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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 INCex3201q093012.htm
EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INCex3101q093012.htm
EX-31.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INCex3102q093012.htm
EX-32.02 - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 - FX ENERGY INCex3202q093012.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, 2012
   
¨
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 2, 2012, was 52,926,098.

 
 

 


FX ENERGY, INC., AND SUBSIDIARIES
Form 10-Q for the Three Months Ended September 30, 2012



TABLE OF CONTENTS


Item
 
Page
 
Part I—Financial Information
 
     
1
Financial Statements (Unaudited)
 
 
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
13
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,
 
2012
 
2011
ASSETS
         
           
Current assets:
         
Cash and cash equivalents
$
45,180 
 
$
50,859 
Receivables:
         
Accrued oil and gas sales
 
2,745 
   
3,446 
Joint interest and other receivables
 
4,215 
   
4,768 
VAT receivable
 
-- 
   
389 
Inventory
 
194 
   
196 
Other current assets
 
862 
   
542 
Total current assets
 
53,196 
   
60,200 
           
Property and equipment, at cost:
         
Oil and gas properties (successful efforts method):
         
Proved
 
56,035 
   
49,388 
Unproved
 
2,822 
   
3,482 
Other property and equipment
 
10,443 
   
9,968 
Gross property and equipment
 
69,300 
   
62,838 
Less accumulated depreciation, depletion and amortization
 
(18,143)
   
(14,942)
Net property and equipment
 
51,157 
   
47,896 
           
Other assets:
         
Certificates of deposit
 
382 
   
406 
Loan fees
 
1,460 
   
1,722 
Total other assets
 
1,842 
   
2,128 
           
Total assets
$
106,195 
 
$
110,224 

 

-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,
 
2012
 
2011
LIABILITIES AND STOCKHOLDERS’ EQUITY
         
           
Current liabilities:
         
Accounts payable
$
6,849 
 
$
9,736 
VAT payable
 
180 
   
-- 
Accrued liabilities
 
546 
   
677 
Total current liabilities
 
7,575 
   
10,413 
           
Long-term liabilities:
         
Notes payable
 
40,000 
   
40,000 
Asset retirement obligation
 
1,292 
   
1,184 
Total long-term liabilities
 
41,292 
   
41,184 
           
Total liabilities
 
48,867 
   
51,597 
           
Stockholders’ equity:
         
Preferred stock, $0.001 par value, 5,000,000 shares authorized
         
as of September 30, 2012, and December 31, 2011; no shares
         
outstanding
 
-- 
   
-- 
Common stock, $0.001 par value, 100,000,000 shares authorized
         
as of September 30, 2012, and December 31, 2011; 52,926,098
         
and 52,787,350 shares issued and outstanding as of
         
September 30, 2012, and December 31, 2011, respectively
 
53 
   
53 
Additional paid-in capital
 
221,847 
   
219,522 
Cumulative translation adjustment
 
20,787 
   
28,964 
Accumulated deficit
 
(185,359)
   
(189,912)
Total stockholders’ equity
 
57,328 
   
58,627 
           
Total liabilities and stockholders’ equity
$
106,195 
 
$
110,224 

 
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,
  2012   2011   2012   2011
Revenues:
                     
Oil and gas sales
  9,008 
 
  7,552 
 
 24,816 
 
 22,463 
Oilfield services
 
544 
   
2,568 
   
1,896 
   
3,986 
Total revenues
 
9,552 
   
10,120 
   
26,712 
   
26,449 
                       
Operating costs and expenses:
                     
