10-Q 1 form10q-53756_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 June 30, 2003 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, Houston, TX 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). |_| 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. Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock, $0.01 par value: 38,286,414 shares outstanding as of August 12, 2003. Item 1. Financial Statements. KCS ENERGY, INC. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
Three Months Ended Six Months Ended June 30, June 30, (Amounts in thousands except ----------------------- ----------------------- per share data) Unaudited 2003 2002 2003 2002 ----------------------------------------------------------------- -------- -------- -------- -------- Oil and gas revenue $ 38,422 $ 30,808 $ 78,069 $ 60,165 Other revenue, net 4,310 (531) 5,103 (1,064) --------------------------------------------------------------------------------------------------------------------------- Total revenue 42,732 30,277 83,172 59,101 --------------------------------------------------------------------------------------------------------------------------- Operating costs and expenses Lease operating expenses 6,693 6,873 13,024 13,409 Production taxes 1,468 1,632 3,761 2,955 General and administrative expenses 1,862 1,763 3,662 3,890 Stock compensation 257 194 411 510 Accretion of asset retirement obligation 279 -- 558 -- Depreciation, depletion and amortization 11,441 12,031 22,083 25,131 --------------------------------------------------------------------------------------------------------------------------- Total operating costs and expenses 22,000 22,493 43,499 45,895 --------------------------------------------------------------------------------------------------------------------------- Operating income 20,732 7,784 39,673 13,206 --------------------------------------------------------------------------------------------------------------------------- Interest and other income, net 75 9 102 79 Interest expense (4,588) (4,836) (9,202) (9,666) --------------------------------------------------------------------------------------------------------------------------- Income before income taxes and cumulative effect of accounting change 16,219 2,957 30,573 3,619 Federal and state income (taxes) benefit 11,082 (15,325) 11,564 (14,729) --------------------------------------------------------------------------------------------------------------------------- Net income (loss) before cumulative effect of accounting change 27,301 (12,368) 42,137 (11,110) Cumulative effect of accounting change, net of tax -- -- (934) (6,166) --------------------------------------------------------------------------------------------------------------------------- Net income (loss) 27,301 (12,368) 41,203 (17,276) Dividends and accretion of issuance costs on preferred stock (132) (372) (442) (625) --------------------------------------------------------------------------------------------------------------------------- Income (loss) available to common stockholders $ 27,169 $(12,740) $ 40,761 $(17,901) =========================================================================================================================== Earnings (loss) per share of common stock - basic Before cumulative effect of accounting change $ 0.71 $ (0.36) $ 1.10 $ (0.34) Cumulative effect of accounting change $ -- $ -- $ (0.02) $ (0.17) --------------------------------------------------------------------------------------------------------------------------- Earnings (loss) per share of common stock - basic $ 0.71 $ (0.36) $ 1.08 $ (0.51) =========================================================================================================================== Earnings (loss) per share of common stock - diluted Before cumulative effect of accounting change $ 0.66 $ (0.36) $ 1.02 $ (0.34) Cumulative effect of accounting change $ -- $ -- $ (0.02) $ (0.17) --------------------------------------------------------------------------------------------------------------------------- Earnings (loss) per share of common stock - diluted $ 0.66 $ (0.36) $ 1.00 $ (0.51) =========================================================================================================================== Average shares outstanding for computation of earnings per share Basic 38,227 35,674 37,833 35,332 Diluted 41,531 35,674 41,295 35,332 ===========================================================================================================================
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, June 30, December 31, except share and per share data) Unaudited 2003 2002 ----------------------------------------------------------------------- --------- ------------ Assets Current assets Cash and cash equivalents $ 2,301 $ 6,935 Trade accounts receivable, less allowance for doubtful accounts-2003 $4,692; 2002 $4,678 24,169 16,863 Prepaid drilling 5,615 1,362 Other current assets 1,400 2,034 ------------------------------------------------------------------------------------------------------------ Current assets 33,485 27,194 ------------------------------------------------------------------------------------------------------------ Oil and gas properties, full cost method, less accumulated DD&A-2003 $908,368; 2002 $891,124 259,318 231,579 Other property, plant and equipment at cost less accumulated depreciation; 2003 $10,999; 2002 $10,415 8,423 8,715 ------------------------------------------------------------------------------------------------------------ Property, plant and equipment, net 267,741 240,294 ------------------------------------------------------------------------------------------------------------ Deferred charges and other assets Deferred taxes 11,160 -- Other 3,391 645 ------------------------------------------------------------------------------------------------------------ Deferred charges and other assets 14,551 645 ------------------------------------------------------------------------------------------------------------ Total Assets $ 315,777 $ 268,133 ============================================================================================================ Liabilities and stockholders' equity (deficit) Current liabilities Accounts payable $ 35,479 $ 23,854 Accrued interest 6,288 8,174 Accrued drilling cost 8,913 2,861 Other accrued liabilities 8,649 8,784 ------------------------------------------------------------------------------------------------------------ Current liabilities 59,329 43,673 ------------------------------------------------------------------------------------------------------------ Deferred credits and other liabilities Deferred revenue 51,385 66,582 Asset retirement obligation 11,608 -- Other 929 961 ------------------------------------------------------------------------------------------------------------ Deferred credits and other liabilities 63,922 67,543 ------------------------------------------------------------------------------------------------------------ Long-term debt Credit facility 54,000 500 Senior notes -- 61,274 Senior subordinated notes 125,000 125,000 ------------------------------------------------------------------------------------------------------------ Long-term debt 179,000 186,774 ------------------------------------------------------------------------------------------------------------ Commmitments and contingencies Preferred stock, authorized 5,000,000 shares, issued 30,000 shares redeemable convertible preferred stock, par value $0.01 per share, liquidation preference $1,000 per share - 9,388 and 13,288 shares outstanding, respectively 9,116 12,859 ------------------------------------------------------------------------------------------------------------ Stockholders' equity (deficit) Common stock, par value $0.01 per share, authorized 75,000,000 shares, issued 40,419,367 and 38,611,816, respectively 404 386 Additional paid-in capital 172,550 167,335 Accumulated deficit (155,554) (196,315) Unearned compensation (1,243) (880) Accumulated other comprehensive income (7,006) (8,501) Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741) ------------------------------------------------------------------------------------------------------------ Total stockholders' equity (deficit) 4,410 (42,716) ------------------------------------------------------------------------------------------------------------ Total liabilities and stockholders' equity (deficit) $ 315,777 $ 268,133 ============================================================================================================
