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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, 2004

or

|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

  For the transition period from ______________ to ______________

Commission file number: 001-13781

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

Delaware
(State or other jurisdiction of incorporation
or organization) 		22-2889587
(I.R.S. Employer Identification No.)

5555 San Felipe, Suite 1200, Houston, Texas
(Address of principal executive offices) 		77056
(Zip Code)

(713) 877-8006
(Registrant’s telephone number, including area code)

NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)

        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.  |X| Yes       |_| No

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  |X| Yes       |_| No

        Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  |_| Yes     |_| No

        Not applicable. Although the registrant was involved in bankruptcy proceedings during the preceding five years, the registrant did not distribute securities under its plan of reorganization.

        Number of shares of common stock, par value $0.01 per share, outstanding as of November 1, 2004: 48,947,733.



KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Amounts in thousands, except   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
per share data)
Unaudited
  2004
  2003
  2004
  2003
 
Oil and gas revenue     $ 52,983   $ 41,085   $ 154,279   $ 119,154  
Other, net       (1,700 )   (414 )   (1,911 )   4,689  
          Total revenue and other       51,283     40,671     152,368     123,843  
Operating costs and expenses    
    Lease operating expenses       6,747     6,384     21,375     18,117  
    Production and other taxes       3,958     2,586     10,169     7,638  
    General and administrative expenses       2,226     1,989     6,698     5,651  
    Stock compensation       478     633     2,045     1,044  
    Accretion of asset retirement obligation       257     279     772     837  
    Depreciation, depletion and amortization       13,874     12,678     39,882     34,761  
          Total operating costs and expenses       27,540     24,549     80,941     68,048  
Operating income       23,743     16,122     71,427     55,795  
Interest and other income, net       85     (1 )   313     101  
Redemption premium on early extinguishment of debt       —     —     (3,698 )   —  
Interest expense       (3,415 )   (4,623 )   (10,812 )   (13,825 )
Income before income taxes and cumulative effect of accounting change       20,413     11,498     57,230     42,071  
Federal and state income (taxes) benefit       (1,595 )   183     (4,470 )   11,747  
Net income before cumulative effect of accounting change       18,818     11,681     52,760     53,818  
Cumulative effect of accounting change, net of tax       —     —     —     (934 )
Net income       18,818     11,681     52,760     52,884  
Dividends and accretion of issuance costs on preferred stock       —     (287 )   —     (729 )
Income available to common stockholders     $ 18,818   $ 11,394   $ 52,760   $ 52,155  
Earnings per share of common stock - basic    
    Before cumulative effect of accounting change     $ 0.38   $ 0.30   $ 1.08   $ 1.39  
    Cumulative effect of accounting change       —     —     —     (0.02 )
 Earnings per share of common stock - basic     $ 0.38   $ 0.30   $ 1.08   $ 1.37  
Earnings per share of common stock - diluted    
    Before cumulative effect of accounting change     $ 0.38   $ 0.28   $ 1.06   $ 1.30  
    Cumulative effect of accounting change       —     —     —     (0.02 )
  Earnings per share of common stock - diluted     $ 0.38   $ 0.28   $ 1.06   $ 1.28  
Average shares outstanding for computation of earnings per share    
  Basic       48,936     38,464     48,831     38,046  
  Diluted       49,767     41,905     49,613     41,431  

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these financial statements.

1


KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

(Amounts in thousands,
except share and per share data)
Unaudited
  September 30,
2004
  December 31,
2003
 
Assets            
Current assets    
      Cash and cash equivalents     $ 13,287   $ 2,178  
      Trade accounts receivable, less allowance    
         for doubtful accounts-2004 $4,910; 2003 $4,896       27,153     23,911  
      Prepaid drilling       1,121     1,014  
      Derivative assets       —     689  
      Other current assets       1,518     3,017  
           Current assets       43,079     30,809  
Oil and gas properties, full cost method, less accumulated DD&A-2004 $972,734; 2003 $933,572     358,494     283,791  
Other property, plant and equipment at cost less accumulated depreciation-2004 $12,318; 2003 $11,598     7,891     8,214  
           Property, plant and equipment, net       366,385     292,005  
Deferred charges and other assets    
      Deferred taxes       17,459     18,818  
      Other       8,663     1,334  
           Deferred charges and other assets       26,122     20,152  
Total Assets     $ 435,586   $ 342,966  
Liabilities and stockholders’ equity    
Current liabilities    
      Accounts payable     $ 33,219   $ 27,834  
      Accrued interest       6,236     5,100  
      Accrued drilling cost       14,477     9,596  
      Other accrued liabilities       10,178     9,071  
      Derivative liabilites       9,527     —  
           Current liabilities       73,637     51,601  
Deferred credits and other non-current liabilities    
      Deferred revenue       22,199     38,696  
      Asset retirement obligations       12,255     11,918  
      Derivative liabilites       1,073     —  
      Other       690     720  
           Deferred credits and other non-current liabilities       36,217     51,334  
Long-term debt    
      Credit facility       —     17,000  
      Senior notes       175,000     —  
      Senior subordinated notes       —     125,000  
           Long-term debt       175,000     142,000  
Stockholders’ equity    
      Common stock, par value $0.01 per share,    
         authorized 75,000,000 shares, issued 51,113,085    
         and 50,532,373, respectively       511     505  
      Additional paid-in capital       240,793     236,204  
      Accumulated deficit       (75,872 )   (128,632 )
      Unearned compensation       (1,459 )   (725 )
      Accumulated other comprehensive loss       (8,500 )   (4,580 )
      Less treasury stock, 2,167,096 shares, at cost       (4,741 )   (4,741 )
           Total stockholders’ equity       150,732     98,031  
Total liabilities and stockholders’ equity     $ 435,586   $ 342,966  

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these financial statements.

2


KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

  Nine Months Ended
September 30,
 
(Amounts in thousands)
Unaudited
  2004
  2003
 
Cash flows from operating activities:            
      Net income     $ 52,760   $ 52,884  
      Adjustments to reconcile net income to net cash    
       provided by operating activities:    
          Depreciation, depletion and amortization       39,882     34,761  
          Amortization of deferred revenue       (16,497 )   (21,745 )
          Non-cash losses on derivative instruments       4,733     4,134  
          Redemption premium on early extinguishment of debt       3,698     —  
          Deferred income tax expense (benefit)       3,469     (12,447 )
          Cumulative effect of accounting change, net of tax       —     934  
          Asset retirement obligation accretion       772     837  
          Other non-cash charges and credits, net       2,962     1,892  
      Changes in operating assets and liabilities:    
          Trade accounts receivable       (3,384 )   (9,505 )
          Accounts payable and accrued liabilities       6,856     7,080  
          Accrued interest       1,136     (4,837 )
          Other, net       (1,074 )   (683 )
Net cash provided by operating activities       95,313     53,305  
     
Cash flows from investing activities:    
      Investments in oil and gas properties       (109,787 )   (61,790 )
      Proceeds from sales of oil and gas properties       840     (119 )
      Other capital expenditures       (397 )   (486 )
Net cash used in investing activities       (109,344 )   (62,395 )
     
Cash flows from financing activities:    
      Proceeds from borrowings       175,000     69,499  
      Repayments of debt       (142,000 )   (61,274 )
      Proceeds from issuance of common stock       1,452     81  
      Redemption premium on early extinguishment of debt       (3,698 )   —  
      Deferred financing costs       (5,614 )   (3,397 )
Net cash provided by financing activities       25,140     4,909  
Increase (decrease) in cash and cash equivalents       11,109     (4,181 )
Cash and cash equivalents at beginning of period       2,178     6,935  
Cash and cash equivalents at end of period     $ 13,287   $ 2,754  

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these financial statements.