Lease operating expenses
 
862 
   
1,064 
   
2,605 
   
2,865 
Exploration costs
 
10,923 
   
5,237 
   
15,874 
   
12,168 
Property impairment
 
2,000 
   
-- 
   
2,000 
   
-- 
Loss on sale of assets
 
-- 
   
-- 
   
49 
   
-- 
Oilfield services costs
 
387 
   
1,640 
   
1,481 
   
2,981 
Depreciation, depletion and amortization
 
1,006 
   
930 
   
2,796 
   
2,598 
Accretion expense
 
16 
   
21 
   
46 
   
55 
Stock compensation
 
557 
   
412 
   
1,659 
   
1,123 
General and administrative
 
1,788 
   
1,676 
   
6,042 
   
5,799 
Total operating costs and expenses
 
17,539 
   
10,980 
   
32,552 
   
27,589 
                       
Operating income (loss)
 
(7,987)
   
(860)
   
(5,840)
   
(1,140)
                       
Other income (expense):
                     
Interest expense
 
(602)
   
(512)
   
(1,862)
   
(1,547)
Interest and other income
 
88 
   
23 
   
259 
   
131 
Foreign exchange gain (loss)
 
10,490 
   
(26,178)
   
11,996 
   
(15,890)
Total other income (expense)
 
9,976 
   
(26,667)
   
10,393 
   
(17,306)
                       
Net income (loss)
 
1,989 
   
(27,527)
   
4,553 
   
(18,446)
                       
Other comprehensive income (loss)
                     
Foreign currency translation adjustment
 
(6,822)
   
16,665 
   
(8,177)
   
9,856 
Comprehensive income (loss)
   (4,833)
 
 (10,862)
 
  (3,624)
 
  (8,590)
                       
Net income (loss) per common share
                     
Basic
  0.04 
 
   (0.53)
 
   0.09 
 
   (0.37)
Diluted
   0.04 
 
  (0.53)
 
   0.09 
 
    (0.37)
Weighted average common shares outstanding
                     
Basic
 
52,255 
   
51,691 
   
52,244 
   
49,756 
Dilutive effect of stock options
 
391 
   
-- 
   
329 
   
-- 
Diluted
 
52,646 
   
51,691 
   
52,573 
   
49,756 

 

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,
 
2012
 
2011
Cash flows from operating activities:
         
Net income (loss)
$
4,553 
 
$
(18,446)
Adjustments to reconcile net loss to net cash
         
provided by (used in) operating activities:
         
Depreciation, depletion and amortization
 
2,796 
   
2,598 
Accretion expense
 
46 
   
55 
Amortization of bank fees
 
374 
   
429 
Property impairment
 
6,532 
   
-- 
Loss on property dispositions
 
49 
   
-- 
Stock compensation
 
1,659 
   
1,123 
Unrealized foreign exchange (gains) losses
 
(11,993)
   
15,874 
Common stock issued for services
 
669 
   
711 
Increase (decrease) from changes in working capital items:
         
Receivables
 
2,350 
   
(2,581)
Inventory
 
   
(28)
Other current assets
 
(306)
   
(36)
Other assets
 
24 
   
-- 
Accounts payable and accrued liabilities
 
(924)
   
1,535 
Net cash provided by operating activities
 
5,831 
   
1,234 
           
Cash flows from investing activities:
         
Additions to oil and gas properties
 
(11,836)
   
(14,866)
Additions to other property and equipment
 
(464)
   
(1,015)
Proceeds from sale of assets
 
221 
   
-- 
Net cash used in investing activities
 
(12,079)
   
(15,881)
           
Cash flows from financing activities:
         
Proceeds from stock option exercises
 
-- 
   
800 
Proceeds from common stock offering, net
 
-- 
   
45,042 
Payments made on credit facility
 
-- 
   
(35,000)
Net cash provided by financing activities
 
-- 
   
10,842 
           
Effect of exchange-rate changes on cash
 
569 
   
(742)
           
Net decrease in cash
 
(5,679)
   
(4,547)
Cash and cash equivalents at beginning of year
 
50,859 
   
19,740 
           
Cash and cash equivalents at end of period
$
45,180 
 
$
15,193 



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, 2011, and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2012.

