-----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, CZkqiHMfw3lgN27iQXr4LtrXty5Vzqvm14Sk2l1hiVK/G5tdimXOur8Qr1AC9Tgx VgfincCfFH0orN0f0cp0yQ== 0001040593-04-000099.txt : 20040816 0001040593-04-000099.hdr.sgml : 20040816 20040816125138 ACCESSION NUMBER: 0001040593-04-000099 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20040630 FILED AS OF DATE: 20040816 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: 04977318 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 q063004.txt SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2004 ------------- [ ] 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 incorporation or organization) Identification No.) 14701 St. Mary's Lane, Suite 800, Houston, TX 77079 - --------------------------------------------- ----- (Address of principal executive offices) (Zip Code) (281) 496-1352 (Registrant's telephone number) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [X] The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of August 6, 2004, the latest practicable date, was 21,900,927. CARRIZO OIL & GAS, INC. FORM 10-Q FOR THE QUARTERLY PERIOD ENDED June 30, 2004 INDEX
PART I. FINANCIAL INFORMATION PAGE Item 1. Consolidated Balance Sheets - As of December 31, 2003 and June 30, 2004 2 Consolidated Statements of Income - For the three and six month periods ended June 30, 2003 and 2004 3 Consolidated Statements of Cash Flows - For the six-month periods ended June 30, 2003 and 2004 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 14 Item 3. Quantitative and Qualitative Disclosure About Market Risk 27 Item 4. Controls and Procedures 28 PART II. OTHER INFORMATION Items 1-6. 29 SIGNATURES 32
CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS December 31, June 30, ------------ ------------ 2003 2004 ------------ ------------ (In thousands) CURRENT ASSETS: Cash and cash equivalents $ 3,322 $ 2,999 Accounts receivable, trade (net of allowance for doubtful accounts of none at December 31, 2003 and June 30, 2004, respectively) 8,970 8,270 Advances to operators 1,877 3,776 Deposits 56 156 Other current assets 100 277 ------------ ------------ Total current assets 14,325 15,478 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and natural gas properties) 135,273 168,135 Investment in Pinnacle Gas Resources, Inc. 6,637 6,028 Deferred financing costs 479 963 Other assets 89 64 ------------ ------------ $ 156,803 $ 190,668 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade $ 19,515 $ 17,103 Accrued liabilities 1,057 4,379 Advances for joint operations 3,430 4,429 Current maturities of long-term debt 1,037 433 Current maturities of seismic obligation payable 1,103 - ------------ ------------ Total current liabilities 26,142 26,344 LONG-TERM DEBT 34,113 36,851 ASSET RETIREMENT OBLIGATION 883 998 DEFERRED INCOME TAXES 12,479 15,131 COMMITMENTS AND CONTINGENCIES (Note 7) CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares of preferred stock authorized, of which 150,000 are shares designated as convertible participating shares, with 71,987 and zero convertible participating shares issued and outstanding at December 31, 2003 and June 30, 2004, respectively) (Note 8) 7,114 - SHAREHOLDERS' EQUITY: Warrants (3,262,821 and 334,210 outstanding at December 31, 2003 and June 30, 2004, respectively) 780 80 Common stock, par value $.01 (40,000,000 shares authorized with 14,591,348 and 21,897,297 issued and outstanding at December 31, 2003 and June 30, 2004, respectively) 146 219 Additional paid in capital 65,103 97,359 Retained earnings 10,229 14,200 Accumulated other comprehensive income (186) (514) ------------ ------------ 76,072 111,344 ------------ ------------ $ 156,803 $ 190,668 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. 2 CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
For the Three For the Six Months Ended Months Ended June 30, June 30, ----------------------- ----------------------- 2003 2004 2003 2004 ---------- ---------- ---------- ---------- (In thousands except per share amounts) OIL AND NATURAL GAS REVENUES $ 8,828 $ 11,959 $ 19,492 $ 22,833 COSTS AND EXPENSES: Oil and natural gas operating expenses (exclusive of depreciation shown separately below) 1,763 2,046 3,483 3,723 Depreciation, depletion and amortization 2,605 3,607 5,641 6,853 General and administrative 1,267 1,647 2,650 3,779 Accretion expense related to asset retirement obligations 10 6 18 13 Stock option compensation 33 746 23 756 ---------- ---------- ---------- ---------- Total costs and expenses 5,678 8,052 11,815 15,124 ---------- ---------- ---------- ---------- OPERATING INCOME 3,150 3,907 7,677 7,709 OTHER INCOME AND EXPENSES: Other income and expenses (82) (348) 18 (583) Interest income 22 10 40 23 Interest expense (118) (235) (316) (330) Interest expense, related parties (591) (464) (1,174) (1,079) Capitalized interest 704 656 1,479 1,323 ---------- ---------- ---------- ---------- INCOME BEFORE INCOME TAXES 3,085 3,526 7,724 7,063 INCOME TAXES (Note 6) 1,125 1,388 2,794 2,742 ---------- ---------- ---------- ---------- NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 1,960 2,138 4,930 4321 DIVIDENDS AND ACCRETION ON PREFERRED STOCK 181 153 362 350 ---------- ---------- ---------- ---------- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 1,779 1,985 4,568 3,971 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE - - 128 - ---------- ---------- ---------- ---------- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 1,779 $ 1,985 $ 4,440 $ 3,971 ========== ========== ========== ========== BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.13 $ 0.10 $ 0.32 $ 0.22 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES - - (0.01) - ---------- ---------- ---------- ---------- BASIC EARNINGS PER COMMON SHARE $ 0.13 $ 0.10 $ 0.31 $ 0.22 ========== ========== ========== ========== DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.11 $ 0.10 $ 0.28 $ 0.21 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES - - (0.01) - ---------- ---------- ---------- ---------- DILUTED EARNINGS PER COMMON SHARE $ 0.11 $ 0.10 $ 0.27 $ 0.21 ========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 3 CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
For the Six Months Ended June 30, ----------------------------- 2003 2004 ------------ ------------ (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income before cumulative effect of change in accounting principle $ 4,930 $ 4,321 Adjustment to reconcile net income to net cash provided by operating activities- Depreciation, depletion and amortization 5,641 6,853 Discount accretion 60 134 Ineffective derivative instruments (91) - Interest payable in kind 704 743 Stock option compensation (benefit) 23 756 Equity in loss of Pinnacle Gas Resources, Inc. - 609 Deferred income taxes 2,704 2,652 Changes in assets and liabilities- Accounts receivable (350) 700 Other assets 336 (662) Accounts payable 776 (275) Other liabilities 324 1,503 ------------ ------------ Net cash provided by operating activities 15,057 17,334 ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (13,984) (39,888) Change in capital expenditure accrual 2,329 (1,611) Advances to operators (185) (1,899) Advances for joint operations 123 999 ------------ ------------ Net cash used in investing activities (11,717) (42,399) ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from the sale of common stock 115 24,198 Advances under the Borrowing Base Facility - 9,000 Debt repayments (4,138) (8,456) ------------ ------------ Net cash provided by (used in) financing activities (4,023) 24,742 ------------ ------------ NET DECREASE IN CASH AND CASH EQUIVALENTS (683) (323) CASH AND CASH EQUIVALENTS, beginning of period 4,743 3,322 ------------ ------------ CASH AND CASH EQUIVALENTS, end of period $ 4,060 $ 2,999 ============ ============ SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized) $ - $ 86 ============ ============ Cash paid for income taxes $ - $ - ============ ============
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. 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, 2003. 2. MAJOR CUSTOMERS The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:
For the Three Months For the Six Months Ended June 30, Ended June 30, -------------------- -------------------- 2003 2004 2003 2004 --------- --------- --------- --------- Cokinos Natural Gas Company 11% 23% 14% 24% Gulfmark Energy, Inc. 15% - 19% - WMJ Investments Corp. 12% 12% - 15% Texon L.P. - 19% - 19%
3. EARNINGS PER COMMON SHARE: Supplemental earnings per share information is provided below:
For the Three Months Ended June 30, --------------------------------------------------------------------------- (In thousands except share and per share amounts) Income Shares Per-Share Amount ----------------------- ----------------------- ----------------------- 2003 2004 2003 2004 2003 2004 ---------- ---------- ---------- ---------- ---------- ---------- Basic Earnings per Common Share Net income available to common shareholders $ 1,779 $ 1,985 14,211,173 19,213,010 $ 0.13 $ 0.10 ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions - - 2,384,642 1,080,091 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions before cumulative effect of change in accounting principle $ 1,779 $ 1,985 16,595,815 20,293,101 $ 0.11 $ 0.10 ========== ========== ========== ========== ========== ==========
5
For the Six Months Ended June 30, --------------------------------------------------------------------------- (In thousands except share and per share amounts) Income Shares Per-Share Amount ----------------------- ----------------------- ----------------------- 2003 2004 2003 2004 2003 2004 ---------- ---------- ---------- ---------- ---------- ---------- Basic Earnings per Common Share Net income available to common shareholders before cumulative effect of change in accounting principle $ 4,568 $ 3,971 14,204,690 17,913,220 $ 0.32 $ 0.22 ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions - - 2,260,300 1,001,630 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions before cumulative effect of change in accounting principle $ 4,568 $ 3,971 16,464,990 18,914,850 $ 0.28 $ 0.21 ========== ========== ========== ========== ========== ==========
For the Three Six Ended June 30, --------------------------------------------------------------------------- (In thousands except share and per share amounts) Income Shares Per-Share Amount ----------------------- ----------------------- ----------------------- 2003 2004 2003 2004 2003 2004 ---------- ---------- ---------- ---------- ---------- ---------- Cumulative effect of change in accounting principle net of income taxes Basic Earnings per Common Share Net loss available to common shareholders $ (128) $ - 14,204,690 17,913,220 $ (0.01) $ - ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions - - 2,260,300 1,001,630 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions $ (128) $ - 16,464,990 18,914,850 $ (0.01) $ - ========== ========== ========== ========== ========== ==========