3


KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY (UNAUDITED)
(Dollars in thousands)

  Common
Stock
  Additional
Paid-in
Capital
  Accumulated
Deficit
  Unearned
Compensation
  Accumulated
Other
Comprehensive
Loss 
  Treasury
Stock
  Comprehensive
Income
  Stockholders’
Equity
 
Balance at December 31, 2003     $ 505   $ 236,204   $ (128,632 ) $ (725 ) $ (4,580 ) $ (4,741 )       $ 98,031  
   Comprehensive income    
      Net income       —     —     52,760     —     —     —   $ 52,760     52,760  
      Commodity hedges, net of tax       —     —     —     —     (3,920 )   —     (3,920 )   (3,920 )
   Comprehensive income                                         $ 48,840        
   Stock issuances - exercise of warrants       2     798     —     —     —     —           800  
   Stock issuances - costs incurred       —     (221 )   —     —     —     —           (221 )
   Stock issuances - stock option exercise,    
       benefit plans and restricted stock awards       4     2,697     —     (1,464 )   —     —           1,237  
   Stock compensation expense       —     1,315     —     730     —     —           2,045  
Balance at September 30, 2004     $ 511   $ 240,793   $ (75,872 ) $ (1,459 ) $ (8,500 ) $ (4,741 )       $ 150,732  

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these financial statements.

4

KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.  Basis of Presentation

        The condensed consolidated interim financial statements included herein have been prepared by KCS Energy, Inc. (“KCS” or the “Company”), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for quarterly reports on Form 10-Q and reflect all adjustments which are of a normal recurring nature and which are, in the opinion of management, necessary for a fair presentation of the interim results. Certain information and footnote disclosures have been condensed or omitted pursuant to such rules and regulations. Although the Company believes that the disclosures are adequate to make the information presented herein not misleading, it is suggested that these condensed consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003. Certain previously reported amounts have been reclassified to conform with current period presentations. The results of operations for the three and nine months ended September 30, 2004 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004.

2.  Stock Compensation

        The cost of awards of restricted stock, determined as the market value of the shares as of the date of grant, is expensed ratably over the restricted period. Stock options issued under the Company’s 2001 stock plan within six months of the cancellation of options in connection with the Company’s plan of reorganization are subject to variable accounting in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation.” Under variable accounting for stock options, the amount of expense recognized during a reporting period is directly related to the movement in the market price of the Company’s common stock during that period. For the three months ended September 30, 2004, stock compensation was $0.5 million compared to $0.6 million for the three months ended September 30, 2003. For the nine months ended September 30, 2004, stock compensation was $2.0 million compared to $1.0 million for the nine months ended September 30, 2003 as a result of the significant increase in the market price of the Company’s common stock.

        As permitted under Statement of Financial Accounting Standards (“SFAS”) No. 123 “Accounting for Stock-Based Compensation,” as amended (“SFAS No. 123”), the Company has elected to continue to account for stock options under the provisions of Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees.” Under this method, the Company does not record any compensation expense for stock options granted if the exercise price of those options is equal to or greater than the market price of the Company’s common stock on the date of grant, unless the awards are subsequently modified. The following table illustrates the effect on income available to common stockholders and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123.

5


(amounts in thousands, except For the Three Months Ended
September 30,
  For the Nine Months Ended
September 30,
 
per share data)
2004
  2003
  2004
  2003
 
Income available to common                    
   stockholders, as reported     $ 18,818   $ 11,394   $ 52,760   $ 52,155  
Add: Stock-based compensation expense    
   included in reported net income       478     633     2,045     1,044  
Deduct: Total stock-based employee    
   compensation expense determined    
   under fair value-based method for    
   all awards       (615 )   (451 )   (1,671 )   (1,395 )
Pro forma income available to                            
   common stockholders     $ 18,681   $ 11,576   $ 53,133   $ 51,804  
Earnings per share:    
   Basic - as reported     $ 0.38   $ 0.30   $ 1.08   $ 1.37  
   Basic - pro forma     $ 0.38   $ 0.30   $ 1.09   $ 1.36  
   Diluted - as reported     $ 0.38   $ 0.28   $ 1.06   $ 1.28  
   Diluted - pro forma     $ 0.38   $ 0.28   $ 1.07   $ 1.27  

3.  Income Taxes

        The Company records deferred tax assets and liabilities to account for temporary differences arising from events that have been recognized in its financial statements and will result in future taxable or deductible items in its tax returns. To the extent deferred tax assets exceed deferred tax liabilities, at least annually and more frequently if events or circumstances change materially, the Company assesses the realizability of its net deferred tax assets. A valuation allowance is recognized if, at the time, it is anticipated that some or all of the net deferred tax assets may not be realized.

        In making this assessment, management performs an extensive analysis of the operations of the Company to determine the sources of future taxable income. Such an analysis consists of a detailed review of all available data, including the Company’s budget for the ensuing year, forecasts based on current as well as historical prices, and the Company’s oil and gas reserves.

        The determination to establish and adjust a valuation allowance requires significant judgment as the estimates used in preparing budgets, forecasts and reserve reports are inherently imprecise and subject to substantial revision as a result of changes in the outlook for prices, production volumes and costs, among other factors. It is difficult to predict with precision the timing and amount of taxable income the Company will generate in the future. Accordingly, while the Company’s current net operating loss carryforwards (approximately $173 million as of December 31, 2003) have remaining lives ranging from nine to 19 years (with the majority having a life in excess of 15 years), management examines a much shorter time horizon (usually two to three years), when projecting estimates of future taxable income and making the determination as to whether the valuation allowance should be adjusted.

        The Company currently estimates an annual effective tax rate for the year ending December 31, 2004 of approximately 7.8%. The primary item affecting the Company’s annual effective tax rate determination, as compared to the U.S. corporate statutory rate of 35%, is the anticipated reduction of the Company’s valuation allowance that is currently applied against the deferred tax asset associated with the Company’s net operating losses (“NOLs”). Management believes that the increased taxable income the Company expects to generate during 2004, in light of the favorable commodity pricing environment and other factors, will more likely than not result in the Company’s utilization of an additional portion of its unbenefited NOLs.

6


        Based upon the applicable provisions of SFAS No. 109, “Accounting for Income Taxes,” the Company has included the benefit associated with the realization of its NOLs in its estimated annual effective tax rate because the realization relates to additional estimated ordinary income in the current year.

        The Company estimates that it will make alternative minimum tax payments of approximately 1 to 2% of pre-tax income in 2004.

4.  Deferred Revenue

        In February 2001, the Company entered into a production payment transaction whereby it sold 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) to be delivered over 60 months (the “Production Payment”). Net proceeds from the Production Payment of approximately $175 million were recorded as deferred revenue on the Company’s balance sheet. Deliveries under the Production Payment are recorded as oil and gas revenue with a corresponding reduction of deferred revenue at the average discounted price per Mcf of natural gas and per barrel of oil received when the Production Payment was sold. The Company also reflects the production volumes and depletion expense as deliveries are made. However, the associated oil and gas reserves are excluded from the Company’s reserve data. For the nine months ended September 30, 2004, the Company delivered 4.0 Bcfe and recorded $16.5 million of oil and gas revenue. This compares to Production Payment deliveries of 5.3 Bcfe and $21.7 million of oil and gas revenue for the nine months ended September 30, 2003. From the sale of the Production Payment in February 2001 to September 30, 2004, the Company had delivered 37.7 Bcfe, or 88% of the total quantity to be delivered.