We evaluated subsequent events through the date of our financial statement issuance.  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, 2012, 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, 2012 and 2011, were as follows:

 
Options and
   
 
Unvested Restricted Stock
 
Price Range
Balance sheet date:
     
September 30, 2012
1,321,041
 
$0.00 - $5.06
September 30, 2011
1,732,211
 
$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, 2012, 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, 2011.  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, 2012.

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, 2012, the nine months ended September 30, 2012, and as of September 30, 2012, is as follows (in thousands):

 
Reportable Segments
   
 
Exploration & Production
Oilfield Services
Non-Segmented
Total
 
U.S.
Poland
     
Three months ended September 30, 2012:
         
Revenues
$ 1,014
$  7,994
$    544
$         --
$   9,552
Net income (loss)(1)
       (974)
     (4,543)
      (117)
     7,623
     1,989
Nine months ended September 30, 2012:
         
Revenues
$ 3,137
$21,679
$ 1,896
$         --
$ 26,712
Net income (loss)(1)
       (183)
     2,484
      (418)
     2,670
      4,553
As of September 30, 2012:
         
Identifiable net property and equipment
$ 2,260
$46,327
$ 2,515
$       55
$ 51,157
_______________
 
(1)
Nonsegmented reconciling items for the third quarter include $1,788 of G&A costs, $557 of noncash stock compensation expense, $514 of other expense, $8 of corporate DD&A costs, and $10,490 of foreign exchange gains.  Nonsegmented reconciling items for the first nine months include $6,042 of G&A costs, $1,659 of noncash stock compensation expense, $1,603 of other expense, $22 of corporate DD&A costs, and $11,996 of foreign exchange gains.
 
8
 
 

 


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.

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 a term of ten years and vest over 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.

Stock Options

The following table summarizes option activity for the first nine months of 2012:

    
Weighted
Weighted Average
 
 
Number of
Average
Remaining Contractual
Aggregate
 
Options
Exercise Price
Life (in years)
Intrinsic Value
         
Options outstanding:
       
Beginning of year
668,129
$5.31
   
Expired
  (35,000)
  9.89
   
End of period
633,129
  5.06
8.97
 
Exercisable at end of period
211,043
  5.06
8.97
$504,393
 
9
 
 

 


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
   
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 $1,781,036, which will be amortized ratably over a three-year vesting period.  Expense recognized during the first nine months of 2012 and 2011 totaled $442,491 and $35,726, respectively.

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $7.45 as of September 30, 2012, and $4.13 as of September 30, 2011, 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 first nine months of 2012 and 2011 totaled $400,086 and $20,589, respectively.

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 2012 and 2011 totaled $558,359 and $564,918, respectively.

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 2012 and 2011 totaled $257,434 and $260,087, 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 2012 and 2011 totaled $0 and $241,254, respectively.
 
10
 
 

 


The following table summarizes restricted stock activity during the first nine months of 2012 and 2011:

 
Number of Shares
 
2012
 
2011
Unvested restricted stock outstanding:
     
Beginning of year
687,912
 
   746,398
Issued
           --
 
    318,251
Forfeited
           --
 
       (3,947)
Vested
(105,538)
 
              --
End of period
582,374
 
1,060,702

Note 6:  Stockholders’ Equity

During the first nine months of 2012, we issued 138,748 shares for the 2011 contribution to our employee benefit plan.

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.

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, 2012, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first nine months of 2012.
 
11
 
 

 


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.

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 30, 2012 (in thousands):

 
September 30,
           
 
2012
 
Level 1(1)
 
Level 2(2)
 
Level 3(3)
Cash equivalents:
             
Money market funds
$1,926
 
$1,926
 
--
 
--
_______________
 
(1)
Quoted prices in active markets for identical assets.
(2)
Significant other observable inputs.
(3)
Significant unobservable inputs.

