10-Q 1 form10q-71843_kcs.txt 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, 2005 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 22-2889587 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 5555 San Felipe Road, Suite 1200, Houston, Texas 77056 (Address of principal executive offices) (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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). |_| Yes |X| 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, 2005: 50,276,669. PART I - FINANCIAL INFORMATION Item 1. Financial Statements.
KCS ENERGY, INC. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED INCOME (Amounts in thousands, except per share data) (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2004 2005 2004 2005 --------- --------- --------- --------- Oil and natural gas revenue $ 101,714 $ 52,983 $ 246,310 $ 154,279 Other, net 22 (416) (195) (546) --------- --------- --------- --------- Total revenue and other 101,736 52,567 246,115 153,733 --------- --------- --------- --------- Operating costs and expenses Lease operating expenses 9,469 6,747 25,264 21,375 Production and other taxes 6,674 3,958 14,064 10,169 General and administrative expenses 2,733 2,226 8,254 6,698 Stock compensation 1,353 478 2,314 2,045 Accretion of asset retirement obligation 241 257 723 772 Depreciation, depletion and amortization 24,279 13,874 64,882 39,882 --------- --------- --------- --------- Total operating costs and expenses 44,749 27,540 115,501 80,941 --------- --------- --------- --------- Operating income 56,987 25,027 130,614 72,792 --------- --------- --------- --------- Loss on mark-to-market derivatives, net (12,160) (1,284) (12,997) (1,365) Interest and other income 20 85 94 313 Redemption premium on early extinguishment of debt -- -- -- (3,698) Interest expense (5,012) (3,415) (13,471) (10,812) --------- --------- --------- --------- Income before income taxes 39,835 20,413 104,240 57,230 Federal and state income tax expense (15,348) (1,595) (39,403) (4,470) --------- --------- --------- --------- Net income 24,487 18,818 64,837 52,760 ========= ========= ========= ========= Earnings per share of common stock - basic $ 0.49 $ 0.38 $ 1.31 $ 1.08 ========= ========= ========= ========= Earnings per share of common stock - diluted $ 0.49 $ 0.38 $ 1.29 $ 1.06 ========= ========= ========= ========= Average shares outstanding for computation of earnings per share Basic 49,688 48,936 49,570 48,831 Diluted 50,308 49,767 50,117 49,613 The accompanying notes are an integral part of these financial statements.
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KCS ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (Amounts in thousands, except share and per share data) (Unaudited) September 30, December 31, 2005 2004 -------------- -------------- ASSETS Current assets Cash and cash equivalents $ 5,078 $ 6,613 Trade accounts receivable, less allowance for doubtful accounts of $4,981 in 2005 and $4,880 in 2004 63,450 35,173 Prepaid drilling 2,264 510 Other current assets 1,825 3,549 -------------- -------------- Current assets 72,617 45,845 -------------- -------------- Property, plant and equipment Oil and gas properties, full cost method, $32,871 and $11,239 excluded from amortization in 2005 and 2004, respectively, less accumulated DD&A - 2005 $1,054,115; 2004 $989,930 614,222 393,217 Other property, plant and equipment, at cost less accumulated depreciation - 2005 $13,246; 2004 $12,549 7,597 7,788 -------------- -------------- Property, plant and equipment, net 621,819 401,005 -------------- -------------- Deferred charges and other assets Deferred taxes 35,216 31,713 Other 11,022 8,745 -------------- -------------- Deferred charges and other assets 46,238 40,458 -------------- -------------- TOTAL ASSETS $ 740,674 $ 487,308 ============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 44,056 $ 38,772 Accrued interest 9,818 3,118 Accrued drilling cost 25,148 21,922 Derivative liabilities 102,872 -- Other accrued liabilities 13,100 10,775 Income taxes payable 819 -- -------------- -------------- Current liabilities 195,813 74,587 -------------- -------------- Deferred credits and other non-current liabilities Deferred revenue 4,666 17,326 Asset retirement obligation 13,967 12,655 Derivative liabilities 14,830 -- Other 692 691 -------------- -------------- Deferred credits and other non-current liabilities 34,155 30,672 -------------- -------------- Long-term debt Credit facility 19,000 -- Senior notes 275,580 175,000 -------------- -------------- Long-term debt 294,580 175,000 -------------- -------------- Commitments and contingencies Stockholders' equity Common stock, par value $0.01 per share, authorized 75,000,000 shares; issued 52,434,475 and 51,395,536, respectively 524 514 Additional paid-in capital 251,341 241,545 Retained earnings (deficit) 36,640 (28,197) Unearned compensation (2,419) (1,225) Accumulated other comprehensive loss (65,219) (847) Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741) -------------- -------------- Total Stockholders' equity 216,126 207,049 -------------- -------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 740,674 $ 487,308 ============== ============== The accompanying notes are an integral part of these financial statements.
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KCS ENERGY, INC. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Amounts in thousands) (Unaudited) For the Nine Months Ended September 30, -------------------------- 2005 2004 ----------- ----------- Cash flows from operating activities: Net income $ 64,837 $ 52,760 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 64,882 39,882 Amortization of deferred revenue (12,660) (16,497) Non-cash losses on derivative instruments 14,402 4,733 Redemption premium on early extinguishment of debt -- 3,698 Deferred income tax expense 37,653 3,469 Stock compensation 2,314 2,045 Accretion of asset retirement obligation 723 772 Other non-cash charges and credits, net 1,150 917 Changes in operating assets and liabilities: Trade accounts receivable (28,420) (3,384) Accounts payable and accrued liabilities 8,163 6,856 Accrued interest 6,700 1,136 Other, net (1,900) (1,074) ----------- ----------- Net cash provided by operating activities 157,844 95,313 ----------- ----------- Cash flows from investing activities: Investment in oil and gas properties (282,317) (109,787) Investment in other property, plant and equipment (506) (397) Other, net 1,511 840 ----------- ----------- Net cash used in investing activities (281,312) (109,344) ----------- ----------- Cash flows from financing activities: Proceeds from borrowings 119,625 175,000 Repayments of debt -- (142,000) Proceeds from issuance of common stock 5,744 1,452 Redemption premium on early extinguishment of debt -- (3,698) Deferred financing costs (3,436) (5,614) ----------- ----------- Net cash provided by financing activities 121,933 25,140 ----------- ----------- Increase (decrease) in cash and cash equivalents (1,535) 11,109 Cash and cash equivalents at beginning of period 6,613 2,178 ----------- ----------- Cash and cash equivalents at end of period $ 5,078 $ 13,287 =========== =========== The accompanying notes are an integral part of these financial statements.
