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EX-31.01 - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13A-14 - FX ENERGY INCex3101q093014.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 INCex3202q093014.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, 2014
   
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______________ to _______________

Commission File No. 001-35012

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

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

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

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

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

Yes
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.  As of November 3, 2014, there were 54,073,918 and 800,000 shares outstanding of $0.001 par value common stock and 9.25% cumulative convertible preferred stock, respectively.
 
 

 
 

 


FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Three Months Ended September 30, 2014



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
15
3
Quantitative and Qualitative Disclosures about Market Risk
25
4
Controls and Procedures
26
     
 
Part II—Other Information
 
     
1A
Risk Factors
26
6
Exhibits
27
--
Signatures
28

2
 
 

 

PART I—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

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


 
September 30,
 
December 31,
 
2014
 
2013
ASSETS
         
           
Current assets:
         
Cash and cash equivalents
$
23,467 
 
$
11,153 
Marketable securities
 
4,059 
   
-- 
Receivables:
         
Accrued oil and gas sales
 
3,460 
   
3,464 
Joint interest and other receivables
 
1,527 
   
5,029 
VAT receivable
 
-- 
   
1,847 
Inventory
 
99 
   
100 
Other current assets
 
345 
   
234 
Total current assets
 
32,957 
   
21,827 
           
Property and equipment, at cost:
         
Oil and gas properties (successful-efforts method):
         
Proved
 
82,996 
   
85,244 
Unproved
 
2,327 
   
2,404 
Other property and equipment
 
12,590 
   
11,857 
Gross property and equipment
 
97,913 
   
99,505 
Less accumulated depreciation, depletion, and amortization
 
(26,082)
   
(23,369)
Net property and equipment
 
71,831 
   
76,136 
           
Other assets:
         
Certificates of deposit
 
406 
   
406 
Loan fees
 
1,769 
   
2,323 
Total other assets
 
2,175 
   
2,729 
           
Total assets
$
106,963 
 
$
100,692 


 
-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,
 
2014
 
2013
LIABILITIES AND STOCKHOLDERS’ EQUITY
         
           
Current liabilities:
         
Accounts payable
$
2,713 
 
$
9,694 
VAT payable
 
502 
   
-- 
Accrued dividends
 
385 
   
-- 
Accrued liabilities
 
640 
   
833 
Total current liabilities
 
4,240 
   
10,527 
           
Long-term liabilities:
         
Notes payable
 
50,000 
   
45,000 
Asset retirement obligation
 
1,748 
   
1,620 
Total long-term liabilities
 
51,748 
   
46,620 
           
Total liabilities
 
55,988 
   
57,147 
           
Stockholders’ equity:
         
Preferred stock, $0.001 par value, 5,000,000 shares authorized
         
as of September 30, 2014, and December 31, 2013; 800,000 and
         
0 shares issued and outstanding as of September 30, 2014, and
         
December 31, 2013, respectively
 
   
-- 
Common stock, $0.001 par value, 100,000,000 shares authorized
         
as of September 30, 2014, and December 31, 2013; 54,073,918
         
and 53,733,398 shares issued and outstanding as of
         
September 30, 2014, and December 31, 2013, respectively
 
54 
   
54 
Additional paid-in capital
 
247,707 
   
226,060 
Cumulative translation adjustment
 
23,132 
   
15,025 
Accumulated other comprehensive loss
 
(7)
   
-- 
Accumulated deficit
 
(219,912)
   
(197,594)
Total stockholders’ equity
 
50,975 
   
43,545 
           
Total liabilities and stockholders’ equity
$
106,963 
 
$
100,692 

 

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,
    2014     2013     2014     2013
Revenues:
                     
Oil and gas sales
   8,472 
 
  8,034 
 
  26,782 
 
  25,663 
Oilfield services
 
1,722 
   
194 
   
3,088 
   
256 
Total revenues
 
10,194 
   
8,228 
   
29,870 
   
25,919 
                       
Operating costs and expenses:
                     
Lease operating expenses
 
1,213 
   
932 
   
3,502 
   
2,650 
Exploration costs
 
1,935 
   
7,158 
   
8,846 
   
17,355 
Property impairments
 
4,540 
   
-- 
   
8,274 
   
5,633 
Oilfield services costs
 
941 
   
164 
   
1,987 
   
412 
Depreciation, depletion, and amortization
 
1,264 
   
1,125 
   
3,859 
   
3,562 
Accretion expense
 
22 
   
22 
   
69 
   
67 
Stock compensation
 
650 
   
701 
   
2,016 
   
2,083 
General and administrative
 
1,869 
   
1,847 
   
5,794 
   
6,451 
Total operating costs and expenses
 
12,434 
   
11,949 
   
34,347 
   
38,213 
                       
Operating loss
 
(2,240)
   
(3,721)
   
(4,477)
   
(12,294)
                       
Other income (expense):
                     
Interest expense
 
(802)
   
(1,346)
   
(2,143)
   
(2,600)
Interest and other income
 
22 
   
17 
   
48 
   
324 
Foreign exchange gain (loss)
 
(13,425)
   
11,512 
   
(15,361)
   
(1,041)
Total other income (expense)
 
(14,205)
   
10,183 
   
(17,456)
   
(3,317)
                       
Net income (loss)
 
(16,445)
   
6,462 
   
(21,933)
   
(15,611)
                       
Other comprehensive income (loss)
                     
Decrease in market value of available
                     
for sale marketable securities
 
(7)
   
-- 
   
(7)
   
-- 
Foreign currency translation adjustment
 
7,144 
   
(7,660)
   
8,107 
   
605 
Comprehensive loss
  (9,308)
 
 (1,198)
 
 (13,833)
 
 (15,006)
                       
Dividends on preferred stock
 
(385)
   
-- 
   
(385)
   
-- 
Net income (loss) attributable to common stockholders
  (16,830)
 
  6,462 
 
 (22,318)
 
 (15,006)
                       
Net loss per common share
                     
Basic
   (0.31)
 
   0.12 
 
    (0.42)
 
    (0.30)
Diluted
   (0.31)
 
   0.12 
 
    (0.42)
 
    (0.30)
Weighted average common shares outstanding
                     
Basic
 
53,453 
   
52,778 
   
53,338 
   
52,748 
Dilutive effect of stock options
 
-- 
   
958 
   
-- 
   
-- 
Diluted
 
53,453 
   
53,736 
   
53,338 
   
52,748 



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,
 
2014
 
2013
Cash flows from operating activities:
         
Net income (loss)
$
(21,933)
 
