-----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, Tuo6ZvWSHWH3C08NWZmnkSSh7jsG7EETG6jE7AM9gsvUW1fbuaPQCtFvkOAQxnKL 5xoOODF+EXzVjh0svAvZwg== 0000950129-02-005663.txt : 20021114 0000950129-02-005663.hdr.sgml : 20021114 20021114081136 ACCESSION NUMBER: 0000950129-02-005663 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021114 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: 02821835 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 h01129e10vq.txt CARRIZO OIL & GAS, INC. - DATED 9/30/2002 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended SEPTEMBER 30, 2002 ------------------ [ ] 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 -- -- The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of November 8, 2002, the latest practicable date, was 14,176,716. CARRIZO OIL & GAS, INC. FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002 INDEX
PART I. FINANCIAL INFORMATION PAGE Item 1. Consolidated Balance Sheets - As of December 31, 2001 and September 30, 2002 2 Consolidated Statements of Operations - For the three-month and nine-month periods ended September 30, 2001 and 2002 3 Consolidated Statements of Cash Flows - For the nine-month periods ended September 30, 2001 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 3B. Quantitative and Qualitative Disclosures About Market Risk 22 Item 4. Controls and Procedures 23 PART II. OTHER INFORMATION Items 1-6. 24 SIGNATURES 26
CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (UNAUDITED)
December 31, September 30, ASSETS 2001 2002 ------------- -------------- CURRENT ASSETS: Cash and cash equivalents $ 3,235,712 $ 2,798,297 Accounts receivable, net of allowance for doubtful accounts of $480,000 at December 31, 2001 and September 30, 2002, respectively 8,111,482 8,488,670 Advances to operators 508,563 541,197 Deposits 47,901 173,828 Other current assets 599,882 970,195 ------------- -------------- Total current assets 12,503,540 12,972,187 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and gas properties) 104,132,392 117,779,955 OTHER ASSETS 755,731 878,011 ------------- -------------- $ 117,391,663 $ 131,630,153 ============= ============== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade $ 10,263,176 $ 14,227,747 Accrued liabilities 347,778 973,303 Advances for joint operations 367,942 1,014,380 Current maturities of long-term debt (Note 3) 2,107,030 1,571,483 ------------- -------------- Total current liabilities 13,085,926 17,786,913 LONG-TERM DEBT (Note 3) Notes Payable 30,831,057 30,968,297 Notes Payable, recourse solely to interest in oil and gas leases 5,250,000 4,875,000 ------------- -------------- Total long-term debt 36,081,057 35,843,297 OTHER LIABILITIES -- 842,582 DEFERRED INCOME TAXES 5,020,576 6,353,934 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 62,185.08 convertible participating shares issued and outstanding at September 30, 2002) (Note 6) Issued and outstanding -- 6,044,592 Accrued dividends -- 155,463 SHAREHOLDERS' EQUITY: Warrants (3,010,189 and 3,262,821 outstanding at December 31, 2001 and September 30, 2002, respectively) 765,047 780,047 Common stock, par value $.01 (40,000,000 shares authorized with 14,064,077 and 14,176,716 issued and outstanding at December 31, 2001 and September 30, 2002, respectively) (Note 7) 140,641 141,767 Additional paid in capital 62,735,659 63,222,539 Retained earnings (deficit) (1,143,634) 835,543 Other comprehensive income (loss) 706,391 (376,524) ------------- -------------- 63,204,104 64,603,372 ------------- -------------- $ 117,391,663 $ 131,630,153 ============= ==============
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 For the Nine Months Ended Months Ended September 30, September 30, ---------------------------- ------------------------------ 2001 2002 2001 2002 ---------- ----------- ----------- ----------- OIL AND NATURAL GAS REVENUES $6,161,679 $ 6,752,567 $ 21,981,362 $ 17,559,346 COSTS AND EXPENSES: Oil and natural gas operating expenses 927,893 1,333,761 3,359,025 3,687,022 Depreciation, depletion and amortization 1,672,308 2,726,108 4,987,634 7,331,941 General and administrative 691,146 990,068 2,434,291 3,049,395 Stock option compensation (benefit) (55,942) (14,220) (501,623) (70,475) ---------- ----------- ----------- ----------- Total costs and expenses 3,235,405 5,035,717 10,279,327 13,997,883 ---------- ----------- ----------- ----------- OPERATING INCOME 2,926,274 1,716,850 11,702,035 3,561,463 OTHER INCOME AND EXPENSES: Other income and expenses, net 2,529,231 117,391 2,529,231 244,831 Interest income 57,695 16,345 250,722 44,236 Interest expense (788,269) (589,961) (2,218,395) (2,022,927) Interest expense, related parties (51,646) (57,646) (152,806) (168,880) Capitalized interest 833,042 647,607 2,364,328 2,191,807 ---------- ----------- ----------- ----------- INCOME BEFORE INCOME TAXES 5,506,327 1,850,586 14,475,115 3,850,530 INCOME TAXES (Note 4) 1,960,301 674,313 5,165,550 1,456,163 ---------- ----------- ----------- ----------- NET INCOME $3,546,026 $ 1,176,273 $ 9,309,565 $ 2,394,367 ========== =========== =========== =========== DIVIDENDS AND ACCRETION OF DISCOUNT ON PREFERRED STOCK -- 173,164 -- 415,190 ---------- ----------- ----------- ----------- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $3,546,026 $ 1,003,109 $ 9,309,565 $ 1,979,177 ========== =========== =========== =========== BASIC EARNINGS PER COMMON SHARE (Note 2) $ 0.25 $ 0.07 $ 0.66 $ 0.14 ========== =========== =========== =========== DILUTED EARNINGS PER COMMON SHARE (Note 2) $ 0.22 $ 0.06 $ 0.56 $ 0.12 ========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. -3- CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Nine Months Ended September 30, -------------------------------- 2001 2002 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 9,309,565 $ 2,394,367 Adjustment to reconcile net income to net cash provided by operating activities- Depreciation, depletion and amortization 4,987,634 7,331,941 Discount accretion 64,007 64,261 Income from derivative instruments -- (547,688) Interest payable in kind -- 1,007,879 Stock option compensation (benefit) (501,623) (70,476) Gain on sale of Michael Petroleum Corporation (3,900,723) -- Deferred income taxes 5,066,291 1,333,358 Changes in assets and liabilities- Accounts receivable 1,506,293 1,301,757 Deposits and other current assets (250,434) (496,240) Other assets (52,549) (248,280) Accounts payable, trade 2,790,061 107,459 Other current liabilities 517,630 160,774 ----------- ----------- Net cash provided by operating activities 19,536,152 12,339,112 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures, accrual basis (30,903,306) (20,853,504) Proceeds from sale of Michael Petroleum Corporation 5,444,903 -- Adjustment to cash basis 8,735,333 3,495,756 Advances to operators 436,758 (32,634) Advances for joint operations 17,679 646,438 ----------- ----------- Net cash used in investing activities (16,268,633) (16,743,944) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Cash proceeds from the sale of common stock 14,548 13,000 Net proceeds from the sale of preferred stock -- 5,784,865 Net proceeds from the sale of warrants -- 15,000 Advances under Borrowing Base Credit Facility -- 6,500,000 Debt repayments (4,765,301) (8,345,448) ----------- ----------- Net cash used in financing activities (4,750,753) 3,967,417 ----------- ----------- NET DECREASE IN CASH AND CASH EQUIVALENTS (1,483,234) (437,415) CASH AND CASH EQUIVALENTS, beginning of period 8,217,427 3,235,712 ----------- ----------- CASH AND CASH EQUIVALENTS, end of period $ 6,734,193 $ 2,798,297 =========== =========== SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized) $ 6,873 $ -- =========== ===========