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KCS ENERGY, INC. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (Unaudited) Accumulated Additional Retained Unearned Other Compre- Compre- Stock- Common Paid-in Earnings Compen- hensive Treasury hensive holders' Stock Capital (Deficit) sation Loss Stock Income Equity -------- -------- -------- -------- -------- -------- -------- -------- (Dollars in thousands) Balance at December 31, 2004 $ 514 $241,545 $(28,197) $ (1,225) $ (847) $ (4,741) $207,049 Comprehensive income Net income -- -- 64,837 -- -- -- $ 64,837 64,837 Commodity hedges, net of tax -- -- -- -- (64,372) -- (64,372) (64,372) -------- Comprehensive income $ 465 ======== Stock issuances - exercise of warrants 2 798 -- -- -- -- 800 Stock issuances - exercise of stock options 6 2,995 -- -- -- -- 3,001 Stock issuances - benefit plans and awards of restricted stock 2 2,742 -- (2,161) -- -- 583 Tax benefit of stock option exercise -- 1,914 -- -- -- -- 1,914 Stock compensation expense -- 1,347 -- 967 -- -- 2,314 -------- -------- -------- -------- -------- -------- -------- Balance at September 30, 2005 $ 524 $251,341 $ 36,640 $ (2,419) $(65,219) $ (4,741) $216,126 ======== ======== ======== ======== ======== ======== ======== The accompanying notes 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, 2004. 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, 2005 are not necessarily indicative of the results that may be expected for the year ending December 31, 2005. 2. Income Taxes Federal alternative minimum tax payments, or AMT, of $1.0 million were made during each of the nine months ended September 30, 2005 and 2004. No state income tax payments were made during the nine months ended September 30, 2005 or 2004. 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 reserve report. The determination to establish or 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 aggregating approximately $159 million as of December 31, 2004 have remaining lives ranging from 14 to 18 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 a valuation allowance is required. In the fourth quarter of 2004, based on the aforementioned analysis and the Company's belief that the future outlook for continued generation of taxable income is positive based on existing available information, including current prices quoted on the New York Mercantile Exchange, the Company reversed the remainder of the valuation allowance against net deferred income tax assets. Accordingly, beginning January 1, 2005, the 5 Company resumed recording book income taxes at close to statutory rates. The Company currently anticipates that its effective federal and state book income tax rate for 2005 will be 37.8%. However, the Company will continue to utilize its net operating loss carryforwards to offset taxable income and will be subject primarily to AMT in 2005. 3. Earnings Per Share Basic earnings per share of common stock is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share of common stock reflects the potential dilution that could occur if the Company's dilutive outstanding stock options and warrants were exercised using the average common stock price for the period. The following table sets forth the computation of basic and diluted earnings per share:
For the Three Months Ended For the Nine Months Ended September 30, September 30, (amounts in thousands --------------------------- --------------------------- except per share data) 2005 2004 2005 2004 ------------------------------------------------------- ------------ ------------ ------------ ------------ Net income $ 24,487 $ 18,818 $ 64,837 $ 52,760 ------------ ------------ ------------ ------------ Basic earnings per share: Average shares of common stock outstanding 49,688 48,936 49,570 48,831 ------------ ------------ ------------ ------------ Basic earnings per share $ 0.49 $ 0.38 $ 1.31 $ 1.08 ============ ============ ============ ============ Diluted earnings per share: Average shares of common stock outstanding 49,688 48,936 49,570 48,831 Stock options, warrants and non-vested shares 620 831 547 782 ------------ ------------ ------------ ------------ Average diluted shares of common stock outstanding 50,308 49,767 50,117 49,613 ------------ ------------ ------------ ------------ Diluted earnings per share $ 0.49 $ 0.38 $ 1.29 $ 1.06 ============ ============ ============ ============
4. 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 Employee and Directors 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" until exercised. 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. Stock compensation expense, which is included as a component of general and administrative expenses on the Condensed Statements of Consolidated Income, was $1.4 million for the three months ended September 30, 2005 compared to $0.5 million for the three months ended September 30, 2004. For the nine months ended September 30, 2005, stock compensation was $2.3 million compared to $2.0 million for the nine months ended September 30, 2004. 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 6 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. As indicated in Note 11 below, the adoption of SFAS No. 123 (Revised 2004), "Share-Based Payment", will result in recognition of compensation expense beginning in the first quarter of 2006, and thus may impact the Company's future results of operations. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123.
For the Three Months Ended For the Nine Months Ended September 30, September 30, ---------------------------- ---------------------------- 2005 2004 2005 2004 ------------ ------------ ------------ ------------ (amounts in thousands except per share data) Net income .......................... $ 24,487 $ 18,818 $ 64,837 $ 52,760 Add: Stock-based compensation expense included in reported net income ... 880 478 1,504 2,045 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards ....................... (535) (615) (1,452) (1,671) ------------ ------------ ------------ ------------ Pro forma net income ................ $ 24,832 $ 18,681 $ 64,889 $ 53,134 ============ ============ ============ ============ Basic earnings per share: ------------ ------------ ------------ ------------ Average shares outstanding .......... 49,688 48,936 49,570 48,831 ------------ ------------ ------------ ------------ Basic - as reported .............. $ 0.49 $ 0.38 $ 1.31 $ 1.08 Basic - pro forma ................ $ 0.50 $ 0.38 $ 1.31 $ 1.09 Diluted earnings per share: ------------ ------------ ------------ ------------ Average diluted shares outstanding .. 50,308 49,767 50,117 49,613 ------------ ------------ ------------ ------------ Diluted - as reported ............ $ 0.49 $ 0.38 $ 1.29 $ 1.06 Diluted - pro forma .............. $ 0.49 $ 0.38 $ 1.29 $ 1.07
5. Deferred Revenue For the nine months ended September 30, 2005, the Company delivered 3.1 Bcfe and recorded $12.7 million of oil and gas revenue associated with a production payment sold in February 2001. This compares to production payment deliveries of 4.0 Bcfe and $16.5 million of oil and gas revenue for the nine months ended September 30, 2004. As of September 30, 2005, 1.1 Bcfe remained to be delivered under the production payment, of which 0.8 Bcfe is to be delivered in the remainder of 2005 and 0.3 Bcfe in 2006. 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. The Company accounts for its derivative contracts in accordance with Statement of Financial Accounting Standards No. 133, "Accounting for derivative Instruments and Hedging Activities ("SFAS No. 133"). Commodity Price Swaps. Commodity price swap agreements require the Company to make payments to, or entitle it to receive payments from, the counterparties 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 counterparty 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 counterparty 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. Commodity Basis Swaps. Commodity basis swap agreements require the Company to make payments to, or receive payments from, the counterparties based upon the differential between certain pricing indices and a stated differential amount. As of September 30, 2005, the Company had outstanding derivative instruments covering 5.8 million MMBtu of 2005 natural gas production, 18.1 million MMbtu of 2006 natural gas production, 2.3 million MMbtu of 2007 natural gas production, 0.1 million barrels of 2005 oil production and 0.2 million barrels of 2006 oil production. The following table sets forth information with respect to the Company's open derivative contracts as of September 30, 2005. 8