$
(15,611)
Adjustments to reconcile net loss to net cash
         
provided by (used in) operating activities:
         
Depreciation, depletion, and amortization
 
3,859 
   
3,562 
Accretion expense
 
69 
   
67 
Amortization of loan fees
 
379 
   
1,055 
Stock compensation
 
2,016 
   
2,083 
Property impairments
 
8,232 
   
5,633 
Unrealized foreign exchange losses
 
15,340 
   
1,014 
Common stock issued for services
 
657 
   
694 
Increase (decrease) from changes in working capital items:
         
Receivables
 
5,340 
   
6,595 
Inventory
 
   
(7)
Other current assets
 
(112)
   
295 
Other assets
 
-- 
   
(25)
Accounts payable and accrued liabilities
 
(5,066)
   
(2,483)
Net cash provided by operating activities
 
8,783 
   
2,872 
           
Cash flows from investing activities:
         
Additions to oil and gas properties
 
(15,143)
   
(16,656)
Additions to other property and equipment
 
(730)
   
(869)
Net cash used in investing activities
 
(15,873)
   
(17,525)
           
Cash flows from financing activities:
         
Repayment of credit facility
 
-- 
   
(40,000)
Proceeds from common stock issuance
 
615 
     
Proceeds from issuance of preferred stock, net of issuance costs
 
18,361 
   
-- 
Purchases of marketable securities
 
(4,066)
   
-- 
Proceeds from notes payable
 
5,000 
   
42,000 
Payment of loan fees
 
-- 
   
(2,036)
Net cash provided by (used) in financing activities
 
19,910 
   
(36)
           
Effect of exchange-rate changes on cash
 
(506)
   
(119)
           
Net increase (decrease) in cash
 
12,314 
   
(14,808)
Cash and cash equivalents at beginning of year
 
11,153 
   
33,990 
           
Cash and cash equivalents at end of period
$
23,467 
 
$
19,182 

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,” and “our” 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, 2013, and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2014.

Note 2:  Net Income (Loss) 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-month period ended September 30, 2013, 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.  As we had a net loss in all other periods presented, no options were included in the computation of diluted earnings per share for those periods because the effect would have been antidilutive.

Outstanding options and unvested restricted stock as of September 30, 2014 and 2013, were as follows:

 
Options and
   
 
Unvested Restricted Stock
 
Price Range
Balance sheet date:
     
September 30, 2014
2,438,449
 
$0.00 - $5.06
September 30, 2013
1,808,589
 
$0.00 - $5.06
 
7
 
 

 


Note 3:  Income Taxes

No income tax expense was recognized for the three-month period ended September 30, 2013, due to the reversal of 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, 2013.  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, 2014.

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 in 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, 2014, the nine months ended September 30, 2014, and as of September 30, 2014, is as follows (in thousands):

    Reportable Segments              
  Exploration &
Production
  Oilfield
Services
  Non-
Segmented
  Total
  U.S.   Poland                    
Three months ended September 30, 2014:
                             
Revenues
   892 
 
  7,580 
 
1,722
 
          -- 
   
  10,194 
Net income (loss)
 
(45)
   
(179)
   
521
   
(16,742)
(1)    
(16,445)
Nine months ended September 30, 2014:
                             
Revenues
2,816 
 
23,966 
 
3,088
 
          -- 
   
 29,870 
Net income (loss)
 
327 
   
2,700 
   
350
   
(25,310)
(1)    
(21,933)
As of September 30, 2014:
                             
Identifiable net property and equipment
2,762 
 
66,474 
 
2,584
 
         11 
   
 71,831 
_______________
 
(1)
Nonsegmented reconciling items for the third quarter 2014 include $1,869 of G&A costs, $650 of noncash stock compensation expense, $780 of other expense, $18 of corporate DD&A costs, and $13,425 of foreign exchange losses.  Nonsegmented reconciling items for the first nine months include $5,794 of G&A costs, $2,016 of noncash stock compensation expense, $2,095 of other expense, $44 of corporate DD&A costs, and $15,361 of foreign exchange losses.
 
8
 
 

 

Reportable business segment information for the three months ended September 30, 2013, the nine months ended September 30, 2013, and as of September 30, 2013, is as follows (in thousands):

  Reportable Segments              
  Exploration &
Production
  Oilfield
Services
  Non-
Segmented
    Total
  U.S.   Poland                    
Three months ended September 30, 2013:
                             
Revenues
1,111
 
  6,923 
 
   194 
 
        --
   
    8,228 
Net income (loss)
 
304
   
(1,260)
   
(207)
   
7,625
(1)    
6,462 
Nine months ended September 30, 2013:
                             
Revenues
2,963
 
22,700 
 
  256 
 
        --
   
  25,919 
Net income (loss)
 
921
   
(3,583)
   
(870)
   
(12,079
)(1)    
(15,611)
As of September 30, 2013:
                             
Identifiable net property and equipment
2,624
 
58,701 
 
2,616 
 
       32
   
  63,973 
_______________
 
(1)
Nonsegmented reconciling items for the third quarter 2013 include $1,847 of G&A costs, $701 of noncash stock compensation expense, $1,329 of other expense, $10 of corporate DD&A costs, and $11,512 of foreign exchange gains.  Nonsegmented reconciling items for the first nine months include $6,451 of G&A costs, $2,083 of noncash stock compensation expense, $2,480 of other expense, $25 of corporate DD&A costs, and $1,040 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 10 years and vest in three equal annual installments from the date of grant.  Under the terms of the stock option award plans, we may also issue restricted stock.  Restricted stock awards vest in three equal annual installments from the date of grant.