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, 2001, 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, 2001. Certain items in the prior years have been reclassified to be consistent with the current presentation. -5- 2. EARNINGS PER COMMON SHARE: Supplemental earnings per share information is provided below:
For the Three Months Ended September 30, ------------------------------------------------------------------------------- Income Shares Per-Share Amount ------------------------- --------------------------- ----------------- 2001 2002 2001 2002 2001 2002 ----------- ----------- ---------- ---------- -------- ------ Basic Earnings per Common Share: Net Income $ 3,546,026 $ 1,176,273 Less: Dividends and Accretion of Discount on Preferred Shares -- 173,164 ------------ ------------ Net income available to common shareholders $ 3,546,026 $ 1,003,109 14,059,216 14,176,528 $ 0.25 $0.07 =========== =========== ========== ========== ======== ====== Diluted Earnings per Common Share: Net Income $ 3,546,026 $ 1,003,109 14,176,528 Stock Options -- -- 546,952 399,500 Warrants -- -- 1,647,006 1,326,326 ----------- ----------- ---------- ---------- Net Income $ 3,546,026 $ 1,003,109 16,253,174 15,902,354 $ 0.22 $0.06 =========== =========== ========== ========== ======== ======
For the Nine Months Ended September 30, ------------------------------------------------------------------------------- Income Shares Per-Share Amount ------------------------- --------------------------- ----------------- 2001 2002 2001 2002 2001 2002 ----------- ----------- ---------- ---------- -------- ------ Basic Earnings per Common Share: Net Income $ 9,309,565 $ 2,394,367 Less: Dividends and Accretion of Discount on Preferred Shares -- 415,190 ----------- ----------- Net income available to common shareholders $ 9,309,565 $ 1,979,177 14,058,470 14,152,239 $ 0.66 $ 0.14 =========== =========== ========== ========== ======== ====== Diluted Earnings per Common Share: Net Income $ 9,309,565 $ 1,979,177 14,058,470 14,152,239 Stock Options -- -- 650,719 421,554 Warrants -- -- 1,862,898 1,354,537 ----------- ----------- ---------- ---------- Net Income $ 9,309,565 $ 1,979,177 16,572,087 15,928,330 $ 0.56 $ 0.12 =========== =========== ========== ========== ======== ======
Net income per common share has been computed by dividing net income by the weighted average number of shares of common stock outstanding during the periods. The Company had outstanding 161,500 and 393,833 stock options, zero and 252,632 warrants and zero and 1,090,649 convertible preferred shares during the three months ended September 30, 2001 and 2002, 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. The Company also had outstanding 79,500 and 406,833 stock options, zero and 252,632 warrants and zero and 1,090,649 convertible preferred shares during the nine months ended September 30, 2001 and 2002, respectively, which were antidilutive and were not included in the calculation. -6- 3. DEBT: At December 31, 2001 and September 30, 2002, debt consisted of the following:
December 31, September 30, 2001 2002 ------------- ------------- Compass Facility $ 7,166,000 $ -- Hibernia Credit Facility -- 6,500,000 Senior subordinated notes 21,635,252 22,600,179 Senior subordinated notes, related parties 2,403,916 2,511,130 Capital lease obligation 232,919 178,471 Non-recourse note payable to Rocky Mountain Gas, Inc. 6,750,000 5,625,000 ------------ ------------ 38,188,087 37,414,780 Less: current maturities (2,107,030) (1,571,483) ------------ ------------ $ 36,081,057 $ 35,843,297 ============ ============
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 million. It is secured by substantially all of the Company's assets and is guaranteed by all of the Company's subsidiaries. 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 million and the borrowing base as of October 31, 2002 was $13 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 $1,250,000. The quarterly borrowing base reduction effective January 31, 2003 is $1,750,000. In November, 2002, the Company received a commitment from Hibernia National Bank to provide additional availability under the Hibernia Facility in the amount of $2.5 million which is structured as an additional "Tranche B" under the Hibernia Facility. As such, upon completion of the amendment to the credit agreement, the total borrowing base under the Hibernia Facility will be $15.5 million, of which $6.5 million is currently drawn. The Tranche B bears interest at LIBOR plus 3.375%, is secured by certain leases and working interests in oil and natural gas wells and matures 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 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 -7- 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, 2001 and September 30, 2002, amounts outstanding under the Compass Facility totaled $7,166,000 and zero, respectively, with an additional $620,000 and zero, respectively, available for future borrowings. At December 31, 2001 and September 30, 2002, amounts outstanding under the Hibernia Facility totaled zero and $6,500,000, respectively, with an additional zero and $4,250,000, respectively, available for future borrowings. At December 31, 2001, one letter of credit was issued and outstanding under the Compass Facility in the amount of $224,000. At September 30, 2002, one letter of credit was issued and outstanding under the Hibernia Facility in the amount of $224,000. 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 $7,500,000 to Rocky Mountain Gas, Inc. ("RMG") as consideration for certain interests in oil and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $125,000 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 gas leases in Wyoming and Montana. At December 31, 2001 and September 30, 2002, the outstanding principal balance of this note was $6,750,000 and $5,625,000, respectively. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $243,369. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1. In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC) which included certain members of the Board of Directors. Concurrently, the Company also sold $8 million of Common Stock and Warrants to this investor group. The Subordinated Notes were sold at a discount of $688,761, 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, 2001 and September 30, 2002, the outstanding balance of the Subordinated Notes had been increased by $2,552,970 and $3,560,850, respectively, for such interest paid in kind. The Company is subject to certain covenants under the terms under 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). 4. INCOME TAXES: The Company has recorded a provision for deferred income taxes at the rate of 35%, which also approximates its statutory rate. Such provisions were $1,927,215 and $633,378 for the three months ended September 30, 2001 and 2002, respectively and $5,066,291 and $1,333,358 for the nine months ended September 30, 2001 and 2002, 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. In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in N. La Copita Prospect in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the four Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of its lease, remove cloud on title, quiet title to the property, and for conversion, trespass and -8- punitive damages. ExxonMobil seeks unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that the Company acted in good faith and intends to vigorously defend its position. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its drilling and operating costs as a good faith trespasser. A complete loss of the lease in question would result in the loss to the Company of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with respect to these properties were included in the Company's reported proved reserves as of December 31, 2001 and September 30, 2002. At the time of shut in, the Neblett #1 well was producing at the rate of approximately 45 Mcfe per day, the Neblett #2 was producing at the rate of approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day, all net to the Company's interest. The Company believes that an unfavorable outcome in this matter would not have a material impact on its financial statements. The Company has recorded revenues only to the extent of well costs funded by the Company. The Company and the other working interest owners in the Neblett Unit have reached an agreement in principal with ExxonMobil and the landowner, pursuant to which the parties will settle their disputes in this litigation. Drafts of the settlement documents have been circulated for review. Pursuant to the terms of the settlement, the Company will transfer its interest in the Neblett Unit leases to ExxonMobil in return for a payment representing reimbursement of the net, un-recouped costs of drilling, completing, producing and operating the four Neblett wells. In addition, the landowner will reimburse the working interest group (including the Company) the amount of the lease bonus and certain excess royalty payments. There can be no assurance as to a final settlement or the terms thereof until all settlement agreements are approved and executed by all parties. During November 2000, the Company entered into a one-year contract with Grey Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of drilling wells to a depth of approximately 18,000 feet. The contract provided for a dayrate of $12,000 per day. The rig was utilized primarily to drill wells in the Company's focus areas, including the Matagorda Project Area and the Cabeza Creek Project Area. The contract contained a provision which would allow the Company to terminate the contract early by tendering payment equal to one-half the dayrate for the number of days remaining under the term of the contract as of the date of termination. The contract commenced in February 2001 and expired in February 2002. Steven A. Webster, who is the Chairman of the Board of Directors of the Company, is a member of the Board of Directors of Grey Wolf, Inc. During August 2001, the Company entered into a one year agreement, that was extended to March 2003, whereby the lessor will provide to the Company up to $800,000 in financing for production equipment utilizing capital leases. At December 31, 2001 and September 30, 2002, one lease in the amount of $243,369 had been executed under this facility. 6. CONVERTIBLE PARTICIPATING PREFERRED STOCK: In February 2002, the Company consummated the sale of $6 million of Convertible Participating Series B Preferred Stock (the "Series B Preferred Stock") and warrants to purchase Carrizo common stock to an investor group led by Mellon Ventures, Inc. which included Steven A. Webster, the Company's Chairman of the Board of Directors. 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 September 30, 2002, the outstanding balance of the Series B Preferred Stock has been increased by $218,508 (2,185.08 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 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 that were used primarily to fund the Company's ongoing exploration and development program. 7. COMMON STOCK: The Company issued 106,472 shares of common stock during the nine months ended September 30, 2002 at a valuation of $475,006. Of these shares issued, 76,472 were issued as partial consideration for the purchase of an interest in certain oil and gas properties and 30,000 shares were issued as an advance payment towards the purchase of certain interests in coalbed methane properties that closed during July 2002. -9- 8. CHANGE IN ACCOUNTING PRINCIPLE: 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 gas revenues when the forecasted transaction occurs. All of the Company's derivative instruments were designated and effective as cash flow hedges except for its positions with an affiliate of Enron Corp. discussed below. 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 crude 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. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. 