Expected Maturity --------------------------------------------------------------------------------- Fair Value 2005 2006 2007 as of ---------- ---------------------------------------------------------- --------- September 30, 2005 4th 1st 2nd 3rd 4th Full -------------- Quarter Quarter Quarter Quarter Quarter Total Year (1) (In thousands) Swaps: Oil Volumes (bbl) 91,650 30,000 30,200 30,400 30,400 121,000 -- $ (3,850) Weighted average price ($/bbl) $ 44.22 $ 52.28 $ 51.62 $ 51.04 $ 50.47 $ 51.35 -- Natural Gas Volumes (MMbtu) 4,730,000 4,815,000 3,210,000 2,780,000 1,860,000 12,665,000 2,255,000 $ (93,376) Weighted average price ($/MMbtu) $ 7.81 $ 8.11 7.31 7.35 6.92 $ 7.57 $ 7.78 Collars: Oil Volumes (bbl) -- 22,500 22,750 23,000 23,000 91,250 -- $ (17) Weighted average price ($/bbl) Floor $ -- $ 55.00 $ 55.00 $ 55.00 $ 55.00 $ 55.00 -- Cap $ -- $ 81.00 $ 81.00 $ 81.00 $ 81.00 $ 81.00 -- Natural Gas Volumes (MMbtu) 460,000 1,800,000 1,365,000 1,380,000 -- 4,545,000 -- $ (10,935) Weighted average price ($/MMbtu) Floor $ 5.50 $ 8.44 $ 8.00 $ 8.00 -- $ 8.17 -- Cap $ 7.61 $ 12.89 $ 11.01 $ 10.90 -- $ 11.72 -- Sold calls: Natural Gas Volumes (MMbtu) 610,000 900,000 -- -- -- 900,000 -- $ (9,524) Weighted average price ($/MMbtu) $ 8.00 $ 8.00 -- -- -- $ 8.00 -- ----------- Fair value of derivatives at September 30, 2005. $ (117,702) ----------------------------------------------- =========== (1)First and second quarter only
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, 2005 ------------------ (in thousands) Derivative liabilities-current $ 102,872 Derivative liabilities-non-current 14,830 ------------------ Fair value of derivatives at September 30, 2005 $ 117,702 ================== In addition to the information set forth in the first table above, the Company will deliver 0.8 Bcfe during the remainder of 2005 and 0.3 Bcfe in 2006 under the production payment discussed in Note 5 and amortize deferred revenue with respect to such deliveries at a weighted average price of $4.05 per Mcfe. Reflected in the first table above are natural gas call options covering 1,510,000 MMbtu of natural gas production that were sold for proceeds of $1.2 million ($0.805 per MMbtu) during the first quarter of 2005. These options do not qualify for hedge accounting treatment under SFAS No. 133 and therefore all realized and unrealized gains and losses related to changes in fair value are being reported as a net gain or loss on mark-to-market derivatives on the Condensed Statements of Consolidated Income. Unrealized losses associated with these sold call options were $7.9 million and $8.3 million for the three and nine months ended September 30, 2005, respectively. 9 As of September 30, 2005, the Company had approximately $65.2 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, 2005 on both a pre-tax and after-tax basis. Pre-tax After-tax ---------- ---------- (In thousands) Terminated commodity derivatives (a) $ (756) $ (474) Other commodity derivatives (b) (104,092) (64,745) ---------- --------- AOCI at September 30, 2005 $ (104,848) $ (65,219) ========== ========= (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, 2004 $ (3,026) $ (1,967) Reclassified as a charge against earnings 2,270 1,493 -------- -------- Balance included in AOCI, September 30, 2005 $ (756) $ (474) ======== ======== The $0.5 million after-tax loss remaining in AOCI at September 30, 2005 related to the terminated commodity derivatives will be reclassified as a charge against earnings during the fourth quarter of 2005. (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, 2004 $ 1,723 $ 1,120 Change in fair market value (119,853) (74,596) Ineffective portion of hedges 3,854 2,397 Reclassified into earnings 10,184 6,334 ------------ ---------- Balance included in AOCI, September 30, 2005 $ (104,092) $ (64,745) ============ ========== 10 7. Debt The following table sets forth information regarding the Company's outstanding debt. September 30, December 31, 2005 2004 ------------ ----------- (Amounts in thousands) Bank Credit Facility $ 19,000 $ -- 7-1/8% Senior Notes 275,580 175,000 ------------ ----------- 294,580 175,000 Classified as short-term debt -- -- ------------ ----------- Long-term debt $ 294,580 $ 175,000 ============ =========== Bank Credit Facility. On March 31, 2005, the Company amended its bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million, extend the maturity date to March 31, 2009, and permit an additional $125 million of indebtedness for money borrowed. In connection with the amended bank credit facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of the Company's oil and natural gas reserves and other factors, from $100 million to $185 million. The borrowing base is automatically reduced by an amount equal to a specified percentage of the net proceeds from the issuance of any additional indebtedness that is not applied to refinance existing public indebtedness. As a result of the $100 million Senior Notes offering discussed below, the borrowing base was automatically reduced by $20 million to $165 million and the amount of permitted additional indebtedness was reduced to $25 million. Effective December 1, 2004, borrowings under the bank credit facility bear interest, at the Company's option, at an interest rate of LIBOR plus 1.75% to 2.5% or the greater of (1) the Federal Funds Rate plus 0.5% or (2) the Base Rate, plus 0.0% to 0.75%, depending on utilization. The LIBOR and Base Rate margins will decrease by 0.5%, but not to less than 0.0%, after the final deliveries are made in connection with the Production Payment and the lien on the subject property is released. Also effective December 1, 2004, a commitment fee of 0.35% to 0.5% per year, depending on utilization, is paid on the unused availability under the bank credit facility. From November 18, 2003 through November 30, 2004, the applicable margin for LIBOR rate loans was 2.25% to 3.0%, the applicable margin for base rate loans was 0.5% to 1.25%, depending on utilization, and the commitment fee was 0.5% per year on the unused availability under the bank credit 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, acceleration upon the occurrence of an event of default, restrictions on certain other distributions and restricted payments, and limitations on the incurrence of additional debt and the sale of assets. 