Stock Options

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

       
Weighted
 
Weighted Average
   
       
Average
 
Remaining
 
Aggregate
   
Number of
 
Exercise
 
Contractual
 
Intrinsic
   
Options
 
Price
 
Life (in years)
 
Value
                 
Options outstanding:
               
Beginning of year
 
1,911,872 
 
$4.22
       
Expired
 
(6,799)
 
  4.25
       
End of period
 
1,905,073 
 
  4.22
 
8.09
   
Exercisable at end of period
 
838,323 
 
  4.86
 
7.26
 
$0
 
9
 
 

 

The following table summarizes option activity for the first nine months of 2013:

       
Weighted
 
Weighted Average
   
       
Average
 
Remaining
 
Aggregate
   
Number of
 
Exercise
 
Contractual
 
Intrinsic
   
Options
 
Price
 
Life (in years)
 
Value
                 
Options outstanding:
               
Beginning of year
 
1,275,299 
 
$4.65
       
Forfeited
 
(10,583)
 
  4.46
       
End of period
 
1,264,716 
 
  4.65
 
8.55
   
Exercisable at end of period
 
421,205 
 
  5.06
 
7.97
 
$0

The aggregate intrinsic value in the tables above represents the total pretax intrinsic value, based on our stock price of $3.04 as of September 30, 2014, and $3.43 as of September 30, 2013, 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

The following table summarizes restricted stock activity during the first nine months of 2014 and 2013:

 
Number of Shares
 
2014
 
2013
Unvested restricted stock outstanding:
         
Beginning of year
640,056 
   
655,099 
 
Vested
(104,182)
   
(105,069)
 
Forfeited
(2,498)
   
(6,157)
 
End of period
533,376 
   
543,873 
 

Stock Compensation

The following table summarizes the quantity of restricted stock awards, total deferred compensation expense arising from those awards, and year-to-date compensation expense for each equity award that is included in stock compensation expense:

Year
   
Total Deferred
Stock Compensation Expense
Ended
Number of
Compensation
(thousands)
Dec. 31,
Shares
(thousands)
2014
2013
2013
324,033
 
$1,095
 
$272
 
$    --
 
2012
321,086
 
1,365
 
336
 
338
 
2011
318,252
 
1,610
 
375
 
397
 
2010
373,500
 
  2,260
 
--
 
554
 
Total
1,336,871
 
$6,330
 
$983
 
$1,289
 
 
10
 
 

 

The following table summarizes the quantity of stock option awards, total deferred compensation expense arising from those awards, and year-to-date compensation expense for each equity award that is included in stock compensation expense:

Year
   
Total Deferred
Stock Compensation Expense
Ended
Number of
Compensation
(thousands)
Dec. 31,
Options
(thousands)
2014
2013
2013
648,058
 
$1,084
 
$   270
 
$     -
 
2012
642,170
 
  1,421
 
349
 
354
 
2011
636,509
 
  1,781
 
414
 
440
 
Total
1,926,737
 
$4,286
 
$1,033
 
$794
 

Note 6:  Stockholders’ Equity

Common Stock

We have a Stock Bonus Plan covering all of our employees under section 401(k) of the Internal Revenue Code.  During the first nine months of 2014 and 2013, we made discretionary contributions of 171,879 and 162,402 shares of our common stock, respectively, to employees under this plan for the prior year’s service and recorded $629,000 and $667,000 of expenses associated with these contributions for the years ended December 31, 2013 and 2012, respectively.  During the second quarter of 2014, we sold 163,639 shares of common stock under our at-the-market agreement in connection with our existing shelf registration.  Net proceeds from the stock sale were approximately $615,000, after deducting associated costs of approximately $27,000.  During 2014, we issued 7,500 shares of our stock to Polish consultants, resulting in expense of $28,000 that will be amortized monthly during 2014.

Preferred Stock

During the third quarter of 2014, we closed an underwritten public offering of 800,000 shares of our 9.25% Series B Cumulative Convertible Preferred Stock (the “Series B Preferred Stock”) at a public offering price of $25.00 per share.  The Series B Preferred Stock has a liquidation preference of $25.00 per share.  Holders of Series B Preferred Stock may convert their shares, in whole or in part, into shares of our common stock at a conversion price of $5.00 per share.  The Series B Preferred Stock ranks senior to our common stock in the payment of dividends and distribution of assets upon liquidation or dissolution.  The Series B Preferred Stock has no stated maturity and is not subject to mandatory redemption.

The net proceeds from the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $18.4 million.  We intend to use the net proceeds from the offering primarily to fund seismic and new drilling costs near our Tuchola discovery, which is located in the Edge license in north central Poland.

Holders of the Series B Preferred Stock are entitled to receive, when, as, and if declared by our board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 9.25% per annum of the $25.00 liquidation preference per share (equivalent to $2.3125 per annum per share).  Dividends are payable quarterly in arrears on the last day of each January, April, July, and October, commencing on October 31, 2014, when, as, and if declared by our board.  As of September 30, 2014, the board declared a dividend of $0.48 per share, or a total of $385,000.
 
11
 
 

 

We may cause conversion of the Series B Preferred Stock if the trading price of our common stock exceeds $6.00 for 20 trading days in any consecutive 30-day trading period.  On or after July 17, 2017, we, at our option, may redeem the Series B Preferred Stock, in whole or in part, for cash at a redemption price of $25.00 per share, plus all accrued and unpaid dividends thereon to the date fixed for redemption, without interest.  We may also redeem the Series B Preferred Stock following certain changes of control as defined in the Series B Preferred Stock designation, in whole or in part, within 90 days after the date on which the change of control has occurred, for cash at $25.00 per share, plus accumulated accrued and unpaid dividends to the date of redemption.  If we elect not to exercise this option, the holders of the Series B Preferred Stock have the option to convert each share into common stock at a conversion price of $5.00 per share, subject to certain adjustments.

Except as required by law, holders of the Series B Preferred Stock will have no voting rights unless dividends fall into arrears for four or more quarterly periods (whether or not consecutive).  In that event and until such dividends in arrears are paid in full, the holders will be entitled to elect two directors to the board, which will increase in size by that same number of directors.

Note 7:  Fair Value Measurements

The accounting standard for fair value measurements provides a framework for measuring fair value and requires expanded disclosures regarding fair value measurements.  Fair value is defined as the price that would be received for an asset or the exit price that would be paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date.  The accounting standard establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs, when 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, 2014, nor did we have any assets or liabilities measured at fair value on a nonrecurring basis to report in the first nine months of 2014.

Recurring Fair Value

The following tables set 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.
 