5.  Earnings Per Share

        The following table sets forth the computation of basic and diluted earnings per share:


(amounts in thousands,   Three months ended
September 30,
  Nine months ended
September 30,
 
except per share data)
  2004
  2003
  2004
  2003
 
Basic earnings per share:                    
     Income available to common stockholders     $ 18,818   $ 11,394   $ 52,760   $ 52,155  
     Average shares of common stock outstanding       48,936     38,464     48,831     38,046  
Basic earnings per share     $ 0.38   $ 0.30   $ 1.08   $ 1.37  
Diluted earnings per share:    
     Income available to common stockholders     $ 18,818   $ 11,394   $ 52,760   $ 52,155  
     Dividends and accretion of issuance costs    
        on preferred stock       —     287     —     729  
Diluted earnings     $ 18,818   $ 11,681   $ 52,760   $ 52,884  
     Average shares of common stock outstanding       48,936     38,464     48,831     38,046  
     Assumed conversion of convertible
       preferred stock       —     2,898     —     3,195  
     Stock options and warrants       831     543     782     190  
     Average diluted shares of common stock outstanding       49,767     41,905     49,613     41,431  
Diluted earnings per share     $ 0.38   $ 0.28   $ 1.06   $ 1.28  

7


6.  Derivatives

        Oil and natural gas prices have historically been volatile. The Company has at times utilized derivative contracts, including commodity price swaps, futures contracts, option contracts and price collars, to manage this price risk.

        Commodity Price Swaps. Commodity price swap agreements require the Company to make payments to, or entitle it to receive payments from, the counter parties based upon the differential between a specified fixed price and a price related to those quoted on the New York Mercantile Exchange for the period involved.

        Futures Contracts. Oil or natural gas futures contracts require the Company to sell and the counter party to buy oil or natural gas at a future time at a fixed price.

        Option Contracts. Option contracts provide the right, not the obligation, to buy or sell a commodity at a fixed price. By buying a “put” option, the Company is able to set a floor price for a specified quantity of its oil or natural gas production. By selling a “call” option, the Company receives an upfront premium from selling the right for a counter party to buy a specified quantity of oil or natural gas production at a fixed price.

        Price Collars. Selling a call option and buying a put option creates a “collar” whereby the Company establishes a floor and ceiling price for a specified quantity of future production. Buying a call option with a strike price above the sold call strike price establishes a “3-way collar” that entitles the Company to capture the benefit of price increases above that call price.

        As of September 30, 2004, the Company had outstanding derivative instruments covering 4.1 million MMBtu of 2004 natural gas production, 6.4 million MMbtu of 2005 natural gas production, 0.1 million barrels of 2004 oil production and 0.2 million barrels of 2005 oil production. The Company does not currently have any outstanding derivative instruments related to future production that extend beyond 2005. The following table sets forth the Company’s open derivative contracts as of September 30, 2004.

8


Expected Maturity
     
2004
  2005
  Fair Value as of
September 30, 		 
  4th   1st   2nd   3rd   4th       2004
 
  Quarter
  Quarter
  Quarter
  Quarter
  Quarter
  Total
  (In thousands)
  		 
Swaps:                                
Oil    
   Volumes (bbl)       138,000     45,000     45,500     46,000     46,000     182,500   $ (3,239 )
   Weighted average price ($/bbl)     $ 38.11   $ 36.16   $ 35.22   $ 34.56   $ 33.99   $ 34.98        
Natural Gas    
   Volumes (MMbtu)       1,920,000     1,350,000     1,365,000     460,000     460,000     3,635,000   $ (4,871 )
   Weighted average price ($/MMbtu)     $ 5.88   $ 6.77   $ 5.54   $ 5.23   $ 6.44   $ 6.07        
Collars:    
Natural Gas    
    Volumes (MMbtu)       1,840,000     900,000     455,000     460,000     460,000     2,275,000   $ (1,698 )
    Weighted average price ($/MMbtu)    
        Floor     $ 4.00   $ 5.25   $ 5.50   $ 5.50   $ 5.50   $ 5.40        
        Cap     $ 7.52   $ 7.52   $ 7.61   $ 7.61   $ 7.61   $ 7.57        
Sold calls:    
Natural Gas    
    Volumes (MMbtu)       305,000     450,000     —     —     —     450,000   $ (792 )
    Weighted average price ($/MMbtu)     $ 7.10   $ 7.10     —     —     —   $ 7.10        
     
    Fair value of derivatives at September 30, 2004                                 $ (10,600 )

          The fair value of the Company’s derivative instruments are reflected as assets or liabilities in the Company’s financial statements as presented in the following table.

  September 30, 2004
 
  (in thousands)  
          Derivative liabilities-current     $ (9,527 )
          Derivative liabilities-non current       (1,073 )
          Fair value of derivatives at September 30, 2004     $ (10,600 )

        In addition to the information set forth in the first table above, the Company will deliver 1.2 Bcfe during the remainder of 2004, 3.9 Bcfe in 2005 and 0.2 Bcfe in 2006 under the Production Payment sold in February 2001 and amortize deferred revenue at a weighted average price of $4.05 per Mcfe.

        Reflected in the first table above are natural gas call options covering 755,000 MMbtu of natural gas production that were sold for proceeds of $0.3 million. These options do not qualify for hedge accounting treatment under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) and therefore, all unrealized gains and losses related to changes in fair value and realized gains and losses are being reported in other, net on the Condensed Statements of Consolidated Income. Unrealized losses associated with these sold call options were $0.3 million and $0.4 million for the three and nine months ended September 30, 2004, respectively. In addition, for the month of September 2004, a portion of the Company’s oil swaps covering 128,050 bbls ceased to qualify for hedge accounting. Therefore, the unrealized losses related to September 2004 changes in fair value of $0.8 million were recorded in other, net on the Condensed Statements of Consolidated Income. The unrealized losses on these positions as of August 31, 2004 will remain in Other Comprehensive Income ("OCI") until the hedge transaction occurs. In October 2004, these positions again qualified for hedge accounting. As a result, future changes in the fair market value of these positions, to the extent that they are effective, will also be deferred in OCI until the hedge transaction occurs.

9


        As of September 30, 2004, the Company had approximately $8.5 million of derivative losses, net of tax, recorded in Accumulated Other Comprehensive Income (Loss) (“AOCI”) which included losses associated with terminated commodity derivatives and other commodity derivatives. The following table recaps the balance of AOCI at September 30, 2004 on both a pre-tax and after-tax basis.

  Pre-tax
  After-tax
 
  (In thousands)  
Terminated commodity derivatives (a)     $ (4,161 ) $ (2,705 )
Other commodity derivatives (b)       (8,915 )   (5,795 )
AOCI at September 30, 2004     $ (13,076 ) $ (8,500 )

        (a) During 2001, the Company terminated certain commodity derivative instruments and recognized a charge to AOCI. As the original forecasted transaction occurs, this loss is reclassified as a charge against earnings. The following table details the activity of these terminated commodity instruments on both a pre-tax and after-tax basis.

  Pre-tax
  After-tax
 
  (In thousands)  
Balance included in AOCI, December 31, 2003     $ (7,566 ) $ (4,918 )
Reclassified as a charge against earnings       3,405     2,213  
Balance included in AOCI, September 30, 2004     $ (4,161 ) $ (2,705 )

        Of the $2.7 million after-tax loss remaining in AOCI at September 30, 2004 related to the terminated commodity derivatives, $0.7 million and $2.0 million will be reclassified as a charge against earnings during the remainder of 2004 and 2005, respectively.

        (b) The Company also has other commodity derivatives, which were accounted for as hedges under SFAS No. 133. The following table details the activity of those commodity derivatives on both a pre-tax and after-tax basis.

  Pre-tax
  After-tax
 
  (In thousands)  
Balance included in AOCI, December 31, 2003     $ 520   $ 338  
Reclassified into earnings       922     599  
Change in fair market value       (11,237 )   (7,304 )
Ineffective portion of hedges       880      572  
Balance included in AOCI, September 30, 2004     $ (8,915 ) $ (5,795 )

7.  Debt

        The following table sets forth information regarding the Company’s outstanding debt.