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 the obligations under the bank credit facility. As of September 30, 2005, $19 million was outstanding under the bank credit facility and $146 million of unused borrowing capacity was available for future financing needs. The Company was in compliance with all covenants under the bank credit facility as of that date. 11 Senior Notes. On April 1, 2004, the Company issued $175 million of 7-1/8% senior notes due April 1, 2012 (the "Original Notes"). The Company received $171.1 million in net proceeds from the issuance of the Original 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 Original Notes were outstanding during the month of April 2004. On April 8, 2005, the Company consummated a private placement of $100 million aggregate principal amount of 7-1/8% senior notes due 2012 (the "Additional Notes"). In connection therewith, the Company entered into a supplemental indenture that amended the indenture governing the Original Notes so that the Original Notes together with the Additional Notes would form a single class of securities (the "Senior Notes"). All other material terms of the original indenture remain the same. The Additional Notes were issued at 100.625% of the face amount. The net proceeds from the issuance of the Additional Notes were approximately $98.2 million after deducting the expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance the Company's acquisition of oil and gas properties and related assets located primarily in the Company's North Louisiana-East Texas core operating area. The remainder of the net proceeds from the issuance of the Additional Notes was used to repay approximately $16.0 million of outstanding borrowings under the bank credit facility. 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 of the Senior Notes 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. 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, restrict or limit 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 12 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. 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. 9. Comprehensive Income The following table presents the components of comprehensive income for the three months and nine months ended September 30, 2005 and 2004:
Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ------------------------ (Amounts in thousands) 2005 2004 2005 2004 -------------------------- ---------- ---------- ---------- ---------- Net income $ 24,487 $ 18,818 $ 64,837 $ 52,760 Commodity hedges, net of tax (54,490) (2,077) (64,372) (3,920) ---------- ---------- ---------- ---------- Comprehensive income $ (30,003) $ 16,741 $ 465 $ 48,840 ========== ========== ========== ==========
10. Acquisition of Oil and Gas Properties On April 13, 2005, the Company completed an acquisition of oil and gas properties and related assets located primarily in the Company's North Louisiana-East Texas core operating area for $86.9 million, of which approximately $64 million was allocated to proved properties and the remainder allocated to unproven properties. The acquisition included internally estimated net proved reserves of approximately 47 Bcfe, of which approximately two-thirds were undeveloped, associated with 137 producing wells and 81 proved undeveloped drilling locations and additional acreage with an estimated 185 drilling locations for which no proved reserves were assigned. The acquisition was primarily financed with proceeds from issuance of the Additional Notes as described in Note 7 to Condensed Consolidated Financial Statements. Through the third quarter of 2005, eleven successful wells have been drilled on the acquired properties and approximately 150 additional drilling locations have been identified. The following table reflects the Company's unaudited pro forma revenue, net income and earnings per share as if the acquisition had taken place at the beginning of fiscal 2005 and 2004. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future. 13
Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ------------------------ 2005 2004 2005 2004 -------- -------- -------- ---------- Total revenue and other $ 101,736 $ 56,466 $ 250,352 $ 163,630 Net income $ 24,487 $ 17,728 $ 64,261 $ 48,812 Earnings per share of common stock - basic $ 0.49 $ 0.36 $ 1.30 $ 1.00 Earnings per share of common stock - diluted $ 0.49 $ 0.36 $ 1.28 $ 0.98
11. New Accounting Principles On December 16, 2004, the Financial Accounting Standards Board issued SFAS No. 123 (Revised 2004) "SFAS 123(R)," "Share-Based Payment," which is a revision of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS 123(R) supersedes APB Opinion No. 25, and amends SFAS Statement No. 95, "Statement of Cash Flows." Generally, the approach in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. The Company plans to adopt SFAS 123(R) on January 1, 2006. The impact of adoption of SFAS 123(R) on the Company's results of operations cannot be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had we adopted Statement 123(R) in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the table in Note 4 above. 14 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, future cash flows and borrowings, pursuit of potential acquisition opportunities, 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 "may," "will," "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, among others: o the timing and success of our drilling activities; o the volatility of prices and supply of, and demand for, oil and natural gas; o the numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and actual future production rates and associated costs; o our ability to successfully identify, execute or effectively integrate future acquisitions; o the usual hazards associated with the oil and gas industry (including fires, natural disasters, well blowouts, adverse weather conditions, pipe failure, spills, explosions and other unforeseen hazards); o our ability to effectively transport and market our oil and natural gas; o the results of our hedging transactions; o the availability of rigs, equipment, supplies and personnel; o our ability to acquire or discover additional reserves; o our ability to satisfy future capital requirements; o changes in regulatory requirements; o the credit risks associated with our customers; 15 o economic and competitive conditions; o our ability to retain key members of senior management and key employees; o uninsured judgments or a rise in insurance premiums; o our outstanding indebtedness; o continued hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage; and o if underlying assumptions prove incorrect. These and other risks are described in greater detail in the section entitled "Business - Risk Factors" included in our annual report on Form 10-K for the year ended December 31, 2004. All forward-looking statements attributable to us 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 the year ended December 31, 2004, we drilled a record 130 wells, of which 126 were completed, resulting in a 97% success rate and significantly increased production and reserves. In 2004, gross production increased 15%, to 40 Bcfe, while net production after production payment delivery obligations that do not contribute to cash flow from operating activities increased 25% compared to 2003. Natural gas and oil reserves increased 22% to 328 Bcfe as of December 31, 2004 compared to 268 Bcfe as of December 31, 2003. In total, we added 94.5 Bcfe of proved reserves during 2004, of which 97% was through the drill bit. Total oil and gas capital expenditures were $166.7 million. In 2005, our strategy has been, and will continue, to focus on low-risk development and exploitation drilling in our core operating areas and to commit approximately 15% to 20% of our capital expenditure budget to moderate-risk, higher-potential exploration prospects primarily in the onshore Gulf Coast region. We follow a 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. Please read Note 6 to our Condensed Consolidated Financial Statements for more information regarding our hedging activities. We plan to maintain a conservative capital structure and the financial flexibility to capitalize on growth opportunities when they become available. The execution of these strategies was evident in our results for the nine months ended September 30, 2005. We accelerated our drilling program, investing $191.0 million (excluding acquisitions), and drilled 152 wells, of which 143 were successful and two are currently being tested, resulting in a 94% success rate and significant increases in our oil and natural gas