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Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 30, 2014 (in thousands):

     
Fair Value Measurements Using
     
Quoted Prices
       
     
in Active
 
Significant
   
     
Markets for
 
Other
 
Significant
     
Identical
 
Observable
 
Unobservable
 
Carrying
 
Assets
 
Inputs
 
Inputs
 
Amount
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets:
             
Money market funds
$8,126
 
$8,126
 
--
 
--
Marketable securities
  4,059
 
  4,059
 
--
 
--

Assets and liabilities measured at fair value on a recurring basis consisted of the following as of September 30, 2013 (in thousands):

     
Fair Value Measurements Using
     
Quoted Prices
       
     
in Active
 
Significant
   
     
Markets for
 
Other
 
Significant
     
Identical
 
Observable
 
Unobservable
 
Carrying
 
Assets
 
Inputs
 
Inputs
 
Amount
 
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets:
             
Money market funds
$279
 
$279
 
--
 
--

Marketable Securities

We classify our marketable securities as short-term based on their availability for use in current operations.  The marketable securities have been classified as available-for-sale and are reported at fair value with unrealized gains and losses, if any, recorded as a component of other comprehensive loss.

The marketable securities consist primarily of highly rated corporate bonds, with maturity dates of less than four years, whose values fluctuate with changes in interest rates.  We generally invest with the primary objective of minimizing the potential risk of principal loss.  The marketable securities decreased slightly in value during the three months ended September 30, 2014.  We believe the gross unrealized losses are temporary.  The marketable securities have been classified as available-for-sale and are reported at fair value, with unrealized gains and losses, if any, recorded as a component of other comprehensive loss.

The cost and estimated market value of marketable securities at September 30, 2014, are as follows (in thousands):

       
Gross
 
Estimated
       
Unrealized
 
Market
   
Cost
 
Losses
 
Value
             
Marketable securities                                                             
 
$  4,066
 
$    (7)
 
$   4,059
 
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Note 8:  Notes Payable

We maintain a five-year, up to $100 Million Senior Reserve Based Lending Facility with BNP Paribas (Suisse) SA and ING Bank N.V.  The initial commitment of the facility is $65 million.  We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion, or expansion, mechanism.  Initial proceeds from the facility were used to repay our previously existing facility.  Payment of the credit facility is secured by our assets in Poland and guaranteed by us.

In consideration of this credit facility, we paid various arrangement, structuring, legal, and other fees totaling approximately $2.2 million during 2013.  These fees, along with approximately $399,000 associated with our previous facility, have been capitalized as loan fees and will be amortized over the five-year term of the loan.

The credit facility calls for a periodic interest rate of three-, six-, or twelve-month-LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years.  The facility has a term of five years, with semiannual borrowing base reductions beginning on June 30, 2016.  An unused commitment fee of 40% of the applicable interest margin is charged monthly based on the average daily unused portion of the credit facility.  There are no financial covenants associated with the credit facility.  As of September 30, 2014, the total amount drawn under the credit facility was $50 million, and the interest rate was 3.90% per annum.

Our notes payable are stated at book value, which approximated their fair value at September 30, 2014.  Estimated fair values for notes payable have been determined based on borrowing rates currently available to us for bank loans with similar terms and maturities and are based on Level 3 criteria in the Financial Accounting Standards Board’s fair value hierarchy.

Note 9:  Capitalized Exploratory Well Costs

The following table shows the capitalized costs, by well, along with the year for which the costs of each well were incurred, for those costs that are capitalized and included in proved property costs, pending the determination of proved reserves:

 
Capitalized Costs
 
Total at
September 30,
 
2014(1)
 
2013
 
2012
 
2014
Well:
                     
Tuchola-4K
$
8,706 
 
$
290 
 
$
-- 
 
$
8,996
Tuchola-3K
 
(771)
   
7,513 
   
1,467 
   
8,209
Karmin-1
 
1,439 
   
-- 
   
-- 
   
1,439
Frankowo-1
 
(446)
   
472 
   
4,752 
   
4,778
Total cost
$
8,928 
 
$
8,275 
 
$
6,219 
 
$
23,422
_______________
 
(1)
Negative figures are associated with the effect of current-year exchange rate changes on costs incurred in prior years.

Note 10:  Foreign Currency Translation and Risk

During the first nine months of 2014, we recorded foreign currency transaction losses of approximately $15.4 million.  This amount was attributable to increases in the amount of Polish zlotys necessary for FX Energy Poland to satisfy outstanding intercompany and other dollar-denominated loans and unpaid interest.  There was a corresponding credit to other comprehensive income for gains 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, 2014
Balance at December 31, 2013
15,025 
Increase related to losses on intercompany loans
 
15,340 
Decrease related to translation adjustments
 
(7,233)
Balance at September 30, 2014
23,132 

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.


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

Introduction

In the last several years, we have devoted most of our technical talent and capital expenditures to our operations in Poland, where the majority of our operations are conducted.  The decision to devote most of our available capital to this area drives most of our operating results and the changes to our balance sheet and liquidity.  Our operations in Poland are a combination of existing production and substantial exploration to discover new reserves.

Our U.S. operations also have an impact.  Our U.S. operations are smaller than our operations in Poland and do not present the same level of opportunities for expansion; however, our U.S. operations are a relatively stable source of cash flow.  This, too, is reflected in our operating results.

Results of Operations by Business Segment

Quarter Ended September 30, 2014, Compared to the Same Period of 2013

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $7.6 million during the third quarter of 2014, compared to $6.9 million during the same quarter of 2013.  Higher production and prices in the 2014 quarter led to the increase in natural gas revenues.

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

 
For the Quarter Ended September 30,
   
 
2014
 
2013
 
Change
Gas revenues
$7,580,000
 
$6,923,000
 
+9%
Average price (per thousand cubic feet)
$7.26
 
$7.02
 
+3%
Production volumes (thousand cubic feet)
1,045,000
 
986,000
 
+6%
 
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Daily gas production was 11.3 million cubic feet of natural gas per day, or MMcfd, in the third quarter of 2014, compared to 10.7 MMcfd in the third quarter of 2013.  Production declines at our Roszkow and Zaniemysl wells were offset by increases at our Winna Gora, Komorze, Lisewo-1, and Lisewo-2 wells.

Natural gas prices were higher during the 2014 third quarter as a result of two factors.  First, the Polish low-methane tariff, which serves as the reference price for our gas sales agreements, was 3.1% higher during the third quarter of 2014.  Second, period-to-period weakness in the U.S. dollar against the Polish zloty increased our dollar-denominated gas prices.  The average exchange rate during the third quarter of 2014 was 3.15 zlotys per dollar.  The average exchange rate during the third quarter of 2013 was 3.21 zlotys per dollar, a change of approximately 2%.

