-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, MkhGS/M+poEu5wZZgZfEVXZd/LBWS03/uzsEm3TPdLmRzQh62Y8bkWmsW5uOpnS2 xsOgMVeZIYAbzeoGl/Y9ug== 0000950129-03-002663.txt : 20030513 0000950129-03-002663.hdr.sgml : 20030513 20030513142115 ACCESSION NUMBER: 0000950129-03-002663 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20030331 FILED AS OF DATE: 20030513 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CARRIZO OIL & GAS INC CENTRAL INDEX KEY: 0001040593 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760415919 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-29187-87 FILM NUMBER: 03695091 BUSINESS ADDRESS: STREET 1: 14701 ST MARYS LANE STREET 2: STE 800 CITY: HOUSTON STATE: TX ZIP: 77079 BUSINESS PHONE: 2814961352 MAIL ADDRESS: STREET 1: 14701 ST MARYS LANE STREET 2: SUITE 800 CITY: HOUSTON STATE: TX ZIP: 77079 10-Q 1 h05693e10vq.txt CARRIZO OIL & GAS, INC. 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 MARCH 31, 2003 -------------- [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to _________ Commission File Number 000-22915. CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 76-0415919 ----- ---------- (State or other jurisdiction of (IRS Employer Identification No.) incorporation or organization) 14701 ST. MARY'S LANE, SUITE 800, HOUSTON, TX 77079 - --------------------------------------------- ----- (Address of principal executive offices) (Zip Code) (281) 496-1352 -------------- (Registrant's telephone number) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 126-2 of the Exchange Act). YES [ ] NO [X] The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of May 1, 2003, the latest practicable date, was 14,200,716. CARRIZO OIL & GAS, INC. FORM 10-Q FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003 INDEX
PAGE PART I. FINANCIAL INFORMATION Item 1. Consolidated Balance Sheets - As of December 31, 2002 and March 31, 2003 2 Consolidated Statements of Operations - For the three-month periods ended March 31, 2003 and 2002 3 Consolidated Statements of Cash Flows - For the three-month periods ended March 31, 2003 and 2002 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 12 Item 3A. Quantitative and Qualitative Disclosure About Market Risk 23 Item 4. Controls and Procedures 24 PART II. OTHER INFORMATION Items 1-6. 25 SIGNATURES 26
CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (UNAUDITED)
DECEMBER 31, MARCH 31, 2002 2003 ------------ ------------ (In thousands) ASSETS CURRENT ASSETS: Cash and cash equivalents $ 4,743 $ 7,184 Accounts receivable, trade (net of allowance for doubtful accounts of $0.5 million at December 31, 2002 and March 31, 2003, respectively) 8,207 7,751 Advances to operators 501 59 Deposits 46 46 Other current assets 605 981 ------------ ------------ Total current assets 14,102 16,021 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and natural gas properties) 120,526 121,596 Deferred financing costs 760 717 ------------ ------------ $ 135,388 $ 138,334 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade $ 9,957 $ 6,181 Accrued liabilities 1,014 1,848 Advances for joint operations 1,550 3,122 Current maturities of long-term debt 1,609 1,611 Current maturities of seismic obligation payable 1,414 1,412 ------------ ------------ Total current liabilities 15,544 14,174 LONG-TERM DEBT 37,886 37,852 SEISMIC OBLIGATION PAYABLE 1,103 750 ASSET RETIREMENT OBLIGATION -- 608 DEFERRED INCOME TAXES 7,666 9,221 COMMITMENTS AND CONTINGENCIES (Note 5) CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares of preferred stock authorized, of which 150,000 are shares designated as convertible participating shares, with 65,294 convertible participating shares issued and outstanding at December 31, 2002 and March 31, 2003, respectively) (Note 6) Issued and outstanding 6,373 6,391 Accrued dividends -- 163 SHAREHOLDERS' EQUITY: Warrants (3,262,821 outstanding at December 31, 2002 and March 31, 2003, respectively) 780 780 Common stock, par value $.01 (40,000,000 shares authorized with 14,177,383 and 14,200,716 issued and outstanding at December 31, 2002 and March 31, 2003, respectively) 142 142 Additional paid in capital 63,224 63,271 Retained earnings 3,058 5,719 Accumulated other comprehensive loss (388) (737) ------------ ------------ 66,816 69,175 ------------ ------------ $ 135,388 $ 138,334 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. -2- CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
FOR THE THREE MONTHS ENDED MARCH 31, -------------------------- 2002 2003 ---------- ---------- (In thousands except per share amounts) OIL AND NATURAL GAS REVENUES $ 4,027 $ 10,663 COSTS AND EXPENSES: Oil and natural gas operating expenses (exclusive of depreciation shown separately below) 1,012 1,720 Depreciation, depletion and amortization 1,970 3,036 General and administrative 916 1,383 Accretion expense related to asset retirement obligations -- 8 Stock option compensation (42) (10) ---------- ---------- Total costs and expenses 3,856 6,137 ---------- ---------- OPERATING INCOME 171 4,526 OTHER INCOME AND EXPENSES: Other income and expenses 93 100 Interest income 20 18 Interest expense (216) (198) Interest expense, related parties (552) (583) Capitalized interest 768 776 ---------- ---------- INCOME BEFORE INCOME TAXES 284 4,639 INCOME TAXES (Note 4) 140 1,669 ---------- ---------- NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 144 2,970 DIVIDENDS AND ACCRETION ON PREFERRED STOCK 74 181 ---------- ---------- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 70 2,789 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES (Note 8) -- 128 ---------- ---------- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 70 $ 2,661 ========== ========== BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.00 $ 0.20 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES 0.00 (0.01) ---------- ---------- BASIC EARNINGS PER COMMON SHARE $ 0.00 $ 0.19 ========== ========== DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.00 $ 0.17 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES 0.00 (0.01) ---------- ---------- DILUTED EARNINGS PER COMMON SHARE $ 0.00 $ 0.16 ========== ========== PRO FORMA AMOUNTS ASSUMING ASSET RETIREMENTS OBLIGATION IS APPLIED RETROACTIVELY: BASIC EARNINGS PER COMMON SHARE $ 0.00 $ 0.20 ========== ========== DILUTED EARNINGS PER COMMON SHARE $ 0.00 $ 0.17 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. -3- CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE THREE MONTHS ENDED MARCH 31, -------------------------- 2002 2003 ---------- ---------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income before cumulative effect of change in accounting principle $ 144 $ 2,970 Adjustment to reconcile net income to net cash provided by operating activities- Depreciation, depletion and amortization 1,970 3,036 Discount accretion 21 30 Ineffective derivative instruments (232) -- Interest payable in kind 331 350 Stock option compensation (benefit) (42) (10) Deferred income taxes 99 1,624 Changes in assets and liabilities- Accounts receivable 2,550 456 Other assets (7) (203) Accounts payable (2,493) (2,307) Other liabilities 163 307 ---------- ---------- Net cash provided by operating activities 2,504 6,253 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (5,808) (4,001) Change in capital expenditure accrual (123) (1,469) Advances to operators (528) 442 Advances for joint operations 1,117 1,572 ---------- ---------- Net cash used in investing activities (5,342) (3,456) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from the sale of common stock -- 47 Net proceeds from the sale of preferred stock 5,785 -- Net proceeds from the sale of warrants 15 -- Debt repayments (933) (403) ---------- ---------- Net cash provided by (used in) financing activities 4,867 (356) ---------- ---------- NET INCREASE IN CASH AND CASH EQUIVALENTS 2,029 2,441 CASH AND CASH EQUIVALENTS, beginning of period 3,236 4,743 ---------- ---------- CASH AND CASH EQUIVALENTS, end of period $ 5,265 $ 7,184 ========== ========== SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized) $ -- $ 5 ========== ========== Cash paid for income taxes $ -- $ -- ========== ========== Common stock issued for oil and gas property (Note 7) $ 325 $ -- ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. -4- CARRIZO OIL & GAS, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. ACCOUNTING POLICIES: The consolidated financial statements included herein have been prepared by Carrizo Oil & Gas, Inc. (the Company), and are unaudited, except for the balance sheet at December 31, 2002, which has been prepared from the audited financial statements at that date. The financial statements reflect the accounts of the Company and its subsidiary after elimination of all significant intercompany transactions and balances. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 2. EARNINGS PER COMMON SHARE: Supplemental earnings per share information is provided below:
FOR THE THREE MONTHS ENDED MARCH 31, ----------------------------------------------------------------------------- (In thousands except share and per share amounts) INCOME SHARES PER-SHARE AMOUNT ------------------------ ----------------------- ----------------------- 2002 2003 2002 2003 2002 2003 ---------- ---------- ---------- ---------- ---------- ---------- Net income before cumulative effect of change in accounting principle net of income taxes $ 144 $ 2,970 Less: Dividends and Accretion of Discount on Preferred Shares (74) (181) ---------- ---------- Basic Earnings per Share Net income available to common shareholders 70 2,789 14,128,653 14,198,134 $ 0.00 $ 0.20 ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions -- 181 2,105,154 3,258,632 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions $ 70 $ 2,970 16,233,807 17,456,766 $ 0.00 $ 0.17 ========== ========== ========== ========== ========== ==========
FOR THE THREE MONTHS ENDED MARCH 31, ---------------------------------------------------------------------------- (In thousands except share and per share amounts) INCOME SHARES PER-SHARE AMOUNT ----------------------- ----------------------- ----------------------- 2002 2003 2002 2003 2002 2003 ---------- ---------- ---------- ---------- ---------- ---------- Cumulative effect of change in accounting principle net of income taxes $ -- $ (128) Basic Earnings per Share Net loss available to common shareholders -- (128) 14,128,653 14,198,134 $ 0.00 $ (0.01) ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions -- -- 2,105,154 3,258,632 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions $ -- $ (128) 16,233,807 17,456,766 $ 0.00 $ (0.01) ========== ========== ========== ========== ========== ==========
-5-
FOR THE THREE MONTHS ENDED MARCH 31, ----------------------------------------------------------------------------- (In thousands except share and per share amounts) INCOME SHARES PER-SHARE AMOUNT ------------------------ ----------------------- ----------------------- 2002 2003 2002 2003 2002 2003 ---------- ---------- ---------- ---------- ---------- ---------- Net income $ 144 $ 2,842 Less: Dividends and Accretion of Discount on Preferred Shares (74) (181) ---------- ---------- Basic Earnings per Share Net income available to common shareholders 70 2,661 14,128,653 14,198,134 $ 0.00 $ 0.19 ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions -- 181 2,105,154 3,258,632 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions $ 70 $ 2,842 16,233,807 17,456,766 $ 0.00 $ 0.16 ========== ========== ========== ========== ========== ==========
Basic earnings per common share is based on the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential common shares outstanding during the periods. The Company had outstanding 189,833 and 149,833 stock options and 252,632 warrants during the three months ended March 31, 2002 and 2003, respectively, which were antidilutive and were not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants. At March 31, 2002 and 2003, the Company also had 1,052,632 and zero shares, respectively, based on the assumed conversion of the Series B Convertible Participating Preferred Stock, that were antidilutive and were not included in the calculation. 3. LONG-TERM DEBT: At December 31, 2002 and March 31, 2003, long-term debt consisted of the following:
DECEMBER 31, MARCH 31, 2002 2003 ------------ ------------ Borrowing base facility $ 8,500 $ 8,500 Senior subordinated notes, related parties 25,478 25,849 Capital lease obligations 267 239 Non-recourse note payable to Rocky Mountain Gas, Inc. 5,250 4,875 ------------ ------------ 39,495 39,463 Less: current maturities (1,609) (1,611) ------------ ------------ $ 37,886 $ 37,852 ============ ============
On May 24, 2002, the Company entered into a credit agreement with Hibernia National Bank (the "Hibernia Facility") which matures on January 31, 2005, and repaid its existing facility with Compass Bank (the "Compass Facility"). The Hibernia Facility provides a revolving line of credit of up to $30.0 million. It is secured by the Mortgaged Properties, which include substantially all of the Company's producing oil and gas properties, and is guaranteed by the Company's subsidiary. The borrowing base will be determined by Hibernia National Bank at least semi-annually on each October 31 and April 30. The initial borrowing base was $12.0 million, and the borrowing base as of October 31, 2002 was $13.0 million. Each party to the credit agreement can request one unscheduled borrowing base determination subsequent to each scheduled determination. The borrowing base will at all times equal the borrowing base most recently determined by Hibernia National Bank, less quarterly borrowing base reductions required subsequent to such determination. Hibernia National Bank will reset the borrowing base amount at each scheduled and each unscheduled borrowing base determination date. The initial quarterly borrowing base reduction, which commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base reduction effective January 31, 2003 was $1.8 million. -6- On December 12, 2002, the Company entered into an Amended and Restated Credit Agreement with Hibernia National Bank that provided additional availability under the Hibernia Facility in the amount of $2.5 million which was structured as an additional "Facility B" under the Hibernia Facility. As such, the total borrowing base under the Hibernia Facility as of December 31, 2002 and March 31, 2003 was $15.5 million and $13.8 million, respectively, of which $8.5 million was outstanding on December 31, 2002 and March 31, 2003 and $6.5 million is currently drawn. The Facility B bore interest at LIBOR plus 3.375%, was secured by certain leases and working interests in oil and natural gas wells and matured on April 30, 2003. If the principal balance of the Hibernia Facility ever exceeds the borrowing base as reduced by the quarterly borrowing base reduction (as described above), the principal balance in excess of such reduced borrowing base will be due as of the date of such reduction. Otherwise, any unpaid principal or interest will be due at maturity. If the principal balance of the Hibernia Facility ever exceeds any re-determined borrowing base, the Company has the option within thirty days to (individually or in combination): (i) make a lump sum payment curing the deficiency; (ii) pledge additional collateral sufficient in Hibernia National Bank's opinion to increase the borrowing base and cure the deficiency; or (iii) begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Such payments are in addition to any payments that may come due as a result of the quarterly borrowing base reductions. For each tranche of principal borrowed under the revolving line of credit, the interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an applicable margin equal to 2.375% if the amount borrowed is greater than or equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than 90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate, plus an applicable margin of 0.375% if the amount borrowed is greater than or equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on either the last day of each Eurodollar option period or monthly, whichever is earlier. Interest on Base Rate Loans is payable monthly. The Company is subject to certain covenants under the terms of the Hibernia Facility, including, but not limited to the maintenance of the following financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (ii) a minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million, plus 100% of all subsequent common and preferred equity contributed by shareholders, plus 50% of all positive earning occurring subsequent to such quarter end, all ratios as more particularly discussed in the credit facility. The Hibernia Facility also places restrictions on additional indebtedness, dividends to non-preferred stockholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of the Company's common or preferred stock, speculative commodity transactions, and other matters. At December 31, 2002 and March 31, 2003, amounts outstanding under the Hibernia Facility totaled $8.5 million with an additional $4.3 million and $2.5 million, respectively, under Facility A and $2.5 million under Facility B available for future borrowings. No amounts under the Compass Facility were outstanding at December 31, 2002. At December 31, 2002 and March 31, 2003, one letter of credit was issued and outstanding under the Hibernia Facility in the amount of $0.2 million. On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7.5 million to RMG as consideration for certain interests in oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. At December 31, 2002 and March 31, 2003, the outstanding principal balance of this note was $5.3 million and $4.9 million, respectively. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.2 million. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. In October 2002, the Company entered a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,462 including interest at 6.4% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1, under both leases. DD&A on the capital leases for the three months ended March 31, 2002 and 2003 amounted to $6,000 and $10,000, respectively, and accumulated DD&A on the leased equipment at December 31, 2002 and March 31, 2003 amounted to $28,000 and $38,000, respectively. In December 1999, the Company consummated the sale of $22.0 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and $8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, -7- respectively. The Subordinated Notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest payments are due quarterly commencing on March 31, 2000. The Company may elect, for a period of up to five years, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2002 and March 31, 2003, the outstanding balance of the Subordinated Notes had been increased by $3.9 million and $4.3 million, respectively, for such interest paid in kind. The Company is subject to certain covenants under the terms of the Subordinated Notes securities purchase agreement, including but not limited to, (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) a limitation of its capital expenditures to an amount equal to the Company's EBITDA for the immediately prior fiscal year (unless approved by the Company's Board of Directors and a JPMorgan Partners, LLC appointed director), as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates and (vi) make certain repayments and prepayments, including any prepayment of the subordinated debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect certain permanent reductions in revolving credit facilities. EBITDA was part of a negotiated covenant with the purchasers and is presented here as a disclosure of the Company's covenant obligations. At December 31, 2002 and March 31, 2003, the Company believes it was in compliance with all of its debt covenants. 4. INCOME TAXES: The Company provided deferred income taxes at the rate of 35%, which also approximates its statutory rate, that amounted to $0.1 million and $1.6 million for the three months ended March 31, 2002 and 2003, respectively. 5. COMMITMENTS AND CONTINGENCIES: From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. The operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable. During August 2001, the Company entered into an agreement whereby the lessor will provide to the Company up to $0.8 million in financing for production equipment utilizing capital leases. At December 31, 2002 and March 31, 2003, two leases in the amount of $0.5 million had been executed under this facility. Pursuant to agreements entered into with RMG in June 2001, CCBM has an obligation to fund $2.5 million of drilling costs on behalf of RMG. Through March 31, 2003, CCBM had satisfied $1.7 million of the drilling obligation on behalf of RMG. 6. CONVERTIBLE PARTICIPATING PREFERRED STOCK: In February 2002, the Company consummated the sale of 60,000 shares of Convertible Participating Series B Preferred Stock (the "Series B Preferred Stock") and Warrants to purchase Carrizo 252,632 shares of common stock for an aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000 shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock is convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustments, and is initially convertible into 1,052,632 shares of common stock. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of 8% per annum or, at the Company's option, by payment in kind of additional shares of the same series of preferred stock at a rate of 10% per annum. At December 31, 2002 and March 31, 2003, the outstanding balance of the Series B Preferred Stock has been increased by $0.5 million (5,294 shares) for dividends paid in kind. The Series B Preferred Stock is redeemable at varying prices in whole or in part at the holders' option after three years or at the Company's option at any time. The Series B Preferred Stock will also participate in any dividends declared on the common stock. Holders of the Series B Preferred Stock will receive a liquidation preference upon the liquidation of, or certain mergers or sales of substantially all assets involving, the Company. Such holders will also have the option of receiving a change of -8- control repayment price upon certain deemed change of control transactions. The warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo's common stock at a price of $5.94 per share, subject to adjustments, and are exercisable at any time after issuance. The warrants may be exercised on a cashless exercise basis. Net proceeds of this financing were approximately $5.8 million and were used primarily to fund the Company's ongoing exploration and development program and general corporate purposes. 7. SHAREHOLDER'S EQUITY: The Company issued 76,472 and 23,333 shares of common stock during the three months ended March 31, 2002 and March 31, 2003, respectively. The shares issued during the three months ended March 31, 2002 were partial consideration for the acquisition of an interest in certain oil and natural gas properties and the shares issued during the three months ended March 31, 2003 were the result of the exercise of options granted under the Company's Incentive Plan. In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation", which requires the Company to record stock-based compensation at fair value. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure". The Company has adopted the disclosure requirements of SFAS No. 148 and has elected to record employee compensation expense utilizing the intrinsic value method permitted under Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees". The Company accounts for its employees' stock-based compensation plan under APB Opinion No. 25 and its related interpretations. Accordingly, any deferred compensation expense would be recorded for stock options based on the excess of the market value of the common stock on the date the options were granted over the aggregate exercise price of the options. This deferred compensation would be amortized over the vesting period of each option. Had compensation cost been determined consistent with SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the Company's net income (loss) and earnings per share would have been as follows:
FOR THE THREE MONTHS ENDED MARCH 31, -------------------------- 2002 2003 ---------- ---------- (In thousands except per share amounts) Net income available to common shareholders, as reported $ 70 $ 2,661 Less: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects (199) (132) ---------- ---------- Pro forma net income (loss) available to common shareholders $ (129) $ 2,529 ========== ========== Net income per common share, as reported: Basic $ 0.00 $ 0.19 Diluted 0.00 0.16 ProForma net income (loss) per common share, as if value method had been applied to all awards: Basic $ (0.01) $ 0.18 Diluted (0.01) 0.16
Diluted earnings per share amounts for the three months ended March 31, 2002 and 2003 are based upon 16,233,807 and 16,311,251 shares, respectively, that include the dilutive effect of assumed stock option and warrant conversions of 2,105,154 and 2,113,117, respectively. -9- 8. CHANGE IN ACCOUNTING PRINCIPLE: In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". This Statement is effective for fiscal years beginning after June 15, 2002, and the Company adopted the Statement effective January 1, 2003. During the three months ended March 31, 2003, the Company recorded a cumulative effect of change in accounting principle of $0.1 million, $0.4 million as proved properties and $0.5 million as a liability for its plugging and abandonment expenses. 9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY: The Company's operations involve managing market risks related to changes in commodity prices. Derivative financial instruments, specifically swaps, futures, options and other contracts, are used to reduce and manage those risks. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and natural gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. The Company enters into the majority of its hedging transactions with two counterparties and a netting agreement is in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production from December 2001 through December 2002. The value of these derivatives at that time was $0.8 million. Because of Enron's financial condition, the Company concluded that the derivatives contracts were no longer effective and thus did not qualify for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 $(0.8 million) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. An allowance for the related asset totalling $0.8 million, net of tax of $0.4 million, was charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4 million, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. The remaining balance in other comprehensive income was reported as oil and natural gas revenues in 2002 as the terms of the original derivative expired. As of December 31, 2002 and March 31, 2003, $0.4 million and $0.7 million, net of tax of $0.2 million and $0.4 million, respectively, remained in accumulated other comprehensive income related to the valuation of the Company's hedging positions. Total oil purchased and sold under swaps and collars during the three months ended March 31, 2002 and 2003 were zero Bbls and 63,000 Bbls, respectively. Total natural gas purchased and sold under swaps and collars in the three months ended March 31, 2002 and 2003 were zero MMBtu and 540,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were zero and $1.2 million for the three months ended March 31, 2002 and 2003, respectively, and are included in oil and natural gas revenues. At December 31, 2002 and March 31, 2003 the Company had the following outstanding hedge positions: -10-