Note 8:  Notes Payable

FX Energy Poland has a $55 million Senior Reserve Base Lending 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 an interest margin of 4.0%, and has a term of five years, with semiannual borrowing base reductions of $11 million each beginning on June 30, 2013.  The credit facility was an interest-only facility until June 30, 2012.  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 $374,000 of deferred financing costs associated with our existing credit facility to interest expense during the first nine months of 2012.  Payment of the credit 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 credit facility as of March 31, 2011.  As of September 30, 2012, we had $40 million outstanding and $15 million available under the credit facility.  Our notes payable is stated at book value, which approximated its fair value at September 30, 2012.  Estimated fair values for notes payable have been determined based on borrowing rates currently available to us for bank loans with similar terms and maturities and are classified as Level 2 (significant observable inputs other than quoted prices) in the Financial Accounting Standards Board’s fair value hierarchy.

Note 9:  Capitalized Exploratory Well Costs

We had $4.7 million, $4.6 million, and $2.4 million of capitalized costs related to our Komorze 3-K, Plawce-2 and Frankowo wells, respectively, which were in progress at September 30, 2012.

Note 10:  Foreign Currency Translation and Risk

During the first nine months of 2012, we recorded foreign currency transaction gains of approximately $12.0 million.  This amount was attributable to decreases 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 debit 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, 2012
Balance at December 31, 2011
$ 28,964
Decrease related to gains on intercompany loans
    (11,993)
Increase related to translation adjustments
      3,816
Balance at September 30, 2012
$ 20,787

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.


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, 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, 2012, Compared to the Same Period of 2011

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $8.0 million during the third quarter of 2012, compared to $6.5 million during the same quarter of 2011.  Full production at our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells was an important component in increased 2012 third quarter natural gas production and revenues.
 
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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, 2012 and 2011, is set forth in the following table:

 
For the Quarter Ended September 30,
   
 
2012
 
2011
 
Change
Gas revenues
$7,994,000
 
$6,480,000
 
+23%
Average price (per thousand cubic feet)
          $7.05
 
          $6.37
 
+11%
Production volumes (thousand cubic feet)
  1,135,000
 
  1,017,000
 
+12%

As we discussed in our Form 10-Q for the period ended June 30, 2012, our KSK wells were shut in for two weeks during September 2012 for annual maintenance and pressure testing.  In addition, the operator of all of our Fences concession area wells, the Polish Oil and Gas Company, or PGNiG, unexpectedly shut in the Zaniemsyl well for approximately 30 days.  Following the maintenance, PGNiG reduced the daily production at our Zaniemysl well by approximately 42%, while production at our KSK wells resumed at prior levels.

Our increased revenues were a combination of higher prices and higher production during the third quarter of 2012.  Daily gas production for the third quarter of 2012 was 12.3 million cubic feet of natural gas per day, or MMcfd, compared to 11.1 MMcfd during the same quarter of 2011.  Third quarter of 2012 production from our KSK wells increased by 219,000 thousand cubic feet of natural gas over 2011 third quarter levels.  We achieved full production at our KSK wells on June 28, 2012, following a successful resolution of a pipeline bottleneck.  Without the unexpected shut-in at Zaniemysl, our production rate for the third quarter of 2012 would have been approximately 12.8 MMcfd.  At September 30, 2012, our net natural gas production rate was approximately 12.7 MMcfd.

Natural gas prices increased 11% quarter over quarter during the last 12 months.  The Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 21% higher during the third quarter of 2012, compared to the same quarter of 2011.  The increase was primarily a function of a tariff increase implemented by the Polish utility regulator of 16.9% that became effective for us on April 1, 2012.  However, period-to-period strength in the U.S. dollar against the Polish zloty partially offset the higher prices.  The average exchange rate during the third quarter of 2012 was 3.31 zlotys per U.S. dollar.  The average exchange rate during the third quarter of 2011 was 2.94 zlotys per U.S. dollar, a change of approximately 13%.  In addition, with full 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 $1.0 million for the third quarter of 2012, a 5% decrease from $1.1 million recognized during the third quarter of 2011.  Production levels decreased, due to normal production declines, by approximately 1% from 2011 to 2012.  The decrease in production was exacerbated by the lower prices received during the third quarter of 2012.  Our average oil price during the third quarter of 2012 was $74.30 per barrel, a 4% decrease from $77.26 per barrel received during the same quarter of 2011.
 