During the fourth quarter of 2014, our Kromolice-1, Sroda-4, and Kromolice-2, or KSK, wells will be shut in for two weeks for annual maintenance and pressure testing.

Oil Revenues.  Oil revenues were $0.9 million for the third quarter of 2014, a 20% decrease from $1.1 million recognized during the third quarter of 2013.  Production levels decreased, due to normal production declines, by approximately 9% from 2013 to 2014.  The decrease in production was coupled with lower prices received during the third quarter of 2014.  Our average oil price during the third quarter of 2014 was $78.18 per barrel, an 11% decrease from $88.14 per barrel received during the same quarter of 2013.

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

 
For the Quarter Ended September 30,
   
 
2014
 
2013
 
Change
Oil revenues
$892,000
 
$1,111,000
 
-20%
Average price (per barrel)
$78.18
 
$88.14
 
-11%
Production volumes (barrels)
11,400
 
12,600
 
-9%

Lease Operating Costs.  Lease operating costs of $1.2 million during the third quarter of 2014 were 30% higher than the third quarter of 2013 amount of $0.9 million.  Poland operating costs increased approximately $93,000, or 34%, from quarter to quarter, with a portion of the increase attributable to new production at our Lisewo-1 and Komorze-3K wells, along with workover costs at our Komorze and Winna Gora wells.  Operating costs and production taxes in the United States increased from 2013 to 2014 as we incurred workover and other costs at our Montana properties during the 2014 quarter.

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $1.9 million during the third quarter of 2014, compared to $7.2 million during the same period of 2013.

Third quarter of 2014 exploration costs included approximately $0.9 million in period-to-date dry-hole costs associated with our Baraniec well, $0.7 million associated with three-dimensional, or 3-D, and two-dimensional, or 2-D, seismic surveys at both our Fences area and our 100%-owned concessions in Poland and $0.4 million of current period dry-hole costs associated primarily with our Gorka-Duchowna well.  Third quarter of 2013 exploration costs included approximately $5.8 million associated with 3-D and 2-D seismic surveys at both our Fences area and our 100%-owned concessions in Poland and $1.4 million of dry-hole costs associated primarily with the unsuccessful fracture stimulation of our Plawce-2 well.
 
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Property Impairment.  During the third quarter of 2014, we recorded property impairment costs of $4.5 million, essentially all of which were prior-year costs associated with our Gorka Duchowna well.  We have determined to relinquish part of our Block 246 concession, which contains the Gorka Duchowna well, in order to narrow our exploration focus in that concession.  The well will be plugged during the fourth quarter of 2014.  There were no property impairments during the third quarter of 2013.

DD&A Expense–Exploration and Production.  DD&A expense for producing properties was $1.0 million for the third quarter of 2014, an increase of approximately 12%, compared to $0.9 million during the same period of 2013.  Higher DD&A expense in 2014 was due to increased depreciation expense at our Lisewo-1 and Komorze-3K, reflecting higher and new production in 2014.

Accretion Expense.  Accretion expense was $22,000 for the third quarters of both 2014 and 2013.  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 $1.7 million during the third quarter of 2014, compared to $0.2 million for the third quarter of 2013.  During the third quarter of 2014, we drilled five wells for third parties, along with additional well service work.  During the third quarter of 2013, we drilled one well for third parties, along with additional well service work.  Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our own properties, and other factors.

Oilfield Services Costs.  Oilfield services costs were $0.9 million during the third quarter of 2014, compared to $0.2 million during the same period of 2013.  Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our own properties, and other factors.

DD&A Expense–Oilfield Services.  DD&A expense for oilfield services was $0.3 million during the third quarter of 2014, compared to $0.2 million during the same period of 2013.  The quarter-to-quarter increase was primarily due to new capital additions during 2014.

Nonsegmented Information

G&A Costs.  G&A costs were $1.9 million during the third quarter of 2014, compared to $1.8 million during the third quarter of 2013.  Higher Polish compensation costs caused the increase from 2013 to 2014.

Stock Compensation (G&A).  We recognized $0.7 million of stock compensation expense related to the amortization of deferred compensation associated with stock option and restricted stock grants for both three-month periods ended September 30, 2014 and 2013.

Interest and Other Income (Expense).  During the third quarter of 2014, we incurred $0.8 million in interest expense, which included amortization of loan fees and unused commitment and other fees totaling $0.3 million.  During the third quarter of 2013, we incurred $1.4 million in interest expense.  We recorded $0.8 million of amortization of loan fees, including $0.7 million related to our prior credit facility that was charged to interest expense by virtue of our refinance, and $0.1 million in unused commitment fees during the quarter.
 
17
 
 

 

Foreign Exchange Gain (Loss).  During the third quarter of 2014, we recorded noncash foreign currency transaction losses of approximately $13.4 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans.  During the third quarter of 2013, we recorded noncash foreign currency transaction gains of approximately $11.5 million, which were also principally related to our intercompany loans.  During the third quarter of 2014, the zloty weakened by approximately 8% against the dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction losses.  During the third quarter of 2013, the zloty strengthened by approximately 6% against the dollar from the beginning to the end of the quarter, which caused us to recognize foreign currency transaction gains.

Nine Months Ended September 30, 2014, Compared to the Same Period of 2013

Exploration and Production Segment

Gas Revenues.  Revenues from gas sales were $24.0 million during the first nine months of 2014, compared to $22.7 million during the same period of 2013.

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

 
For the Nine Months Ended September 30,
   
 
2014
 
2013
 
Change
Revenues
$23,966,000
 
$22,700,000
 
+6%
Average price (per thousand cubic feet)
$7.41
 
$7.06
 
+5%
Production volumes (thousand cubic feet)
3,233,000
 
3,213,000
 
+1%

Daily gas production for the first nine months of both 2014 and 2013 was approximately 11.8 MMcfd, with 2014 production only slightly higher than 2013.  New and full period production from our Lisewo-1, Lisewo-2, Winna Gora, and Komorze-3K wells added 697,000 cubic feet of natural gas over 2013 first nine-month levels.  These increases helped offset production declines at our Zaniemysl-3 and Roszkow wells.  In addition, production was stopped for 40 days at our Kromolice-1 well for some unexpected flow line repairs, now completed, which also reduced our first nine months’ production.  Production from our Lisewo-2 well, which began in September, is adding approximately 1.3 MMcfd to our net daily production.