AS OF DECEMBER 31, 2002 - ------------------------------------------------------------------------------------------------------------- CONTRACT VOLUMES ------------------------------- AVERAGE AVERAGE AVERAGE QUARTER BBls MMbtu FIXED PRICE FLOOR PRICE CEILING PRICE - ------------------- ------------- ------------- ------------- ------------- ------------- First Quarter 2003 27,000 $ 24.85 First Quarter 2003 36,000 $ 23.50 $ 26.50 First Quarter 2003 540,000 3.40 5.25 Second Quarter 2003 27,300 24.85 Second Quarter 2003 36,000 23.50 26.50 Second Quarter 2003 546,000 3.40 5.25 Third Quarter 2003 552,000 3.40 5.25 Fourth Quarter 2003 552,000 3.40 5.25
AS OF MARCH 31, 2003 - ------------------------------------------------------------------------------------------------------------- CONTRACT VOLUMES ------------------------------- AVERAGE AVERAGE AVERAGE QUARTER BBls MMbtu FIXED PRICE FLOOR PRICE CEILING PRICE - ------------------- ------------- ------------- ------------- ------------- ------------- Second Quarter 2003 27,300 $ 24.85 Second Quarter 2003 36,000 $ 23.50 $ 26.50 Second Quarter 2003 273,000 4.70 Second Quarter 2003 546,000 3.40 5.25 Third Quarter 2003 276,000 4.70 Third Quarter 2003 552,000 3.40 5.25 Fourth Quarter 2003 552,000 3.40 5.25
During April 2003, the Company entered into costless collar arrangements covering 642,000 MMBtu of natural gas for April 2004 through October 2004 production with a floor of $4.00 and a ceiling of $5.20. -11- ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is management's discussion and analysis of certain significant factors that have affected certain aspects of the Company's financial position and results of operations during the periods included in the accompanying unaudited financial statements. This discussion should be read in conjunction with the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the annual financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 and the unaudited financial statements included elsewhere herein. Unless otherwise indicated by the context, references herein to "Carrizo" or "Company" mean Carrizo Oil & Gas, Inc., a Texas corporation that is the registrant. GENERAL OVERVIEW The Company began operations in September 1993 and initially focused on the acquisition of producing properties. As a result of the increasing availability of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic data and options to lease substantial acreage in 1995 and began to drill its 3-D based prospects in 1996. The Company drilled 25 gross wells in 2002 and four gross wells through the three months ended March 31, 2003 in the Gulf Coast region. The Company has budgeted to drill up to 27 gross wells (10.7 net) in the Gulf Coast region in 2003; however, the actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, Company cash flow, success of drilling programs, weather delays and other factors. If the Company drills the number of wells it has budgeted for 2003, depreciation, depletion and amortization, oil and gas operating expenses and production are expected to increase over levels incurred in 2002. The Company has typically retained the majority of its interests in shallow, normally pressured prospects and sold a portion of its interests in deeper, overpressured prospects. The Company has primarily grown through the internal development of properties within its exploration project areas, although the Company acquired properties with existing production in the Camp Hill Project in late 1993, the Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company made these acquisitions through the use of limited partnerships with Carrizo or Carrizo Production, Inc. as the general partner. In addition, in November 1998, the Company acquired assets in Wharton County, Texas in the Jones Branch project area for approximately $3.0 million. During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM") as a wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane and develop such interests. The Company also acquired a 1,940 gross acre coalbed methane property in Wyoming, the "Bobcat Project", for $0.7 million in cash and common stock in July 2002. CCBM plans to spend up to $5.0 million for drilling costs on these leases through December 2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of RMG, from whom the interests in the leases were acquired. Through March 31, 2003, CCBM has satisfied $1.7 million of its obligation on behalf of RMG. CCBM has drilled or acquired 75 gross wells (28.0 net) and incurred total drilling costs of $3.0 million through December 31, 2002 and drilled two gross wells (1.0 net) and incurred total drilling costs of $0.2 million during the three months ended March 31, 2003. These wells typically take up to 18 months to evaluate and determine whether or not they are successful. CCBM has budgeted to drill up to 50 gross (18 net) wells in 2003. The coalbed methane wells include 17 wells acquired as a result of the Bobcat acquisition. Of the approximately 55,000 net mineral acres held by CCBM as of March 31, 2003, approximately 25,600 net mineral acres are located in the state of Montana. The issuance of new coalbed methane drilling permits in Montana had been temporarily halted pending a final Record of Decision for Montana's Environmental Impact Statement ("EIS") to be issued by the Federal Bureau of Land Management ("BLM"). As expected, a final Record of Decision ("Decision") favorable to coalbed methane development was issued on March 26, 2003. Based upon this favorable Decision, the Company anticipates that new drilling permits may be issued soon and new wells could again be drilled by coalbed methane industry participants in Montana. Opponents of coalbed methane drilling in Montana could continue their legal challenge, but the Company believes that the Decision will ultimately be upheld which would allow new coalbed methane development to commence in Montana as early as late 2003. RMG, CCBM's partner and project operator, holds approximately 114 grandfathered drilling permits in Montana for acreage in which CCBM also has an interest. Although the Company believes the Decision is an important milestone, there can be no assurance when, if ever, any new permits will be obtained or the timing thereof. -12- The Company's operations involve managing market risks related to changes in commodity prices. Derivative financial instruments, specifically swaps, futures, options and other contracts, are used to reduce and manage those risks. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and natural gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. The Company enters into the majority of its hedging transactions with two counterparties and a netting agreement is in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production from December 2001 through December 2002. The value of these derivatives at that time was $0.8 million. Because of Enron's financial condition, the Company concluded that the derivatives contracts were no longer effective and thus did not qualify for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 $(0.8 million) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. An allowance for the related asset totalling $0.8 million, net of tax of $0.4 million, was charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4 million, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. The remaining balance in other comprehensive income was reported as oil and natural gas revenues in 2002 as the terms of the original derivative expired. As of December 31, 2002 and March 31, 2003, $0.4 million and $0.7 million, net of tax of $0.2 million and $0.4 million, respectively, remained in accumulated other comprehensive income related to the valuation of the Company's hedging positions. Total oil purchased and sold under swaps and collars during the three months ended March 31, 2002 and 2003 were zero Bbls and 63,000 Bbls, respectively. Total natural gas purchased and sold under swaps and collars in the three months ended March 31, 2002 and 2003 were zero MMBtu and 540,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were zero and $1.2 million for the three months ended March 31, 2002 and 2003, respectively, and are included in oil and natural gas revenues. At December 31, 2002 and March 31, 2003 the Company had the following outstanding hedge positions: -13-