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 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. For the nine months ended September 30, 2002, $158,700 was reclassified from other comprehensive income into oil and gas revenues. An allowance for the related asset totaling $759,000, net of tax of $409,000, was charged to other expense during the fourth quarter of 2001. At December 31, 2001 and September 30, 2002, $706,000, net of tax of $380,000, and $159,000 net of tax of $85,000, respectively, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. In March 2002, the Company, in accordance with the provisions of the Enron contracts, formally notified Enron of its default thereunder and terminated all remaining outstanding contracts with Enron. The Company has filed a claim in the amount of approximately $1.2 million in the Enron bankruptcy proceedings. At September 30, 2002, the Company had recorded $535,000 of hedging losses in other comprehensive income, substantially all of which is expected to be reclassified to earnings within the next twelve months. The amount ultimately reclassified to earnings will vary due to changes in the fair values of the derivatives designated as cash flow hedges prior to their settlement. Total oil and natural gas purchased and sold under hedging arrangements during the three months ended September 30, 2001 and 2002 were 18,000 Bbls and 33,600 Bbls, respectively, and 8,220,000 MMBtu and 731,000 MMBtu, respectively. Losses realized by the Company under such hedging arrangements were $1,538,700 and $78,000 for the three months ended September 30, 2001 and 2002, respectively. Total oil and natural gas purchased and sold under hedging arrangements during the nine months ended September 30, 2001 and 2002 were 18,000 Bbls and 79,100 Bbls, respectively, and 2,541,000 MMBtu and 3,094,000 MMBtu, respectively. Losses realized by the Company under such hedging arrangements were $857,638 and $447,000 for the nine months ended September 30, 2001 and 2002, respectively. At September 30, 2001 and 2002, the Company had the following outstanding hedge positions: -10-
September 30, 2001 - ------------------------------------------------------------------------------------------------ Contract Volumes ------------------------ Average Average Average Quarter BBls Mmbtu Fixed Price Floor Price Ceiling Price - ------------------------ ---------- ----------- ----------- ----------- ------------- Fourth Quarter 2001 639,000 $ -- $ 4.44 $ 5.44 First Quarter 2002 270,000 4.25 5.15 First Quarter 2002 540,000 3.20 Second Quarter 2002 546,000 3.20 Third Quarter 2002 552,000 3.20 Fourth Quarter 2002 552,000 3.20
September 30, 2002 - ------------------------------------------------------------------------------------------------ Contract Volumes ------------------------- Average Average Average Quarter BBls Mmbtu Fixed Price Floor Price Ceiling Price - ------------------------ ---------- ----------- ----------- ----------- ------------- Fourth Quarter 2002 52,200 $ 26.04 $ -- $ -- Fourth Quarter 2002 183,000 3.50 4.52 Fourth Quarter 2002 672,000 3.42 First Quarter 2003 27,000 24.85 First Quarter 2003 540,000 3.40 5.25 Second Quarter 2003 27,300 24.85 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
9. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENT: 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 expects to adopt the Statement effective January 1, 2003. The Company is currently assessing the impact of the Standard on it's consolidated financial statements. -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, 2001 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 the Gulf Coast region in 2001 and 12 gross wells through the nine months ended September 30, 2002. The Company has budgeted to drill up to 16 gross wells (6.6 net) in the Gulf Coast region in 2002; 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 2002, depreciation, depletion and amortization, oil and gas operating expenses and production are expected to increase over levels incurred in 2001. 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 has acquired properties with existing production in the past. 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. CCBM agreed to spend up to $5 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. CCBM drilled 31 gross wells (12.0 net) and incurred total drilling costs of $819,000 in 2001 and drilled 82 gross wells (30 net) and incurred total drilling costs of $1.4 million through the nine months ended September 30, 2002. These wells typically take up to 18 months to evaluate and determine whether or not they are successful. CCBM has budgeted to drill 97 gross (33 net) wells in 2002. Through September 30, 2002, CCBM has satisfied $1.4 million of the drilling obligations on behalf of RMG. In order to reduce its exposure to short-term fluctuations in the price of oil and natural gas, and not for speculation purposes, the Company periodically enters into hedging arrangements. The Company's hedging arrangements apply to only a portion of its production and provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, the Company's hedging arrangements limit the benefit to the Company of increases in the price of oil and natural gas. At September 30, 2002, the Company had recorded $535,000 of hedging losses in other comprehensive income, substantially all of which is expected to be reclassified to earnings within the next twelve months. The amount ultimately reclassified to earnings will vary due to changes in the fair values of the derivatives designated as cash flow hedges prior to their settlement. Total oil and natural gas purchased and sold under hedging arrangements during the three months ended September 30, 2001 and 2002 were 18,000 Bbls and 33,600 Bbls, respectively, and 8,220,000 MMBtu and 731,000 MMBtu, respectively. Losses realized by the Company under such hedging arrangements were $1,538,700 and $78,000 for the three months ended September 30, 2001 and 2002, respectively. Total oil and natural gas purchased and sold under hedging arrangements during the nine months ended September 30, 2001 and 2002 were 18,000 Bbls and 79,100 Bbls, respectively, and 2,541,000 MMBtu and 3,094,000 MMBtu, respectively. Losses realized by the Company under such hedging arrangements were $857,638 and $447,000 for the nine months ended September 30, 2001 and 2002, respectively. At September 30, 2001 and 2002, the Company had the following outstanding hedge positions: -12-
September 30, 2001 - ---------------------------------------------------------------------------------------------- Contract Volumes ------------------------ Average Average Average Quarter BBls Mmbtu Fixed Price Floor Price Ceiling Price - -------------------------- ------------ --------- ----------- ----------- ------------- Fourth Quarter 2001 639,000 $ -- $ 4.44 $ 5.44 First Quarter 2002 270,000 4.25 5.15 First Quarter 2002 540,000 3.20 Second Quarter 2002 546,000 3.20 Third Quarter 2002 552,000 3.20 Fourth Quarter 2002 552,000 3.20
September 30, 2002 - ---------------------------------------------------------------------------------------------- Contract Volumes ------------------------ Average Average Average Quarter BBls Mmbtu Fixed Price Floor Price Ceiling Price - -------------------------- ------------ --------- ----------- ----------- ------------- Fourth Quarter 2002 52,200 $ 26.04 $ -- $ -- Fourth Quarter 2002 183,000 3.50 4.52 Fourth Quarter 2002 672,000 3.42 First Quarter 2003 27,000 24.85 First Quarter 2003 540,000 3.40 5.25 Second Quarter 2003 27,300 24.85 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