We recognized a 5% increase in natural gas prices period over period as a result of two factors.  First, the Polish low-methane tariff was 3.1% higher beginning in February of 2014.  Second, period-to-period weakness in the U.S. dollar against the Polish zloty increased our dollar-denominated gas prices.  The average exchange rate during the first nine months of 2014 was 3.08 zlotys per dollar.  The average exchange rate during the first nine months of 2013 was 3.19 zlotys per dollar, a change of approximately 3%.

Oil Revenues.  Oil revenues were $2.8 million for the first nine months of 2014, a 5% decrease from the $3.0 million recognized during the first nine months of 2013.  Production from our U.S. properties declined 4% during the first nine months of 2014 due to regular production declines.  The decline in production was coupled with lower prices received during the first nine months of 2014.  Our average oil price during the first nine months of 2014 was $79.60 per barrel, a 1% decrease from $80.75 per barrel received during the same period of 2013.
 
18
 
 

 

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

 
For the Nine Months Ended September 30,
   
 
2014
 
2013
 
Change
Revenues
$2,816,000
 
$2,963,000
 
-5%
Average price (per barrel)
$79.60
 
$80.75
 
-1%
Production volumes (barrels)
35,400
 
36,700
 
-4%

Lease Operating Costs.  Lease operating costs were $3.5 million during the first nine months of 2014, an increase of 32% compared to the same period of 2013.  Poland operating costs increased approximately $0.4 million, or 42%, from year to year, with a portion of the increase attributable to new production at our Lisewo-1, Lisewo-2, and Komorze-3K wells, along with workover costs at our Komorze and Winna Gora wells.  Operating costs and production taxes in the United States increased from 2013 to 2014 as we incurred extensive workover and other costs at our Montana properties.

Exploration Costs.  Our exploration costs consist of geological and geophysical costs and the costs of exploratory dry holes.  Exploration costs were $8.8 million during the first nine months of 2014, compared to $17.4 million during the same period of 2013.  Nine-month 2014 exploration costs included approximately $0.9 million in period-to-date dry-hole costs associated with our Baraniec well, approximately $3.2 million of dry-hole costs, primarily associated with our Szymanowice well, which was plugged following an unsuccessful workover, and $4.8 million associated with 3-D and 2-D seismic surveys at both our Fences and Edge project areas in Poland.

Our 2013 exploration costs included approximately $6.6 million of dry-hole costs, $3.8 million associated with our Mieczewo well, which was plugged at the end of the first quarter of the year, and approximately $2.4 million associated with the unsuccessful fracture stimulation of our Plawce-2 well.  In addition, we spent approximately $10.7 million associated with 3-D and 2-D seismic surveys at both our Fences area and our 100%-owned concessions in Poland.

Property Impairment.  During the first nine months of 2014, we recorded property impairment costs of $8.3 million.  Approximately $4.5 million is associated with prior-year costs at our Gorka Duchowna well, which we intend to abandon in the fourth quarter.  We have determined to relinquish part of our Block 246 concession, which contains the Gorka Duchowna well, in order to narrow our exploration focus in that concession.  In addition, we impaired $3.7 million of prior-year costs associated with our Szymanowice well, which was plugged during the first half of 2014.  During the first nine months of 2013, we recorded property impairment costs of $5.6 million.  We impaired approximately $4.6 million of prior-year costs associated with our Plawce-2 well following its unsuccessful fracture stimulation, along with approximately $0.2 million of prior-year costs associated with our Mieczewo well.  In addition, our Zaniemysl-3 well ceased production during 2013, causing us to charge its remaining net book value of $0.4 million to impairment expense.  Finally, we recorded an impairment charge of $0.5 million related to concession costs in our Northwest project area, where we made the determination to cease all exploration efforts.

DD&A Expense–Exploration and Production.  DD&A expense for producing properties was $3.1 million for the first nine months of 2014, an increase of 8% compared to $2.8 million during the same period of 2013.  Higher DD&A expense in 2014 was due to increased depreciation expense at our Lisewo-1 and Komorze-3K, reflecting higher and new production in 2014.

Accretion Expense.  Accretion expense was $69,000 and $67,000 for the first nine months of 2014 and 2013, respectively.  Accretion expense is related entirely to our asset retirement obligation.
 
19
 
 

 

Oilfield Services Segment

Oilfield Services Revenues.  Oilfield services revenues were $3.1 million during the first nine months of 2014, compared to $0.3 million for the first nine months of 2013.  We drilled nine wells for third parties during the first nine months of 2014, along with additional well service work.  We drilled one well for third parties during the first nine months of 2013, along with additional well service work.  Oilfield services revenues will continue to fluctuate from period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our own properties, and other factors.

Oilfield Services Costs.  Oilfield services costs were $2.0 million during the first nine months of 2014, compared to $0.4 million during the same period of 2013.  Oilfield services costs will also continue to fluctuate period to period based on market demand, weather, the number of wells drilled, downtime for equipment repairs, the degree of emphasis on utilizing our oilfield servicing equipment on our own properties, and other factors.

DD&A Expense–Oilfield Services.  DD&A expense for oilfield services was $0.8 million during the first nine months of 2014, compared to $0.7 million during the same period of 2013.  The year-to-year increase was primarily due to new capital additions during 2014.

Nonsegmented Information

G&A Costs.  G&A costs were $5.8 million during the first nine months of 2014, compared to $6.5 million during the first nine months of 2013, a decrease of $0.7 million.  The decrease is primarily due to lower compensation costs.  During the first nine months of 2013, compensation costs included the payment of incentive awards totaling approximately $0.9 million, of which approximately $0.5 million related to 2008, which had been deferred until the Company met certain performance benchmarks.  There were no incentive compensation payments made during the first nine months of 2014.

Stock Compensation (G&A).  For the nine-month periods ended September 30, 2014 and 2013, we recognized $2.0 million and $2.1 million, respectively, of stock compensation expense for the amortization of deferred compensation related to stock option and restricted stock grants.

Interest and Other Income (Expense).  Interest and other income was nominal during the first nine months of 2014, a $0.3 million decrease from the same period in 2013, when we recognized insurance proceeds and had lower cash balances available for investment.  During the first nine months of 2014, we incurred $2.1 million in interest expense, which included $0.4 million of amortization of previously incurred loan fees and $0.3 million in commitment and other fees.  During the first nine months of 2013, we incurred $2.6 million in interest expense.  We recorded $1.1 million of amortization of loan fees, including $0.7 million related to our prior credit facility that was charged to interest expense by virtue of our refinance, and $0.2 million in unused commitment fees.
 