AS OF DECEMBER 31, 2002 - ------------------------------------------------------------------------------------------------------------- CONTRACT VOLUMES ------------------------------- AVERAGE AVERAGE AVERAGE QUARTER BBls MMbtu FIXED PRICE FLOOR PRICE CEILING PRICE - ------------------- ------------- ------------- ------------- ------------- ------------- First Quarter 2003 27,000 $ 24.85 First Quarter 2003 36,000 $ 23.50 $ 26.50 First Quarter 2003 540,000 3.40 5.25 Second Quarter 2003 27,300 24.85 Second Quarter 2003 36,000 23.50 26.50 Second Quarter 2003 546,000 3.40 5.25 Third Quarter 2003 552,000 3.40 5.25 Fourth Quarter 2003 552,000 3.40 5.25
AS OF MARCH 31, 2003 - ------------------------------------------------------------------------------------------------------------- CONTRACT VOLUMES ------------------------------- AVERAGE AVERAGE AVERAGE QUARTER BBls MMbtu FIXED PRICE FLOOR PRICE CEILING PRICE - ------------------- ------------- ------------- ------------- ------------- ------------- Second Quarter 2003 27,300 $ 24.85 Second Quarter 2003 36,000 $ 23.50 $ 26.50 Second Quarter 2003 273,000 4.70 Second Quarter 2003 546,000 3.40 5.25 Third Quarter 2003 276,000 4.70 Third Quarter 2003 552,000 3.40 5.25 Fourth Quarter 2003 552,000 3.40 5.25
During April 2003, the Company entered into costless collar arrangements covering 642,000 MMBtu of natural gas for April 2004 through October 2004 production with a floor of $4.00 and a ceiling of $5.20. RESULTS OF OPERATIONS Three Months Ended March 31, 2003, Compared to the Three Months Ended March 31, 2002 Oil and natural gas revenues for the three months ended March 31, 2003 increased 165% to $10.7 million from $4.0 million for the same period in 2002. Production volumes for natural gas during the three months ended March 31, 2003 were unchanged at 1.1 Bcf. Average natural gas prices increased 121% to $5.91 per Mcf in the first quarter of 2003 from $2.67 per Mcf in the same period in 2002. Production volumes for oil in the first quarter of 2003 increased 161% to 139 Bbls from 53 Bbls for the same period in 2002. Average oil prices increased 45% to $29.74 per barrel in the first quarter of 2003 from $20.50 per barrel in the same period in 2002. The increase in oil production was due primarily to the commencement of production at the Burkhart #1R, Pauline Huebner A-382 #1, Matthes Huebner #1 and Delta Farms #1 wells offset by the natural decline in production from other wells. The natural gas production was unchanged primarily due to the commencement of production at the Burkhart #1R, Pauline Huebner A-382 #1, Matthes Huebner #1 and Delta Farms #1 wells offset by the natural decline in production at the Riverdale #2 and other wells. Oil and natural gas revenues include the impact of hedging activities as discussed above under "General Overview". The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the three months ended March 31, 2002 and 2003: -14-
2003 Period Compared to 2002 Period March 31, ------------------------- ------------------------- Increase % Increase 2002 2003 (Decrease) (Decrease) ---------- ---------- ---------- ---------- Production volumes - Oil and condensate (MBbls) 53 139 86 161% Natural gas (MMcf) 1,099 1,104 5 -% Average sales prices - (1) Oil and condensate (per Bbls) $ 20.50 $ 29.74 $ 9.24 45% Natural gas (per Mcf) 2.67 5.91 3.24 121% Operating revenues (In thousands)- Oil and condensate $ 1,091 $ 4,136 $ 3,045 279% Natural gas 2,936 6,527 3,591 122% ---------- ---------- ---------- Total $ 4,027 $ 10,663 $ 6,636 165% ========== ========== ==========
- ---------- (1) Includes impact of hedging activities. Oil and natural gas operating expenses for the three months ended March 31, 2003 increased 70% to $1.7 million from $1.0 million for the same period in 2002 primarily due to higher severance taxes and other operating costs associated with the addition of new production. Operating expenses per equivalent unit increased 24% to $0.89 per Mcfe in the first quarter of 2003 from $0.71 per Mcfe in the same period in 2002 primarily as a result of higher severance taxes. Depreciation, depletion and amortization (DD&A) expense for the three months ended March 31, 2003 increased 54% to $3.0 million from $2.0 million for the same period in 2002. This increase was due to increased production and additional seismic and drilling costs. General and administrative expense for the three months ended March 31, 2003 increased 51% to $1.4 million from $0.9 million for the same period in 2002 primarily as a result of the addition of contract staff to handle increased drilling and production activities, higher compensation costs and higher insurance. Income taxes increased to $1.7 million for the three months ended March 31, 2003 from $0.1 million for the same period in 2002 as a result of higher taxable income based on the factors described above. Interest income for the three months ended March 31, 2003 decreased to $18,000 from $20,000 in the first quarter of 2002 primarily as a result of lower interest rates during the first quarter of 2003. Capitalized interest was $0.8 million in the first quarter of 2003 and 2002. The Company adopted Financial Accounting Standards Board's Statement of Financial Standards No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003 and recorded a cumulative effect of change in accounting principle of $0.1 million in the three months ended March 31, 2003. Income before income taxes for the three months ended March 31, 2003 increased to $4.6 million from $0.3 million in the same period in 2002. Net income for the three months ended March 31, 2003 increased to $2.8 million from $0.1 million for the same period in 2002 primarily as a result of the factors described above. LIQUIDITY AND CAPITAL RESOURCES The Company has made and is expected to make oil and gas capital expenditures in excess of its net cash flows provided by operating activities in order to complete the exploration and development of its existing properties. The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the Company and to fund leasehold costs and geological and geophysical costs on its exploration projects. While the Company believes that the current cash balances and anticipated 2003 cash provided by operating activities will provide sufficient capital to carry out the Company's 2003 exploration plans, management of the Company continues to seek financing for its capital program from a variety of sources. No assurance can be given that the Company will be able to obtain additional financing on terms that would be acceptable to the Company. The Company's inability to obtain additional financing could have a material adverse -15- effect on the Company. Without raising additional capital, the Company anticipates that it may be required to limit or defer its planned oil and gas exploration and development program, which could adversely affect the recoverability and ultimate value of the Company's oil and gas properties. The Company's primary sources of liquidity have included proceeds from the 1997 initial public offering, from the December 1999 sale of Subordinated Notes, Common Stock and Warrants, the 2002 sale of shares of Series B Convertible Participating Preferred Stock and Warrants, the 1998 sale of shares of Series A Preferred Stock and Warrants, funds generated by operations, equity capital contributions, borrowings (primarily under revolving credit facilities) and the Palace Agreement that provided a portion of the funding for the Company's 1999, 2000, 2001 and 2002 drilling program in return for participation in certain wells. Cash flows provided by operating activities were $2.5 million and $6.3 million for the three months ended March 31, 2002 and 2003, respectively. The increase in cash flows provided by operating activities in 2003 as compared to 2002 was due primarily to additional revenue as a result of higher oil and natural gas prices and higher oil and condensate production offset by the increase of working capital during the first quarter of 