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
Six Months Ended June 30, ----------------------- (Dollars in thousands) Unaudited 2003 2002 --------------------------------------------------------- -------- -------- Cash flows from operating activities: Net income (loss) $ 41,203 $(17,276) Non-cash charges (credits): Depreciation, depletion and amortization 22,083 25,131 Amortization of deferred revenue (15,197) (24,343) Non-cash derivative losses, net 2,756 2,138 Deferred income taxes (benefit) (11,965) 14,729 Cumulative effect of accounting change 934 6,166 Accretion of asset retirement obligation 558 -- Other non-cash charges and credits, net 917 510 Net changes in assets and liabilities: Change in trade accounts receivable (7,328) (3,067) Change in accounts payable and accrued liabilities 11,793 (4,484) Change in accrued interest payable (1,886) (841) Other, net (261) 1,262 ----------------------------------------------------------------------------------------- Net cash provided by (used in) operating activities 43,607 (75) ----------------------------------------------------------------------------------------- Cash flows from investing activities: Investment in oil and gas properties (36,845) (26,201) Proceeds from sales of oil and gas properties (130) 24,674 Other capital expenditures (292) (34) ----------------------------------------------------------------------------------------- Net cash used in investing activities (37,267) (1,561) ----------------------------------------------------------------------------------------- Cash flows from financing activities: Proceeds from borrowings 69,295 10,800 Repayments of debt (77,069) (18,526) Deferred financing costs and other, net (3,200) -- ----------------------------------------------------------------------------------------- Net cash used in financing activities (10,974) (7,726) ----------------------------------------------------------------------------------------- Decrease in cash and cash equivalents (4,634) (9,362) Cash and cash equivalents at beginning of period 6,935 22,927 ----------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 2,301 $ 13,565 =========================================================================================
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 (Amounts in thousands)
Accumulated Additional Other Common Paid-in Accumulated Comprehensive Unaudited Stock Capital Deficit Income --------------------------------------------------- ---------- ----------- ------------- Balance at December 31, 2002 $ 386 $167,335 $(196,315) $(8,501) Comprehensive income Net income -- -- 41,203 -- Commodity hedges, net of tax -- -- -- 1,495 Comprehensive income Conversion of redeemable preferred stock 13 3,887 -- -- Stock issuances - benefit plans and awards of restricted stock 4 1,127 -- -- Stock compensation expense -- 36 -- -- Dividends and accretion of issuance costs on preferred stock 1 165 (442) -- ------- -------- --------- ------- Balance at June 30, 2003 $ 404 $172,550 $(155,554) $(7,006) ======= ======== ========= ======= Total Stockholders' Unearned Treasury Comprehensive (Deficit) Unaudited Compensation Stock Income Equity ------------------------------------------- ------------ -------- ------------- ------------- Balance at December 31, 2002 $ (880) $(4,741) $(42,716) Comprehensive income Net income -- -- $ 41,203 41,203 Commodity hedges, net of tax -- -- 1,495 1,495 -------- Comprehensive income $ 42,698 ======== Conversion of redeemable preferred stock -- -- 3,900 Stock issuances - benefit plans and awards of restricted stock (738) -- 393 Stock compensation expense 375 -- 411 Dividends and accretion of issuance costs on preferred stock -- -- (276) ------- ------- --------- Balance at June 30, 2003 $(1,243) $(4,741) $ 4,410 ======= ======= =========
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. The condensed consolidated interim financial statements included herein have been prepared by KCS Energy, Inc. ("KCS" or "Company"), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and reflect all adjustments which are of a normal recurring nature and which are in the opinion of management, necessary to a fair statement of the results for the interim periods presented. Certain information and footnote disclosures have been condensed or omitted pursuant to such rules and regulations. Although KCS believes that the disclosures are adequate to make the information presented 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 KCS Annual Report on Form 10-K for the year ended December 31, 2002. Certain previously reported amounts have been reclassified to conform with current period presentations. 2. New Accounting Principles Effective January 1, 2003, the Company adopted Financial Accounting Standards Board Statement No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143 requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the periods in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of settlement over the useful life of the asset, and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption of SFAS No. 143, the Company's net property, plant and equipment was increased by $10.2 million, an additional asset retirement obligation of $11.1 million (primarily for plugging and abandonment costs of oil and gas wells) was recorded and a $0.9 million charge, net of tax against net income (or a $0.02 loss per basic and diluted share) was reported in the first quarter of 2003 as a cumulative effect of a change in accounting principle. Subsequent to adoption, the effect of the change in accounting principle in the first six months of 2003 was a immaterial. Had the provisions of SFAS No. 143 been applied as of January 1, 2002, the asset retirement obligation would have been $10.1 million. The following table illustrates the pro forma effect on net loss available to common stockholders and loss per share if the Company had applied the provisions of SFAS No. 143 during the first half of 2002:
For the For the Quarter Ended Six Months Ended (Amounts in thousands, except per share data) June 30, 2002 June 30, 2002 --------------------------------------------- ------------- ---------------- Loss available to common stockholders As reported $ (12,740) $ (17,901) Pro forma (12,865) (18,159) Loss per share Basic - as reported $ (0.36) $ (0.51) Basic - pro forma $ (0.36) $ (0.51) Diluted - as reported $ (0.36) $ (0.51) Diluted - pro forma $ (0.36) $ (0.51)
Effective January 1, 2002, the Company began amortizing the capitalized costs related to oil and gas properties on the unit-of-production basis ("UOP") using proved oil and gas reserves. Previously, the 5 Company had computed amortization on the basis of future gross revenues ("FGR"). The Company determined that the change to UOP was preferable under accounting principles generally accepted in the United States, since among other reasons, it provides a more rational basis for amortization during periods of volatile commodity prices and also increases consistency with others in the industry. As a result of this change, the Company recorded a non-cash cumulative effect charge of $6.2 million, net of tax, (or $0.17 per basic and diluted common share) in the first quarter of 2002. In January 2003, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51." Interpretation No. 46 requires a company to consolidate a variable interest entity ("VIE") if the company has a variable interest (or combination of variable interests) that is exposed to a majority of the entity's expected losses if they occur, receives a majority of the entity's expected residual returns if they occur, or both. In addition, more extensive disclosure requirements apply to the primary and other