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September 30,
2004
  December 31,
2003
 
(Amounts in thousands)
Bank Credit Facility     $ —   $ 17,000  
8-7/8% Senior Subordinated Notes       —     125,000  
7-1/8% Senior Notes       175,000     —  
        175,000     142,000  
Classified as short-term debt       —     —  
Long-term debt     $ 175,000   $ 142,000  

        Bank Credit Facility. The Company has a bank credit facility that provides up to $100 million of revolving borrowing capacity and matures on November 20, 2006. Borrowing capacity under the bank credit facility is subject to a borrowing base (currently $100 million) and is reviewed at least semi-annually and may be adjusted based on the lenders’ valuation of the Company’s oil and natural gas reserves and other factors. Substantially all of the Company’s assets, including the stock of all of its subsidiaries, are pledged to secure the bank credit facility. Further, each of the Company’s subsidiaries has guaranteed its obligations under the bank credit facility.

        Borrowings under the bank credit facility bear interest, at the Company’s option, at an interest rate of LIBOR plus 2.25% to 3.0% or the greater of (1) the Federal Funds Rate plus 0.5% or (2) the Base Rate, plus 0.5% to 1.25%, depending on utilization. These rates will decrease by 0.5% after the final deliveries are made in connection with the Production Payment discussed in Note 4 above and the lien on the subject property is released. A commitment fee of 0.5% per year is paid on the unused availability under the bank credit facility. Financing fees pertaining to the bank credit facility are being amortized over the life of the facility.

        The bank credit facility contains various restrictive covenants, including minimum levels of liquidity and interest coverage. The bank credit facility also contains other usual and customary terms and conditions of a conventional borrowing base facility, including prohibitions on a change of control, prohibitions on the payment of cash dividends, restrictions on certain other distributions and restricted payments, and limitations on the incurrence of additional debt and the sale of assets.

        As of September 30, 2004, we did not have any outstanding amounts under the bank credit facility and had $100 million of unused borrowing capacity available for future financing needs. In addition, the Company was in compliance with all covenants under the bank credit facility as of that date.

        Senior Notes. On April 1, 2004, the Company issued $175 million of 7-1/8% senior notes due April 1, 2012 (the “Senior Notes”). The Senior Notes bear interest at a rate of 7-1/8% per annum with interest payable semi-annually on April 1 and October 1. The Company may redeem the Senior Notes at its option, in whole or in part, at any time on or after April 1, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 3.563% in 2008 to 0% in 2010 and thereafter. In addition, at any time prior to April 1, 2007, the Company may redeem up to a maximum of 35% of the aggregate principal amount with the net cash proceeds of one or more equity offerings at a price equal to 107.125% of the principal amount, plus accrued and unpaid interest. The Senior Notes are senior unsecured obligations and rank subordinate in right of payment to all existing and future secured debt, including secured debt under the Company’s bank credit facility, and will rank equal in right of payment to all existing and future senior indebtedness.

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        The Senior Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s current subsidiaries. KCS Energy, Inc., the issuer of the Senior Notes, has no independent assets or operations apart from the assets and operations of its subsidiaries.

        The indenture governing the Senior Notes contains covenants that, among other things, restricts or limits the ability of the Company and the subsidiary guarantors to: (i) borrow money; (ii) pay dividends on stock; (iii) purchase or redeem stock or subordinated indebtedness; (iv) make investments; (v) create liens; (vi) enter into transactions with affiliates; (vii) sell assets; and (viii) merge with or into other companies or transfer all or substantially all of the Company’s assets.

        In addition, upon the occurrence of a change of control (as defined in the indenture governing the Senior Notes), the holders of the Senior Notes will have the right to require the Company to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest, if any.

        The Company received $171.1 million in net proceeds from the issuance of the Senior Notes. Net proceeds of the issuance were used to redeem the aggregate principal amount of the Company’s $125 million 8-7/8% senior subordinated notes due 2006 (the “Senior Subordinated Notes”) together with an early redemption premium of $3.7 million, to repay the $22 million outstanding under the Company’s bank credit facility, and for general corporate purposes.

        The Senior Subordinated Notes were redeemed on May 1, 2004 and the early redemption premium of $3.7 million was charged against earnings in the second quarter of 2004. In addition, the Company incurred an additional $0.9 million of interest expense as both the Senior Subordinated Notes and the Senior Notes were outstanding during the month of April 2004.

8.  Supplemental Cash Flow Information

        The Company considers all highly liquid financial instruments with a maturity of three months or less when purchased to be cash equivalents. Interest payments were $8.5 million for the nine months ended September 30, 2004 compared to $17.0 million for the nine months ended September 30, 2003. Income tax payments were $1.0 million for the nine months ended September 30, 2004 compared to income tax payments of $0.7 million during the nine months ended September 30, 2003.

        In connection with the adoption of SFAS No. 143 in 2003, the Company recorded a non-cash increase to oil and gas properties of $10.2 million, a non-cash increase in liabilities of $11.1 million and a non-cash charge of $0.9 million as a cumulative effect of accounting change.

        Additions to oil and gas properties for the nine months ended September 30, 2004 were $114.7 million. Of this amount, $109.8 million were cash expenditures and are reflected as investments in oil and gas properties on the Company’s Condensed Statements of Consolidated Cash Flows. The remaining $4.9 million was primarily from increased accrued drilling costs.

        Additions to oil and gas properties for the nine months ended September 30, 2003 were $67.2 million. Of this amount, $61.8 million were cash expenditures and are reflected as investments in oil and gas properties on the Company’s Condensed Statements of Consolidated Cash Flows. The remaining $5.4 million was made up of increases in accrued drilling cost of $5.8 million and capitalized asset retirement obligation of $0.3 million, offset by increased drilling prepayments of $0.7 million.

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9.  Comprehensive Income

        The following table presents the components of comprehensive income for the three months and nine months ended September 30, 2004 and 2003:

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
(Amounts in thousands)
  2004
  2003
  2004
  2003
 
     
Net income     $ 18,818   $ 11,681   $ 52,760   $ 52,884  
     
Commodity hedges,    
   net of tax       (2,077 )   1,233     (3,920 )   2,728  
Comprehensive income     $ 16,741   $ 12,914   $ 48,840   $ 55,612  

10.  New Accounting Principles

        The SEC issued Staff Accounting Bulletin No. 106 ("SAB 106"), effective October 1, 2004. SAB 106 provides interpretive guidance on how full cost companies should reflect asset retirement obligations ("ARO") in their full cost ceiling and depreciation, depletion and amortization expense  calculations. SAB 106 requires future cash outflows associated with settling ARO’s that have accrued on the balance sheet to be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. SAB 106 also requires the inclusion of the estimated amount of ARO that will be incurred as a future development activity on proved reserves in the costs to be amortized. The Company does not believe that adoption of SAB 106 will have a material impact on the Company.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

        The following is a discussion and analysis of our financial condition and results of operations and should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this quarterly report on Form 10-Q. Unless the context otherwise requires, the terms “KCS,” “we,” “our,” or “us” refer to KCS Energy, Inc. and subsidiaries on a consolidated basis.

Forward-Looking Statements

        The information discussed in this quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and natural gas production, the number of anticipated wells to be drilled in the future, our financial position, business strategy and other plans and objectives for future operations are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “expect,” “estimate,” “project,” “plan,” “believe,” “achievable,” “anticipate” and similar terms and phrases. Although we believe that the expectations reflected in any forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including:

  • the timing and success of our drilling activities;

  • the volatility of prices and supply of, and demand for, oil and natural gas;

  • the numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and actual future production rates and associated costs;

  • our ability to successfully identify, execute or effectively integrate future acquisitions;

  • the usual hazards associated with the oil and gas industry (including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards);

  • our ability to effectively market our oil and natural gas;

  • the results of our hedging transactions;

  • the availability of rigs, equipment, supplies and personnel;

  • our ability to acquire or discover additional reserves;

  • our ability to satisfy future capital requirements;

  • changes in regulatory requirements;

  • the credit risks associated with our customers;

  • economic and competitive conditions;

  • our ability to retain key members of senior management and key employees;

  • uninsured judgments or a rise in insurance premiums;

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  • continued hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage; and

  • if underlying assumptions prove incorrect.