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. On January 1, 2001, the Company adopted Statement of Financial Standards No. 133. See Note 8 to the Financial Statements. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. 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 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. For the nine months ended September 30, 2002, $548,000 was reclassified from other comprehensive income into oil and gas revenues. An allowance for the related asset totaling $759,000, net of tax of $409,000, was charged to other expense during the fourth quarter of 2001. At December 31, 2001 and September 30, 2002, $706,000, net of tax of $380,000, and $159,000 net of tax of $85,000, respectively, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. In March 2002, the Company, in accordance with the provisions of the Enron contracts, formally notified Enron of its default thereunder and terminated all remaining outstanding contracts with Enron. The Company has filed a claim in the amount of approximately $1.2 million in the Enron bankruptcy proceedings. The Company uses the full-cost method of accounting for its oil and gas properties. Under this method, all acquisition, exploration and development costs, including any general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. The Company records depletion of its full-cost pool using the unit-of-production method. To the extent that such capitalized costs in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations in the form of a "ceiling test write-down". Primarily as a result of depressed oil and natural gas prices, and the resulting downward reserve quantities revisions, the Company recorded a ceiling test write-down of $20.3 million in 1998. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, -13- improvements in pricing subsequent to December 31, 2001 removed the necessity to record a ceiling writedown. Using prices in effect on December 31, 2001 the pretax writedown would have been approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown in future periods. A ceiling test write-down was not required for the three months and nine months ended September 30, 2002 or 2001. Once incurred, a write-down of oil and gas properties is not reversible at a later date. RESULTS OF OPERATIONS Three Months Ended September 30, 2002 Compared to the Three Months Ended September 30, 2001 Production volumes for oil in the third quarter of 2002 increased 159% to 113,000 Bbls from 44,000 Bbls for the same period in 2001. Average oil prices decreased 4% to $23.82 per barrel in the third quarter of 2002 from $24.75 per barrel in the same period in 2001. Production volumes for natural gas during the three months ended September 30, 2002 increased 1% to 1,137,000 Mcf from 1,124,000 Mcf for the same period in 2001. Average natural gas prices decreased 21% to $3.57 per Mcf in the third quarter of 2002 from $4.52 per Mcf in the same period in 2001. As a result of higher production, partially offset by lower prices, oil and natural gas revenues for the three months ended September 30, 2002 increased 10% to $6,753,000 from $6,162,000 for the same period in 2001. The increase in oil production was due primarily to new production from the Staubach #1, Burkhart #1R, and Delta Farms #1 wells, offset by the natural decline in production of other older wells, primarily at initial Matagorda County Project wells and the Riverdale #2 well. The increase in natural gas production was due primarily to new production at the Staubach #1, Burkhart #1R, Delta Farms #1 and Riverdale #3 wells, offset by the natural decline in production of other older 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 September 30, 2001 and 2002:
2002 Period Compared to 2001 Period September 30, ---------------------------- ---------------------------- Increase % Increase 2001 2002 (Decrease) (Decrease) ----------- ----------- ----------- ---------- Production volumes - Oil and condensate (Bbls) 43,619 112,943 69,324 159% Natural gas (Mcf) 1,123,724 1,136,710 12,986 1% Average sales prices - (1) Oil and condensate (per Bbls) $ 24.75 $ 23.82 $ (0.93) (4%) Natural gas (per Mcf) 4.52 3.57 (0.95) (21%) Operating revenues - Oil and condensate $ 1,079,384 $ 2,690,659 $ 1,611,275 149% Natural gas 5,082,295 4,061,908 (1,020,387) (20%) ----------- ----------- ----------- Total operating revenues $ 6,161,679 $ 6,752,567 $ 590,888 10% =========== =========== ===========
- ------------------ (1) Includes impact of hedging activities. Oil and natural gas operating expenses for the three months ended September 30, 2002 increased 44% to $1,334,000 from $928,000 for the same period in 2001 primarily due to increased severance taxes and the addition of more wells, offset by a reduction in costs on older producing fields. Operating expenses per equivalent unit increased to $.74 per Mcfe in the third quarter of 2002 from $.67 per Mcfe in the same period in 2001 primarily as a result of higher severance taxes, partially offset by increased production of oil and natural gas on new, high rate, lower cost per unit wells. Depreciation, depletion and amortization (DD&A) expense for the three months ended September 30, 2002 increased 63% to $2,726,000 from $1,672,000 for the same period in 2001. This increase was due to increased production and the addition of costs to the proved property cost pool. General and administrative expense for the three months ended September 30, 2002 increased 43% to $990,000 from $691,000 for the same period in 2001 primarily as a result of the addition of staff to handle increased drilling and production activities. -14- Other income and expenses for the three months ended September 30, 2001 includes a gain on the sale of the investment in Michael Petroleum Corporation of $3.9 million offset by a charge and related legal expenses in respect of the final settlement of the litigation with BNP Petroleum Corporation. Income taxes decreased to $674,000 for the three months ended September 30, 2002 from $2.0 million for the same period in 2001. Interest income for the three months ended September 30, 2002 decreased to $16,000 from $58,000 in the third quarter of 2001 primarily as a result of lower interest rates during 2002. Capitalized interest decreased to $648,000 in the third quarter of 2002 from $833,000 in the third quarter of 2001 primarily due to lower interest rates that resulted in lower interest costs during the third quarter of 2002. Income before income taxes for the three months ended September 30, 2002 decreased to $1.9 million from $5.5 million in the same period in 2001. Net income for the three months ended September 30, 2002 decreased to $1.1 million from $3.5 million for the same period in 2001 primarily as a result of the factors described above. Nine Months Ended September 30, 2002, Compared to the Nine Months Ended September 30, 2001 Production volumes for oil in the first nine months of 2002 increased 98% to 261,031 Bbls from 131,593 Bbls for the same period in 2001. Average oil prices decreased 9% to $23.34 per barrel in the first nine months of 2002 from $25.77 per barrel in the same period in 2001. Production volumes for natural gas during the nine months ended September 30, 2002 increased 3% to 3,543,000 Mcf from 3,436,000 Mcf for the same period in 2001. Average natural gas prices decreased 40% to $3.24 per Mcf in the first nine months of 2002 from $5.41 per Mcf in the same period in 2001. Primarily as a result of such lower prices, oil and natural gas revenues for the nine months ended September 30, 2002 decreased 20% to $17,559,000 from $21,981,000 for the same period in 2001. The increase in oil production was due primarily to the commencement of production at the Delta Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset by the natural decline in production of other older wells. The increase in natural gas production was due primarily to the commencement of production at the Delta Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset by the natural decline in production at other wells, primarily from the initial Matagorda County Project 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 nine months ended September 30, 2001 and 2002:
2002 Period Compared to 2001 Period September 30, ---------------------------- ---------------------------- Increase % Increase 2001 2002 (Decrease) (Decrease) ----------- ----------- ----------- ---------- Production volumes - Oil and condensate (Bbls) 131,593 261,031 129,438 98% Natural gas (Mcf) 3,435,995 3,542,915 106,920 3% Average sales prices - (1) Oil and condensate (per Bbls) $ 25.77 $ 23.34 $ (2.43) (9%) Natural gas (per Mcf) 5.41 3.24 (2.17) (40%) Operating revenues - Oil and condensate $ 3,391,277 $ 6,091,506 $ 2,700,229 80% Natural gas 18,590,085 11,467,840 (7,122,245) (38%) ----------- ----------- ----------- Total operating revenues $21,981,362 $17,559,346 $(4,422,016) (20%) =========== =========== ===========
- ------------------ (2) Includes impact of hedging activities. Oil and natural gas operating expenses for the nine months ended September 30, 2002 increased 10% to $3,687,000 from $3,359,000 for the same period in 2001 primarily due to the addition of more wells and increased ad valorem taxes. Operating expenses per equivalent unit decreased to $.72 per Mcfe in the first nine months of 2002 from $.80 per Mcfe in the same period in 2001 primarily as a result of the addition of higher rate, lower cost per unit wells, offset by higher ad valorem taxes and decreased production of natural gas as older wells naturally decline. -15- Depreciation, depletion and amortization (DD&A) expense for the nine months ended September 30, 2002 increased 47% to $7.3 million from $5.0 million for the same period in 2001. This increase was due to increased production and additional seismic and drilling costs. General and administrative expense for the nine months ended September 30, 2002 increased 25% to $3.0 million from $2.4 million for the same period in 2001 primarily as a result of the addition of staff to handle increased drilling and production activities. Other income and expenses for the nine months ended September 30, 2001 includes a gain on the sale of the investment in Michael Petroleum Corporation of $3.9 million offset by a charge and related legal expenses in respect of the final settlement of the litigation with BNP Petroleum Corporation. Income taxes decreased to $1.5 million for the nine months ended September 30, 2002 from $5.2 million for the same period in 2001. Interest income for the nine months ended September 30, 2002 decreased to $44,000 from $251,000 in the first nine months of 2001 primarily as a result of lower interest rates during 2002. Capitalized interest decreased to $2.1 million in the first nine months of 2002 from $2.4 million in the first nine months of 2001 primarily due to lower interest costs during the first nine months of 2002. Income before income taxes for the nine months ended September 30, 2002 decreased to $3.9 million from $14.5 million in the same period in 2001. Net income for the nine months ended September 30, 2002 decreased to $2.4 million from $9.3 million for the same period in 2001 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 flow from operations 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 active exploration projects. While the Company believes that the current cash balances and anticipated operating cash flow will provide sufficient capital to carry out the Company's near term 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 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 funds generated by operations, equity capital contributions, proceeds from the 1997 initial public offering, the 1998 sale of shares of Series A Preferred Stock and Warrants, 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, borrowings (primarily under revolving credit facilities) and the sale of promoted interests under the Palace Agreement and to other industry partners that have 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 operations (after changes in working capital) were $19.5 million and $12.3 million for the nine months ended September 30, 2001 and 2002, respectively. The decrease in cash flows provided by operations in 2002 as compared to 2001 was due primarily to higher prevailing oil and natural gas prices during the first nine months of 2001 and the timing of accounts payable. The Company has budgeted capital expenditures for the year ended December 31, 2002 of approximately $31.0 million of which $5.8 million is expected to be used to fund 3-D seismic data acquisition and land acquisitions and $21.2 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 16 gross wells (6.6 net) in the Gulf Coast region and up to 69 gross (27 net) CCBM coalbed methane wells in 2002. As of September 30, 2002 the Company had drilled 12 gross wells (4.9 net) in the Gulf Coast region and 58 gross wells (22 net) CCBM coalbed methane wells. 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 $20.8 million for the nine months ended September 30, 2002, which included $2.9 million of capitalized interest and general and administrative costs. During the third quarter of 2002, the Company incurred net capital expenditures of $2.4 million for seismic data and -16- increased its 3-D seismic data library from approximately 2,800 to 4,800 square miles. The Company recorded a current liability of approximately $2.2 million and a non-current liability of approximately $800,000 related to third quarter 2002 acquisitions. The Company's drilling efforts in the Gulf Coast region resulted in the successful completion of 20 gross wells (5.9 net) during the year ended December 31, 2001 and the successful completion of 10 gross wells (3.8 net) drilled during the nine months ended September 30, 2002. Of the 82 gross wells (30 net) drilled by CCBM, 24 gross wells (8 net) are currently producing and 59 gross wells (22 net) are awaiting evaluation before a determination can be made as to their success. 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 million. It is secured by substantially all of the Company's assets and is guaranteed by all of the Company's subsidiaries. 