20
 
 

 

Foreign Exchange Gain (Loss).  As discussed in Note 10 to the financial statements, during the first nine months of 2014, we recorded noncash foreign currency transaction losses of approximately $15.4 million, principally attributable to increases in the amount of Polish zlotys necessary to satisfy outstanding intercompany dollar-denominated loans and unpaid interest to FX Energy, Inc.  During the first nine months of 2014, the zloty weakened by approximately 9% against the 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 2013, we recorded noncash foreign currency transaction losses of approximately $1.0 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.  During the first nine months of 2013, the zloty weakened by approximately 1% against the U.S. dollar from the beginning to the end of the period, which caused us to recognize foreign currency transaction losses.

Liquidity and Capital Resources

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

2014 Liquidity and Capital

Working Capital (current assets less current liabilities).  Our working capital was $28.7 million as of September 30, 2014, up from $11.3 million at December 31, 2013.

In July 2014, we closed an underwritten public offering of 800,000 shares of our 9.25% Series B Cumulative Convertible Preferred Stock (the “Series B Preferred Stock”) at a public offering price of 25.00 per share.  The aggregate gross proceeds from the offering were $20 million, with net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $18.4 million.  Cumulative dividends of 9.25%, or $1.9 million per year, are payable out of funds legally available therefor.  We intend to use funds available for exploration efforts in our Edge concession in Poland and for general corporate purposes, including declaring and paying dividends on our Series B Preferred Stock.

Our current assets at September 30, 2014, included approximately $27.5 million in cash and cash equivalents and marketable securities, $3.5 million in accrued oil and gas sales from both the United States and Poland, and $1.5 million in receivables from our joint interest partners in both the United States and Poland.  At September 30, 2014, $13.2 million of our cash and cash equivalents were held in Poland at ING Bank N.V.  We have not historically repatriated, and do not plan in the foreseeable future to repatriate, any cash held in Poland to the United States.  Consequently, we do not expect to incur repatriation taxes in the foreseeable future.  Our current liabilities at quarter-end included approximately $1.6 million payable by us for various drilling and development operations in Poland.  Our total outstanding long-term debt at quarter-end was $50 million.

Operating Activities.  Net cash provided by operating activities was $8.8 million during the first nine months of 2014, compared to $2.9 million during the first nine months of 2013.
 
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Investing Activities.  During the first nine months of 2014, we used cash of $15.9 million in investing activities.  We used $15.1 million for capital additions in Poland and $0.7 million for capital additions in our office and drilling equipment.  During the first nine months of 2013, we used cash of $17.5 million in investing activities.  We used $16.7 million for capital additions in Poland and $0.8 million for capital additions in our office and drilling equipment.

Financing Activities.  During the first nine months of 2014, we increased our outstanding debt by $5.0 million.  As described above, we sold 800,000 shares of Series B Preferred Stock during 2014.  After associated offering costs, the net proceeds from the offering were approximately $18.4 million.  Following the issuance of the Series B Preferred Stock, we purchased $4.1 million of marketable securities.  We also sold 163,639 shares of common stock under our at-the-market agreement, in connection with our existing shelf registration.  Net proceeds from the stock sale were approximately $0.6 million after deducting associated costs.

During the first nine months of 2013, we paid $2.0 million in fees for our new credit facility that closed in July of that year.  We used proceeds of $42.0 million from our new facility to repay the prior facility, as well as to pay for the new facility fees.  These fees were capitalized as loan fees and are being amortized over the life of the new facility, beginning in the third quarter of 2013.

Our Capital Resources and Future Expenditures

Our anticipated sources of liquidity and capital for 2014 include our working capital of $28.7 million at September 30, 2014, available credit under our credit facility, and cash available from our operations.

In July 2013, we finalized a new, five-year, up to $100 Million Senior Reserve Based Lending Facility with BNP Paribas (Suisse) SA and ING Bank N.V.  The initial commitment of the facility is $65 million.  We can seek to increase the commitment up to $100 million under certain conditions via an embedded accordion mechanism.  Initial proceeds from the facility were used to repay our previously existing facility.  Payment of the credit facility is secured by our assets in Poland and guaranteed by us.

The credit facility calls for a periodic interest rate of LIBOR, plus an interest margin of 3.75% for the first three years of the facility and 4.00% for the final two years.  The facility has a term of five years, with semiannual borrowing base reductions of $13 million beginning on June 30, 2016.  There are no financial covenants associated with the new credit facility.  As of September 30, 2014, we had $50 million outstanding under the facility and $15 million of available credit.

We expect to continue to generate cash from our operating activities to help fund our exploration and development activities in 2014.  We expect that our 2014 production will approximate or be higher than our 2013 production with the addition of production at our Komorze-3K and Lisewo-2 wells.  Production began at Komorze-3K in late February of 2014 and at Lisewo-2 during September of 2014.  We currently expect to receive 86% of the published low-methane tariff, adjusted for energy content, for each of the two new wells.  The amount of revenue from this increased production will depend on applicable gas sales prices and prevailing currency exchange rates.

We have an effective Securities Act universal shelf registration statement under which we may sell up to $200 million of equity or debt securities of various kinds.  As discussed above, we closed a $20 million preferred stock offering in July 2014, which was made under the shelf registration.  Any additional stock issued to cover over-allotments will also be issued under the shelf registration.
 
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In June 2012, we entered into an agreement to possibly sell up to $50 million in common stock in at-the-market transactions.  During the first half of 2014, we sold approximately $0.7 million of common stock under that agreement.  Currently, we have approximately $179.3 million of securities available for sale at any time under the registration statement, $49.3 million of which is covered by the at-the-market facility.  Future issuances of stock under the shelf registration to finance our exploration and development plans in Poland and for other corporate purposes are subject to market conditions and our ability to access the capital markets.

At September 30, 2014, we were in the process of conducting drilling operations at our Karmin-1 and Baraniec-1 wells, and we had agreed to proceed with sidetrack operations at our Zaniemysl well.  Total remaining costs for these is expected to be approximately $6.3 million.  We had no other firm commitments for future capital and exploration costs at September 30, 2014.