        These and other risks are described in greater detail in “Business — Risk Factors” included in our annual report on Form 10-K for the year ended December 31, 2003. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Overview

        In 2004, we have continued to execute the strategies that were successful for us in 2003. Our focus is on low-risk development and exploitation drilling in our core operating areas and to commit approximately 12 to 15% of our capital expenditure budget to moderate-risk, higher-potential exploration prospects primarily in the onshore Gulf Coast region. We continue to stay focused on natural gas, which we believe offers more upside potential than oil or liquids. We plan to maintain a conservative capital structure and continue to reduce debt per Mcfe by increasing our oil and gas reserve base. We have continued our disciplined hedging program designed to protect against price declines while participating to a large extent in future price increases. In this way, we endeavor to ensure that we generate a sufficient level of cash flow to carry out a capital expenditure program sufficient to at least replace our expected production and still benefit if prices rise. In November 2004, we further increased our 2004 capital budget from $125 million to $140 million due to the success of our drilling program and the continued strength of natural gas and oil prices resulting in increased cash flow. We believe that these factors present us with a unique opportunity to accelerate the drilling of our prospect inventory and to increase our oil and gas production and reserves. For the three months ended September 30, 2004 we invested $40.1 million and drilled 34 wells, of which 31 were completed resulting in a 91% success rate. During the first nine months of 2004, we invested $114.7 million and drilled 99 wells, of which 95 were completed resulting in a 96% success rate. We expect to drill between 25 and 35 wells during the fourth quarter of the year.

        In 2004, we further strengthened our financial condition and provided additional financial flexibility by completing a $175 million senior notes offering. The new senior notes bear interest at an annual rate of 7-1/8% and mature in 2012. The proceeds of this issuance were used to redeem the $125 million 8-7/8% senior subordinated notes due 2006, including an early redemtion premium, and to repay the $22 million outstanding under our bank credit facility. As of September 30, 2004, we had $13.3 million of cash on hand and $100 million of unused committed borrowing capacity under our bank credit facility. Please read Note 7 to our Condensed Consolidated Financial Statements for more information regarding our senior notes and our bank credit facility.

        In the Mid-Continent region, we concentrate our drilling programs primarily in north Louisiana, east Texas, Oklahoma (Anadarko and Arkoma basins) and west Texas. Our Mid-Continent operations provide us with a solid base for production and reserve growth. We plan to continue to exploit areas within the various basins that require low-risk exploitation wells for additional reservoir drainage. Our exploitation wells are generally step-out and extension type wells with moderate reserve potential. We have a multi-year inventory of locations in the Mid-Continent region and have increased the level of drilling in our Elm Grove and Joaquin fields and continued the development program in our Sawyer Canyon and Talihina Fields. For the three months ended September 30, 2004, we drilled 31 wells in this region with a success rate of 94%. During the first nine months of 2004, we drilled 79 wells in this region with a success rate of 96%.

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        In the Gulf Coast region, we concentrate our drilling programs primarily in onshore south Texas. We also have working interests in several minor non-operated offshore and Mississippi salt basin properties. We conduct development programs and pursue moderate-risk, higher potential exploration drilling programs in this region. Our Gulf Coast operations have numerous exploration prospects that are expected to provide us additional growth. For the three months ended September 30, 2004, we drilled 2 exploratory wells and 1 development well in this region with a success rate of 67%. During the first nine months of 2004, we drilled 10 exploratory wells and 10 development wells in this region with a success rate of 95%. In the third quarter of 2004, we acquired a 42,300 acre lease and license to approximately 100 square miles of 3D seismic data in Goliad County, Texas.

Results of Operations

        Income available to common stockholders for the three months ended September 30, 2004 was $18.8 million, or $0.38 per basic and diluted share, compared to $11.4 million, or $0.30 per basic share and $0.28 per diluted share, for the three months ended September 30, 2003. This increase reflects  a 10% increase in gross production (17% increase in net production after production payment delivery obligations that do not contribute to cash flow from operating activities), 17% higher natural gas and oil prices, and lower interest expense, partially offset by non-cash derivative losses, higher production and other taxes as a result of higher oil and gas revenue, and value of oil and gas properties higher depreciation, depletion and amortization expense (“DD&A”) as a result of higher production and an increase in our income tax provision (primarily non-cash). The increase in natural gas and oil production reflects our successful drilling program.

        For the nine months ended September 30, 2004, operating income was $71.4 million compared to $55.8 million for the nine months ended September 30, 2003. This increase was primarily attributable to a 16% increase in natural gas and oil production (27% increase in net production contributing to cash flow from operating activities) and an 11% increase in natural gas and oil prices, partially offset by lower non-oil and gas revenue (including non-cash derivative losses) and higher operating expenses. A $3.7 million redemption premium associated with the early redemption of our 8-7/8% senior subordinated notes due 2006 and interest expense of $10.8 million (which included $0.9 million of additional interest expense associated with the early redemption) brought income before income taxes and cumulative effect of accounting change to $57.2 million for the nine months ended September 30, 2004 compared to $42.1 million for the nine months ended September 30, 2003. The significant decrease in interest expense for the nine months ended September 30, 2004 to $10.8 million compared to $13.8 million for the nine months ended September 30, 2003 reflects substantially lower average outstanding borrowings and lower interest rates. Income tax expense was $4.5 million (primarily non-cash) for the nine months ended September 30, 2004 compared to a non-cash income tax benefit of $11.7 million for the nine months ended September 30, 2003 due to changes in the valuation allowance against our net deferred tax asset. During the nine months ended September 30, 2003, we recorded a cumulative effect of accounting change of $0.9 million, or $0.02 per basic and diluted share, as a result of the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). Income available to common stockholders for the nine months ended September 30, 2004 was $52.8 million, or $1.08 per basic share and $1.06 per diluted share, compared to $52.2 million, or $1.37 per basic share and $1.28 per diluted share, for the nine months ended September 30, 2003.

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        The following table sets forth: (i) our gross natural gas and oil production; (ii) our production net of obligations under a production payment (net production); (iii) the average realized prices received for our production; and (iv) our associated revenue for the three and nine months ended September 30, 2004 and 2003.

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
  2004
  2003
  2004
  2003
 
Production (a):                    
      Gas (MMcf)       8,655     7,570     24,711     20,303  
      Oil (Mbbl)       201     207     591     635  
      Natural Gas Liquids (Mbbl)       51     70     161     175  
           Total (MMcfe)       10,168     9,227     29,224     25,160  
      Dedicated to Production    
         Payment       (1,249 )   (1,594 )   (3,994 )   (5,314 )
           Net production (MMcfe)       8,919     7,633     25,230     19,846  
     
Average Realized Prices:    
      Gas (per Mcf)     $ 5.26   $ 4.61   $ 5.43   $ 4.94  
      Oil (per bbl)       32.19     25.36     29.18     25.61  
      Natural Gas Liquids (bbl)       18.52     13.78     17.54     14.81  
      Total (per Mcfe) (b)       5.21     4.45     5.28     4.74  
Revenue (in thousands):    
      Gas     $ 45,568   $ 34,887   $ 134,201   $ 100,302  
      Oil       6,470     5,247     17,256     16,261  
      Natural Gas Liquids       945     951     2,822     2,591  
           Total     $ 52,983   $ 41,085   $ 154,279   $ 119,154  

(a) Includes delivery obligations dedicated to a production payment transaction whereby in February 2001 we sold 43.1 Bcfe (38.3 Bcf of natural gas and 797 Mbbl of oil) to be delivered over 60 months (the “Production Payment”). Production includes 1,249 and 3,994 MMcfe, respectively, for the three and nine months ended September 30, 2004 compared to 1,594 and 5,314 MMcfe, respectively, for the three and nine months ended September 30, 2003 dedicated to the Production Payment. Please read Note 4 to our Condensed Consolidated Financial Statements.