significant variable interest owners of the VIE. This interpretation applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It is also effective for the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which a company holds a variable interest that is acquired before February 1, 2003. The guidance regarding this interpretation is extremely complex and, although we do not believe we have an interest in a VIE, the Company continues to assess the impact, if any, this interpretation will have on the Company's consolidated financial statements. In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards on how the Company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that the Company classify as liabilities the fair value of all mandatorily redeemable financial instruments that had previously been recorded as equity or elsewhere in the consolidated financial statements. This statement is effective for financial instruments entered into or modified after May 31, 2003, and is otherwise effective for all existing financial instruments beginning in the third quarter of 2003. SFAS No. 150 will not have an impact on the Company's classification of its convertible preferred stock because the convertible preferred stock is not mandatorily redeemable as defined by SFAS No. 150. SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Intangible Assets", were issued in June 2001 and became effective July 1, 2001 and January 1, 2002, respectively. It is the Company's understanding that the SEC has questioned other public companies as to whether they properly adopted the provisions of SFAS No. 141 and SFAS No. 142, with respect to how the costs of acquiring contractual mineral interests in oil and gas properties should be classified on the balance sheet. It is also the Company's understanding that the FASB, the SEC and others are engaged in deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that interests held under oil, gas and mineral leases or other contractual arrangements be classified as intangible assets or as oil and gas properties. If such interests were deemed intangible assets, mineral interests for undeveloped and developed leaseholds would be classified separately from oil and gas properties on the balance sheet but would be aggregated with oil and gas properties in the Notes to Consolidated Financial Statements in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities. Historically, the Company has included all oil and gas leasehold interests as part of oil and gas properties. Because this issue is being deliberated and is unresolved, the Company continues to include mineral interests as oil and gas properties on its balance sheet. 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 independent reservoir engineers' reserve report. 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 6 generate in the future. Accordingly, while the Company's current net operating loss carryforwards have remaining lives ranging from 9 1/2 to 19 1/2 years (with the majority having a life in excess of 15 years), management looks at 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. During the second quarter of 2002, uncertainty resulting from relatively low commodity prices and the January 2003 maturity date for the Company's Senior Notes led management to establish a valuation allowance against all of the Company's deferred tax assets. Since that time, the future outlook for taxable income has improved significantly. The Company successfully negotiated an amended and restated credit agreement, allowing it to repay the Senior Notes. Furthermore, oil and natural gas prices have improved significantly and are expected to remain relatively high for the foreseeable future based on existing available information, including current prices quoted on the New York Mercantile Exchange. Therefore, during the second quarter of 2003, the Company reversed approximately $11 million the valuation allowance related to expected taxes on future year's taxable income, which is reflected as an income tax benefit in the condensed statement of consolidated operations. 4. Deferred Revenue In 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) (the "Production Payment"). Net proceeds from the Production Payment of approximately $175 million were recorded as deferred revenue on the Company's balance sheet. In accordance with Financial Accounting Standards Board Statement No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies," 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 six months ended June 30, 2003, the Company delivered 3.7 Bcfe and recorded $15.2 million of oil and gas revenue. Since the sale of the Production Payment in February 2001 through June 30, 2003, the Company has delivered 30.6 Bcfe, or 71% of the total quantity to be delivered. 5. Redeemable Convertible Preferred Stock As a result of conversions of the redeemable convertible preferred stock issued in 2001, 1.3 million shares of common stock were issued in the six months ended June 30, 2003. 7 6. Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share:
Three months ended Six months ended June 30, June 30, (Amounts in thousands, ---------------------- ---------------------- except per share data) 2003 2002 2003 2002 ----------------------------------------------------------------------------------- ---------------------- Basic earnings (loss) per share: Income (loss) available to common stockholders $ 27,169 $(12,740) $ 40,761 $(17,901) ---------------------- ---------------------- Average shares of common stock outstanding 38,227 35,674 37,833 35,332 ---------------------- ---------------------- Basic earnings (loss) per share $ 0.71 $ (0.36) $ 1.08 $ (0.51) ====================== ====================== Diluted earnings (loss) per share: Income (loss) available to common stockholders $ 27,169 $(12,740) $ 40,761 $(17,901) Dividends and accretion of issuance costs on preferred stock 132 N/A 442 N/A ---------------------- ---------------------- Diluted earnings (loss) $ 27,301 $(12,740) $ 41,203 $(17,901) ---------------------- ---------------------- Average shares of common stock outstanding 38,227 35,674 37,833 35,332 Assumed conversion of convertible preferred stock 3,129 N/A 3,346 N/A Stock options and warrants 175 N/A 116 N/A ---------------------- ---------------------- Average diluted shares of common stock outstanding 41,531 35,674 41,295 35,332 ---------------------- ---------------------- Diluted earnings (loss) per share $ 0.66 $ (0.36) $ 1.00 $ (0.51) ====================== ======================
Common shares on assumed conversion of convertible preferred stock amounting to 5.0 million shares for the three months ended June 30, 2002 and 5.1 million shares for the six months ended June 30, 2002 were not included in the computations of diluted loss per common share nor were assumed conversion of dividends on convertible preferred stock or stock options and warrants since they would be anti-dilutive. 7. Derivatives Oil and gas prices have historically been volatile. The Company has at times utilized derivative contracts, including swaps, futures contracts, options and collars to manage this price risk. Commodity Price Swaps. Commodity price swap agreements require the Company to make or 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 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 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 8 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. In 2003, the Company entered into a series of derivative transactions designed to protect a portion of the Company's oil and gas production against possible declines in natural gas prices while enabling the Company to benefit from price increases. At June 30, 2003, the Company had derivative instruments covering 4.1 million Mmbtu of gas production for July 2003 through March 2004. These instruments established an average floor price of $4.44 and enable the Company to receive market prices up to an average cap of $7.04, approximately 20% of any price between $7.04 and $7.54 and 100% of any price above $7.54. The following table sets forth the Company's oil and natural gas hedged position at June 30, 2003.