We expect our primary use of cash for 2014 will be for our exploration and development activities in Poland.  Our board of directors has approved projects whose costs are expected to range from $50 million to $60 million for production facilities for existing discoveries, exploration and development wells, capital additions for our drilling rigs, and 2-D and 3-D seismic data acquisition and analysis, including those items noted above.  All of the approved projects may not be completed during 2014, but we do expect to start work on all of them during 2014.  In 2013, we approved a capital budget of similar size and actually incurred approximately $50.0 million in costs.

The actual amount of our expenditures will depend on ongoing exploration results; the pace at which Polskie Górnictwo Naftowe i Gazownictwo, or PGNiG, our operating partner in the Fences project area, wishes to proceed or the extent it wishes to continue to participate with us in concessions we operate; the pace at which we explore our 100%-owned concessions following our recent discovery at Tuchola; the availability of drilling and other exploration services; and the amount of capital we obtain from the various sources discussed above.  Our various sources of liquidity and capital outlined above should more than enable us to meet our capital needs in Poland and the United States for the next 12 months.  We have the ability to control the timing and amount of most of our future capital and exploration costs.

We may continue to 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, 2014, we have incurred cumulative net losses of approximately $220 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.  Our future losses may also increase due to civil and/or criminal fines, sanctions, attorney and expert fees, and other costs associated with compliance with environmental regulations, including any resulting from ongoing regulatory reviews of our 2011 oil leak in Montana.

We may also seek to obtain additional funds for future capital investments from the sale of partial property interests or arrangements, such as those negotiated in prior years in which industry participants agreed to bear specified exploration costs to earn an interest in the project or other arrangements, all of which may dilute the interests of our existing stockholders or our interest in the specific project financed.

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

On May 28, 2014, the Financial Accounting Standards Board issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers.  ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017.  Early application is not permitted.  The standard permits the use of either the retrospective or cumulative effect transition method.  We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures.  We have not yet selected a transition method or determined the effect of the standard on our ongoing financial reporting.

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

Critical Accounting Policies

A summary of our significant accounting policies is included in Note 1 of our Consolidated Financial Statements contained in our annual report on Form 10-K for the year ended December 31, 2013.  We believe the application of these accounting policies on a consistent basis enables us to provide financial statement users with useful, reliable, and timely information about our earnings results, financial condition, and cash flows.

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

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

Forward-Looking Statements

This report contains statements about the future, sometimes referred to as “forward-looking” statements.  Forward-looking statements are typically identified by the use of the words “believe,” “may,” “could,” “should,” “expect,” “anticipate,” “estimate,” “project,” “propose,” “plan,” “intend,” and similar words and expressions.  We intend that the forward-looking statements will be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Statements that describe our future strategic plans, goals, or objectives are also forward-looking statements.
 
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Readers of this report are cautioned that any forward-looking statements, including those regarding us or our management’s current beliefs, expectations, anticipations, estimations, projections, proposals, plans, or intentions, are not guarantees of future performance or results of events and involve risks and uncertainties, such as the future timing and results of drilling individual wells and other exploration and development activities; future variations in well performance as compared to initial test data; the possible impairment of capitalized drilling costs if no recoverable reserves are established; future events that may result in the need for additional capital; the prices at which we may be able to sell oil or gas; fluctuations in prevailing prices for oil and gas; our ability to complete the acquisition of targeted new or expanded exploration or development prospects; uncertainties of certain terms to be determined in the future relating to our oil and gas interests, including exploitation fees, royalty rates, and other matters; future drilling and other exploration schedules and sequences for various wells and other activities; uncertainties regarding future political, economic, regulatory, fiscal, taxation, and other policies in Poland; the cost of additional capital that we may require and possible related restrictions on our future operating or financing flexibility; our future ability to attract strategic participants to share the costs of exploration, exploitation, development, and acquisition activities; and future plans and the financial and technical resources of strategic participants.

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

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-3, KSK, Winna Gora, Komorze, and Lisewo wells, are tied to published tariffs.  The tariffs are set from time to time by the public utility regulator in Poland.  Although we are not directly subject to such tariffs, we have elected to link our price to these tariffs in our contracts with PGNiG.  We expect that the prices we receive in the short term for gas we produce will be lower than would be the case in an unregulated setting and may be lower than prevailing western European prices.  We believe it is more likely than not that, over time, the end user gas price in Poland will converge with the average price in Europe.

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

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

We enter into various agreements in Poland denominated in the Polish zloty.  The zloty is subject to exchange-rate fluctuations that are beyond our control.  We do not use derivative financial instruments for hedging, trading, or speculative purposes.  We have used forward-purchase contracts to buy zlotys at specified exchange rates.  The fair value of these contracts is estimated based on period-end quoted market prices, and the resulting asset and expense is recognized in our consolidated financial statements.  As of September 30, 2014, we had no outstanding zloty forward-purchase contracts.


ITEM 4.  CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure.  Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2014, pursuant to Rule 13a-15(b) under the Securities Exchange Act.  Based upon that evaluation, our Certifying Officers concluded that, as of September 30, 2014, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


PART II—OTHER INFORMATION


ITEM 1A.  RISK FACTORS

Information regarding risk factors appears in “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Forward-Looking Statements,” in Part I — Item 2 of this Form 10-Q and in Part I — Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013.  The risks described in our Annual Report on Form 10-K for the year ended December 31, 2013, are not the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially and adversely affect our business, financial condition, or operating results.

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ITEM 6.  EXHIBITS

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

Exhibit
Number*
 
 
Title of Document
 
 
Location
         
Item 1
 
Underwriting Agreement
   
1.02
 
Underwriting Agreement dated July 10, 2014, between and among FX Energy, Inc., and MLV & Co. LLC and Euro Pacific Capital, Inc., for themselves and as representatives of the underwriters named in Schedule II thereto
 
Incorporated by reference from the current report on Form 8-K filed July 14, 2014
         
Item 3
 
Articles of Incorporation and Bylaws
   
3.06
 
Amendment to the Articles of Incorporation Designating Rights, Privileges, and Preferences of 9.25% Series B Cumulative Convertible Preferred Stock dated July 11, 2014
 
Incorporated by reference from the current report on Form 8-K filed July 14, 2014
         
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 10, 2014
By:
/s/ David N. Pierce
 
   
David N. Pierce, President,
Chief Executive Officer
 
       
       
Date:  November 10, 2014
By:
/s/ Clay Newton
 
   
Clay Newton, Principal Financial and
Principal Accounting Officer
 


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