production. We anticipate investing a total of $260 million (excluding acquisitions) in our drilling program in 2005. We further strengthened our financial flexibility by 16 amending our bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million, extend the maturity date to March 31, 2009, and permit an additional $125 million of indebtedness for money borrowed. In connection with the amended facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of our oil and natural gas reserves and other factors, from $100 million to $185 million. As a result of the $100 million aggregate principal amount of senior notes offering discussed below, the borrowing base was automatically reduced by $20 million to $165 million and the amount of permitted additional indebtedness was reduced to $25 million. On April 8, 2005, we completed a private placement of $100 million aggregate principal amount of 7-1/8% Senior Notes due 2012. The net proceeds from the private placement were approximately $98.2 million after deducting expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance our acquisition discussed in the following paragraph. The remainder of the net proceeds from the offering was used to repay approximately $16.0 million of outstanding borrowings under our bank credit facility. Please read Note 7 to our Condensed Consolidated Financial Statements. On April 13, 2005, we completed an acquisition of oil and gas properties and related assets located primarily in our North Louisiana-East Texas core operating area for $86.9 million. The acquisition included internally estimated net proved reserves of approximately 47 Bcfe, of which approximately two-thirds were undeveloped, associated with 137 producing wells and 81 proved undeveloped drilling locations and additional acreage with an estimated 185 drilling locations for which no proved reserves had been assigned. The acquisition was primarily financed with proceeds from the private placement of the 7?% senior notes due 2012 discussed in the preceding paragraph. The acquisition is consistent with our strategy of focusing on core areas and growth through drilling. We began drilling operations on these properties late in the second quarter. Through the end of the third quarter of 2005, eleven successful wells have been drilled on the acquired properties and approximately 150 additional drilling locations have been identified. 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. In 2005, we plan to drill 125 to 135 wells in this region, approximately half of which are planned in the Elm Grove Field which is our largest field. We will also pursue drilling in the Sawyer Canyon, Joaquin, Terryville and Talihina fields and development of the acquired properties discussed above. We drilled 33 wells in this region during the quarter, bringing the total drilled for the nine months ended September 30, 2005 to 98 wells, of which 96 wells were completed, resulting in a 98% success rate. 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. We anticipate drilling about 60 wells in this region in 2005, approximately three-fourths of which will be exploratory. The 2005 drilling program is mainly concentrated in the O'Connor Ranch, La Reforma, Coquat and Austin fields and the West Mission Valley area. 17 We drilled eight wells in this region during the quarter, bringing the total drilled for the nine months ended September 30, 2005 to 54 wells, of which 47 were completed, resulting in an 87% success rate. Commodity Price Trends and Uncertainties Oil and natural gas prices historically have been volatile and management expects them to continue to be volatile in the future. Domestic natural gas prices continue to remain high when compared to longer-term historical prices. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas. The price of oil has increased over the last two years to levels above longer-term historical prices. Factors such as geopolitical activities, worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by OPEC, and fluctuating currency exchange rates can cause wide fluctuations in the price of oil. The factors driving the increases in oil and natural gas prices are beyond our control. Results of Operations Oil and gas revenue for the three months ended September 30, 2005 increased 92% to $101.7 million, compared to $53.0 million for the three months ended September 30, 2004 due to a 31% increase in oil and natural gas production (39% increase in daily net production contributing to cash flow from operating activities) and a 47% increase in average realized prices. Operating income for the three months ended September 30, 2005 increased 128% to $57.0 million, compared to $25.0 million for the three months ended September 30, 2004. Non-hedge mark-to-market derivative losses for the three months ended September 30, 2005 were $12.2 million compared to $1.3 million for the same period in 2004. Income before income taxes for the three months ended September 30, 2005 increased 95%, to $39.8 million, compared to $20.4 million for the three months ended September 30, 2004. Income tax expense for the three months ended September 30, 2005 was $15.3 million compared to $1.6 million for the three months ended September 30, 2004 reflecting the increase in our effective federal and state income tax rate to 38.5% in the 2005 three-month period compared to 7.8% for the three months ended September 30, 2004. Please read Note 2 to our Condensed Consolidated Financial Statements for more information regarding our income taxes. Net income for the three months ended September 30, 2005 was $24.5 million, or $0.49 per basic and diluted share, compared to $18.8 million, or $0.38 per basic and diluted share, for the three months ended September 30, 2004. For the nine months ended September 30, 2005, oil and gas revenue increased 60% to $246.3 million compared to $154.3 million for the nine months ended September 30, 2004 due to a 26% increase in oil and natural gas production (34% increase in daily net production contributing to cash flow from operating activities) and a 27% increase in average realized prices. Operating income for the nine months ended September 30, 2005 increased 79% to $130.6 million compared to $72.8 million for the nine months ended September 30, 2004. Non-hedge mark-to-market derivative losses for the nine months ended September 30, 2005 were $13.0 million compared to $1.4 million for the same period in 2004. Income before income taxes for the nine months ended September 30, 2005 increased 82%, to $104.2 million, compared to $57.2 million for the nine months ended September 30, 2004. Income before income taxes for the nine months ended September 30, 2004 was negatively impacted by a $3.7 million redemption premium and $0.9 million in additional interest expense associated with the early redemption of our 8-7/8% senior subordinated notes due 2006. Income tax expense for the nine months ended September 30, 2005 was $39.4 million compared to $4.5 million for the nine months ended September 30, 2004 reflecting the increase in our effective federal and state income tax rate to 37.8% in the 2005 nine-month period compared to 7.8% for the nine months ended September 30, 2004. Net income for the nine months ended September 30, 2005 was $64.8 million, or $1.31 18 per basic share and $1.29 per diluted share, compared to $52.8 million, or $1.08 per basic share and $1.06 per diluted share, for the nine months ended September 30, 2004. The following table sets forth: (i) our gross natural gas, oil and natural gas liquids production; (ii) our production net of obligations under a production payment (net production); (iii) our associated revenue; (iv) the average realized prices received for our production; (v) our production cost; and (vi) our per unit production cost for the three and nine months ended September 30, 2005 and 2004.
Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2005 2004 2005 2004 --------- --------- --------- --------- Production: Natural gas (MMcf) .................... 11,737 8,655 32,096 24,711 Oil (Mbbl) ............................ 207 201 620 591 Natural gas liquids (Mbbl) ............ 50 51 153 161 --------- --------- --------- --------- Total (MMcfe) (a) ............... 13,281 10,168 36,734 29,224 Dedicated to Production Payment (MMcfe) (895) (1,249) (3,051) (3,994) --------- --------- --------- --------- Net Production (MMcfe) .......... 12,386 8,919 33,683 25,230 ========= ========= ========= ========= Revenue ($000's): Natural gas ........................... $ 91,012 $ 45,568 $ 216,997 $ 134,201 Oil ................................... 9,319 6,470 25,592 17,256 Natural gas liquids ................... 1,383 945 3,721 2,822 --------- --------- --------- --------- Total ........................... $ 101,714 $ 52,983 $ 246,310 $ 154,279 ========= ========= ========= ========= Average Price: Natural gas (per Mcf) ................. $ 7.75 $ 5.26 $ 6.76 $ 5.43 Oil (per bbl) ......................... 44.99 32.19 41.28 29.18 Natural gas liquids (per bbl) ......... 27.55 18.52 24.32 17.54 Total (per Mcfe) (b) ............ $ 7.66 $ 5.21 $ 6.71 $ 5.28 Production cost ($000's) Lease operating expense ............... $ 9,469 $ 6,747 $ 25,264 $ 21,375 Production and other taxes ............ 6,674 3,958 14,064 10,169 --------- --------- --------- --------- Total ........................... $ 16,143 $ 10,705 $ 39,328 $ 31,544 ========= ========= ========= ========= Average production cost (per Mcfe): Lease operating expense ............... $ 0.71 $ 0.66 $ 0.69 $ 0.73 Production and other taxes ............ 0.50 0.39 0.38 0.35 --------- --------- --------- --------- Total ........................... $ 1.21 $ 1.05 $ 1.07 $ 1.08 ========= ========= ========= =========
--------- (a) Includes delivery obligations dedicated to the production payment sold in 2001. (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 $8.04 and $7.04 for the three and nine months ended September 30, 2005 compared to $5.56 and $5.66 for the three and nine months ended September 30, 2004. Natural gas revenue For the three months ended September 30, 2005, natural gas revenue increased $45.4 million, to $91.0 million, compared to $45.6 million for the same period in 2004 due to a 36% increase in production and a 47% increase in average realized prices. 19 For the nine months ended September 30, 2005, natural gas revenue increased $82.8 million, to $217.0 million, compared to $134.2 million for the same period in 2004 due to a 30% increase in production and a 24% increase in average realized prices. The increase in production in 2005 is primarily attributed our successful drilling program discussed above in "- Overview". Oil and natural gas liquids revenue For the three months ended September 30, 2005, oil and natural gas liquids revenue increased $3.3 million, to $10.7 million, compared to $7.4 million for the same period in 2004 due to a 2% increase in production and a 42% increase in average realized prices. For the nine months ended September 30, 2005, oil and natural gas liquids revenue increased $9.2 million, to $29.3 million, compared to $20.1 million for the same period in 2004 primarily due to a 3% increase in production and a 42% increase in average realized prices. The increase in production in 2005 is primarily attributed our successful drilling program discussed above in "- Overview". Lease operating expenses For the three months ended September 30, 2005, lease operating expenses ("LOE") increased $2.8 million, to $9.5 million, compared to $6.7 million for the three months ended September 30, 2004. On a per unit of production basis, LOE increased to $0.71 per Mcfe for the three months ended September 30, 2005 compared to $0.66 per Mcfe for the three months ended September 30, 2004. The increase in LOE during the three months ended September 30, 2005 reflects a higher level of workovers on the properties acquired in April, generally higher service costs experienced industry-wide and the increase in the number of producing wells as a result of our expanded acquisition and drilling program. For the nine months ended September 30, 2005, LOE increased $3.9 million, to $25.3 million, compared to $21.4 million for the nine months ended September 30, 2004. On a per unit of production basis, LOE decreased to $0.69 per Mcfe for the nine months ended September 30, 2005 compared to $0.73 per Mcfe for the nine months ended September 30, 2004. The increase in LOE during the 2005 nine-month period as compared to the same period in 2004 reflects generally higher service costs experienced industry-wide and the increase in the number of producing wells as a result of our expanded drilling program and the April acquisition. The decrease in the per unit costs for the nine months ended September 30, 2005 as compared to the same period in 2004 reflect higher production rates and efficiencies realized in certain of our larger fields where significant production increases have been achieved. Production and other taxes For the three months ended September 30, 2005, production and other taxes increased $2.7 million, to $6.7 million, compared to $4.0 million for the three months ended September 30, 2004. On a per unit of production basis, production and other taxes were approximately $0.50 per Mcfe for the three months ended September 30, 2005 compared to $0.39 per Mcfe for the three months ended September 30, 2004. For the nine months ended September 30, 2005, production and other taxes increased $3.9 million, to $14.1 million, compared to $10.2 million for the nine months ended September 30, 2004. On a per unit of production basis, production and other taxes was $0.38 per Mcfe for the nine months ended September 30, 20 2005 compared to $0.35 for the nine months ended September 30, 2004. The 2005 nine-month period includes $1.4 million of production tax refunds. Excluding the impact of these refunds, production and other taxes were $0.42 per Mcfe for the nine months ended September 30, 2005. The increase in production and other taxes during the three and nine months ended September 30, 2005 as compared to the same periods in 2004 reflect higher production taxes due to the significant increase in revenue and higher ad valorem taxes due to the increased value of our oil and gas properties and the significant increase in new wells drilled. General and administrative expenses - excluding stock compensation For the three months ended September 30, 2005, general and administrative expenses ("G&A") increased $0.5 million, to $2.7 million, compared to $2.2 million for the three months ended September 30, 2004. On a per unit of production basis, G&A was $0.21 per Mcfe for the three-month period ended September 30, 2005 compared to $0.22 per Mcfe for the three month period ended September 30, 2004. For the nine months ended September 30, 2005, G&A increased $1.6 million, to $8.3 million, compared to $6.7 million for the nine months ended September 30, 2004. On a per unit of production basis, G&A was $0.22 per Mcfe for the nine-month period ended September 30, 2005 compared to $0.23 per Mcfe for the nine-month period ended September 30, 2004. The increases in G&A in the 2005 three and nine-month periods as compared to the same periods in 2004 were primarily attributable to higher labor costs associated with an increase in the work force and increased costs to comply with the Sarbanes-Oxley Act of 2002. The decrease in the per unit of production costs reflects our commitment to cost containment as we expand the Company and the significant increase in production volumes. General and administrative expenses - 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," 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, 2005, stock compensation was $1.4 million compared to $0.5 million for the three months ended September 30, 2004. For the nine months ended September 30, 2005, stock compensation was $2.3 million compared to $2.0 million for the nine months ended September 30, 2004. The increase in the 2005 three-month and nine-month periods reflects the significant increase in the market price of our common stock during the periods, partially offset by a decrease in the number of outstanding options subject to variable accounting. 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, 2005, depreciation, depletion and amortization ("DD&A") increased $10.4 million, to $24.3 million ($1.83 per Mcfe), compared to $13.9 million ($1.36 per Mcfe) for the three months ended September 30, 2004. For the nine months ended September 30, 2005, DD&A increased $25.0 million, to $64.9 million ($1.77 per Mcfe), compared to $39.9 million ($1.36 per Mcfe) for the nine months ended September 30, 2004. The increase in the 2005 three and nine-month periods reflects increased natural gas and oil production 21 and higher costs. The increased costs reflect, among other things, our decision to pursue certain projects (including our acquisition of oil and gas properties and related assets in our North Louisiana-East Texas core operating area) with higher finding and development costs that provide attractive margins at current oil and gas prices. Loss on Mark-to-Market Derivatives, net Losses on mark-to-market derivatives, net, which were previously reported as a component of other, net on our statements of consolidated income, are comprised of net realized and unrealized gains and losses on derivative contracts not subject to hedge accounting treatment pursuant to Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities" and the "ineffective" component of derivative contracts that that do qualify for hedge accounting treatment pursuant to SFAS No. 133. For the three months ended September 30, 2005, the net loss on mark-to-market derivatives was $12.2 million of which $7.9 million was attributable to the non-cash change in fair value of a call option we sold in February 2005 for $1.2 million ($0.805 per MMbtu) whereby the counterparty purchased the right to call 1.5 million MMbtu of our November 2005 through March 2006 production at $8.00 per MMbtu. Because this derivative contract does not qualify for hedge accounting treatment pursuant to SFAS No. 133, the change in its fair value is recorded as a non-cash unrealized gain or loss each period until settlement. The remainder relates primarily to the "ineffective" component of our derivatives that do qualify for hedge accounting treatment pursuant to SFAS No. 133. This compares to a net loss on mark-to-market derivatives of $1.3 million for the three months ended September 30, 2004 primarily due to the ineffective component of our hedge derivative contracts. For the nine months ended September 30, 2005, the net loss on mark-to-market derivatives was $13.0 million, of which $8.3 million was related to the sold call option discussed above, $3.9 million relates to the "ineffective" component of our derivatives that do qualify for hedge accounting treatment pursuant to SFAS No. 133, and $0.8 million relates to other derivatives that either do not qualify for hedge accounting treatment or were not designated as hedges. This compares to the net loss on mark-to-market derivatives of $1.4 million for the nine months ended September 30, 2004 primarily due to the ineffective component of our hedge derivative contracts. Interest expense For the three months ended September 30, 2005, interest expense was $5.0 million compared to $3.4 million for the three months ended September 30, 2004. For the nine months ended September 30, 2005, interest expense was $13.4 million compared to $10.8 million for the nine months ended September 30, 2004. The increase in interest expense in the 2005 three and nine-month periods as compared to the same periods in 2004 reflects higher average outstanding borrowings following the issuance of $100 million of senior notes in April 2005. 