2003. The Company has budgeted capital expenditures for the year ended December 31, 2003 of approximately $27.2 million of which $6.9 million is expected to be used to fund 3-D seismic surveys and land acquisitions and $20.3 million of which is expected to be used for drilling activities in the Company's project areas. The Company has budgeted to drill up to approximately 27 gross wells (10.7 net) in the Gulf Coast region and up to 50 gross (18 net) CCBM coalbed methane wells in 2003. The actual number of wells drilled and capital expended is dependent upon available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. The Company has continued to reinvest a substantial portion of its cash flows into increasing its 3-D supported drilling prospect portfolio, improving its 3-D seismic interpretation technology and funding its drilling program. Oil and gas capital expenditures were $4.0 million for the three months ended March 31, 2003, which included $1.1 million of capitalized interest and general and administrative costs. The Company's drilling efforts in the Gulf Coast region resulted in the successful completion of 17 gross wells (6.0 net) during the year ended December 31, 2002 and two gross wells (0.1 net) during the three months ended March 31, 2003. Of the 77 gross wells (29 net) drilled or acquired by CCBM through March 31, 2003, 24 gross wells (8 net) are currently producing and 53 gross wells (21 net) are awaiting evaluation before a determination can be made as to their success. CCBM plans to spend up to $5.0 million for drilling costs during the period from June 2001 through December 2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of RMG. Through March 31, 2003, CCBM has satisfied $1.7 million of its drilling obligations on behalf of RMG. FINANCING ARRANGEMENTS On May 24, 2002, the Company entered into a credit agreement with Hibernia National Bank (the "Hibernia Facility") which matures on January 31, 2005, and repaid its existing facility with Compass Bank (the "Compass Facility"). The Hibernia Facility provides a revolving line of credit of up to $30.0 million. It is secured by the Mortgaged Properties, which include substantially all of the Company's producing oil and gas properties, and is guaranteed by the Company's subsidiary. The borrowing base will be determined by Hibernia National Bank at least semi-annually on October 31 and April 30. The initial borrowing base was $12.0 million, and the borrowing base as of October 31, 2002 was $13.0 million. Each party to the credit agreement can request one unscheduled borrowing base determination subsequent to each scheduled determination. The borrowing base will at all times equal the borrowing base most recently determined by Hibernia National Bank, less quarterly borrowing base reductions required subsequent to such determination. Hibernia National Bank will reset the borrowing base amount at each scheduled and each unscheduled borrowing base determination date. The initial quarterly borrowing base reduction, which commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base reduction effective January 31, 2003 was $1.8 million. On December 12, 2002, the Company entered into an Amended and Restated Credit Agreement with Hibernia National Bank that provided additional availability under the Hibernia Facility in the amount of $2.5 million which was structured as an additional "Facility B" under the Hibernia Facility. As such, the total borrowing base under the Hibernia Facility as of December 31, 2002 and March 31, 2003 was $15.5 million and $13.8 million, respectively, of which $8.5 million was outstanding on December 31, 2002 and March 31, 2003 and $6.5 million is currently drawn. The Facility B bore interest at LIBOR plus 3.375%, was secured by certain leases and working interests in oil and natural gas wells and matured on April 30, 2003. -16- If the principal balance of the Hibernia Facility ever exceeds the borrowing base as reduced by the quarterly borrowing base reduction (as described above), the principal balance in excess of such reduced borrowing base will be due as of the date of such reduction. Otherwise, any unpaid principal or interest will be due at maturity. If the principal balance of the Hibernia Facility ever exceeds any re-determined borrowing base, the Company has the option within thirty days to (individually or in combination): (i) make a lump sum payment curing the deficiency; (ii) pledge additional collateral sufficient in Hibernia National Bank's opinion to increase the borrowing base and cure the deficiency; or (iii) begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Such payments are in addition to any payments that may come due as a result of the quarterly borrowing base reductions. For each tranche of principal borrowed under the revolving line of credit, the interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an applicable margin equal to 2.375% if the amount borrowed is greater than or equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than 90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate, plus an applicable margin of 0.375% if the amount borrowed is greater than or equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on either the last day of each Eurodollar option period or monthly, whichever is earlier. Interest on Base Rate Loans is payable monthly. The Company is subject to certain covenants under the terms of the Hibernia Facility, including, but not limited to the maintenance of the following financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (ii) a minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million, plus 100% of all subsequent common and preferred equity contributed by shareholders, plus 50% of all positive earning occurring subsequent to such quarter end, all ratios as more particularly discussed in the credit facility. The Hibernia Facility also places restrictions on additional indebtedness, dividends to non-preferred stockholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of the Company's common or preferred stock, speculative commodity transactions, and other matters. At December 31, 2002 and March 31, 2003, amounts outstanding under the Hibernia Facility totaled $8.5 million with an additional $4.3 million and $2.5 million, respectively, under Facility A and $2.5 million under Facility B available for future borrowings. No amounts under the Compass Facility were outstanding at December 31, 2002. At December 31, 2002 and March 31, 2003, one letter of credit was issued and outstanding under the Hibernia Facility in the amount of $0.2 million. On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7.5 million to RMG as consideration for certain interests in oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. At December 31, 2002 and March 31, 2003, the outstanding principal balance of this note was $5.3 million and $4.9 million, respectively. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.2 million. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. In October 2002, the Company entered a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,462 including interest at 6.4% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1, under both leases. DD&A on the capital leases for three months ended March 31, 2002 and 2003 amounted to $6,000 and $10,000, respectively, and accumulated DD&A on the leased equipment at December 31, 2002 and March 31, 2003 amounted to $28,000 and $38,000, respectively. In December 1999, the Company consummated the sale of $22.0 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and $8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest payments are due quarterly commencing on March 31, 2000. The Company may elect, for a period of up to five years, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2002 and March 31, 2003, the outstanding balance of the Subordinated Notes had been increased by $3.9 million and $4.3 million, respectively, for such interest paid in kind. -17- The Company is subject to certain covenants under the terms of the Subordinated Notes securities purchase agreement, including but not limited to, (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) a limitation of its capital expenditures to an amount equal to the Company's EBITDA for the immediately prior fiscal year (unless approved by the Company's Board of Directors and a JPMorgan Partners, LLC appointed director), as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates and (vi) make certain repayments and prepayments, including any prepayment of the subordinated debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect certain permanent reductions in revolving credit facilities. EBITDA was part of a negotiated covenant with the purchasers and is presented here as a disclosure of our covenant obligations. In February 2002, the Company consummated the sale of 60,000 shares of Series B Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common Stock for an aggregate purchase price of $6.0 million. The Company sold $4.0 million and $2.0 million of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock is convertible into Common Stock by the investors at a conversion price of $5.70 per share, subject to adjustment, and is initially convertible into 1,052,632 shares of Common Stock. The approximately $5.8 million net proceeds of this financing were used to fund the Company's ongoing exploration and development program and general corporate purposes. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of 8% per annum or, at the Company's option, by payment in kind of additional shares of the Series B Preferred Stock at a rate of 10% per annum. At December 31, 2002 and March 31, 2003 the outstanding balance of the Series B Preferred Stock had been increased by $0.5 million (5,294 shares) for dividends paid in kind. In addition to the foregoing, if the Company declares a cash dividend on the Common Stock of the Company, the holders of shares of Series B Preferred Stock are entitled to receive for each share of Series B Preferred Stock a cash dividend in the amount of the cash dividend that would be received by a holder of the Common Stock into which such share of Series B Preferred Stock is convertible on the record date for such cash dividend. Unless all accrued dividends on the Series B Preferred Stock shall have been paid and a sum sufficient for the payment thereof set apart, no distributions may be paid on any Junior Stock (which includes the Common Stock) (as defined in the Statement of Resolutions for the Series B Preferred Stock) and no redemption of any Junior Stock shall occur other than subject to certain exceptions. The Series B Preferred Stock is required to be redeemed by the Company at any time after the third anniversary of the initial issuance of the Series B Preferred Stock (the "Issue Date") upon request from any holder at a price per share equal to Purchase Price/Dividend Preference (as defined below). The Company may redeem the Series B Preferred Stock after the third anniversary of the Issue Date, at a price per share equal to the Purchase Price/Dividend Preference and, prior to that time, at varying preferences to the Purchase Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus all cumulative and accrued dividends on such share of Series B Preferred Stock. In the event of any dissolution, liquidation or winding up or certain mergers or sales or other disposition by the Company of all or substantially all of its assets (a "Liquidation"), the holder of each share of Series B Preferred Stock then outstanding will be entitled to be paid out of the assets of the Company available for distribution to its shareholders, the greater of the following amounts per share of Series B Preferred Stock: (i) $100 in cash plus all cumulative and accrued dividends and (ii) in certain circumstances, the "as-converted" liquidation distribution, if any, payable in such Liquidation with respect to each share of Common Stock. Upon the occurrence of certain events constituting a "Change of Control" (as defined in the Statement of Resolutions), the Company is required to make an offer to each holder of Series B Preferred Stock to repurchase all of such holder's Series B Preferred Stock at an offer price per share of Series B Preferred Stock in cash equal to 105% of the Change of Control Purchase Price, which is generally defined to mean $100 plus all cumulative and accrued dividends. The 2002 Warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share, subject to adjustment, and are exercisable at any time after issuance. For accounting purposes, the 2002 Warrants were recorded at a value of $0.06 per 2002 Warrant. EFFECTS OF INFLATION AND CHANGES IN PRICE The Company's results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that the Company is required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on the Company. -18- CRITICAL ACCOUNTING POLICIES The following summarizes several of our critical accounting policies: Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Oil and Natural Gas Properties Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company proportionally consolidates its interests in oil and natural gas properties. The Company capitalized compensation costs for employees working directly on exploration activities of $0.2 million and $0.3 million for the three months ended March 31, 2002 and 2003, respectively. Maintenance and repairs are expensed as incurred. Oil and natural gas properties are amortized based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until they are impaired. Unevaluated properties are evaluated periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per thousand cubic feet equivalent (Mcfe) for the three months ended March 31, 2002 and 2003 was $1.35 and $1.57 respectively. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The net capitalized costs of proved oil and natural gas properties are subject to a "ceiling test", which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net revenues from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company's oil and natural gas assets was necessary for the three months ended March 31, 2002 or 2003. Based on oil and natural gas prices in effect on December 31, 2001, the unamortized cost of oil and natural gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a write-down. Using prices in effect on December 31, 2001 the pretax write-down would have been approximately $0.7 million. Because of the volatility of oil and natural gas prices, no assurance can be given that the Company will not experience a write-down in future periods. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years. Oil and Natural Gas Reserve Estimates The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are estimates prepared by the Company. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value discount rate. Proved reserve estimates prepared by others may be substantially higher or lower than the Company's estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be -19- significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production. It should not be assumed that the present value of future net cash flows is the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. The Company's rate of recording depreciation, depletion and amortization expense for proved properties is dependent on the Company's estimate of proved reserves. If these reserve estimates decline, the rate at which the Company records these expenses will increase. Derivative Instruments and Hedging Activities In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities". This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument's fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for the Company beginning January 1, 2001 and was adopted by the Company on that date. In accordance with the current transition provisions of SFAS No. 133, the Company recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of its derivatives designated as cash flow hedging instruments at the date of adoption. Upon entering into a derivative contract, the Company designates the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and natural gas revenues when the forecasted transaction occurs. All of the Company's derivative instruments at December 31, 2002 and March 31, 2003 were designated and effective as cash flow hedges. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. Income Taxes Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"), "Accounting for Income Taxes", deferred income taxes are recognized at each yearend for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount expected to be realized. -20- Contingencies Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable. VOLATILITY OF OIL AND NATURAL GAS PRICES The Company's revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation 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 the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may materially adversely affect the Company's financial condition, liquidity, and ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the Company can produce economically. Oil and natural gas prices have declined in the recent past and there can be no assurance that prices will recover or will not decline further. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production from December 2001 through December 2002. The value of these derivatives at that time was $0.8 million. Because of Enron's financial condition, the Company concluded that the derivatives contracts were no longer effective and thus did not qualify for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 $(0.8 million) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. An allowance for the related asset totalling $0.8 million, net of tax of $0.4 million, was charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4 million, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. The remaining balance in other comprehensive income was reported as oil and natural gas revenues in 2002 as the terms of the original derivative expired. As of December 31, 2002 and March 31, 2003, $0.4 million and $0.7 million, net of tax of $0.2 million and $0.4 million, respectively, remained in accumulated other comprehensive income related to the valuation of the Company's hedging positions. Total oil purchased and sold under swaps and collars during the three months ended March 31, 2002 and 2003 were zero Bbls and 63,000 Bbls, respectively. Total natural gas purchased and sold under swaps and collars in the three months ended March 31, 2002 and 2003 were zero MMBtu and 540,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were zero and $1.2 million for the three months ended March 31, 2002 and 2003, respectively, and are included in oil and natural gas revenues. At December 31, 2002 and March 31, 2003 the Company had the following outstanding hedge positions: -21-