For the Six Months Ended June 30, --------------------------------------------------------------------------- (In thousands except share and per share amounts) Income Shares Per-Share Amount ----------------------- ----------------------- ----------------------- 2003 2004 2003 2004 2003 2004 ---------- ---------- ---------- ---------- ---------- ---------- Basic Earnings per Common Share Net income available to common shareholders $ 4,440 $ 3,971 14,204,690 17,913,220 $ 0.31 $ 0.22 ========== ========== Dilutive effect of Stock Options, Warrants and Preferred Stock conversions - - 2,260,300 1,001,630 ---------- ---------- ---------- ---------- Diluted Earnings per Share Net income available to common shareholders plus assumed conversions $ 4,440 $ 3,971 16,464,990 18,914,850 $ 0.27 $ 0.21 ========== ========== ========== ========== ========== ==========
Basic earnings per common share is based on the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential common shares outstanding during the periods. The Company had outstanding 146,500 and 35,500 stock options and 252,632 and zero warrants, respectively, during the three months ended June 30, 2003 and 2004, 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 had outstanding 156,500 and 50,500 stock options and 252,632 and zero warrants during the six months ended June 30, 2003 and 2004, respectively, which were antidilutive because the exercise price of these instruments exceeded the underlying market value of the options and warrants. At June 30, 2003 and 2004, the Company also had 1,202,791 and zero shares, respectively, based on the assumed conversion of the Series B Convertible Participating Preferred Stock, that were antidilutive and were not included in the calculation. 6 4. LONG-TERM DEBT: At December 31, 2003 and June 30, 2004, long-term debt consisted of the following:
December 31, June 30, 2003 2004 ------------ ------------ Hibernia Facility $ 7,000 $ 9,000 Senior subordinated notes - 27,778 Senior subordinated notes, related parties 26,992 - Capital lease obligations 295 206 Non-recourse note payable to Rocky Mountain Gas, Inc. 863 300 ------------ ------------ 35,150 37,284 Less: current maturities (1,037) (433) ------------ ------------ $ 34,113 $ 36,851 ============ ============
On May 24, 2002, the Company entered into a credit agreement with Hibernia National Bank (the "Hibernia Facility") which matures on January 31, 2006, and repaid its existing facility with Compass Bank (the "Compass Facility"). The Hibernia Facility provides a revolving line of credit of up to $30.0 million. It is secured by substantially all of the Company's assets and is guaranteed by the Company's subsidiary. The borrowing base will be determined by Hibernia National Bank at least semi-annually on each October 31 and April 30. The initial borrowing base was $12.0 million. Each party to the credit agreement can request one unscheduled borrowing base determination subsequent to each scheduled determination. The borrowing base will at all times equal the borrowing base most recently determined by Hibernia National Bank, less quarterly borrowing base reductions required subsequent to such determination. Hibernia National Bank will reset the borrowing base amount at each scheduled and each unscheduled borrowing base determination date. The initial quarterly borrowing base reduction, which commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base reduction effective July 31, 2004 was $2.5 million. On December 12, 2002, the Company entered into an Amended and Restated Credit Agreement with Hibernia National Bank that provided additional availability under the Hibernia Facility in the amount of $2.5 million which is structured as an additional "Facility B" under the Hibernia Facility. The Facility B bore interest at LIBOR plus 3.375%, was secured by certain leases and working interests in oil and natural gas wells and matured on April 30, 2003. As such, the total borrowing base under the Hibernia Facility as of December 31, 2003 and June 30, 2004 was $19.0 million and $26.0 million, respectively, of which $7.0 and $9.0 million, respectively, was drawn on the Hibernia Facility. 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 7 minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million, plus 100% of all subsequent common and preferred equity contributed by shareholders, plus 50% of all positive earnings 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, 2003 and June 30, 2004, amounts outstanding under the Hibernia Facility totaled $7.0 million and $9.0 million, respectively, with an additional $12.0 million and $17.0 million, respectively, available for future borrowings. At December 31, 2003 and June 30, 2004, one letter of credit was issued and outstanding under the Hibernia Facility in the amount of $0.2 million. On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7.5 million to RMG as consideration for certain interests in oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. In connection with the Company's investment in Pinnacle Gas Resources, Inc., the Company received a reduction in the principal amount of the RMG note of approximately $1.5 million and relinquished the right to certain revenues related to the properties contributed to Pinnacle. During the second quarter of 2004, CCBM, Inc., relinquished a portion of its interests in certain oil and natural gas leases and reduced the principal due on the note by $0.3 million. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.2 million. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. In October 2002, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,462 including interest at 6.4% per annum. In May 2003, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,030 including interest at 5.5% per annum. In August 2003, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $2,179 including interest at 6.0% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1 under all of these leases. DD&A on the capital leases for the three months ended June 30, 2003 and 2004 amounted to $11,000 and $12,000, respectively. DD&A on the capital leases for the six months ended June 30, 2003 and 2004 amounted to $20,000 and $24,000, respectively, and accumulated DD&A on the leased equipment at December 31, 2003 and June 30, 2004 amounted to $76,000 and $100,000, respectively. In December 1999, the Company consummated the sale of $22.0 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and $8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners (23A SBIC), L.P.), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest payments are due quarterly commencing on March 31, 2000. The Company may elect, until December 2004, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2003 and June 30, 2004, the outstanding balance of the Subordinated Notes had been increased by $5.3 million and $6.0 million respectively, for such interest paid in kind. During the six months ended June 30, 2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and Douglas A. P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006 and 92,006 shares of common stock, respectively, on a cashless exercise basis for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock, respectively, and Paul B. Loyd, Jr., exercised warrants to purchase 92,006 shares for a total of 92,006 shares of common stock. As a result, no warrants to purchase shares remain outstanding from the warrants originally issued in December 1999. On June 7, 2004, an unaffiliated third party (the "Purchaser") purchased all the outstanding Subordinated Notes from the original note holders. In exchange for a $0.4 million amendment fee, certain terms and conditions of the Subordinated Notes were amended, to provide for, among other things, (1) a one year extension of the maturity to December 15, 2008, (2) a one year extension, through December 15, 2005, of the paid-in-kind ("PIK") interest option to pay-in-kind 60% of the interest due each period by increasing the principal balance by a like amount (the "PIK option"), (3) an additional one year option to extend the PIK option through December 15, 2006 at an annual interest rate on the deferred amount of 10% and the payment of a one-time fee equal to 0.5% of the principal then outstanding and (4) additional flexibility to obtain a separate project financing facility in the future. The amendment fee will be amortized over the remaining life of the Note. 8 The Company is subject to certain covenants under the terms of the Subordinated Notes securities purchase agreement, including but not limited to, (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, (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) and (d) a limitation on our Total Debt (as defined in the securities purchase agreement) to 3.5 times EBITDA for any twelve month period. At June 30, 2004, the Company was in compliance with all of its debt covenants. 5. INVESTMENT IN PINNACLE GAS RESOURCES, INC. The Pinnacle Transaction On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and among the Company and its wholly-owned subsidiary, CCBM, Inc. ("CCBM"), Rocky Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their respective interests, having a estimated fair value of approximately $7.5 million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project areas and (2) oil and natural gas reserves in the Bobcat project area to a newly formed entity, Pinnacle Gas Resources, Inc., a Delaware corporation ("Pinnacle"). In exchange for the contribution of these assets, CCBM and RMG each received 37.5% of the common stock of Pinnacle ("Pinnacle Common Stock") as of the closing date and options to purchase Pinnacle Common Stock ("Pinnacle Stock Options"). CCBM no longer has a drilling obligation in connection with the oil and natural gas leases contributed to Pinnacle. Simultaneously with the contribution of these assets, the CSFB Parties contributed approximately $17.6 million of cash to Pinnacle in return for the Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute additional cash, under certain circumstances, of up to approximately $11.8 million to Pinnacle to fund future drilling, development and acquisitions. The CSFB Parties currently have greater than 50% of the voting power of the Pinnacle capital stock through their ownership of Pinnacle Common Stock and Pinnacle Preferred Stock. Immediately following the contribution and funding, Pinnacle used approximately $6.2 million of the proceeds from the funding to acquire an approximate 50% working interest in existing leases and acreage prospective for coalbed methane development in the Powder River Basin of Wyoming from Gastar Exploration, Ltd. Pinnacle also agreed to fund up to $14.9 million of future drilling and development costs on these properties on behalf of Gastar prior to December 31, 2005. The drilling and development work will be done under the terms of an earn-in joint venture agreement between Pinnacle and Gastar. The majority of these leases are part of, or adjacent to, the Bobcat project area. All of CCBM and RMG's interests in the Bobcat project area, the only producing coalbed methane property owned by CCBM prior to the transaction, were contributed to Pinnacle. Prior to and in connection with its contribution of assets to Pinnacle, CCBM paid RMG approximately $1.8 million in cash as part of its outstanding purchase obligation on the coalbed methane property interests CCBM previously acquired from RMG. As of June 30, 2003, approximately $1.1 million remaining balance of CCBM's obligation to RMG is scheduled to