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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, 2012 and 2011, is set forth in the following table:

 
For the Quarter Ended September 30,
   
 
2012
 
2011
 
Change
Oil revenues
$1,014,000
 
$1,072,000
 
-5%
Average price (per barrel)
       $74.30
 
        $77.26
 
-4%
Production volumes (barrels)
       13,700
 
        13,900
 
-1%

Lease Operating Costs.  Lease operating costs of $862,000 during the third quarter of 2012 were 19% lower than the third quarter of 2011 amount of $1,064,000.  Included in third quarter of 2011 operating costs was approximately $161,000 associated with our Montana oil spill clean-up.

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $10.9 million during the third quarter of 2012, compared to $5.2 million during the same period of 2011.

Subsequent to September 30, 2012, we determined that our Kutno-2 well did not find commercial quantities of oil or gas.  Accordingly, we charged to exploration expense our share of dry-hole costs incurred through September 30, 2012, of approximately $9.0 million.  We expect to incur additional costs in the fourth quarter of 2012 related to this well.  In addition, the remaining third quarter of 2012 geological and geophysical costs were primarily associated with two-dimensional, or 2-D, seismic surveys on our 100%-owned acreage in Poland.  Third quarter of 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 2-D seismic surveys at our 100%-owned concessions in Poland, and $1.0 million of dry-hole costs associated with our Machnatka well.

Property Impairment.  Third quarter 2012 property impairment costs totaled $2.0 million.  In the United States, we impaired all of the drilling costs associated with our Montana Bakken project, totaling approximately $1.3 million.  After extensive testing, we determined that the wells drilled in Montana are not capable of commercial production.  In addition, in Poland, we impaired the costs of our Kutno concessions and certain of our Warsaw South concessions that either expired during the quarter or were deemed to be non-prospective for hydrocarbon potential.  The impairments in Poland totaled approximately $700,000.  There were no property impairments during 2011.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $725,000 for the third quarter of 2012, an increase of 11% compared to $652,000 during the same period of 2011.  Higher DD&A expense in 2012 was due in part to depreciation expense associated with full production at our KSK wells.

Accretion Expense.  Accretion expense was $16,000 and $21,000 for the third quarter of 2012 and 2011, respectively.  Accretion expense is related entirely to our Asset Retirement Obligation associated with expected future plugging and abandonment costs.
 
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Oilfield Services Segment

Oilfield Services Revenues.  Oilfield services revenues were $0.5 million during the third quarter of 2012, a decrease of 81% compared to $2.6 million for the third quarter of 2011.  During the third quarter of 2012, we drilled two wells for third parties, along with additional well service work.  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.  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 $0.4 million during the third quarter of 2012, compared to $1.6 million during the same period of 2011.  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 $273,000 during the third quarter of 2012, compared to $261,000 during the same period of 2011.  The quarter-to-quarter increase was primarily due to depreciation on recent capital additions.

Nonsegmented Information

G&A Costs.  G&A costs were $1.8 million during the third quarter of 2012 compared to $1.7 million during the third quarter of 2011.  The increase is primarily due to higher compensation costs related to increased headcount in 2012.

Stock Compensation (G&A).  For the three-month periods ended September 30, 2012 and 2011, we recognized $557,000 and $412,000, 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 $88,000 during the third quarter of 2012, compared to $23,000 during the same period of 2011.

During the third quarter of 2012, we incurred $602,000 in interest expense, which included $124,000 of amortization of loan fees and $104,000 in unused commitment fees.  During the third quarter of 2011, we incurred $512,000 in interest expense.  We recorded $139,000 of amortization of loan fees and $373,000 in unused commitment fees during that quarter.