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 million and the borrowing base as of October 31, 2002 was $13 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, 2003, was $1,250,000. The quarterly borrowing base reduction effective January 31, 2003 is $1,750,000. In November, 2002, the Company received a commitment from Hibernia National Bank to provide additional availability under the Hibernia Facility in the amount of $2.5 million which is structured as an additional "Tranche B" under the Hibernia Facility. As such, upon completion of the amendment to the credit agreement, the total borrowing base under the Hibernia Facility will be $15.5 million, of which $6.5 million is currently drawn. The Tranche B bears interest at LIBOR plus 3.375%, is secured by certain leases and working interests in oil and natural gas wells and matures 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 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, 2001 and September 30, 2002, amounts outstanding under the Compass Facility totaled $7,166,000 and zero, respectively, with an additional $620,000 and zero, respectively, available for future borrowings. At December 31, 2001 and September 30, 2002, amounts outstanding under the Hibernia Facility totaled zero and $6,500,000, respectively, with an additional zero and $4,250,000, respectively, available for future borrowings. At December 31, 2001, one letter of credit was issued and outstanding under the Compass Facility in the amount of $224,000. At September 30, 2002, one letter of credit was issued and outstanding under the Hibernia Facility in the amount of $224,000. -17- 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 $7,500,000 to RMG as consideration for certain interest in oil and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $125,000 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 gas leases in Wyoming and Montana. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $243,369. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1. In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. (now JPMorgan Partners, LLC) which included certain members of the Board of Directors. The Subordinated Notes were sold at a discount of $688,761 which is being amortized over the life of the notes. Interest is payable quarterly beginning March 31, 2000. The Company may elect, for a period of five years, to increase the amount of the Subordinated Notes for up to 60% of the interest which would otherwise be payable in cash. The Subordinated Notes were increased by $2,552,970 and $3,220,375 for such interest as of December 31, 2001 and September 30, 2002, respectively. Concurrent with the sale of the notes, the Company consummated the sale of 3,636,364 shares of Common Stock at a price of $2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at an exercise price of $2.20 per share. For accounting purposes, the Warrants are valued at $0.25 per Warrant. The Warrants have an exercise price of $2.20 per share and expire in December 2007. The Company is subject to certain covenants under the terms under the related 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) limit 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 (vi) make certain repayments and prepayments, including any prepayment of the Company's Term Loan, any 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. Of the approximately $29.0 million net proceeds of this financing, $12.1 million was used to fund the repurchase from certain Enron Corp. affiliates of all the outstanding shares of Series A Preferred Stock and 750,000 Warrants and related expenses, $2.0 million was used to repay the bridge loan extended to the Company by its outside directors, $2.0 million was used to repay a portion of the Compass Term Loan, $1.0 million was used to repay a portion of the Compass Borrowing Base Facility, and the remaining proceeds were used to fund the Company's ongoing exploration and development program and general corporate purposes. 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 to an investor group led by Mellon Ventures, L.P. which included Steven A. Webster, the Company's Chairman of the Board of Directors. 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 net proceeds of this financing were approximately $5.8 million and 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 September 30, 2002 the outstanding balance of the Series B Preferred Stock had been increased by $128,508 (2,185.08 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. -18- 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 a 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 are valued at $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. CRITICAL ACCOUNTING POLICIES 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 gas properties. Additionally, the Company capitalized compensation costs for employees working directly on exploration activities of $763,475 and $703,180, respectively, for the nine months ended September 30, 2001 and 2002. 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 impairment occurs. 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 nine months ended September 30, 2001 and 2002, was $1.18 and $1.44, respectively. Dispositions of oil and 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 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 and six months ended June 30, 2001 and 2002. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and 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 ceiling writedown. Using prices in effect on December 31, 2001 the pretax writedown would -19- have been approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown 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. Stock-Based Compensation The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations. Under this method, the Company records no compensation expense for stock options granted when the exercise price of those options is equal to or greater than the market price of the Company's common stock on the date of grant. Repriced options are accounted for as compensatory options using variable accounting treatment. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock. Variable plan accounting is applied to the repriced options until the options are exercised, forfeited, or expired unexercised. 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 gas revenues when the forecasted transaction occurs. All of the Company's derivative instruments at January 1, 2001, December 31, 2001 and September 30, 2002 were designated and effective as cash flow hedges except for its positions with an affiliate of Enron Corp. as discussed in Note 8 to the Consolidated Financial Statements. All of the Enron positions were terminated by the Company in March 2002 pursuant to the terms of the contracts. 