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. 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 during the three months ended June 30, 2004. 22 Income taxes For the three months ended September 30, 2005, our federal and state income tax provision was $15.3 million (38.5% of pre-tax income) compared to $1.6 million (7.8% of pre-tax income) for the three months ended September 30, 2004. For the nine months ended September 30, 2005, our federal and state income tax provision was $39.4 million (37.8% of pre-tax income) compared to an income tax provision of $4.5 million (7.8% of pre-tax income) for the nine months ended September 30, 2004. Our income tax provisions during each of the aforementioned periods were primarily non-cash as we continued to utilize existing net operating loss carryforwards as discussed below and in Note 2 to our Condensed Consolidated Financial Statements. We currently anticipate that our effective federal and state book income tax rate for 2005 will be 37.8%. This is significantly higher than the effective income tax rates for 2004 as we resumed recording book income taxes at close to statutory rates following the reversal of the remainder of the valuation allowance against net deferred income tax assets at December 31, 2004. However, we have significant net operating loss carryforwards to offset taxable income in 2005 and beyond and anticipate that we will pay only alternative minimum tax ("AMT") in 2005 of approximately 2% to 3% of our pre-tax income. Please read Note 2 to our Condensed Consolidated Financial Statements for more information regarding our income taxes. Liquidity and Capital Resources Our primary cash requirements are for the exploration, development and acquisition 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 acquisitions and working capital requirements. We believe this approach allows us to maintain an appropriate capital structure in order to execute our strategies to increase our oil and gas reserves and production. On March 31, 2005, we further strengthened our financial flexibility by amending our bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million, extend the maturity date to March 31, 2009, and permit an additional $125 million of indebtedness for money borrowed. In connection with the amended facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of the Company's oil and natural gas reserves and other factors, from $100 million to $185 million. As a result of the $100 million aggregate principal amount of senior notes offering discussed below, the borrowing base was automatically reduced by $20 million to $165 million and the amount of permitted additional indebtedness was reduced to $25 million. As of September 30, 2005, $19 million was outstanding under the bank credit facility and $146 million of unused borrowing capacity was available for future financing needs. On April 8, 2005, we completed a private placement of $100 million aggregate principal amount of 7-1/8% Senior Notes due 2012. The net proceeds from the private placement were approximately $98.2 million after deducting expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance the Company's acquisition discussed in the following paragraph. The remainder of the net proceeds from the offering was used to repay approximately $16.0 million of outstanding borrowings under our bank credit facility. On April 13, 2005, we completed an acquisition of oil and gas properties and related assets located primarily in our North Louisiana-East Texas core operating area for $86.9 million. The acquisition included internally estimated net proved reserves of approximately 47 Bcfe, of which approximately two-thirds were 23 undeveloped, associated with 137 producing wells and 81 proved undeveloped drilling locations and additional acreage with an estimated 185 drilling locations for which no proved reserves have been assigned. The acquisition was primarily financed with proceeds from the private placement of 7-1/8% senior notes due 2012 discussed in the preceding paragraph. The acquisition is consistent with our strategy of focusing on core areas and growth through drilling. We began drilling operations on these properties late in the second quarter and as of September 30, 2005, eleven successful wells had been drilled on these properties and approximately 150 additional drilling locations have been identified. Our net working capital position at September 30, 2005 was a deficit of $123.2 million as compared to a deficit of $28.7 million at December 31, 2004. Excluding the affect of derivative liabilities, our working capital deficit at September 30, 2005 was $20.3 million. On September 30, 2005, we had $146.0 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, 2005 working capital deficit was significantly higher than usual due mainly to the fair value of derivatives associated with our hedging program ($102.9 million liability) and the high level of accrued drilling costs ($25.1 million) as a result of our accelerated drilling program. 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 short-term liquidity 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, 2005, net cash provided by operating activities increased 66% to $157.8 million compared to $95.3 million for the nine months ended September 30, 2004. The increase during the 2005 nine-month period was primarily due to the increase in net production and higher natural gas and oil prices. Cash used in investing activities For the nine months ended September 30, 2005, net cash used in investing activities was $281.3 million compared to $109.3 million during the same period in 2004. Substantially all of the net cash used in investing activities for the nine months ended September 30, 2005 and 2004 was invested in oil and gas properties. Capital expenditures for the nine months ended September 30, 2005 were $285.7 million, including $150.7 million used for development activities, $38.9 million for lease acquisitions, seismic surveys and exploratory drilling, $94.2 million for oil and gas property acquisitions, $1.4 million in capitalized asset retirement obligation and $0.5 million for other assets. These amounts include costs that were incurred and accrued as of September 30, 2005 but are not reflected in the net cash used in investing activities above until payment is made. We anticipate investing a total of $260 million (excluding acquisitions) in our drilling program in 2005. Capital expenditures for the nine months ended September 30, 2004 were $115.1 million, including $94.4 million used for development activities, $18.5 million for lease acquisitions, seismic surveys and exploratory drilling, $1.6 million in oil and gas property acquisitions, $0.2 million in capitalized asset retirement obligation and $0.4 million for other assets. These amounts include costs that were incurred and accrued as of September 30, 2004 but are not reflected in the net cash used in investing activities above until 24 payment is made. Cash from financing activities For the nine months ended September 30, 2005, net cash provided by financing activities was $121.9 million, of which $100.6 million was proceeds from our senior notes offering, $19.0 million was from borrowings under our bank credit facility and $5.7 million was from proceeds from the exercise of stock options and warrants, partially offset by $3.4 million of financing costs. 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 in April 2004 as discussed in Note 7 to our Condensed Consolidated Financial Statements. Contractual Cash Obligations The following table summarizes our future contractual cash obligations related to long-term debt as of September 30, 2005. Payments due by period ---------------------- Less Than 1-3 3-5 More Than Total 1 Year Years Years 5 Years ------------------------------------------------------------------------------- Long-term debt $ 294,000 -- -- $ 19,000 $ 275,000 As of September 30, 2005, there have been no other material changes outside the ordinary course of our business to the items listed in the Contractual Cash Obligations table included in our annual report on Form 10-K for the year ended December 31, 2004. New Accounting Principles On December 16, 2004, the Financial Accounting Standards Board issued SFAS No. 123 (Revised 2004) "SFAS 123(R)," "Share-Based Payment," which is a revision of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS 123(R) supersedes APB Opinion No. 25, and amends SFAS Statement No. 95, "Statement of Cash Flows." Generally, the approach in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. We plan to adopt SFAS 123(R) on January 1, 2006. The impact of adoption of SFAS 123(R) on our results of operations cannot be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had we adopted Statement 123(R) in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the table in Note 4 to our Condensed Consolidated Financial Statements. 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." 25 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 swaps, futures contracts, options and collars to manage this price risk. We do not enter into derivative or other financial instruments for trading or speculative purposes. 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, 2005, we had outstanding derivative instruments covering 5.8 million MMBtu of 2005 natural gas production, 18.1 million MMbtu of 2006 natural gas production, 2.3 million MMbtu of 2007 natural gas production, 0.1 million barrels of 2005 oil production and 0.2 million barrels of 2006 oil production. The following table sets forth information with respect to our open derivative contracts as of September 30, 2005.