Foreign Exchange Gain (Loss).  During the third quarter of 2012, we recorded foreign currency transaction gains of approximately $10.5 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans.  We recorded foreign exchange losses of $26.2 million during the same quarter of 2011, which were also principally related to our intercompany loans.  During the third quarter of 2012, the zloty strengthened by approximately 6% against the U.S. dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.  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.
 
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Nine Months Ended September 30, 2012, Compared to the Same Period of 2011

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $21.7 million during the first nine months of 2012, compared to $18.9 million during the same period of 2011.  Full production at our KSK wells was an important component in increased 2012 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, 2012 and 2011, is set forth in the following table:

 
For the Nine Months Ended September 30,
   
 
2012
 
2011
 
Change
Revenues
$21,679,000
 
$18,912,000
 
+15%
Average price (per thousand cubic feet)
             $6.64
 
            $6.28
 
  +6%
Production volumes (thousand cubic feet)
     3,265,000
 
    3,009,000
 
  +9%

Daily gas production for the first nine months of 2012 was 11.9 MMcfd, compared to 11.1 MMcfd during the same quarter of 2011.  The first nine months of 2012 production from our KSK wells increased by 519,000 thousand cubic feet of natural gas over the comparable 2011 nine-month levels.  We achieved full production at our KSK wells on June 28, 2012, following a successful resolution of a pipeline bottleneck.

In addition to our increased production, three factors discussed earlier combined to result in higher gas revenues during the first nine months of 2012.  First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 22% higher during the first nine months of 2012, compared to the same period of 2011.  The increase was a function of two price changes implemented by the Polish utility regulator since the beginning of 2011, including a 12.5% increase that became effective for us on August 1, 2011, and a subsequent 16.9% increase that became effective for us on April 1, 2012.  However, period-to-period strength in the U.S. dollar against the Polish zloty decreased 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 2012 was 3.29 zlotys per U.S. dollar, a change of approximately 15%.  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 $3.1 million for the first nine months of 2012, a 12% decrease from the $3.6 million recognized during the first nine months of 2011.  Production from our U.S. properties declined 5% during the first nine months of 2012 due to regular production declines.  The most significant factor in the decrease in oil revenues was the lower prices received during the first nine months of 2012.  Our average oil price during the first nine months of 2012 was $77.32 per barrel, a 5% decrease from $83.09 per barrel received during the same period of 2011.
 
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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 nine months ended September 30, 2012 and 2011, is set forth in the following table:

 
For the Nine Months Ended September 30,
   
 
2012
 
2011
 
Change
Revenues
$3,137,000
 
$3,551,000
 
-12%
Average price (per barrel)
       $77.32
 
        $83.09
 
  -7%
Production volumes (barrels)
       40,600
 
        42,700
 
  -5%

Lease Operating Costs.  Lease operating costs were $2.6 million during the first nine months of 2012, a decrease of 9% compared to the same period of 2011.  Included in our first nine months of 2011 operating costs was approximately $311,000 associated with our Montana oil spill clean-up.  Without the clean-up costs, our first nine months of 2012 operating costs would have been only 2% higher than the comparable nine-month period of 2011 operating costs.  Those additional operating costs are related to full 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 $15.9 million during the first nine months of 2012, compared to $12.2 million during the same period of 2011.  Subsequent to September 30, 2012, we determined that our Kutno-2 well did not find commercial quantities of oil or gas.  Accordingly, we charged to exploration expense our share of dry-hole costs incurred through September 30, 2012, of approximately $9.0 million.  We expect to incur additional costs in the fourth quarter of 2012 related to this well.  In addition, the remaining first nine months of 2012 exploration costs included approximately $560,000 associated with our Lisewo southeast 3-D seismic survey in our Fences concession, $5.8 million associated with 2-D seismic projects at our other existing Polish concessions, and approximately $485,000 in dry-hole costs associated with a Bakken test well in Montana.  Our first nine months of 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.