be paid in monthly installments of approximately $52,805 through November 2004 and a balloon payment on December 31, 2004. As of June 30, 2004, the remaining balance on this obligation was approximately $0.3 million. The RMG note is secured solely by CCBM's interests in the remaining oil and natural gas leases in Wyoming and Montana. In connection with the Company's investment in Pinnacle, the Company received a reduction in the principal amount of the RMG note of approximately $1.5 million and relinquished the right to receive certain revenues related to the properties contributed to Pinnacle. CCBM continues its coalbed methane business activities and, in addition to its interest in Pinnacle, owns direct interests in acreage in coalbed methane properties in the Castle Rock project area in Montana and the Oyster Ridge project area in Wyoming, which were not contributed to Pinnacle. CCBM and RMG will continue to conduct exploration and development activities on these properties as well as pursue other potential acquisitions. Other than indirectly through Pinnacle, CCBM currently has no proved reserves of, and is no longer receiving revenue from, coalbed methane gas. As of December 31, 2003, on a fully diluted basis, assuming that all parties exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB Parties, CCBM and RMG would have ownership interests of approximately 46.2%, 26.9% and 26.9%, respectively. In March 2004, the CSFB Parties contributed additional funds of $11.8 million into Pinnacle to continue funding the 2004 development program which increased the CSFB Parties' ownership to 66.7% on a fully diluted basis assuming CCBM and RMG each elect not to exercise their Pinnacle Stock Options. Assuming that CCBM and RMG exercise their Pinnacle Stock Options, 9 the CSFB parties' ownership interest in Pinnacle would be 54.6% and CCBM and RMG each would own 22.7% on a fully diluted basis. For accounting purposes, the transaction was treated as a reclassification of a portion of CCBM's investments in the contributed properties. The property contribution made by CCBM to Pinnacle was intended to be treated as a tax-deferred exchange as constituted by property transfers under section 351(a) of the Internal Revenue Code of 1986, as amended. The reclassification of investments in contributed properties resulting from the transaction with Pinnacle are reflected in accordance with the full cost method of accounting in the Company's balance sheet as of December 31, 2003 and June 30, 2004. 6. INCOME TAXES: The Company provided deferred income taxes at the rate of 35%, which also approximates its statutory rate, that amounted to $1.1 million and $1.3 million for the three months ended June 30, 2003 and 2004, respectively and $2.7 million and $2.7 million for the six months ended June 30, 2003 and 2004, respectively. 7. 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 of the Company. The operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable. 8. CONVERTIBLE PARTICIPATING PREFERRED STOCK: In February 2002, the Company consummated the sale of 60,000 shares of Convertible Participating Series B Preferred Stock (the "Series B Preferred Stock") and warrants to purchase 252,632 shares of common stock for an aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000 shares of Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock was convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustments, and was initially convertible into 1,052,632 shares of common stock. Dividends on the Series B Preferred Stock were payable in either cash at a rate of 8% per annum or, at the Company's option, by payment in kind of additional shares of the same series of preferred stock at a rate of 10% per annum. At December 31, 2003 and through the conversion dates specified below, the outstanding balance of the Series B Preferred Stock has been increased by $1.2 million (11,987 shares) and $1.5 million (15,133 shares), respectively, for dividends paid in kind. The Series B Preferred Stock was 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 also participated in any dividends declared on the common stock. Holders of the Series B Preferred Stock would have received a liquidation preference upon the liquidation of, or certain mergers or sales of substantially all assets involving, the Company. Such holders also had the option of receiving a change of control repayment price upon certain deemed change of control transactions. Mellon Ventures, Inc., converted all of its Series B Preferred Stock (approximately 49,938 shares) into 876,099 shares of common stock on May 25, 2004. Steven A. Webster converted all of his Series B Preferred Stock (approximately 25,195 shares) into 442,025 shares of common stock on June 30, 2004. As a result, no shares of Series B Preferred Stock remain outstanding. 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. During the six months ended June 30, 2004, Mellon Ventures, Inc. exercised all of its 168,422 warrants on a cashless exercise basis for a total of 36,570 shares of common stock. Net proceeds of this financing were approximately $5.8 million and were used primarily to fund the Company's ongoing exploration and development program and general corporate purposes. 9. SHAREHOLDER'S EQUITY: In the first quarter of 2004, the Company completed the public offering of 6,485,000 shares of common stock at $7.00 per share. The offering included 3,655,500 newly issued shares offered by the Company and 2,829,500 shares offered by certain existing 10 stockholders. The Company did not receive any proceeds from the shares sold by the selling stockholders. The Company expects to use the net proceeds from this offering to accelerate its drilling program and to retain larger interests in portions of its drilling prospects that the Company otherwise would sell down or for which the Company would seek joint partners and for general corporate purposes. In the meantime, the Company used a portion of the net proceeds to repay the $7 million outstanding principal amount under our revolving credit facility and to complete a $8.2 million Barnett Shale acquisition on February 27, 2004. The Company issued 55,334 and 7,305,949 shares of common stock during the six months ended June 30, 2003 and 2004, respectively. The shares issued during the six months ended June 30, 2003 were the result of the exercise of options granted under the Company's Incentive Plan. The shares issued during the six months ended June 30, 2004, consisted of 3,655,500 shares issued through the secondary offering, 2,159,627 shares issued through the exercise of warrants, 1,318,124 shares issued through the conversion of Series B Preferred Stock and the balance issued through the exercise of options granted under the Company's Incentive Plan. In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation," which requires the Company to record stock-based compensation at fair value. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure." The Company has adopted the disclosure requirements of SFAS No. 148 and has elected to record employee compensation expense utilizing the intrinsic value method permitted under Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The Company accounts for its employees' stock-based compensation plan under APB Opinion No. 25 and its related interpretations. Accordingly, any deferred compensation expense would be recorded for stock options based on the excess of the market value of the common stock on the date the options were granted over the aggregate exercise price of the options. This deferred compensation would be amortized over the vesting period of each option. Had compensation cost been determined consistent with SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the Company's net income (loss) and earnings per share would have been as follows:
For the Three Months Ended June 30, -------------------------- 2003 2004 ----------- ------------ (In thousands except per share amounts) Net income available to common shareholders, as reported $ 1,779 $ 1,985 Less: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects (132) (141) ----------- ------------ Pro forma net income (loss) available to common shareholders $ 1,647 $ 1,844 =========== ============ Net income per common share, as reported: Basic $ 0.13 $ 0.10 Diluted 0.11 0.10 Pro Forma net income (loss) per common share, as if value method had been applied to all awards: Basic $ 0.12 $ 0.10 Diluted 0.10 0.09
11
For the Six Months Ended June 30, -------------------------- 2003 2004 ----------- ------------ (In thousands except per share amounts) Net income available to common shareholders, as reported $ 4,440 $ 3,971 Less: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects (264) (283) ----------- ------------ Pro forma net income (loss) available to common shareholders $ 4,176 $ 3,688 =========== ============ Net income per common share, as reported: Basic $ 0.31 $ 0.22 Diluted 0.27 0.21 Pro Forma net income (loss) per common share, as if value method had been applied to all awards: Basic $ 0.29 $ 0.21 Diluted 0.25 0.19
Diluted earnings per share amounts for the three months ended June 30, 2003 and 2004 are based upon 16,595,815 and 20,293,101 shares, respectively, that include the dilutive effect of assumed stock option and warrant conversions of 2,384,642 and 1,080,091 shares, respectively. Diluted earnings per share amounts for the six months ended June 30, 2003 and 2004 are based upon 16,464,990 and 18,914,850 shares, respectively, that include the dilutive effect of assumed stock option and warrant conversion of 2,260,300 and 1,001,630 shares, respectively. 10. CHANGE IN ACCOUNTING PRINCIPLE: In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement is effective for fiscal years beginning after June 15, 2002, and the Company adopted the Statement effective January 1, 2003. During the three months ended March 31, 2003, the Company recorded a cumulative effect of change in accounting principle of $0.1 million, $0.4 million as proved properties and $0.5 million as a liability for its plugging and abandonment expenses. 11. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY: The Company's operations involve managing market risks related to changes in commodity prices. Derivative financial instruments, specifically swaps, futures, options and other contracts, are used to reduce and manage those risks. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and natural gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. The Company enters into the majority of its hedging transactions with two counterparties and a netting agreement is in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. As of December 31, 2003 and June 30, 2004, $0.2 million and $0.5 million, net of tax of $0.1 million and $0.3 million, respectively, remained in accumulated other comprehensive income related to the valuation of the Company's hedging positions. 12 Total oil hedged under swaps and collars during the three months ended June 30, 2003 and 2004 were 63,300 Bbls and 27,300 Bbls, respectively. Total natural gas hedged under swaps and collars during the three months ended June 30, 2003 and 2004 were 819,000 MMBtu and 1,001,000 MMBtu, respectively. Total oil hedged under swaps and collars during the six months ended June 30, 2003 and 2004 were 126,300 Bbls and 54,300 Bbls, respectively. Total natural gas hedged under swaps and collars during the six months ended June 30, 2003 and 2004 were 1,349,000 MMBtu and 1,727,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were $0.4 and $0.5 million for the three months ended June 30, 2003 and 2004, respectively, and are included in oil and natural gas revenues. The net losses realized by the Company under such hedging arrangements were $1.7 million and $0.4 million for six months ended June 30, 2003 and 2004, respectively, and are included in oil and natural gas revenues. At June 30, 2003 and 2004 the Company had the following outstanding hedge positions:
As of June 30, 2003 - -------------------------------------------------------------------------------------------------- Contract Volumes --------------------------- Average Average Average Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price - ---------------------- ------------ ------------ ------------ ------------ ------------- Third Quarter 2003 276,000 $ 4.70 Third Quarter 2003 552,000 $ 3.40 $ 5.25 Fourth Quarter 2003 552,000 3.40 5.25 Second Quarter 2004 273,000 4.00 5.20 Third Quarter 2004 276,000 4.00 5.20 Third Quarter 2004 93,000 4.00 5.20
As of June 30, 2004 - -------------------------------------------------------------------------------------------------- Contract Volumes --------------------------- Average Average Average Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price - ---------------------- ------------ ------------ ------------ ------------ ------------- Third Quarter 2004 27,600 $ 37.42 Third Quarter 2004 1,012,000 $ 4.52 $ 6.24 Fourth Quarter 2004 9,300 38.85 Fourth Quarter 2004 1,197,000 4.71 6.94 First Quarter 2005 810,000 5.09 8.00
13 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. You should read this in conjunction with the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2003 and the unaudited financial statements included elsewhere herein. General Overview We 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, we began obtaining 3-D seismic data and optioning to lease substantial acreage in 1995 and began drilling our 3-D based prospects in 1996. In 2003, we drilled 39 gross wells (10.2 net), 35 gross wells (9.4 net) of which were successful. During the six months ended June 30, 2004, we participated in the drilling of 40 gross wells (14.7 net) in the Gulf Coast and North Texas regions, 36 gross wells (12.1 net) of which were successful. 33 of these successful wells have been completed and three are in the process of being completed. We have budgeted to drill up to 44 gross wells (15.3 net) in the Gulf Coast region in 2004; 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, our cash flow, success of drilling programs, weather delays and other factors. If we drill the number of wells we have budgeted for 2004, depreciation, depletion and amortization, oil and natural gas operating expenses and production are expected to increase over levels incurred in 2003. Since our initial public offering, we have primarily grown through the internal development of properties within our exploration project areas, although we consider acquisitions from time to time and may in the future complete acquisitions that we find attractive. In February 2004, we acquired assets in a Barnett Shale play in North Texas for approximately $8.2 million. 2004 Public Offering In the first quarter of 2004, we completed the public offering of 6,485,000 shares of our common stock at $7.00 per share. The offering included 3,655,500 newly issued shares offered by us and 2,829,500 shares offered by certain existing stockholders. We did not receive any proceeds from the shares offered by the selling stockholders. We expect to use our estimated net proceeds of approximately $23.4 million from this offering to accelerate our drilling program and to retain larger interests in portions of our drilling prospects that we otherwise would sell down or for which we would seek joint partners and for general corporate purposes. In the meantime, we used a portion of the net proceeds to repay the $7 million outstanding principal amount under our revolving credit facility and to purchase the $8.2 million Barnett Shale acquisition mentioned below. Barnett Shale Activity On February 27, 2004, we closed an $8.2 million transaction with a private company to acquire working interests and acreage in certain oil and natural gas wells located in the Newark East Field in Denton County, Texas in the Barnett Shale trend. This acquisition includes non-operated working interests in properties ranging from 12.5% to 45% over 3,800 gross acres, or an average working interest of 39%. The Barnett Shale acquisition included 21 existing gross wells (6.7 net) and interests in approximately 1,500 net acres, which we expect to provide another 31 gross drill sites: 13 of which will target proved undeveloped reserves and 18 of which will be exploratory. Current net production from the acquired properties in July 2004 was approximately 1.5 Mmcfe/d and net proved reserves are internally estimated at 12.2 Bcfe. Initially, we financed the Barnett Shale acquisition with our available cash on hand. We are exploring a number of financing alternatives to refinance a majority of the acquisition and to fund a majority of our 2004 and 2005 capital expenditure program for the Barnett Shale play. We may not be able to obtain such financing on terms that are acceptable to us, or at all. In mid-2003, we became active in the Barnett Shale play located in Tarrant and Parker counties in Northeast Texas. Our activity accelerated as a result of the acquisition described above. 14 In the Barnett Shale play, we drilled six gross wells in 2003 and 19 gross wells (7.9 net) during the six months ended June 30, 2004, all of which were successful. We plan to drill between 30 and 45 gross wells in this region in 2004, assuming that we obtain the additional financing mentioned above. Pinnacle Gas Resources, Inc. During the second quarter of 2001, we acquired interests in natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane and subsequently began to drill wells on those leases. During the second quarter of 2003, we contributed our interests in certain of these leases to a newly formed company, Pinnacle Gas Resources, Inc. ("Pinnacle"). In exchange for this contribution, we received 37.5% of the common stock of Pinnacle and options to purchase additional Pinnacle common stock. In February 2004, the CSFB Parties contributed additional funds of $11.8 million into Pinnacle to continue funding the 2004 development program which will increase their ownership to 66.7% on a fully diluted basis should we and RMG each elect not to exercise our available options. The business operations and development program of Pinnacle does not require us to provide any further capital infusion, unless we determine to exercise our options. We account for our interest in Pinnacle using the equity method. As a result, our contributed operations and reserves are no longer directly reflected in our financial statements. Our discussion of future drilling and capital expenditures does not reflect operations conducted through Pinnacle. In addition to our interest in Pinnacle, CCBM retained interests in approximately 145,000 gross acres in the Castle Rock coalbed methane project area in Montana and the Oyster Ridge project area in Wyoming. Hedging Our financial results are largely dependent on a number of factors, including commodity prices. Commodity prices are outside of our control and historically have been and are expected to remain volatile. Natural gas prices in particular have remained volatile during the last few years. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, natural gas liquids and crude oil prices, and therefore, cannot accurately predict revenues. Because natural gas and oil prices are unstable, we periodically enter into price-risk-management transactions such as swaps, collars, futures and options to reduce our exposure to price fluctuations associated with a portion of our natural gas and oil production and to achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. Our hedging arrangements may apply to only a portion of our production and provide only partial protection against declines in natural gas and oil prices. Results of Operations Three Months Ended June 30, 2004, Compared to the Three Months Ended June 30, 2003 Oil and natural gas revenues for the three months ended June 30, 2004 increased 35% to $12.0 million from $8.8 million for the same period in 2003. Production volumes for natural gas during the three months ended June 30, 2004 increased from 1.0 Bcf for the three months ended June 30, 2003 to 1.5 Bcf. Average natural gas prices increased 8% to $6.07 per Mcf in the second quarter of 2004 from $5.64 per Mcf in the same period in 2003. Production volumes for oil in the second quarter of 2004 decreased 30% to 83 MBbls from 118 MBbls for the same period in 2003. Average oil prices increased 25% to $35.27 per barrel in the second quarter of 2004 from $28.23 per barrel in the same period in 2003. The increase in natural gas production was due to the commencement of production at the Beach House #1 and #2, Shadyside #1 and the Barnett Shale wells partially offset by the natural decline in production at the Staubach #1, Burkhart #1R, Matthes Heubner #1 and other wells. The decrease in oil production was due primarily to the natural decline of production at the Staubach #1, Burkhart #1R, Pauline Huebner A-382 #1, Matthes Huebner #1 and other wells partially offset by the commencement of production from the Beach House #1 and #2 and from other wells. Oil and natural gas revenues include the impact of hedging activities as discussed above under "General Overview." The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the three months ended June 30, 2003 and 2004: 15
2004 Period Compared to 2003 Period --------------------------- June 30, --------------------------- Increase % Increase 2003 2004 (Decrease) (Decrease) ------------ ------------ ------------ ------------ Production volumes - Oil and condensate (MBbls) 118 83 (35) (30)% Natural gas (MMcf) 973 1,487 514 53% Average sales prices - (1) Oil and condensate (per Bbls) $ 28.23 $ 35.27 $ 7.04 25% Natural gas (per Mcf) 5.64 6.07 0.43 8% Operating revenues (In thousands)- Oil and condensate $ 3,344 $ 2,941 $ (403) (12)% Natural gas 5,484 9,019 3,535 64% ------------ ------------ ------------ Total Operating Revenues $ 8,828 $ 11,960 $ 3,132 35% ============ ============ ============