Expected Maturity ------------------------------------------------------------- 2003 2004 Fair ---------------------------------------------- ---------- Value 3nd Quarter 4th Quarter Total 1st Quarter ($000) ----------- ----------- ----- ----------- ------ Swaps: $ (6) Volumes (bbl) 7,700 -- 7,700 -- Weighted average price ($/bbl) $ 30.00 $ -- $ 30.00 $ -- Puts / Floors: $ 36 Volumes (Mmbtu) 460,000 305,000 765,000 -- Weighted average price ($/Mmbtu) $ 4.25 $ 4.25 $ 4.25 $ -- 3-way collars: $ 252 Volumes (MMbtu) 1,075,000 1,380,000 2,595,000 910,000 Weighted average price ($/Mmbtu) Floor (purchased put option) $ 4.47 $ 4.47 $ 4.47 $ 4.50 Cap 1 (sold call option) $ 5.76 $ 7.08 $ 6.50 $ 8.50 Cap 2 (purchased call option) $ 6.26 $ 7.58 $ 7.00 $ 9.00
In addition to the above, the Company has entered into fixed price sales contracts covering 0.2 million Mmbtu at an average price of $5.30 for July through August 2003 and will deliver 3.1 Bcfe for July through December 2003, 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006 under the Production Payment sold in February 2001 at an average price of $4.05 per Mcfe. The fixed price sales contracts are normal sales pursuant to SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". Accordingly, the Company has designated and accounted for these contracts under the accrual method. During 2001, the Company terminated certain derivative contracts that were in place at the companies acquired in the 1996 acquisition known as the "Medallion Acquisition" and has been amortizing the loss accumulated in other comprehensive income ("OCI") into earnings over the original term of the derivative instruments. During the first six months of 2003, $1.8 million, net of tax, charged to OCI was reclassified as a reduction of oil and gas revenues. As of June 30, 2003, $6.7 million, net of tax, remains in accumulated other comprehensive income and will be amortized against earnings through 2005 ($1.8 million during the remainder of 2003, $2.9 million in 2004 and $2.0 million in 2005). During the first six months of 2003, $0.3 million, net of tax, of unrealized derivative losses were charged to OCI which will be reclassified against earnings within the current fiscal year. The ineffective portion of these derivatives was immaterial in the first half of 2003. 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 paid (net of capitalized interest) for the six months ended June 30, 2003 was $10.5 million. An income tax payment of $0.4 million was made in the six-month period ended June 30, 2003 while no income tax was paid in the six-month period ended June 30, 2002. 9 In connection with the adoption of SFAS No. 143, 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. During the six months ended June 30, 2003 non-cash additions to oil and gas properties as a result of recognizing asset retirement obligations for new wells under SFAS No. 143 was $0.3 million. Other non-cash additions to oil and gas properties netted to $1.8 million with increases in accrued drilling costs offset by increased prepaid drilling costs. 9. Credit Agreement On January 14, 2003, the Company amended and restated its credit agreement (the "Credit Agreement") with a group of institutional lenders. The Credit Agreement, which matures on October 3, 2005, provides up to $90.0 million of borrowing capacity, $40.0 million in the form of a term loan, a $30.0 million revolving "A" facility and a $20.0 million revolving "B" facility. Borrowing capacity is subject to monthly borrowing base calculations with respect to the value of the Company's oil and gas assets. Initial proceeds of $69.3 million were used primarily to pay off the Company's maturing Senior Note obligations. The term loan and the revolving "B" facility, which may be prepaid at any time without penalty, bear interest based on the prime rate, initially equating to 9.0%, and increasing annually. The revolving "A" facility bears, at the Company's option, an interest rate of LIBOR plus 2.75% to 3.0% or prime plus 0.5% to 0.75%, depending on utilization. On June 30, 2003, $54.0 million was outstanding under the Credit Agreement, the weighed average interest rate was 7.8% and $34.0 million was available for additional Company borrowings. The revolving "A" facility requires a commitment fee of 0.5% per annum on the unused availability and carries an early termination penalty of 1.5% in the first year and 1% in the second year. Financing fees associated with the Credit Agreement have been recorded as deferred charges and are being amortized as interest expense over the life of the Credit Agreement. Certain other fees are also payable under the Credit Agreement based on services provided. Substantially all of the Company's assets are pledged to secure the Credit Agreement. The Credit Agreement contains various restrictive covenants including ratios of debt to EBITDA, interest coverage, fixed charge coverage and liquidity. The Credit Agreement also contains provisions that require the hedging of a portion of the Company's oil and gas production, payment upon a change of control, restrictions on the payment of dividends and certain other restricted payments and places limitations on the incurrence of additional debt, capital expenditures, the sale of assets, and the repurchase of Senior Subordinated Notes. Any repayment made on the term loan portion of the facility will permanently reduce the funds available under the Credit Agreement. The Credit Agreement also contains cross-default provisions, which would result in the acceleration of payments if the Company defaults on its other debt instruments. 10. Stock Compensation As permitted under 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 records no 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 (loss) available to common stockholders and earnings (loss) per share if the Company had applied the fair value recognition provision of SFAS No. 123 to stock options. 10
For the Three Months Ended For the Six Months Ended June 30, June 30, (Amounts in thousands, except --------------------------- --------------------------- per share data) 2003 2002 2003 2002 -------------------------------------- ---------- ---------- ---------- ---------- Income (loss) available to common stockholders, as reported $ 27,169 $ (12,740) $ 40,761 $ (17,901) Add: Stock-based compensation expense included in reported net income 257 194 411 510 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards (532) (512) (943) (904) ---------- ---------- ---------- ---------- Pro forma income (loss) available to common stockholders $ 26,894 $ (13,058) $ 40,229 $ (18,295) ========== ========== ========== ========== Earnings (loss) per share: Basic - as reported $ 0.71 $ (0.36) $ 1.08 $ (0.51) Basic - pro forma $ 0.70 $ (0.37) $ 1.06 $ (0.52) Diluted - as reported $ 0.66 $ (0.36) $ 1.00 $ (0.51) Diluted - pro forma $ 0.65 $ (0.37) $ 0.98 $ (0.52)
11. Litigation Environmental Suits The Company was a defendant in a lawsuit originally brought by InterCoast Energy Company and MidAmerican Capital Company ("Plaintiffs") against KCS Energy, Inc., KCS Medallion Resources, Inc. and Medallion California Properties Company ("KCS Defendants"), and Kerr-McGee Oil & Gas Onshore LP and Kerr-McGee Corporation ("Kerr-McGee Defendants") in the 234th Judicial District Court of Harris County, Texas under Cause Number 1999-45998. The suit sought a declaratory judgment declaring the rights and obligations of each of the Plaintiffs, the KCS Defendants and the Kerr-McGee Defendants in connection with environmental damages and surface restoration on lands located in Los Angeles County, California which are covered by an Oil & Gas Lease dated June 13, 1935, from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as Lessee (the "RSF Lease") and by an Oil and Gas Lease dated June 6, 1941, from the Newhall Corporation, as Lessor, to C. G. Willis, as Lessee (the "Ferguson Lease" and together with the RSF Lease, the "Leases"). The Kerr-McGee Defendants, KCS Defendants and Plaintiffs entered into an Agreed Interlocutory Judgment that contains clarification of the language of the 1990 agreement between predecessors of the KCS Defendants and the Kerr-McGee Defendants (the "1990 Agreement") under which the Leases were transferred from Kerr-McGee's predecessor to predecessors of Medallion California Properties Company ("MCPC"). The Court previously entered the Agreed Interlocutory Judgment, which essentially disposed of interpretation questions concerning the 1990 Agreement. After entry of the Agreed Interlocutory Judgment, the remaining issues in the case concerned the interpretation of the 1996 Stock Purchase Agreement through which certain of the KCS Defendants acquired the stock of MCPC. Specifically, the remaining issues involved the extent to which Plaintiffs are obligated to indemnify the KCS Defendants for environmental investigation costs previously incurred by the KCS Defendants and also for costs of defense and liability to the KCS Defendants, if