Property Impairment.  Our first nine months of 2012 property impairment costs totaled $2.0 million.  In the United States, we impaired all of the capitalized drilling costs associated with our Montana Bakken project, totaling approximately $1.3 million.  After extensive testing, we determined that the wells drilled in Montana are not capable of commercial production.  In addition, in Poland, we impaired the costs of our Kutno concessions and certain of our Warsaw South concessions that either expired during 2012 or were deemed to be non-prospective for hydrocarbon potential.  The impairments in Poland totaled approximately $700,000.  We had no property impairments during the first nine months of 2011.

DD&A Expense - Exploration and Production.  DD&A expense for producing properties was $1.9 million for the first nine months of 2012, an increase of 6% compared to $1.8 million during the same period of 2011.  Higher DD&A expense in 2011 was due in part to full production at our KSK wells.

Accretion Expense.  Accretion expense was $46,000 and $55,000 for the first nine months of 2012 and 2011, 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 $1.9 million during the first nine months of 2012, a decrease of 52% compared to $4.0 million for the first nine months of 2011.  We drilled seven wells for third parties, including one drilled for our Alberta Bakken joint venture, during the first nine months of 2012, along with additional well service work.  We drilled nine wells for third parties during the first nine months of 2011, including those drilled for our Alberta Bakken joint venture, 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 $1.5 million during the first nine months of 2012, compared to $3.0 million during the same period of 2011.  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 $834,000 during the first nine months of 2012, compared to $709,000 during the same period of 2011.  The period-to-period increase was primarily due to new depreciation from capital additions in 2011 and 2012.

Nonsegmented Information

G&A Costs.  G&A costs were $6.0 million during the first nine months of 2012, compared to $5.8 million during the first nine months of 2011, an increase of $0.2 million.  Higher compensation costs were partially offset by lower legal costs in the first nine months of 2012.

Stock Compensation (G&A).  For the nine-month periods ended September 30, 2012 and 2011, we recognized $1.7 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 (Expense).  Interest and other income was $259,000 during the first nine months of 2012, compared to $131,000 during the same period of 2011.

During the first nine months of 2012, we incurred $1.9 million in interest expense.  We recorded $374,000 of amortization of loan fees and $256,000 in unused commitment fees.  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 $632,000 in unused commitment fees.

Foreign Exchange Gain (Loss).  As discussed in Note 11 to the financial statements, during the first nine months of 2012, we recorded foreign currency transaction gains of approximately $12.0 million, principally attributable to decreases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.  During the first nine months of 2012, the zloty strengthened by approximately 7% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction gains.  Foreign currency transaction losses during the first nine months of 2011 were $15.9 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.
 
19
 
 

 


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, in the last several years, as our gas production and prices have increased in Poland and as oil prices have generally increased the profitability of our U.S. production, our internally generated cash flow has become a significant source of operations financing.

2012 Liquidity and Capital

Working Capital (current assets less current liabilities).  Our working capital was $45.6 million as of September 30, 2012, a decrease of $4.2 million from December 31, 2011.  Our current assets at September 30, 2012, included $2.7 million in accrued oil and gas sales from both the United States and Poland.  Our current liabilities at quarter-end included approximately $5.6 million in costs related to capital and exploration projects in Poland.  Our outstanding long-term debt at September 30, 2012, was $40 million, with no principal payments due until June 30, 2013.

Operating Activities.  Net cash provided by operating activities was $5.8 million during the first nine months of 2012, compared to net cash provided by operating activities of $1.2 million during the first nine months of 2011.  Slightly higher revenues in 2012 were augmented by decreases in oilfield services costs, along with increases from working capital items.

Investing Activities.  During the first nine months of 2012, we used cash of $12.1 million in investing activities.  We used $11.5 million for current-year capital additions in Poland and $385,000 related to our proved properties in the United States, and used $464,000 for capital additions in our office and drilling equipment.  These costs were offset by approximately $221,000 of proceeds related to the sale of certain leases in Montana.  During the first nine months of 2011, we used cash of $15.9 million in investing activities.  We used $13.3 million for current-year capital additions in Poland, $1.6 million for current-year capital additions in the United States, and $1.0 million 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 2012.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2012 include our working capital of $45.6 million at September 30, 2012, available credit of $15 million as of such date under our credit facility, cash available from our operations, and proceeds from the possible sale of securities.