- ------------------ (1) Includes impact of hedging activities. Oil and natural gas operating expenses for the three months ended June 30, 2004 increased 16% to $2.0 million from $1.8 million for the same period in 2003. Operating expenses per equivalent unit decreased slightly to $1.03 per Mcfe in the second quarter of 2004 compared to $1.05 per Mcfe in the same period in 2003. Depreciation, depletion and amortization (DD&A) expense for the three months ended June 30, 2004 increased 38% to $3.6 million ($1.81 per Mcfe) from $2.6 million ($1.55 per Mcfe) for the same period in 2003. DD&A increased primarily due to increased production and expenses resulting from additional seismic and drilling costs. General and administrative expense for the three months ended June 30, 2004 increased by $0.3 million to $1.6 million from $1.3 million for the same period in 2003 primarily as a result of higher directors' fees ($0.1 million), higher legal fees ($0.1 million) in connection with a subordinated debt refinancing and higher professional expenses related to Sarbanes-Oxley Compliance ($0.1 million). Stock option compensation expense was $0.7 million for the quarter ended June 30, 2004. We recorded a $0.4 million after tax charge, or $0.02 per fully diluted share, on our minority interest in Pinnacle for the three months ended June 30, 2004. It is likely that Pinnacle will continue to record a valuation allowance on the deferred federal tax benefit generated from the operating losses incurred during at least the early development stages of Pinnacle's coalbed methane projects. We have not recorded a deferred federal income tax benefit generated from these operating losses due to the uncertainty of future Pinnacle income. Income taxes increased to $1.4 million for the three months ended June 30, 2004 from $1.1 million for the same period in 2003 as a result of higher taxable income based on the factors described above. Capitalized interest was unchanged at $0.7 million in the second quarter of 2004 from $0.7 million for the second quarter of 2003. Six Months Ended June 30, 2004, Compared to the Six Months Ended June 30, 2003 Oil and natural gas revenues for the six months ended June 30, 2004 increased 17% to $22.8 million from $19.5 million for the same period in 2003. Production volumes for natural gas during the six months ended June 30, 2004 increased 36% to 2.8 Bcf from 2.1 Bcf for the same period in 2003. Average natural gas prices increased 4% to $6.00 per Mcf in the first six months of 2004 from $5.78 per Mcf in the same period in 2003. Production volumes for oil in the first six months of 2004 decreased 34% to 171 MBbls from 258 MBbls for the same period in 2003. Average oil prices increased 18% to $34.41 per barrel in the first six months of 2004 from $29.04 per barrel in the same period in 2003. The increase in natural gas production was primarily due to the commencement of production at the Beach House #1 and #2, Shadyside #1 and the Barnett Shale wells, offset by the natural decline in production at the Staubach #1, Burkhart #1R, Pauline Huebner A-382 #1, Matthes Huebner #1, Delta Farms #1 and other wells. The decrease in oil production was 16 due primarily to the natural decline of production at the Staubach #1, Burkhart #1R, Pauline Huebner A-382 #1, Matthes Huebner #1 and Delta Farms #1 wells, offset by the commencement of production from the Beach House #1 and #2 and from other wells. Oil and natural gas revenues include the impact of hedging activities as discussed above under "General Overview". The following table summarizes production volumes, average sales prices and operating revenues for our oil and natural gas operations for the six months ended June 30, 2003 and 2004:
2004 Period Compared to 2003 Period --------------------------- June 30, --------------------------- Increase % Increase 2003 2004 (Decrease) (Decrease) ------------ ------------ ------------ ------------ Production volumes - Oil and condensate (MBbls) 258 171 (87) (34)% Natural gas (MMcf) 2,077 2,826 749 36% Average sales prices - (1) Oil and condensate (per Bbls) $ 29.04 $ 34.41 $ 5.37 18% Natural gas (per Mcf) 5.78 6.00 0.22 4% Operating revenues (In thousands)- Oil and condensate $ 7,480 $ 5,867 $ (1,613) (22)% Natural gas 12,012 16,966 4,954 41% ------------ ------------ ------------ Total Operating Revenues $ 19,492 $ 22,833 $ 3,341 17% ============ ============ ============
- ------------------ (1) Includes impact of hedging activities. Oil and natural gas operating expenses for the six months ended June 30, 2004 increased to $3.7 million from $3.5 million for the same period in 2003. Operating expenses per equivalent unit were virtually unchanged at $0.97 per Mcfe in the first six months of 2004 compared to $0.96 per Mcfe in the same period in 2003. Depreciation, depletion and amortization (DD&A) expense for the six months ended June 30, 2004 increased 21% to $6.9 million ($1.78 per Mcfe) from $5.6 million ($1.56 per Mcfe) for the same period in 2003. DD&A increased primarily due to increased production and expenses resulting from additional seismic and drilling costs. General and administrative expense for the six months ended June 30, 2004 increased by $1.1 million to $3.8 million from $2.7 million for the same period in 2003 primarily as a result of higher incentive compensation costs ($0.4 million), higher directors' fees ($0.1 million), higher legal fees ($0.1 million) in connection with the subordinated debt refinancing, higher professional expenses related to Sarbanes-Oxley compliance ($0.1 million) and higher professional expenses in connection with the 2003 audit ($0.3 million). Stock option compensation expense was $0.8 million for the six months ended June 30, 2004. We recorded a $0.6 million after tax charge, or $0.03 per fully diluted share, on our minority interest in Pinnacle for the six months ended June 30, 2004. It is likely that Pinnacle will continue to record a valuation allowance on the deferred federal tax benefit generated from the operating losses incurred during at least the early development stages of Pinnacle's coalbed methane projects. We have not recorded a deferred federal income tax benefit generated from these operating losses due to the uncertainty of future Pinnacle income. Income taxes decreased to $2.7 million for the six months ended June 30, 2004 from $2.8 million for the same period in 2003 as a result of lower taxable income based on the factors described above. Capitalized interest decreased to $1.3 million in the first six months of 2004 from $1.5 million for the first six months of 2003 as a result of lower interest due to the repayment of a portion of the Rocky Mountain Gas note and the then outstanding balance under the Hibernia facility. 17 We adopted Financial Accounting Standards Board's Statement of Financial Standards No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003, and recorded a cumulative effect of change in accounting principle of $0.1 million in the six months ended June 30, 2003. Liquidity and Capital Resources During the six months ended June 30, 2004, we made capital expenditures in excess of our net cash flows provided by operating activities, using in part the proceeds generated from our equity offering. For future capital expenditures in 2004, we expect to continue to use such proceeds and cash on hand as well as to draw on the Hibernia facility to partially fund our planned drilling expenditures and fund leasehold costs and geological and geophysical costs on our exploration projects in 2004. We also continue to consider financing alternatives to fund our Barnett Shale capital program. While we believe that current cash balances, availability under the Hibernia Facility and anticipated 2004 cash provided by operating activities will provide sufficient capital to carry out our 2004 exploration plans, there can be no assurance that this will be the case. We may not be able to obtain adequate financing on terms that would be acceptable to us. If we cannot obtain adequate financing, we anticipate that we may be required to limit or defer our planned natural gas and oil exploration and development program, thereby adversely affecting the recoverability and ultimate value of our natural gas and oil properties. Our liquidity position has been enhanced by our receipt of approximately $23.4 million in net proceeds from the completion of our 2004 public offering as described above. Our other primary sources of liquidity have included funds generated by operations, proceeds from the issuance of various securities, including our common stock, preferred stock and warrants, and borrowings, primarily under revolving credit facilities and through the issuance of senior subordinated notes. Cash flows provided by operating activities were $15.1 million and $17.3 million for the six months ended June 30, 2003 and 2004, respectively. The increase in cash flows provided by operating activities in 2004 as compared to 2003 was due primarily to changes in working capital in 2004, primarily higher accrued expenses. We have budgeted capital expenditures in 2004 of approximately $51.3 million, of which $39.8 million is expected to be used for drilling activities in our project areas and the balance is expected to be used to fund 3-D seismic surveys, land acquisitions and capitalized interest and overhead costs. These capital expenditure amounts do not include the approximately $8.2 million for the Barnett Shale acquisition. We have budgeted to drill approximately 44 gross wells (15.3 net) in the Gulf Coast region in 2004. The budget for drilling additional gross and net wells in the Barnett Shale trend in 2004 is dependent upon the timing and amount of additional funding. We intend to obtain alternative financing to fund a majority of our acquisition, exploration and development program in the Barnett Shale trend in 2004. If we are successful in obtaining this facility, we expect our capital expenditures in the trend could increase between $15 and $20 million in 2004. 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. We have continued to reinvest a substantial portion of our cash flows into increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation technology and funding our drilling program. Oil and natural gas capital expenditures were $14.1 million and $39.1 million (including our $8.2 million Barnett Shale acquisition) for the six months ended June 30, 2003 and 2004, respectively. Our drilling efforts resulted in the successful completion of 35 gross wells (9.4 net) in 2003 and 17 gross wells (4.2 net) in the Gulf Coast region and 11 gross wells (3.9 net) in the Barnett Shale play in the six months ended June 30, 2004. We have completed 33 of these wells and are in the process of completing three of these wells as of June 30, 2004. Since inception, Pinnacle has reported that it drilled 210 gross wells through June 30, 2004 and estimates that 80% of them were completed by June 30, 2004. Pinnacle reportedly added approximately 11.4 Bcf of net proved reserves through development drilling through May 31, 2004. Its gross operated production has increased by approximately 117% since its inception (to approximately 10.4 MMcf/d at June 30, 2004), and its total well count stands at 449 gross operated wells. CCBM has spent $4.6 million for drilling costs, of 50% of which was spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of RMG. As of June 30, 2004, CCBM had satisfied $2.3 million of its drilling obligations on behalf of RMG. 18 Financing Arrangements Hibernia Credit Facility On May 24, 2002, we entered into a credit agreement with Hibernia National Bank (the "Hibernia Facility") which matures on January 31, 2006, and repaid our existing facility with Compass Bank (the "Compass Facility"). The Hibernia Facility provides a revolving line of credit of up to $30.0 million. It is secured by substantially all of our assets and is guaranteed by our subsidiary. The borrowing base will be determined by Hibernia National Bank at least semi-annually on each October 31 and April 30. 