any, in the California litigation described below. By Compromise and Settlement Agreement dated as of October 19, 2001, the Plaintiffs and KCS Defendants agreed: (i) to settle those issues dealing with the Plaintiffs' obligations to reimburse costs previously incurred in connection with defense of the California case described below; (ii) to provide prospectively for the control of defense and settlement and the sharing of 11 defense costs in the California case described below; and (iii) to defer any disputes concerning the respective liability of Plaintiffs and KCS Defendants for any individual claims until the extent of such individual claim liability, after giving effect to indemnification obligations under the 1990 Agreement, is fully and finally determined. The Agreed Interlocutory Judgment has now been entered as a final judgment. MCPC is a defendant in a lawsuit filed January 30, 2001, by The Newhall Land and Farming Company ("Newhall") against MCPC and Kerr-McGee Corporation and several Kerr-McGee affiliates. The case is currently pending in Los Angeles County Superior Court under Cause Number BC244203. In the suit, Newhall seeks damages for alleged environmental contamination and surface restoration on the lands covered by the RSF Lease and also seeks a declaration that Newhall may terminate the RSF Lease or alternatively, that it may terminate those portions of the RSF Lease on which there is currently default under the Lease. MCPC claims that Newhall is not entitled to lease termination as a remedy and that Kerr-McGee and InterCoast and MidAmerican owe indemnities to MCPC for defense and certain potential liability under Newhall's action, all as more particularly described in the Harris County, Texas litigation described above. The lawsuit was set for trial in May, 2003. On the eve of trial, the parties agreed to engage in settlement negotiations under the Court's supervision. Tentative settlement terms were agreed to at the end of May, but definitive settlement documents have not been agreed to and negotiations are continuing. The Company is unable to predict the outcome of the settlement negotiations. Other The Company and several of its subsidiaries have been named as co-defendants along with numerous other industry parties in an action brought by Jack Grynberg on behalf of the Government of the United States. The complaint, filed under the Federal False Claims Act, alleges underpayment of royalties to the Government of the United States as a result of alleged mismeasurement of the volume and wrongful analysis of the heating content of natural gas produced from federal and Native American lands. The complaint is substantially similar to other complaints filed by Jack Grynberg on behalf of the Government of the United States against multiple other industry parties. All of the complaints have been consolidated in one proceeding. In April 1999, the Government of the United States filed notice that it had decided not to intervene in these actions. The Company believes that the allegations in the complaint are without merit. The Company is also a party to various other lawsuits and governmental proceedings, all arising in the ordinary course of business. Although the outcome of all of the above proceedings cannot be predicted with certainty, management does not expect such matters to have a material adverse effect, either singly or in the aggregate, on the financial position or results of operations of the Company. It is possible, however, that charges could be required that would be significant to the operating results during a particular period. 12. Comprehensive Income The following table presents the components of comprehensive income (loss) for the three months and six months ended June 30, 2003 and 2002.
Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- (Amounts in thousands) 2003 2002 2003 2002 ---------------------- ---- ---- ---- ---- Net income (loss) $ 27,301 $(12,368) $ 41,203 $(17,276) Commodity hedges, net of tax 700 1,776 1,495 1,673 -------- -------- -------- -------- Comprehensive income (loss) $ 28,001 $(10,592) $ 42,698 $(15,603) ======== ======== ======== ========
12 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 the unaudited condensed consolidated financial statements (including the notes thereto) included elsewhere in this Form 10-Q. 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 fact, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled after the date hereof, the Company's 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 the Company believes that the expectations reflected in such forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, and the Company can give no assurance that such expectations will prove to be correct. The Company's 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 the Company's drilling activities; - the volatility of prices and supply of and demand for oil and gas; - the numerous uncertainties inherent in estimating quantities of oil and gas reserves and actual future production rates and associated costs; - the usual hazards associated with the oil and gas industry (including blowouts, cratering, pipe failure, spills, explosions and other unforeseen hazards); - changes in regulatory requirements; or - if underlying assumptions prove incorrect. These and other risks are described in greater detail in "Oil and Gas Risk Factors" included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. All forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. Other than required under the securities laws, the Company does not assume a duty to update these forward-looking statements. General Our main objective in 2002 was to position the Company to meet the Senior Note obligations due January 15, 2003. In order to meet this objective, we curtailed our drilling and overall capital expenditure programs and sold certain non-core assets. These actions positioned us to reduce debt and negotiate the financing necessary to pay off the remaining portion of the maturing Senior Notes during a difficult period in the capital markets. Although the asset sales and curtailed drilling and capital expenditure programs resulted in lower production and reserves in 2002, we exited the year in a stronger financial position, with increased financial flexibility, a focused asset base in our core areas, and a quality multi-year drilling prospect inventory. On January 14, 2003, we completed the arrangements necessary to amend and restate our existing credit agreement with a group of institutional lenders. The amended facility provides $90.0 million of borrowing capacity, $40.0 million in the form of a term loan and $50.0 million in the form of revolving 13 facilities, and matures on October 3, 2005. Initial proceeds of $69.3 million were used primarily to pay off the balance of the maturing Senior Note obligations, leaving $20.7 million of available borrowing capacity under the facility. With the completion of the financing, we accelerated our drilling program in the first half of 2003 resulting in increased production and reserves. We believe that the Company is positioned to capitalize on the current strong natural gas price environment, to focus on developing our prospect inventory to grow reserves and production in our core areas and to further reduce debt per MCFE. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include political conditions in the Middle East and elsewhere, domestic and foreign supply of oil and natural gas, the level of industrial and consumer demand, weather conditions and overall economic conditions. Demand for natural gas and oil is seasonal, principally related to weather conditions and access to pipeline transportation. Results of Operations Income before income taxes for the three months ended June 30, 2003 was $16.2 million compared to $3.0 million for the three months ended June 30, 2002. This increase was primarily attributable to higher natural gas and oil prices and the $4.7 million sale of emission reduction credits, partially offset by decreased oil and gas production due largely to the sale of certain non-core properties in 2002. Income tax benefit for the three months ended June 30, 2003 was $11.1 million compared to income tax expense of $15.3 million for the same period a year ago due to changes in our valuation allowance against net deferred tax assets (see Note 3 to Condensed Consolidated Financial Statements). Income available to common stockholders for the three months ended June 30, 2003 was $27.2 million, or $0.71 per share ($0.66 per diluted share), compared to a loss of $12.7 million, or $0.36 per basic and diluted share for the three months ended June 30, 2002. Income before income taxes and cumulative effect of accounting change for the six months ended June 30, 2003 was $30.6 million, compared to $3.6 million for the six months ended June 30, 2002. This increase was primarily attributable to higher natural gas and oil prices and the sale of emission reduction credits, partially