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 semiannual borrowing base reductions of $11 million each beginning on June 30, 2013.  The credit facility is an interest-only facility until then.  As of September 30, 2012, we had $40 million outstanding and $15 million available under the credit facility.  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 2011 Lisewo-1 discovery, in a revised credit facility.
 
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As of September 30, 2012, we were producing gas from six wells in Poland, including our Sroda-4 and two Kromolice wells.  We expect our increased production to increase funds available for exploration and development over 2011 levels.  Our Winna Gora well is expected to begin production in the fourth quarter of 2012.  In addition, in 2011, we drilled and completed the successful Lisewo-1 well in our Fences concession, which we expect to further increase production and 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.  The $200 million of securities available for sale under the registration statement are 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 expect our primary use of cash for 2012 will be for our exploration and development activities in Poland.  At September 30, 2012, we were in the process of drilling our Komorze 3-K and Frankowo wells at a total cost through September 30, 2012, of $4.7 million and $2.4 million, respectively.  We have agreed with PGNiG to conduct a fracture stimulation test at the Plawce-2 well during the fourth quarter of 2012.  We were also building production facilities at our Winna Gora well.  We had no other firm commitments for future capital and exploration costs at September 30, 2012.  However, while not currently fully committed, our plans call for drilling operations to begin during the fourth quarter of 2012 at our Tuchola and Mieczewo wells.  In addition, we also plan additional 2-D and 3-D seismic data acquisition and analysis.

We expect the cost of our 2012 exploration and production activities to range from $40 million to $50 million.  During 2010 and 2011, the exchange rate between the Polish zloty and the U.S. dollar averaged approximately 3.0 zlotys per U.S. dollar.  Due to the recent strength of the U.S. dollar, the exchange rate has averaged approximately 3.4 zlotys per U.S. dollar through September 30, 2012.  Accordingly, the actual amount of our U.S. dollar-denominated expenditures will depend on exchange rates between the U.S. dollar and the Polish zloty.  In addition, our expenditures also depend on ongoing exploration results; the pace at which PGNiG, our operating partner in the Fences project area, wishes to proceed or the extent it wishes to continue to participate with us in concessions we operate; the availability of drilling and other exploration services; and the amount of capital we obtain from the various sources discussed above.  Our 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.

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, 2012, we have incurred cumulative net losses of approximately $185 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.  While revenues from our operations exceed our fixed operating and overhead costs, we reported negative cash flow from operating activities as recently as 2011.
 
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We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements in which industry participants bear 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, 2011.  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.
 
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Forward-Looking Statements

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

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

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


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Price Risk

Realized pricing for our oil production in the United States and Poland is primarily driven by the prevailing worldwide price of oil, subject to gravity and other adjustments for the actual oil sold.  Historically, oil prices have been volatile and unpredictable.  Price volatility relating to our oil production is expected to continue in the foreseeable future.

Substantially all of our gas in Poland is sold to PGNiG or its subsidiaries under contracts that extend for the life of each field.  Prices are determined contractually and 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.
 
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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 are recognized in our consolidated financial statements.  As of September 30, 2012, 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, 2012, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2012, 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, 2011.  The risks described in our Annual Report on Form 10-K for the year ended December 31, 2011, 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
   
10.106
 
Amendment No. 1 to At-The-Market Issuance Sales Agreement with McNicoll, Lewis & Vlak LLC
 
Incorporated by reference from the Current Report on Form 8-K filed August 24, 2012
         
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, 2012
By:
/s/ David N. Pierce
   
David N. Pierce, President,
Chief Executive Officer
     
     
Date:  November 9, 2012
By:
/s/ Clay Newton
   
Clay Newton, Principal Financial Officer
 
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