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 terms of our existing and future financial instruments may affect the size of our borrowing base. See "--Senior Subordinated Notes and Related Securities." On December 12, 2002, we entered into an Amended and Restated Credit Agreement with Hibernia National Bank that provided additional availability under the Hibernia Facility in the amount of $2.5 million which is structured as an additional "Facility B" under the Hibernia Facility. As such, the total borrowing base under the Hibernia Facility as of December 31, 2003 and June 30, 2004 was $19.0 million and $26.0 million, respectively, of which $7.0 and $9.0 million, respectively, were drawn as of such dates. The Facility B bore interest at LIBOR plus 3.375%, was secured by certain leases and working interests in oil and natural gas wells and matured on April 30, 2003. We used proceeds from our offering in February 2004 to repay the then outstanding balance under the Hibernia Facility. 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 outstanding principal balance of the Hibernia Facility exceeds the borrowing base at any time, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in Hibernia National Bank's opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity. For each tranche of principal borrowed under the revolving line of credit, the interest rate will be, at our 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. We are subject to certain covenants under the terms of the Hibernia Facility, including, but not limited to the maintenance of the following financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (ii) a minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million, plus 100% of all subsequent common and preferred equity contributed by shareholders, plus 50% of all positive earning occurring subsequent to such quarter end, all ratios as more particularly discussed in the credit facility. The Hibernia Facility also places restrictions on additional indebtedness, dividends to non-preferred stockholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of our common or preferred stock, speculative commodity transactions, and other matters. Rocky Mountain Gas Note In June 2001, CCBM issued a non-recourse promissory note payable in the amount of $7.5 million to RMG as consideration for certain interests in oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. At December 31, 2003 and June 30, 2004, the outstanding principal balance of this note was $0.9 million and $0.3 million, respectively. In connection 19 with our investment in Pinnacle, we received a reduction in the principal amount of the RMG note of approximately $1.5 million and relinquished the right to certain revenues related to the properties contributed to Pinnacle. During the second quarter of 2004, CCBM relinquished a portion of its interests in certain oil and natural gas leases and reduced the principal due on the note by $0.3 million. Capital Leases In December 2001, we entered into a capital lease agreement secured by certain production equipment in the amount of $0.2 million. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. In October 2002, we entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,462 including interest at 6.4% per annum. In May 2003, we entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,030 including interest at 5.5% per annum. In August 2003, we entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $2,179 including interest at 6.0% per annum. We have the option to acquire the equipment at the conclusion of the lease for $1 under all of these leases. DD&A on the capital leases for the three months ended June 30, 2003 and 2004 amounted to $11,000 and $12,000, respectively. DD&A on the capital leases for the six months ended June 30, 2003 and 2004 amounted to $20,000 and $24,000, respectively, and accumulated DD&A on the leased equipment at December 31, 2003 and June 30, 2004 amounted to $76,000 and $100,000, respectively. Senior Subordinated Notes and Related Securities In December 1999, we consummated the sale of $22.0 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and $8.0 million of common stock and Warrants. We sold $17.6 million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of our common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors, L.P. (now known as J.P. Morgan Partners (23A SBIC), L.P.), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest payments are due quarterly commencing on March 31, 2000. We may, until December 2004, elect, and historically have elected, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As a result, our cash obligation on the Subordinated Notes will increase significantly after December 2004. This increase is likely to reduce the amount available to us for borrowing under the Hibernia Facility. As of December 31, 2003 and June 30, 2004, the outstanding balance of the Subordinated Notes had been increased by $5.3 million and $6.0 million, respectively, for such interest paid in kind. Concurrently with the sale of the Subordinated Notes, we sold to the same purchasers 3,636,364 shares of our common stock at a price of $2.20 per share and warrants expiring in December 2007 to purchase up to 2,760,189 shares of our common stock at an exercise price of $2.20 per share. For accounting purposes, the warrants were valued at $0.25 each. During the six months ended June 30, 2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and Douglas A. P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006 and 92,006 shares of common stock, respectively, on a cashless exercise basis for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock, respectively, and Paul B. Loyd, Jr., exercised warrants to purchase 92,006 shares for a total of 92,006 shares of common stock. As a result, no warrants to purchase shares remain outstanding from the warrants originally issued in December 1999. On June 7, 2004, an unaffiliated third party (the "Purchaser") purchased all the outstanding Subordinated Notes from the original note holders. In exchange for a $0.4 million amendment fee, certain terms and conditions of the Subordinated Notes were amended, to provide for, among other things, (1) a one year extension of the maturity to December 15, 2008, (2) a one year extension, through December 15, 2005, of the paid-in-kind ("PIK") interest option to pay-in-kind 60% of the interest due each period by increasing the principal balance by a like amount (the "PIK option"), (3) an additional one year option to extend the PIK option through December 15, 2006 at an annual interest rate on the deferred amount of 10% and the payment of a one-time fee equal to 0.5% of the principal then outstanding, (4) an increase and extension on the prepayment premium on the Subordinated Notes, (5) a modification of a covenant regarding maximum quarterly leverage that our Total Debt will not exceed 3.5 times EBITDA (as such terms are defined in the securities purchase agreement) for the last 12 months at any time and (6) additional flexibility to obtain a separate project financing facility in the future. The amendment fee will be amortized over the remaining life of the Note. We are 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 our capital expenditures to an amount equal to our EBITDA for the immediately prior fiscal year (unless approved by our Board of Directors and a J.P. Morgan Partners (23A SBIC), L.P. appointed director). 20 Series B Preferred Stock In February 2002, we 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. We sold $4.0 million and $2.0 million of Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock is convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustment for transactions including issuance of common stock or securities convertible into or exercisable for common stock at less than the conversion price, and is initially convertible into 1,052,632 shares of common stock. The approximately $5.8 million net proceeds of this financing were used to fund our ongoing exploration and development program and general corporate purposes. In the first quarter of 2004, Mellon Ventures exercised all 168,422 of its 2002 warrants on a cashless basis and received 36,570 shares which it sold in the 2004 public offering. Dividends on the Series B Preferred Stock were payable in either cash at a rate of 8% per annum or, at our option, by payment in kind of additional shares of the Series B Preferred Stock at a rate of 10% per annum. At December 31, 2003 and through the conversion dates, the outstanding balance of the Series B Preferred Stock had been increased by $1.2 million (11,987 shares) and $1.5 million (15,133 shares), respectively, for dividends paid in kind. In addition to the foregoing, if we had declared a cash dividend on our common stock, the holders of shares of Series B Preferred Stock were entitled to receive for each share of Series B Preferred Stock a cash dividend in the amount of the cash dividend that would have been received by a holder of the common stock into which such share of Series B Preferred Stock was convertible on the record date for such cash dividend. Unless all accrued dividends on the Series B Preferred Stock were 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. We must redeem the Series B Preferred Stock at any time after the third anniversary of our initial issuance upon request from any holder at a price per share equal to Purchase Price/Dividend Preference (as defined below). On the other hand, we may opt to redeem the Series B Preferred Stock after the third anniversary of its issuance 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 Preference. "Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus all cumulative and accrued dividends. In the event of any dissolution, liquidation or winding up or specified mergers or sales or other disposition by us of all or substantially all of our assets, the holder of each share of Series B Preferred Stock then outstanding will be entitled to be paid per share of Series B Preferred Stock, prior to the payment to holders of our common stock and out of our assets available for distribution to our shareholders, the greater of: o $100 in cash plus all cumulative and accrued dividends; and o in specified 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), we are required to make an offer to each holder of Series B Preferred Stock to repurchase all of such holder's Series B Preferred Stock at an offer price per share of Series B Preferred Stock in cash equal to 105% of the Change of Control Purchase Price, which is generally defined to mean $100 plus all cumulative and accrued dividends. Mellon Ventures, Inc., converted all of its Series B Preferred Stock (approximately 49,938 shares) into 876,099 shares of common stock on May 25, 2004. Steven A. Webster converted all of his Series B Preferred Stock (approximately 25,195 shares) into 442,025 shares of common stock on June 30, 2004. As a result, no shares of Series B Preferred Stock remain outstanding. The 2002 Warrants have a five-year term and originally entitled the holders to purchase up to 252,632 shares of our common stock at a price of $5.94 per share, subject to adjustment, and are exercisable at any time after issuance. As of June 30, 2004, 84,210 of the 2002 Warrants remained outstanding. For accounting purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant. Each of our series of warrants may be exercised on a cashless basis at the option of the holder. 