our price to these tariffs in our contracts with PGNiG.  We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in an unregulated setting and may be lower than prevailing western European prices.  We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.

We currently do not engage in any hedging activities to protect ourselves against market risks associated with oil and gas price fluctuations, although we may elect to do so in the future.

Foreign Currency Risk

We enter into various agreements in Poland denominated in the Polish zloty.  The Polish zloty is subject to exchange-rate fluctuations that are beyond our control.  Our policy is to reduce currency risk by, under ordinary circumstances, transferring dollars to zlotys, or fixing the exchange rate for future transfers of dollars to zlotys, on or about the occasion of making any significant commitment payable in Polish currency, taking into consideration the future timing and amounts of committed costs and the estimated timing and amounts of zloty-based revenues.  We do not use derivative financial instruments for trading or speculative purposes.  We have used forward-purchase contracts to buy zlotys at specified exchange rates.  The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense is recognized in our consolidated financial statements.  As of September 30, 2011, we had no outstanding zloty forward-purchase contracts.  We expect that foreign currency risks will continue as a result of the ongoing stresses on the international financial system, particularly in view of the deteriorating sovereign debt conditions in Europe and the related Euro crisis that could impact the exchange rates to which we are subject.


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, 2011, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2011, 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.
 
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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, 2010.  The risks described in our Annual Report on Form 10-K for the year ended December 31, 2010, are not the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially and adversely affect our business, financial condition, or operating results.


ITEM 6.  EXHIBITS

The following exhibits are filed as a part of this report:
 
Exhibit
Number*
 
 
Title of Document
 
 
Location
         
Item 10
 
Material Contracts
   
10.101
 
FX Energy, Inc., 2011 Incentive Plan
 
Incorporated by reference from the definitive Proxy Statement on Schedule 14A filed August 8, 2011
         
Item 31
 
Rule 13a-14(a)/15d-14(a) Certifications
   
31.01
 
Certification of Principal Executive Officer Pursuant to Rule 13a-14
 
Attached
         
31.02
 
Certification of Principal Financial Officer Pursuant to Rule 13a-14
 
Attached
         
Item 32
 
Section 1350 Certifications
   
32.01
 
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
Attached
         
32.02
 
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
Attached
         
Item 101
 
Interactive Data File
   
101
 
Interactive Data File
 
Attached

______________
 
*
All exhibits are numbered with the number preceding the decimal indicating the applicable SEC reference number in Item 601 and the number following the decimal indicating the sequence of the particular document.  Omitted numbers in the sequence refer to documents previously filed as an exhibit.
 
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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 9, 2011
By:
/s/ David N. Pierce
   
David N. Pierce, President,
Chief Executive Officer
     
     
Date:  November 9, 2011
By:
/s/ Clay Newton
   
Clay Newton, Principal Financial Officer

 
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