offset by decreased oil and gas production due largely to the sale of certain non-core properties in 2002. Income tax benefit for the six months ended June 30, 2003 was $11.6 million compared to income tax expense of $14.7 million for the same period in 2002 due to changes in our valuation allowance against net deferred tax assets (see Note 3 to Condensed Consolidated Financial Statements). The cumulative effect of an accounting change was $0.9 million, or $0.02 per basic and diluted share for the six months ended June 30, 2003 as a result of the adoption of Financial Accounting Standards Board Statement No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). For the six months ended June 30, 2002, the cumulative effect of accounting change was $6.2 million, or $0.17 per basic and diluted share which reflected the change from the future gross revenue method of accounting for the amortization of capitalized costs related to oil and gas properties to the unit-of-production method. See Note 2 to Condensed Consolidated Financial Statements for more information regarding these accounting changes. Income available to common stockholders for the six months ended June 30, 2003 was $40.8 million, or $1.08 per share ($1.00 per diluted share), compared to a loss of $17.9 million, or $0.51 per basic and diluted share, for the six months ended June 30, 2002. The following table provides our volume and average prices for the three and six month periods ended June 30, 2003 and 2002. 14 Three Months Ended Six Months Ended June 30, June 30, -------------------- -------------------- 2003 2002 2003 2002 ------- ------- ------- ------- Production: (a) Gas (MMcf) 6,758 7,576 12,733 15,888 Oil (Mbbl) 213 260 428 528 Liquids (Mbbl) 58 71 105 142 Summary (MMcfe): Working interest 8,381 8,912 15,933 18,382 VPP -- 646 -- 1,525 ------- ------- ------- ------- Total 8,381 9,558 15,933 19,907 ======= ======= ======= ======= Average Price: (b) Gas (per Mcf) $ 4.81 $ 3.27 $ 5.14 $ 3.07 Oil (per bbl) 23.97 20.45 25.73 19.05 Liquids (per bbl) 14.15 10.10 15.56 9.56 Total (per Mcfe) 4.58 3.22 4.90 3.02 Oil and Gas Revenue: Gas $32,504 $24,784 $65,415 $48,749 Oil 5,103 5,309 11,014 10,062 Liquids 815 715 1,640 1,354 ------- ------- ------- ------- Total $38,422 $30,808 $78,069 $60,165 ======= ======= ======= ======= Notes: (a) Production includes 1,702 and 3,720 Mmcfe, respectively, for the three and six months ended June 30, 2003 compared to 2,809 and 6,043 Mmcfe, respectively, for the three and six months ended June 30, 2002, dedicated to the Production Payment sold in February 2001. See Note 4 to Condensed Consolidated Financial Statements. (b) Includes the effects of the Production Payment sold in February 2001 and hedging activities. See notes 4 and 7 to Condensed Consolidated Financial Statements. Gas revenue For the three months ended June 30, 2003, gas revenue increased $7.7 million, to $32.5 million, from $24.8 million for the same period in 2002 due to a 47% increase in average realized natural gas prices offset by an 11% decrease in production. For the six months ended June 30, 2003, gas revenue increased $16.7 million, to $65.4 million, from $48.7 million for the same period in 2002 due to a 67% increase in average realized gas prices offset by a 20% decrease in production. The production decline in both periods was due to the sale of oil and gas properties in 2002 and the expiration of certain VPPs. Gas production in the second quarter of 2003 increased 13% to 6.8 bcf compared to 6.0 bcf in the first quarter of 2003 reflecting our successful drilling program. 15 Oil and liquids revenue For the three months ended June 30, 2003, oil and liquids revenue decreased $0.1 million, to $5.9 million, from $6.0 million for the same period in 2002, due to a 20% increase in the weighted average price offset by lower production. For the six months ended June 30, 2003, oil and liquids revenue increased $1.3 million, to $12.7 million, from $11.4 million for the same period in 2002 due to a 39% increase in the weighted average price offset by a 20% decrease in production. The decrease in production in 2003 was primarily due to the sale of oil and gas properties in 2002 and the natural declines of producing properties. Other revenue, net Other revenue was $4.3 million for the three months ended June 30, 2003 compared to a net cost of $0.5 million for the same period a year ago. The increase in other revenue was primarily related to the sale of emission reduction credits. For the six months ended June 30, 2003, other revenue was $5.1 million compared to a net cost of $1.1 million for the six months ended June 30, 2003. The net cost in 2002 was primarily attributable to marketing and transportation activities incidental to our oil and gas operations. Lease operating expenses Lease operating expenses decreased $0.2 million, to $6.7 million for the three months ended June 30, 2003, from $6.9 million for the same period in 2002. For the six months ended June 30, 2003, lease operating expense decreased $0.4 million, to $13.0 million, from $13.4 million for the same period in 2002. Continued focus on operating efficiency along with the sale of certain properties contributed to the current year reductions, partially offset by increased workover activity on oil and gas wells during 2003. Production taxes Production taxes, which are generally based on a percentage of revenue (excluding VPP revenue) decreased $0.1 million, to $1.5 million for the three months ended June 30, 2003, from $1.6 million for the same period in 2002, as the impact of higher oil and gas revenue was offset by $0.2 million of production tax refunds and slightly lower production tax rates. For the six months ended June 30, 2003, production taxes increased $0.8 million, to $3.8 million, from $3.0 million for the same period in 2002, primarily due to higher oil and gas revenue associated with higher average realized prices. General and administrative expenses General and administrative ("G&A") expenses for the three months ended June 30, 2003 were $1.9 million compared to $1.8 million for the same period in 2002. The increase was primarily due to higher incentive compensation expense resulting from improved operating results. For the six months ended June 30, 2003, G&A expenses were $3.7 million compared to $3.9 million for the same period in 2002. The decrease was primarily due to lower labor costs associated with a reduced work force, partially offset by higher incentive compensation expense resulting from improved operating results. Stock compensation Stock compensation reflects the non-cash amortization of restricted stock grants and the "in the money" component of 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". For the six-month period ended June 30, 2003, stock compensation was $0.4 million compared to $0.5 million for the same period in 2002. The slight decrease was associated with our reduction in work force. Accretion of asset retirement obligation Accretion of our asset retirement obligation was $0.3 million and $0.6 million for the three month and six month periods ended June 30, 2003, respectively. Effective January 1, 2003, we adopted Financial 16 Accounting Standards Board Statement No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). See Note 2 to Condensed Consolidated Financial Statements for more information regarding this accounting change. Depreciation, depletion and amortization Depreciation, depletion and amortization ("DD&A") expense for the three months ended June 30, 2003, decreased $0.6 million, to $11.4 million, from $12.0 million for the same period in 2002. For the six months ended June 30, 2003, DD&A decreased $3.0 million, to $22.1 million, from $25.1 million for the same period in 2002. The decreases were primarily attributable to reduced production as a result of the non-core property sales in 2002. Interest expense Interest expense for the three months ended June 30, 2003 was $4.6 million compared to $4.8 million for the same period in 2002. For the six-month period ended June 30, 2003, interest expense was $9.2 million compared to $9.7 million for the same period in 2002. The decrease reflects lowering outstanding debt and, to a lesser extent, lower interest rates on our Credit Agreement. Income Taxes For the six months ended June 30, 2003, income tax benefits were $11.6 million compared to an income tax expense of $14.7 million for the same period in 2002. We record deferred tax assets and liabilities to account for temporary differences arising from events that have been recognized in our financial statements and will result in future taxable or deductible items in our tax returns. To the extent our deferred tax assets exceed deferred tax liabilities, at least annually (and more frequently if events or circumstances change materially), we assess the realizability of our net deferred tax assets. A valuation allowance is recognized if, at the time, it is anticipated that some or all of our net deferred tax assets may not be