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 crude 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. -20- 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. Significant estimates include depreciation, depletion and amortization of proved oil and natural gas properties and future income taxes. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, are inherently imprecise and are expected to change as future information becomes available. Concentration of Credit Risk Substantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables. 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, recovery of well costs in 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, 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, 2001 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. 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, 2001. 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. 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. -21- 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. In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in N. La Copita in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the four Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of its lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seeks unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that the Company acted in good faith and intends to vigorously defend its position. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its drilling and operating costs as a good faith trespasser. A complete loss of the lease in question would result in the loss to the Company of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or ..9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with respect to these properties were included in the Company's reported proved reserves as of December 31, 2001 and June 30, 2002. At the time of shut in, the Neblett #1 well was producing at a rate of approximately 45 Mcfe per day, the Neblett #2 well was producing at the rate of approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day, all net to the Company's interest. The Company believes that an unfavorable outcome in this matter would not have a material impact on its financial statements. The Company has recorded revenues only to the extent of well costs funded by the Company. The Company and the other working interest owners in the Neblett Unit have reached an agreement in principal with ExxonMobil and the landowner, pursuant to which the parties will settle their disputes in this litigation. Drafts of the settlement documents have been circulated for review. Pursuant to the terms of the settlement, the Company will transfer its interest in the Neblett Unit leases to ExxonMobil in return for a payment representing reimbursement of the net, un-recouped costs of drilling, completing, producing and operating the four Neblett wells. In addition, the landowner will reimburse the working interest group (including the Company) the amount of the lease bonus and certain excess royalty payments. There can be no assurance as to a final settlement or the terms thereof until all settlement agreements are approved and executed by all parties. 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 At the Annual Meeting of Carrizo Oil & Gas, Inc. held on May 22, 2002, there were represented by person or by proxy 7,635,211 shares out of 14,140,549 entitled to vote as of the record date, constituting a quorum. The matters submitted to a vote of shareholders were (i) the reelection of Steven A. Webster, Christopher C. Behrens, Bryan R. Martin, Douglas A.P. Hamilton, Paul B. Loyd, Jr., F. Gardner Parker, S.P. Johnson IV and Frank A. Wojtek as directors, (ii) the approval of the amendment to the incentive plan increasing the number of shares of common stock available for issuance and (iii) the approval of the appointment of Ernst & Young, LLP as Independent Public Accountants for the fiscal year ended December 31, 2002. With respect to the election of directors, the following number of votes were cast for the nominees: 7,611,358 for Mr. Webster and 23,844 withheld; 7,611,358 for Mr. Behrens and 23,844 withheld; 7,601,258 for Mr. Martin and 33,944 withheld; 7,611,358 for Mr. Hamilton and 23,844 withheld; 7,611,358 for Mr. Loyd and 23,844 withheld; 7,611,217 for Mr. Parker and 23,985 withheld; 7,611,358 for Mr. Johnson and 23,844 withheld; and 7,611,358 for Mr. Wojtek and 23,844 withheld. There were no abstentions in the election of directors. With respect to the amendment to the incentive plan, 7,307,865 votes were cast for the amendment, 238,781 votes were against and 88,565 were abstained. With respect to the appointment of Ernst & Young, LLP as Independent Public Accountants, 7,617,492 votes were cast for the appointment, 14,033 votes were against, and 14,033 votes abstained. Item 5 - Other Information -22- 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). +3.4 -- Credit Agreement dated as of May 24, 2002 by and between Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia National Bank. +3.5 -- Revolving Note by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May 24, 2002. +3.6 -- Commercial Guarantee by and between CCBM, Inc. and Hibernia National Bank dated May 24, 2002. +3.7 - Stock Pledge and Security Agreement by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May 24, 2002. +3.8 - First Amendment to Credit Agreement dated July 9, 2002 to the Credit Agreement by and between Carrizo Oil & Gas, Inc. and Hibernia National Bank dated May 24, 2002. +10.1 - Amendment No. 1 to the Amended and Restated Incentive Plan of the Company. +10.2 - Employment Agreement between the Company and Jeremy T. Greene.
+ Incorporated herein by reference as indicated. Reports on Form 8-K In a Current Report on Form 8-K filed with the SEC on August 14, 2002, we (i) reported pursuant to Item 9 on Form 8-K that we had filed executive sworn statements pursuant to SEC Order N. 4-460 and executive certifications required pursuant to Section 906 of the Sarbannes-Oxley Act of 2002 and (ii) filed the related executive sworn statements and certifications pursuant to Item 7 of Form 8-K. -23- 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: November 14, 2002 By: /s/ S. P. Johnson, IV -------------------------------------------- President and Chief Executive Officer (Principal Executive Officer) Date: November 14, 2002 By: /s/ Frank A. Wojtek -------------------------------------------- Chief Financial Officer (Principal Financial and Accounting Officer) -24- 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: November 14, 2002 /s/ S.P. Johnson ---------------------------- S.P. Johnson Chief Executive Officer Principal Financial Officer I, Frank A. Wojtek, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Edge Petroleum Corporation. 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: November 14, 2002 /s/ Frank A. Wojtek ------------------------------- Senior Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----