(b) The average realized prices reported above include the non-cash effects of volumes delivered under the Production Payment as well as the unwinding of various derivative contracts terminated in 2001. These items do not generate cash to fund our operations. Excluding these items, the average realized price per Mcfe was $5.56 and $5.66 for the three and nine months ended September 30, 2004, respectively, compared to $4.79 and $5.26 for the three and nine months ended September 30, 2003.

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Natural gas revenue

        For the three months ended September 30, 2004, natural gas revenue increased $10.7 million, to $45.6 million, compared to $34.9 million for the same period in 2003 due to a 14% increase in production and a 14% increase in average realized prices.

        For the nine months ended September 30, 2004, natural gas revenue increased $33.9 million, to $134.2 million, compared to $100.3 million for the same period in 2003 due to a 22% increase in production and a 10% increase in average realized prices.

        The production increase in both periods was primarily due to our successful drilling program.

Oil and natural gas liquids revenue

        For the three months ended September 30, 2004, oil and natural gas liquids revenue increased $1.2 million, to $7.4 million, compared to $6.2 million for the same period in 2003 due to a 31% increase in average realized prices, partially offset by a  9% decrease in production.

        For the nine months ended September 30, 2004, oil and natural gas liquids revenue increased $1.2 million, to $20.1 million, compared to $18.9 million for the same period in 2003 due to a 15% increase in average realized prices, partially offset by a 7% decrease in production.

        The decrease in oil and natural gas liquids production reflected the natural decline of our oil and natural gas liquids properties as our drilling program over the last several years has been focused almost entirely on natural gas prospects.

Other, net

        For the three months ended September 30, 2004, other net was a loss of $1.7 million, compared to a $0.4 million loss for the three months ended September 30, 2003. The $1.3 million change was primarily due to non-cash losses associated with certain derivatives that did not qualify for hedge accounting treatment pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Please read Note 6 to our Condensed Consolidated Financial Statements.

        For the nine months ended September 30, 2004, other net was a loss of $1.9 million due mainly to the non-cash derivative losses discussed above. This compares to other net revenue of $4.7 for the nine months ended September 30, 2003 primarily related to the sale of emission reduction credits. We do not anticipate that there will be any significant sales of emission reduction credits during the fourth quarter of 2004.

Lease operating expenses

        For the three months ended September 30, 2004, lease operating expenses (“LOE”) increased $0.3 million, to $6.7 million, compared to $6.4 million for the three months ended September 30, 2003 due to the increase in the number of producing wells as a result of our expanded drilling program. On a per unit of production basis, LOE was $0.66 per Mcfe for the three months ended September 30, 2004 compared to $0.69 per Mcfe for the three months ended September 30, 2003.

        For the nine months ended September 30, 2004, LOE increased $3.3 million, to $21.4 million ($0.73 per Mcfe), compared to $18.1 million ($0.72 per Mcfe) for the nine months ended September 30, 2003. The increase in the 2004 nine-month period was attributable to the increase in the number of producing wells as a result of our expanded drilling program and increased workover activity during the first half of 2004.

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Production and other taxes

        For the three months ended September 30, 2004, production and other taxes increased $1.4 million, to $4.0 million, compared to $2.6 million for the three months ended September 30, 2003. For the nine months ended September 30, 2004, production and other taxes increased $2.6 million, to $10.2 million, compared to $7.6 million for the nine months ended September 30, 2003. The increases in the 2004 three and nine-month periods were primarily due to increased production (severance) taxes due to higher oil and gas revenues and higher ad valorem taxes due to the higher value of our oil and gas properties.

General and administrative expenses

        For the three months ended September 30, 2004, general and administrative expenses (“G&A”) increased $0.2 million, to $2.2 million, compared to $2.0 million for the three months ended September 30, 2003. On a per unit of production basis, G&A was $0.22 per Mcfe for both the three months ended September 30, 2004 and three months ended September 30, 2003.

        For the nine months ended September 30, 2004, G&A increased $1.0 million, to $6.7 million ($0.23 per Mcfe), compared to $5.7 million ($0.22 per Mcfe) for the nine months ended September 30, 2003. The increases in the 2004 three and nine-month periods were primarily attributable to increased costs to comply with corporate governance initiatives mandated by the Sarbanes-Oxley Act of 2002 and the New York Stock Exchange and rising labor costs.

Stock compensation

        Stock compensation reflects the non-cash expense associated with stock options issued in 2001 that are subject to variable accounting in accordance with FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation” (“FIN 44”), and the non-cash expense associated with the amortization of restricted stock grants. Under variable accounting for stock options, the amount of expense recognized during a reporting period is directly related to the movement in the market price of our common stock during that period.

        For the three months ended September 30, 2004, stock compensation was $0.5 million compared to $0.6 million for the three months ended September 30, 2003. For the nine months ended September 30, 2004, stock compensation was $2.0 million compared to $1.0 million for the nine months ended September 30, 2003. The increase in the 2004 nine-month period reflects the significant increase in the market price of our common stock.

Depreciation, depletion and amortization

        We amortize our oil and gas properties using the unit-of-production method based on proved reserves. For the three months ended September 30, 2004, DD&A increased $1.2 million, to $13.9 million ($1.36 per Mcfe), compared to $12.7 million ($1.37 per Mcfe) for the three months ended September 30, 2003.

        For the nine months ended September 30, 2004, DD&A increased $5.1 million, to $39.9 million ($1.36 per Mcfe), compared to $34.8 million ($1.38 per Mcfe) for the nine months ended September 30, 2003.

        The increases in the 2004 three and nine-month periods reflect the higher production associated with our successful drilling program.

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Redemption premium on early extinguishment of debt

        On May 1, 2004, we redeemed our $125 million 8-7/8% senior subordinated notes due 2006. Pursuant to the indenture, we paid an early redemption premium of $3.7 million, which was charged against earnings in the second quarter of 2004.

Interest expense

        For the three months ended September 30, 2004, interest expense was $3.4 million compared to $4.6 million for the three months ended September 30, 2003. For the nine months ended September 30, 2004, interest expense was $10.8 million compared to $13.8 million for the nine months ended September 30, 2003. The 2004 nine-month period included an additional $0.9 million of interest expense as both our 8-7/8% senior subordinated notes due 2006 and our 7-1/8% senior notes due 2012 were outstanding during the month of April 2004. Our 8-7/8% senior subordinated notes were redeemed on May 1, 2004.

        The significant decrease in interest expense in the 2004 three and nine-month periods as compared to the same periods in 2003 reflects reduced amounts of outstanding debt and substantially lower borrowing costs.

Income taxes

        For the three months ended September 30, 2004, our income tax provision was $1.6 million (primarily non-cash) compared to a non-cash income tax benefit of $0.2 million for the three months ended September 30, 2003. For the nine months ended September 30, 2004, the income tax provision was $4.5 million (primarily non-cash) compared to a non-cash income tax benefit of $11.7 million for the nine months ended September 30, 2003. The income tax benefit in the 2003 nine-month period reflects an adjustment to our valuation allowance against our net deferred tax asset as a result of the substantial improvement in our financial condition and other factors. Please read Note 3 to our Condensed Consolidated Financial Statements.

        We currently estimate that our annual effective tax rate for the year ending December 31, 2004 will be approximately 7.8%. The primary item affecting our annual effective tax rate determination, as compared to the U.S. corporate statutory rate of 35%, is the anticipated reduction of our valuation allowance that is currently applied against the deferred tax asset associated with our net operating losses (“NOLs”). We believe that the increased taxable income expected to be generated during 2004, in light of the favorable commodity pricing environment and other factors, will more likely than not result in the utilization of an additional portion of our unbenefited NOLs.