realized. See Note 3 to Condensed Consolidated Financial Statements. During the second quarter of 2002, we increased the valuation allowance on the Company's deferred tax assets, which are primarily related to tax net operating loss carryforwards, by $15.9 million, thereby reducing to zero the carrying amount of net deferred tax assets with a corresponding non-cash charge to income tax expense. In making that assessment, management considered several factors, including future projections of taxable income, which reflected relatively low natural gas and oil prices at that time, and the January 2003 maturity of the Company's Senior Note obligations that required refinancing. In 2003, we negotiated and amended our credit agreement with a group of institutional lenders and repaid the remaining Senior Note obligations. In addition, natural gas and oil prices improved significantly and we generated significant income in the first half of 2003 thereby utilizing a portion of our deferred tax assets. As a result of the substantial improvement in our financial condition and current and projected profitability levels over the next several years, we reversed $11 million of our valuation allowance related to the tax effects on future gross taxable income which is reflected as an income tax benefit in the statement of operations for the second quarter of 2003. Liquidity and Capital Resources Our main objective in 2002 was to position the Company to meet the Senior Note obligations due January 15, 2003. In order to meet this objective, we curtailed our drilling and overall capital expenditure programs and sold certain non-core assets. These actions positioned us to reduce debt and negotiate the financing necessary to pay off the remaining portion of the maturing Senior Notes during a difficult period in the capital markets. Although the asset sales and curtailed drilling and capital expenditure programs resulted 17 in lower production and reserves in 2002, we exited the year in a stronger financial position, with increased financial flexibility, a focused asset base in our core areas, and a quality multi-year drilling prospect inventory. On January 14, 2003, we completed the arrangements necessary to amend and restate our existing credit agreement ("Credit Agreement") with a group of institutional lenders. Initial proceeds of $69.3 million were used primarily to pay off the balance of the maturing Senior Note obligations. On June 30, 2003, $54.0 million was outstanding under the Credit Agreement, the weighted average interest rate was 7.8% and $34.0 million was available for additional Company borrowings. With the completion of the financing, we accelerated our drilling program in the first half of 2003 resulting in increased production and reserves. We believe that the Company is positioned to capitalize on the current strong natural gas price environment, to focus on developing our prospect inventory to grow reserves and production in our core areas and to further reduce debt per MCFE. Cash flow from operating activities Net cash provided by operating activities for the six months ended June 30, 2003 was $43.6 million compared to net cash used in operating activities of $0.1 million during the same period in 2002. The improvement in our cash flow in 2003 was primarily due to higher realized oil and natural gas prices and substantially less production dedicated to repayment of the production payment discussed in Note 4 to Condensed Consolidated Financial Statements. The net change in trade accounts receivable reflects the higher natural gas and oil price environment in 2003 and the timing of cash receipts. The net change in accounts payable and accrued liabilities was primarily attributable to the significant increase in our drilling program in the current year. Investing activities For the six months ended June 30, 2003, net cash used in investing activities was $37.3 million of which $36.8 million was invested in oil and gas properties compared to net cash used in investing activities of $1.6 million for the same period in 2002. For the 2002 six-month period, the Company invested $26.2 million on oil and gas properties and sold $24.7 million of non-core properties. We recently increased our 2003 budget for investments in oil and gas properties from $55 million to $65 million. KCS believes that cash on hand, net cash generated from operations and unused committed borrowing capacity under the Credit Agreement will be adequate to satisfy its liquidity needs. In the future, the Company may utilize various financing sources including the issuance of debt or equity securities. New Accounting Principles Effective January 1, 2003, we adopted SFAS No. 143 which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the periods in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of settlement over the useful life of the asset, and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption of SFAS No. 143, our net property, plant and equipment was increased by $10.2 million, an additional asset retirement obligation of $11.1 million (primarily for plugging and abandonment costs of oil and gas wells) was recorded and a $0.9 million charge, net of tax against net income (or a $0.02 loss per basic and diluted share) was reported in the first quarter of 2003 as a cumulative effect of a change in accounting principle. Subsequent to adoption, the effect of the change in accounting principle in the first six months of 2003 was a charge of $0.3 million, or $0.01 per basic and diluted share. Effective January 1, 2002, we began amortizing the capitalized costs related to oil and gas properties on the unit-of-production basis ("UOP") using proved oil and gas reserves. Previously, we had computed amortization on the basis of future gross revenue ("FGR"). The Company determined that the change to UOP was preferable under accounting principles generally accepted in the United States, since among other reasons, it provides a more rational basis for amortization during periods of volatile commodity prices and also 18 increases consistency with others in the industry. As a result of this change, we recorded a non-cash cumulative effect charge of $6.2 million, net of tax, (or $0.17 per basic and diluted common share) in the first quarter of 2002. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51." Interpretation No. 46 requires a company to consolidate a variable interest entity ("VIE") if the company has a variable interest (or combination of variable interests) that is exposed to a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. In addition, more extensive disclosure requirements apply to the primary and other significant variable interest owners of the VIE. This interpretation applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It is also effective for the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which a company holds a variable interest that is acquired before February 1, 2003. The guidance regarding this interpretation is extremely complex and, although we do not believe we have an interest in a VIE, the Company continues to assess the impact, if any, this interpretation will have on the Company's consolidated financial statements. In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards on how the Company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that the Company classify as liabilities the fair value of all mandatorily redeemable financial instruments that had previously been recorded as equity or elsewhere in the consolidated financial statements. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for all existing financial instruments beginning in the third quarter of 2003. SFAS No. 150 will not have an impact on the Company's classification of its convertible preferred stock because the convertible preferred stock is not mandatorily redeemable as defined by SFAS No. 150. 19 Item 3. Quantitative and Qualitative Disclosures about Market Risk. Derivative Instruments. The Company's major market risk exposure is to oil and 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. The Company has utilized, and may continue to utilize, derivative contracts, including swaps, futures contracts, options and collars to manage this price risk. See Note 7 to Condensed Consolidated Financial Statements. While these derivative contracts are structured to reduce the Company's exposure to decreases in the price associated with the underlying commodity, they also limit the benefit the Company might otherwise receive from any price increases. At June 30, 2003, the Company had derivative instruments covering 4.1 million Mmbtu of gas production for July 2003 through March 2004. These instruments established an average floor price of $4.44 and enable the Company to receive market prices up to an average cap of $7.04, approximately 20% of any price between $7.04 and $7.54 and 100% of any price above $7.54. The following table sets forth the Company's oil and natural gas hedged position at June 30, 2003.