AS OF DECEMBER 31, 2002 - ------------------------------------------------------------------------------------------------------------- CONTRACT VOLUMES ------------------------------- AVERAGE AVERAGE AVERAGE QUARTER BBls MMbtu FIXED PRICE FLOOR PRICE CEILING PRICE - ------------------- ------------- ------------- ------------- ------------- ------------- First Quarter 2003 27,000 $ 24.85 First Quarter 2003 36,000 $ 23.50 $ 26.50 First Quarter 2003 540,000 3.40 5.25 Second Quarter 2003 27,300 24.85 Second Quarter 2003 36,000 23.50 26.50 Second Quarter 2003 546,000 3.40 5.25 Third Quarter 2003 552,000 3.40 5.25 Fourth Quarter 2003 552,000 3.40 5.25
AS OF MARCH 31, 2003 - ------------------------------------------------------------------------------------------------------------- CONTRACT VOLUMES ------------------------------- AVERAGE AVERAGE AVERAGE QUARTER BBls MMbtu FIXED PRICE FLOOR PRICE CEILING PRICE - ------------------- ------------- ------------- ------------- ------------- ------------- Second Quarter 2003 27,300 $ 24.85 Second Quarter 2003 36,000 $ 23.50 $ 26.50 Second Quarter 2003 273,000 4.70 Second Quarter 2003 546,000 3.40 5.25 Third Quarter 2003 276,000 4.70 Third Quarter 2003 552,000 3.40 5.25 Fourth Quarter 2003 552,000 3.40 5.25
During April 2003, the Company entered into costless collar arrangements covering 642,000 MMBtu of natural gas for April 2004 through October 2004 production with a floor of $4.00 and a ceiling of $5.20. FORWARD LOOKING STATEMENTS The statements contained in all parts of this document, including, but not limited to, those relating to the Company's schedule, targets, estimates or results of future drilling, budgeted wells, increases in wells, budgeted and other future capital expenditures, use of offering proceeds, outcome and effects of litigation, expected production or reserves, increases in reserves, acreage working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, the timing and results of the issuance of new drilling permits for coalbed methane drilling in Montana and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words "anticipate," "estimate," "expect," "may," "project," "believe" and similar expression are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company's dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to, limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather and other factors detailed in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 and other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. -22- ITEM 3A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK For information regarding our exposure to certain market risks, see "Quantitative and Qualitative Disclosures about Market Risk" in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2002 except for the Company's hedging activity subsequent to December 31, 2002 as described above in "Volatility of Oil and Natural Gas Prices". There have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report. For additional information regarding our long-term debt, see Note 3 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q. -23- ITEM 4 - CONTROLS AND PROCEDURES Within the 90 days prior to the date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial and Accounting Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer and the Chief Financial and Accounting Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's periodic filings with the Securities and Exchange Commission. Subsequent to the date of their evaluation, there were no significant changes in the Company's internal controls or in other factors that could significantly affect the internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses. -24- PART II. OTHER INFORMATION Item 1 - Legal Proceedings From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. Item 2 - Changes in Securities and Use of Proceeds None Item 3 - Defaults Upon Senior Securities None Item 4 - Submission of Matters to a Vote of Security Holders None Item 5 - Other Information None. Item 6 - Exhibits and Reports on Form 8-K Exhibits Exhibit Number Description +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of September 6, 1997 (incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915) Amendment No. 2 (incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999) and Amendment No. 3 (Incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated February 20, 2002). +3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated February 20, 2002). 99.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. + Incorporated herein by reference as indicated. Reports on Form 8-K None. -25- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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. Carrizo Oil & Gas, Inc. (Registrant) Date: May 12, 2003 By: /s/ S. P. Johnson, IV -------------------------------------------- President and Chief Executive Officer (Principal Executive Officer) Date: May 12, 2003 By: /s/ Frank A. Wojtek -------------------------------------------- Chief Financial Officer (Principal Financial and Accounting Officer) -26- CERTIFICATIONS Principal Executive Officer I, S.P. Johnson IV, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil & Gas, Inc. 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons fulfilling the equivalent function); a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 12, 2003 /s/ S.P. Johnson, IV ------------------------------------ S.P. Johnson, IV Chief Executive Officer -27- Principal Financial Officer I, Frank A. Wojtek, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil & Gas, Inc. 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons fulfilling the equivalent function); a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 12, 2003 /s/ Frank A. Wojtek ------------------------------------------ Vice President and Chief Financial Officer -28- EXHIBIT INDEX
Exhibit Number Description ------- ----------- +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of September 6, 1997 (incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915) Amendment No. 2 (incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999) and Amendment No. 3 (Incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated February 20, 2002). +3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated February 20, 2002). 99.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
+ Incorporated herein by reference as indicated. EX-99.1 3 h05693exv99w1.txt SECTION 906 CERTIFICATION EXHIBIT 99.1 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE) Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson, IV, Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the "Company"), hereby certify, to my knowledge, that: (1) the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: May 12, 2003 /s/ S.P. Johnson, IV ----------------------------------------- Name: S.P. Johnson, IV Chief Executive Officer The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document. A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request. EX-99.2 4 h05693exv99w2.txt SECTION 906 CERTIFICATION EXHIBIT 99.2 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE) Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Frank A. Wojtek, Chief Financial Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the "Company"), hereby certify, to my knowledge, that: (1) the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: May 12, 2003 /s/ Frank A. Wojtek ----------------------------------------- Name: Frank A. Wojtek Chief Financial Officer The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document. A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----