21 Effects of Inflation and Changes in Price Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us. Critical Accounting Policies The following summarizes several of our critical accounting policies: Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. The use of these estimates significantly affects natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below. Oil and Natural Gas Properties We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs for employees working directly on exploration activities of $0.7 million and $0.9 million for the six months ended June 30, 2003 and 2004, respectively. We expense maintenance and repairs as they are incurred. We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil 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 Mcfe for the six months ended June 30, 2003 and 2004 was $1.50 and $1.80, respectively. We account for dispositions of natural gas and oil properties 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. We have not had any transactions that significantly alter that relationship. The net capitalized costs of proved oil and natural gas properties are subject to a "ceiling test" which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net revenues from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. In mid-March 2004, during the year-end close of our 2003 financial statements, it was determined that there was a computational error in the ceiling test calculation which overstated the tax basis used in the computation to derive our after-tax present value (discounted at 10%) of future net revenues from proved reserves. We further determined that this tax basis error was also present in each of our previous ceiling test computations dating back to 1997. This error only affected our after-tax computation, used in the ceiling test calculation and the unaudited supplemental oil and natural gas disclosure, and did not impact our: (1) pre-tax valuation of the present value (discounted at 10%) of future net revenues from proved reserves, (2) our proved reserve volumes, (3) our EBITDA or our future cash flows from operations, (4) our net deferred tax liability, (5) our estimated tax basis in oil and natural gas properties, or (6) our estimated tax net operating losses. After discovering this computational error, the ceiling tests for all quarters since 1997 were recomputed and it was determined that no write-down of our oil and natural gas assets was necessary in any of the years from 1997 to 2003. Additionally, no write-down of our oil and natural gas assets was necessary for the six months ended June 30, 2004. However, based upon the oil and natural gas prices in effect on December 31, 2001, March 31, 2003 and September 30, 2003, the unamortized cost of oil and natural gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing and/or the addition of proved 22 reserves subsequent to those dates sufficiently increased the present value of our oil and natural gas assets and removed the necessity to record a write-down in these periods. Using the prices in effect and estimated proved reserves existing on December 31, 2001, March 31, 2003 and September 30, 2003, the after-tax write-down would have been approximately $6.3 million, $1.0 million, and $6.3 million, respectively, had we not taken into account these subsequent improvements. These improvements at September 30, 2003 included estimated proved reserves attributable to our Shady Side #1 well. Because of the volatility of oil and natural gas prices, no assurance can be given that we will not experience a write-down in future periods. In connection with our June 30, 2004 ceiling test computation, a price sensitivity study also indicated that a 20% increase in commodity prices at June 30, 2004 would have increased the pre-tax present value of future net revenues ("NPV") by approximately $36.4 million. Conversely, a 20% decrease in commodity prices at June 30, 2004 would have reduced our NPV by approximately $36.3 million. This would have caused our unamortized cost of proved oil and natural gas properties to exceed the cost pool ceiling, resulting in an after-tax write-down of approximately $6.8 million. The aforementioned price sensitivity and NPV is as of June 30, 2004 and, accordingly, does not include any potential changes in reserves due to third quarter 2004 performance, such as commodity prices, reserve revisions and drilling results. Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value and estimated future development costs to calculate the depletion expense. We have a significant amount of proved undeveloped reserves, which are primarily oil reserves. We had 44.9 Bcfe and, based on internal estimates, 55.1 Bcfe of proved undeveloped reserves, representing 64% and 64% of our total proved reserves at December 31, 2003 and June 30, 2004, respectively. As of December 31, 2003 and June 30, 2004, a large portion of these proved undeveloped reserves, or approximately 43.9 Bcfe, are attributable to our Camp Hill properties that we acquired in 1994. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties. Furthermore, the average depletable life of our Camp Hill properties is considerably higher, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 2.25 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream. It has also resulted in the build-up of nondepleted capitalized costs associated with properties that have been completely produced out. We expect our relatively low historical depletion rate condition to continue until the high level of nonproducing reserves to total proved reserves is reduced and the average life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves and current prices were both to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down. We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years. Oil and Natural Gas Reserve Estimates The reserve data included in this document are estimates prepared by Ryder Scott Company and Fairchild & Wells, Inc., Independent Petroleum Engineers. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value discount rate. Proved reserve estimates prepared by others may be substantially higher or lower than these estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production. 23 You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Our rate of recording depreciation, depletion and amortization expense for proved properties depends on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. Derivative Instruments and Hedging Activities Upon entering into a derivative contract, we designate the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and natural gas revenues when the forecasted transaction occurs. All of our derivative instruments at December 31, 2003 and June 30, 2004 were designated and effective as cash flow hedges. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings. We typically use fixed rate swaps and costless collars to hedge our exposure to material changes in the price of natural gas and oil. We formally document all relationships between hedging instruments and hedged items, as well as our 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. We also formally assess, 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. Our Board of Directors sets all of our 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 representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. Income Taxes Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"), "Accounting for Income Taxes," deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount expected to be realized. Contingencies Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable. Volatility of Oil and Natural Gas Prices Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas. We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the Commission. See "--Critical Accounting Policies and Estimates--Oil and Natural Gas Properties." Total oil hedged under swaps and collars during the three months ended June 30, 2003 and 2004 were 63,300 Bbls and 27,300 Bbls, respectively. Total natural gas hedged under swaps and collars during the three months ended June 30, 2003 and 2004 were 819,000 24 MMBtu and 1,001,000 MMBtu, respectively. Total oil hedged under swaps and collars during the six months ended June 30, 2003 and 2004 were 126,300 Bbls and 54,300 Bbls, respectively. Total natural gas hedged under swaps and collars during the six months ended June 30, 2003 and 2004 were 1,349,000 MMBtu and 1,727,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were $0.4 and $0.5 million for the three months ended June 30, 2003 and 2004, respectively, and are included in oil and natural gas revenues. The net losses realized by the Company under such hedging arrangements were $1.7 million and $0.4 million for six months ended June 30, 2003 and 2004, respectively, and are included in oil and natural gas revenues. To mitigate some of our commodity price risk, we engage periodically in certain other limited hedging activities. For instance, during the second quarter of 2003, we acquired options to sell 6,000 MMBtu of natural gas per day for the period July 2003 through September 2003 (552,000 MMBtu) at $8.00 per MMBtu for approximately $119,000. We acquired these options to protect its cash position against potential margin calls on certain natural gas derivative due to large increases in the price of natural gas. These options were classified as derivatives. The costs were recorded as a reduction of natural gas revenues as the options expired. As of December 31, 2003 and June 30, 2004, $0.2 million and $0.5 million, net of tax of $0.1 million and $0.3 million, respectively, remained in accumulated other comprehensive income related to the valuation of our hedging positions. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our hedging transactions with two counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have some risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Moreover, our hedging arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time. Our natural gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the NYMEX for each trading day of a particular calendar month. For the month of June 2004, a $0.10 change in the price per Mcf of gas sold would have changed revenue by $49,000. A $0.70 change in the price per barrel of oil would have changed revenue by $18,000. The table below summarizes our total natural gas production volumes subject to derivative transactions during the six months ended June 30, 2004 and the weighted average NYMEX reference price for those volumes.
Natural Gas Swaps Natural Gas Collars - ----------------------------- ----------------------------- Volumes (MMBtu) Volumes (MMBtu) 1,727,000 Average price ($/MMBtu) $ - Average price ($/MMBtu) Floor $ 4.33 Ceiling $ 6.26
The table below summarizes our total crude oil production volumes subject to derivative transactions for the six months ended June 30, 2004 and the weighted average NYMEX reference price for those volumes.