        Based upon the applicable provisions of SFAS No.109, “Accounting for Income Taxes,” we included the benefit associated with the realization of our NOLs in the estimated annual effective tax rate because the realization relates to additional estimated ordinary income in the current year.

        We also believe that if the current pricing environment continues, the valuation allowance on our deferred tax assets for NOLs may be further reduced or eliminated.

        We estimate that we will make alternative minimum tax payments of approximately 1 to 2% of pre-tax income in 2004.

Liquidity and Capital Resources

        Our primary cash requirements are for the exploration, development and aquisitions of oil and gas properties, operating expenses and debt service. We expect to fund our drilling activities primarily with internally generated cash flow and to have sufficient capital resources available to allow us the flexibility to be opportunistic with our drilling program and to fund larger aquisitions and working capital requirements. We believe this approach allows us to maintain an appropriate capital structure that allows us to increase our oil and gas reserves and to reduce debt per MCFE.

        In April 2004, we completed a private placement of $175 million of 7-1/8% senior notes due 2012. The net proceeds of this issuance were used to redeem our $125 million 8-7/8% senior subordinated notes due 2006, to repay the $22 million outstanding under our credit facility and for general corporate purposes.  On May 1, 2004 we redeemed our $125 million $ 7-/8% senior subordinated notes due 2006.  Pursuant to the indenture, we paid an early redemption premium of $3.7 million. Please read Note 7 to our Condensed Consolidated Financial Statements for more information regarding our senior notes, including a discussion of restrictive covenants, and our bank credit facility.

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        In November 2004, we announced a second increase in our 2004 capital budget from $125 million to $140 million due to the success of our drilling program and the continued strength of natural gas and oil prices resulting in increased cash flow. For the three months ended September 30, 2004, we invested $40.1 million and drilled 34 wells, of which 31 were completed resulting in a 91% success rate. During the first nine months of 2004, we invested $114.7 million and drilled 99 wells, of which 95 were completed resulting in a 96% success rate. We expect to drill between 25 and 35 wells during the fourth quarter of 2004. We believe that this program will be funded primarily through internally generated cash flow. The amount and allocation of our capital budget is subject to change based on operational developments, commodity prices, service costs, acquisitions and numerous other factors. Generally, we do not budget for acquisitions.

        Our net working capital position at September 30, 2004 was a deficit of $30.6 million. On that date, we had $100.0 million of unused availability under our bank credit facility. Working capital deficits are not unusual in our industry. We, like many other oil and gas companies, typically maintain relatively low cash reserves and use any excess cash to fund our capital expenditure program or pay down borrowings under our bank credit facility. The September 30, 2004 working capital deficit was somewhat higher than usual due mainly to the high level of accrued drilling costs ($14.5 million) as a result of our active drilling program and the timing of associated payments, and derivative liabilities ($9.5 million) that reflect the “mark-to-market” fair value of our outstanding derivative positions.

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        We believe that cash on hand, net cash generated from operations and unused committed borrowing capacity under our bank credit facility will be adequate to fund our capital budget and satisfy our liquidity needs. As of September 30, 2004, we had $13.3 million of cash on hand and $100 million of unused committed borrowing capacity under our bank credit facility available for future financing needs. In the future, we may also utilize various financing sources available to us, including the issuance of debt or equity securities under our shelf registration statement or through private placements. Our ability to complete future debt and equity offerings and the timing of these offerings will depend upon various factors including prevailing market conditions, interest rates and our financial condition.

Cash flow provided by operating activities

        For the nine months ended September 30, 2004, net cash provided by operating activities increased 79% to $95.3 million compared to $53.3 million for the nine months ended September 30, 2003. The increase during the 2004 nine-month period was primarily due to the increase in net production as discussed above and higher natural gas and oil prices.

Cash used in investing activities

        For the nine months ended September 30, 2004, net cash used in investing activities was $109.3 million compared to $62.4 million during the same period in 2003. Substantially all of the net cash used in investing activities for the nine months ended September 30, 2004 and 2003 was invested in oil and gas properties.

Cash from financing activities

        For the nine months ended September 30, 2004, net cash provided by financing activities was $25.1 million due to the refinancing of our debt as discussed above and in Note 7 to our Condensed Consolidated Financial Statements. For the nine months ended September 30, 2003, net cash provided by financing activities was $4.9 million due to additional borrowings used to fund our drilling program.

Contractual Cash Obligations

        The following table summarizes our future contractual cash obligations related to long-term debt as of September 30, 2004 after taking into account the issuance of the $175 million of 7-1/8% senior notes due 2012 as described above and as further described in Note 7 to our Condensed Consolidated Financial Statements (in thousands).

    Payments due by period
   
  Total   Less Than
1 Year 		  1-3
Years 		  3-5
Years 		  More Than
5 Years 		 
Long-term debt     $ 175,000     —     —     —   $ 175,000  

        As of September 30, 2004, there have been no other material changes outside the ordinary course of our business to the other items listed in the Contractual Cash Obligations table included in our annual report on Form 10-K for the year ended December 31, 2003.

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New Accounting Principles

        The SEC issued Staff Accounting Culletin No. 106 (“SAB 106”), effective October 1, 2004. SAB 106 provides interpretive guidance on how full cost companies should reflect asset retirement obligations (“ARO”)  in their full cost ceiling and DD&A calculations. SAB 106 requires future cash outflows associated with settling ARO’s that have accrued on the balance sheet to be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. SAB 106 also requires the inclusion of the estimated amount of ARO that will be incurred as a future development activity on proved reserves in the costs to be amortized. We do not believe that adoption of SAB 106 will have a material impact on us.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

        All information and statements included in this section, other than historical information and statements, are “forward-looking statements.” Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Statements.”

Commodity Price Risk

        Our major market risk exposure is to oil and natural gas prices, which have historically been volatile. Realized prices are primarily driven by the prevailing worldwide price for crude oil and regional spot prices for natural gas production. We have utilized, and may continue to utilize, derivative contracts, including commodity price swaps, futures contracts, options contracts and price collars to manage this price risk. We do not enter into derivative or other financial instruments for trading or speculative purposes. Effective January 1, 2001, we adopted SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). While these derivative contracts are structured to reduce our exposure to decreases in the price associated with the underlying commodity, they also limit the benefit we might otherwise receive from price increases. We maintain a system of controls that includes a policy covering authorization, reporting and monitoring of derivative activity. Please read Note 6 to our Condensed Consolidated Financial Statements for more information on our derivative contracts.

        As of September 30, 2004, we had outstanding derivative instruments covering 4.1 million MMBtu of 2004 natural gas production, 6.4 million MMbtu of 2005 natural gas production, 0.1 million barrels of 2004 oil production and 0.2 million barrels of 2005 oil production. We do not currently have any outstanding derivative instruments related to future production that extend beyond 2005. The following table sets forth information with respect to our open derivative contracts as of September 30, 2004.

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Expected Maturity
     
2004
  2005
  Fair Value as of
September 30, 		 
  4th   1st   2nd   3rd   4th       2004
 
  Quarter
  Quarter
  Quarter
  Quarter
  Quarter
  Total
  (In thousands)
 		  
Swaps:                                
Oil    
   Volumes (bbl)       138,000     45,000     45,500     46,000     46,000     182,500   $ (3,239 )
   Weighted average price ($/bbl)     $ 38.11   $ 36.16   $ 35.22   $ 34.56   $ 33.99   $ 34.98        
Natural Gas    
   Volumes (MMbtu)       1,920,000     1,350,000     1,365,000     460,000     460,000     3,635,000   $ (4,871 )
   Weighted average price ($/MMbtu)     $ 5.88   $ 6.77   $ 5.54   $ 5.23   $ 6.44   $ 6.07        
Collars:    
Natural Gas    
    Volumes (MMbtu)       1,840,000     900,000     455,000     460,000     460,000     2,275,000   $ (1,698 )
    Weighted average price ($/MMbtu)    
        Floor     $ 4.00   $ 5.25   $ 5.50   $ 5.50   $ 5.50   $ 5.40        
        Cap     $ 7.52   $ 7.52   $ 7.61   $ 7.61   $ 7.61   $ 7.57        
Sold calls:    
Natural Gas    
    Volumes (MMbtu)       305,000     450,000     —     —     —     450,000   $ (792 )
    Weighted average price ($/MMbtu)     $ 7.10   $ 7.10     —     —     —   $ 7.10        
     
    Fair value of derivatives at September 30, 2004                                 $ (10,600 )

        In addition to the information set forth in the table above, we will deliver 1.2 Bcfe during the remainder of 2004, 3.9 Bcfe in 2005 and 0.2 Bcfe in 2006 under the Production Payment and amortize deferred revenue at a weighted average price of $4.05 per Mcfe.