Expected Maturity Fair Value ---------------------------------------------------------------------------------- as of 2005 2006 2007 September 30, ---------- ---------------------------------------------------------- ---------- 2005 4th 1st 2nd 3rd 4th Full ------------ Quarter Quarter Quarter Quarter Quarter Total Year (1) (In thousands) ------- ------- ------- ------- ------- ----- -------- Swaps: Oil Volumes (bbl) 91,650 30,000 30,200 30,400 30,400 121,000 -- $ (3,850) Weighted average price ($/bbl) $ 44.22 $ 52.28 $ 51.62 $ 51.04 $ 50.47 $ 51.35 -- Natural Gas Volumes (MMbtu) 4,730,000 4,815,000 3,210,000 2,780,000 1,860,000 12,665,000 2,255,000 $ (93,376) Weighted average price ($/MMbtu) $ 7.81 $ 8.11 7.31 7.35 6.92 $ 7.57 $ 7.78 Collars: Oil Volumes (bbl) -- 22,500 22,750 23,000 23,000 91,250 -- $ (17) Weighted average price ($/bbl) Floor $ -- $ 55.00 $ 55.00 $ 55.00 $ 55.00 $ 55.00 -- Cap $ -- $ 81.00 $ 81.00 $ 81.00 $ 81.00 $ 81.00 -- Natural Gas Volumes (MMbtu) 460,000 1,800,000 1,365,000 1,380,000 -- 4,545,000 -- $ (10,935) Weighted average price ($/MMbtu) Floor $ 5.50 $ 8.44 $ 8.00 $ 8.00 -- $ 8.17 -- Cap $ 7.61 $ 12.89 $ 11.01 $ 10.90 -- $ 11.72 -- Sold calls: Natural Gas Volumes (MMbtu) 610,000 900,000 -- -- -- 900,000 -- $ (9,524) Weighted average price ($/MMbtu)$ 8.00 $ 8.00 -- -- -- $ 8.00 -- ---------- Fair value of derivatives at September 30, 2005. $ (117,702) ----------------------------------------------- ========== (1)First and second quarter only
In addition to the information set forth in the table above, we will deliver 0.8 Bcfe during the remainder of 2005 and 0.3 Bcfe in 2006 under a production payment and amortize deferred revenue with respect to such deliveries at a weighted average price of $4.05 per Mcfe. 26 Reflected in the table above are natural gas call options covering 1,510,000 MMbtu of natural gas production that were sold for proceeds of $1.2 million ($0.805 per MMbtu) during first quarter of 2005. These options do not qualify for hedge accounting treatment under SFAS No. 133 and therefore, all realized and unrealized gains and losses related to changes in fair value and realized gains and losses are being reported as a net gain or loss on mark-to-market derivatives on the Condensed Statements of Consolidated Income. Unrealized losses associated with these sold call options were $7.9 million for the three months ended September 30, 2005 and $8.3 million for the nine months ended September 30, 2005. Commodity Price Swaps. Commodity price swap agreements require us to make payments to, or entitle us to receive payments from, the counterparties 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 counterparty 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, 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 counterparty 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. Commodity Basis Swaps. Commodity basis swap agreements require the Company to make payments to, or receive payments from, the counterparties based upon the differential between certain pricing indices and a stated differential amount. 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 $275.0 million at 7-1/8% as of September 30, 2005 and $175 million at 7-1/8% as of December 31, 2004 and September 30, 2004. Our variable rate debt and weighted average interest rate was $19.0 million at 6.41% on September 30, 2005. We did not have any outstanding variable rate debt as of December 31, 2004 or September 30, 2004. The table below presents our debt obligations and related average interest rates expected by maturity date as of September 30, 2005 (dollars in millions).
As of September 30, 2005 ---------------------------------------------------------------------------------------------- Expected Maturity Date --------------------------------------------------------------------- Fair 2005 2006 2007 2008 2009 Thereafter Total Value ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Long-term debt Fixed rate -- -- -- -- -- $ 275.0 $ 275.0 $ 279.1 Average interest rate -- -- -- -- -- 7.125% 7.125% -- Variable rate -- -- -- -- $ 19.0 -- $ 19.0 $ 19.0 Average interest rate -- -- -- -- 6.41% -- 6.41% --
27 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. Item 5. Other Information. On October 12, 2005, the compensation committee of our board of directors approved modifications in the 2005 target award levels for our executive officers under our Annual Performance Incentive Award Plan to bring them to market levels. The increased 2005 target award levels and the other terms of our Annual Performance Incentive Award Plan are included in Exhibit 10.1 attached hereto and are incorporated herein by reference. 28 PART II - OTHER INFORMATION Item 6. Exhibits. +10.1 KCS Energy, Inc. Annual Performance Incentive Award Plan. +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. -------------------- + Filed herewith. 29 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. KCS ENERGY, INC. Date: November 9, 2005 /s/ Frederick Dwyer ---------------------------------------- Frederick Dwyer Vice President, Controller and Secretary (Signing on behalf of the registrant and as Principal Accounting Officer) 30 EXHIBIT INDEX Exhibit No. Description ------ ----------- +10.1 KCS Energy, Inc. Annual Performance Incentive Award Plan. +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. -------------------- + Filed herewith. 31