Expected Maturity ------------------------------------------------------------- 2003 2004 Fair ---------------------------------------------- ---------- Value 3nd Quarter 4th Quarter Total 1st Quarter ($000) ----------- ----------- ----- ----------- ------ Swaps: $ (6) Volumes (bbl) 7,700 -- 7,700 -- Weighted average price ($/bbl) $ 30.00 $ -- $ 30.00 $ -- Puts / Floors: $ 36 Volumes (Mmbtu) 460,000 305,000 765,000 -- Weighted average price ($/Mmbtu) $ 4.25 $ 4.25 $ 4.25 $ -- 3-way collars: $ 252 Volumes (MMbtu) 1,075,000 1,380,000 2,445,000 910,000 Weighted average price ($/Mmbtu) Floor (purchased put option) $ 4.47 $ 4.47 $ 4.47 $ 4.50 Cap 1 (sold call option) $ 5.76 $ 7.08 $ 6.50 $ 8.50 Cap 2 (purchased call option) $ 6.26 $ 7.58 $ 7.00 $ 9.00
In addition to the above, the Company has entered into fixed price sales contracts covering 0.3 million Mmbtu at an average price of $5.30 for July through August 2003 and will deliver 3.1 Bcfe for July through December 2003, 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006 under the Production Payment sold in February 2001 at an average price of $4.05 per Mcfe. Interest Rate Risk. The Company uses fixed and variable rate long-term debt to finance its capital spending program and for general corporate purposes. These variable rate debt instruments expose the Company to market risk related to changes in interest rates. The Company's fixed rate debt and the associated weighted average interest rate was $125.0 million at 8.9% on June 30, 2003 and $195.9 million at 9.6% on June 30, 2002. The Company's variable rate debt and weighted average interest rate was $54.0 million at 7.8% on June 30, 2003 and $12.0 million at 4.2% on June 30, 2002. 20 Item 4. Controls and Procedures. We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as of the end of the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic Exchange Act reports. There have been no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are likely to materially affect, our internal control over financial reporting. 21 PART II - OTHER INFORMATION Item 1. Legal Proceedings. Reference is made to Note 11 to Condensed Consolidated Financial Statements included herein. Item 4. Submission of Matters to a Vote of Security Holders. The Company held its Annual Meeting of Stockholders on May 27, 2003 in Houston, Texas. All nominated directors were elected and will serve a three-year term expiring in 2006. (a) Directors elected at the Annual Meeting: Votes in Favor Votes Withheld William N. Hahne 33,750,327 90,140 James L. Bowles 33,750,161 90,306 (b) Directors with terms of office continuing after the Annual Meeting: Directors with terms expiring in 2004 ------------------------------------- G. Stanton Geary Robert G. Reynolds Directors with terms expiring in 2005 ------------------------------------- James W. Christmas Joel D. Siegel Christopher A. Viggiano Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: 3.1 Amendments to Restated By-Laws of KCS Energy, Inc. effective April 22, 2003. 10.1 First, Second and Third Amendments to the Amended and Restated Credit Agreement by and among KCS Energy, Inc., the lenders from time to time hereto, Foothill Capital Corporation, as collateral and administrative agent, and Highbridge/ Zwirn Special Opportunities Fund, L.P., as lead arranger. 10.2 Change on Control Agreement between KCS Energy, Inc. and Joseph T. Leary. 10.3 Change in Control Agreement between KCS Energy, Inc. and Frederick Dwyer. 31.1 Certification of James W. Christmas, Chairman and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Joseph T. Leary, Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of James W. Christmas, Chairman and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Joseph T. Leary, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) Reports on Form 8-K. The Company furnished a report on Form 8-K on April 4, 2003 under Item 9 reporting the issuance of a press release announcing the Company's 2002 fourth quarter and full year operating and financial results. The Company furnished a report on Form 8-K on May 13, 2003 under Item 12, Results of Operations and Financial Condition, reporting the issuance of a press release announcing the Company's first quarter 2003 operational and financial results. 22 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. August 14, 2003 By: /S/ FREDERICK DWYER ------------------------------ Frederick Dwyer Vice President, Controller and Secretary Exhibit Index Exhibit No. Description ------ ----------------- 3.1 Amendments to Restated By-Laws of KCS Energy, Inc. effective April 22, 2003. 10.1 First, Second and Third Amendments to the Amended and Restated Credit Agreement by and among KCS Energy, Inc., the lenders from time to time hereto, Foothill Capital Corporation, as collateral and administrative agent, and Highbridge/Zwirn Special Opportunities Fund, L.P., as lead arranger. 10.2 Change in Control Agreement between KCS Energy, Inc. and Joseph T. Leary. 10.3 Change in Control Agreement between KCS Energy, Inc. and Frederick Dwyer. 31.1 Certification of James W. Christmas, Chairman and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Joseph T. Leary, Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of James W. Christmas, Chairman and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Joseph T. Leary, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 23