        Reflected in the table above are natural gas call options covering 755,000 MMbtu of natural gas production that were sold for proceeds of $0.3 million. These options do not qualify for hedge accounting treatment under SFAS No. 133  and therefore, all unrealized gains and losses related to changes in fair value and realized gains and losses are being reported in other, net on the Condensed Statements of Consolidated Income. Unrealized losses associated with these sold call options were $0.3 million and $0.4 million for the three and nine months ended September 30, 2004, respectively. In addition, for the month of September 2004, oil swaps covering 128,050 bbls ceased to qualify for hedge accounting.  Therefore, the unrealized losses related to September 2004 changes in fair value of $0.8 million were recorded in other, net on the Condensed Statements of Consolidated Income. The unrealized losses on these positions as of August 31, 2004 will remain in Other Comprehensive Income ("OCI") until the hedge transaction occurs.  In October 2004, these positions again qualified for hedge accounting.  As a result, future changes in the fair market value of these positions, to the extents that they are effective, will also be deferred in OCI until the hedge transaction occurs. 

        Commodity Price Swaps. Commodity price swap agreements require us to make payments to, or entitle us to receive payments from, the counter parties based upon the differential between a specified fixed price and a price related to those quoted on the New York Mercantile Exchange for the period involved.

        Futures Contracts. Oil or natural gas futures contracts require us to sell and the counter party to buy oil or natural gas at a future time at a fixed price.

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        Option Contracts. Option contracts provide the right, not the obligation, to buy or sell a commodity at a fixed price. By buying a “put” option, we are able to set a floor price for a specified quantity of our oil or natural gas production. By selling a “call” option, we receive an upfront premium from selling the right for a counter party to buy a specified quantity of oil or natural gas production at a fixed price.

        Price Collars. Selling a call option and buying a put option creates a “collar” whereby we establish a floor and ceiling price for a specified quantity of future production. Buying a call option with a strike price above the sold call strike establishes a “3-way collar” that entitles us to capture the benefit of price increases above that call price.

Interest Rate Risk

        We use fixed and variable rate long-term debt to finance our capital spending program and for general corporate purposes. Our variable rate debt instruments expose us to market risk related to changes in interest rates. Our fixed rate debt and the associated weighted average interest rate was $175.0 million at 7-1/8% as of September 30, 2004 and $125.0 million at 8-7/8% on December 31, 2003 and September 30, 2003. We did not have any outstanding variable rate debt as of September 30, 2004. Our variable rate debt and weighted average interest rate was $17.0 million at 3.6% as of December 31, 2003 and $70.0 million at 7.6% on September 30, 2003.

        On April 1, 2004, we issued $175.0 million of 7-1/8% senior notes due April 1, 2012. Please read Note 7 to our Condensed Consolidated Financial Statements for more information on the senior notes. The table below presents our debt obligations and related average interest rates expected by maturity date as of September 30, 2004 (dollars in millions).

As of September 30, 2004
 
  Expected Maturity Date
    Fair  
2004
  2005
  2006
  2007
  2008
  Thereafter
  Total
  Value
 
Long-term debt                                    
        Fixed rate       —     —     —     —     —   $ 175.0   $ 175.0   $ 180.3  
        Average interest rate       —     —     —     —     —     7.125 %   7.125 %   —  
        Variable rate       —     —     —     —     —     —     —     —  
        Average interest rate       —     —     —     —     —     —     —     —  

Item 4.  Controls and Procedures.

        Evaluation of disclosure controls and procedures. Based on their evaluation of our disclosure controls and procedures as of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective in ensuring that the information required to be disclosed by us (including our consolidated subsidiaries) in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

        Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting that occurred during our last 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 1.  Legal Proceedings.

        Note 11 (Litigation) to our Condensed Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2003 is incorporated herein by reference.

Item 6.  Exhibits.

  10.1 Amendment No. 1 to Employment Agreement, dated August 1, 2004, between KCS Energy, Inc. and James W. Christmas.

  10.2 Amendment No. 1 to Employment Agreement, dated August 1, 2004,  between KCS Energy, Inc. and William N. Hahne.

  10.3 Amendment No. 1 to Employment Agreement, dated August 1, 2004,  between KCS Energy, Inc. and Harry Lee Stout.

  10.4 Amendment No. 1 to Change in Control Agreement, dated August 1, 2004,  between KCS Energy, Inc. and Joseph T. Leary.

  10.5 Amendment No. 1 to Change in Control Agreement , dated August 1, 2004, between KCS Energy, Inc. and Frederick Dwyer.

  10.6 Form of Supplemental Stock Option Agreement.

  10.7 Form of Directors Supplemental Stock Option Agreement.

  10.8 Form of Restricted Stock Award Agreement.

  10.9 Form of Restricted Stock Award Agreement (with accelerated vesting provision).

  31.1 Rule 13a-14(a)/15d-14(a) Certification of James W. Christmas, Chief Executive Officer.

  31.2 Rule 13a-14(a)/15d-14(a) Certification of Joseph T. Leary, Chief Financial Officer.

  32.1 Section 1350 Certification of James W. Christmas, Chief Executive Officer.

  32.2 Section 1350 Certification of Joseph T. Leary, Chief Financial Officer.

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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.




Date: November 9, 2004 		KCS ENERGY, INC.


/s/ Frederick Dwyer
————————————————————
      Frederick Dwyer
      Vice President, Controller and Secretary
      (Signing on behalf of the registrant and
      as Principal Accounting Officer)

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EXHIBIT INDEX

  Exhibit
    No.		 Description
 

  10.1 Amendment No. 1 to Employment Agreement, dated August 1, 2004,  between KCS Energy, Inc. and James W. Christmas.

  10.2 Amendment No. 1 to Employment Agreement, dated August 1, 2004,  between KCS Energy, Inc. and William N. Hahne.

  10.3 Amendment No. 1 to Employment Agreement, dated August 1, 2004,  between KCS Energy, Inc. and Harry Lee Stout.

  10.4 Amendment No. 1 to Change in Control Agreement, dated August 1, 2004,  between KCS Energy, Inc. and Joseph T. Leary.

  10.5 Amendment No. 1 to Change in Control Agreement, dated August 1, 2004,  between KCS Energy, Inc. and Frederick Dwyer.

  10.6 Form of Supplemental Stock Option Agreement.

  10.7 Form of Directors Supplemental Stock Option Agreement.

  10.8 Form of Restricted Stock Award Agreement.

  10.9 Form of Restricted Stock Award Agreement (with accelerated vesting provision).

  31.1 Rule 13a-14(a)/15d-14(a) Certification of James W. Christmas, Chief Executive Officer.

  31.2 Rule 13a-14(a)/15d-14(a) Certification of Joseph T. Leary, Chief Financial Officer.

  32.1 Section 1350 Certification of James W. Christmas, Chief Executive Officer.

32.2 Section 1350 Certification of Joseph T. Leary, Chief Financial Officer.


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