Crude Oil Swaps Crude Oil Collars - ----------------------------- ----------------------------- Volumes (Bbls) 54,300 Volumes (Bbls) - Average price ($/Bbls) $ 30.96 Average price ($/Bbls) Floor $ - Ceiling $ -
25 At June 30, 2003 and 2004 we had the following outstanding hedge positions:
As of June 30, 2003 - -------------------------------------------------------------------------------------------------- Contract Volumes --------------------------- Average Average Average Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price - ---------------------- ------------ ------------ ------------ ------------ ------------- Third Quarter 2003 276,000 $ 4.70 Third Quarter 2003 552,000 $ 3.40 $ 5.25 Fourth Quarter 2003 552,000 3.40 5.25 Second Quarter 2004 273,000 4.00 5.20 Third Quarter 2004 276,000 4.00 5.20 Third Quarter 2004 93,000 4.00 5.20
As of June 30, 2004 - -------------------------------------------------------------------------------------------------- Contract Volumes --------------------------- Average Average Average Quarter BBls MMbtu Fixed Price Floor Price Ceiling Price - ---------------------- ------------ ------------ ------------ ------------ ------------- Third Quarter 2004 27,600 $ 37.42 Third Quarter 2004 1,012,000 $ 4.52 $ 6.24 Fourth Quarter 2004 9,300 38.85 Fourth Quarter 2004 1,197,000 4.71 6.94 First Quarter 2005 810,000 5.09 8.00
Forward Looking Statements The statements contained in all parts of this document, including, but not limited to, those relating to our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and natural gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement our business strategy, future hiring, future exploration activity, production rates, potential drilling locations targeting coal seams, the outcome of legal challenges to new coalbed methane drilling permits in Montana, financing of the February 2004 acquisition costs in the Barnett Shale trend and the exploration and development expenditures in that trend, all 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, availability of financing and other factors detailed in the Company's Annual Report on Form 10-K for the year ended December 31, 2003 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. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and the Company undertakes no obligation to update or revise any forward looking statement. 26 ITEM 3 - 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, 2003 except for the Company's hedging activity subsequent to December 31, 2003 as described above in "Volatility of Oil and Natural Gas Prices." There have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report. For additional information regarding our long-term debt, see Note 4 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q. 27 ITEM 4 - CONTROLS AND PROCEDURES In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Except as set forth below, there has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. Management has and is implementing procedures and controls to address the following deficiencies and enhance the reliability of our internal control procedures: (1) the presence of underlying errors in the tax basis utilized in our full cost ceiling test computations and certain disclosures and the lack of underlying detailed tax basis documentation which adversely impacted our ability to evaluate the appropriateness of the tax basis (see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Critical Accounting Policies -- Oil and Natural Gas Properties") and (2) the sufficiency of review applied to the financial statement close process and account reconciliation. 28 PART II. OTHER INFORMATION Item 1 - Legal Proceedings From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. Item 2 - Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities In May 2004, Mellon Ventures converted all of its approximately 49,938 shares of Series B Preferred Stock into 876,099 shares of common stock. In June 2004, each of Messrs. Webster and Hamilton exercised all of his warrants to purchase 92,006 shares of common stock issued in 1999 on a cashless "net exercise" basis and received 70,205 shares of common stock. In June 2004, Mr. Loyd exercised all of his warrants to purchase 92,006 shares of common stock issued in 1999 and received 92,006 shares of common stock. In June 2004, Mr. Webster converted all of his approximately 25,195 shares of Series B Preferred Stock into 442,025 shares of common stock. All of these transactions were exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) as a transaction not involving any public offering and the exercises of warrants on a cashless "net exercise" basis were also exempt by virtue of Section 3(a)(9). 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 21, 2004, there were represented by person or by proxy 17,441, 554 shares out of 18,392,386 entitled to vote as of the record date, constituting a quorum. The matters submitted to a vote of shareholders were (1) 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 and the election of Mr. Roger A. Ramsey as directors, (2) the approval of an amendment to the incentive plan to increase by 500,000 the number of shares of common stock available for issuance under the plan, replace automatic annual grants of options to nonemployee directors with discretionary awards of options or restricted stock, provide for additional stock option grants to the chairman and certain members of the nominating committee of the Board of Directors and make certain clarifications to other provisions of the plan and (3) the approval of the appointment of Ernst & Young LLP as Independent Public Accountants for the fiscal year ended December 31, 2004. With respect to the election of directors, the following number of votes were cast for the nominees: 15,691,839 for Mr. Webster and 1,749,715 withheld; 17,388,434 for Mr. Behrens and 53,120 withheld; 17,388,334 for Mr. Martin and 53,220 withheld; 17,433,034 for Mr. Hamilton and 8,520 withheld; 15,692,839 for Mr. Loyd and 1,748,715 withheld; 17,428,234 for Mr. Parker and 13,320 withheld; 17,387,334 for Mr. Johnson and 54,220 withheld; 17,310,473 for Mr. Wojtek and 131,081 withheld; and 17,377,634 for Mr. Ramsey and 63,920 withheld. There were no abstentions in the election of directors. With respect to the amendment to the incentive plan, 10,943,924 votes were cast for the amendment, 1,661,934 votes were against and 23,200 votes abstained. With respect to the appointment for Ernst & Young LLP as Independent Public Accountants, 16,566,220 votes were cast for the appointment and 6,720 votes were against, and 746,579 votes abstained. Item 5 - Other Information Mr. Hamilton resigned as a director on July 6, 2004. Mr. Behrens resigned as a director on July 15, 2004. Item 6 - Exhibits and Reports on Form 8-K
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. 29 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). +10.1 -- Amendment No. 4 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Appendix B to the Company's Proxy Statement dated April 26, 2004). +10.2 -- First Amendment to Securities Purchase Agreement dated as of June 7, 2004 among Carrizo Oil & Gas, Inc., Steelhead Investments Ltd., Douglas A.P. Hamilton, Paul B. Loyd, Jr., Steven A. Webster and Mellon Ventures, L.P. (incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K filed on July 10, 2004). +10.3 -- Form of Amended and Restated 9% Senior Subordinated Note due 2008 (incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed on July 10, 2004). +10.4 -- Consent dated as of June 7, 2004 among Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia National Bank (incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed on July 10, 2004). +10.5 -- First Amendment to Shareholders Agreement dated as of April 21, 2004 among Carrizo Oil & Gas, Inc., J.P. Morgan Partners (23A SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek and Steven A. Webster (incorporated herein by reference to Exhibit 29 to the Schedule 13D/A filed by Paul B. Loyd, Jr. on May 28, 2004). +10.6 -- First Amendment to Shareholders Agreement dated as of April 21, 2004 among Carrizo Oil & Gas, Inc., Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek, Steven A. Webster, Douglas A.P. Hamilton, Paul B. Loyd, Jr. and DAPHAM Partnership, L.P. (incorporated herein by reference to Exhibit 30 to the Schedule 13D/A filed by Paul B. Loyd, Jr. on May 28, 2004). +10.7 -- Second Amendment to Shareholders Agreement dated as of June 7, 2004 among Carrizo Oil & Gas, Inc., J.P. Morgan Partners (23A SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek and Steven A. Webster (incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K filed on July 10, 2004). +10.8 -- Termination Agreement dated as of June 7, 2004 among Carrizo Oil & Gas, Inc., Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek and Steven A. Webster (incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K filed on July 10, 2004). 31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes- Oxley Act of 2002. 31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes- Oxley Act of 2002. 32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002. 32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002.
+ Incorporated herein by reference as indicated. 30 Reports on Form 8-K The Company filed a Current Report on Form 8-K on April 30, 2004 announcing operating results for the quarter ended March 31, 2004 (information furnished not filed) and disclosing information regarding the Company's 2004 drilling schedule and 2004 budgeted capital expenditures, a Current Report on Form 8-K on May 20, 2004 announcing financial results for the quarter ended March 31, 2004 (information furnished not filed), and a Current Report on Form 8-K on June 10, 2004 announcing the purchase of the Company's outstanding 9% senior subordinated notes from the original holder by an unaffiliated third party, and related transactions. 31 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: August 16, 2004 By: /s/S. P. Johnson, IV ------------------------- President and Chief Executive Officer (Principal Executive Officer) Date: August 16, 2004 By: /s/Paul F. Boling ---------------------- Chief Financial Officer (Principal Financial and Accounting Officer) EX-31 2 exhibit31-1.txt EXHIBIT 31.1 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 officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and c) disclosed in this quarterly report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 16, 2004 /s/ S. P. JOHNSON IV -------------------- S.P. Johnson IV President and Chief Executive Officer EX-31 3 exhibit31-2.txt EXHIBIT 31.2 CERTIFICATIONS PRINCIPAL FINANCIAL OFFICER I, Paul F. Boling, 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 officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and c) disclosed in this quarterly report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 16, 2004 By: /s/ PAUL F. BOLING ----------------------- Paul F. Boling Chief Financial Officer EX-32 4 exhibit32-1.txt Exhibit 32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson, IV, President and Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the "Company"), hereby certify, to my knowledge, that: (1) the Company's Quarterly Report on Form 10-Q for the three months ended June 30, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 16, 2004 /s/ S. P. JOHNSON IV -------------------- S.P. Johnson IV President and Chief Executive Officer The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document. A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request. EX-32 5 exhibit32-2.txt Exhibit 32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Paul Boling, Vice President and Chief Financial Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the "Company"), hereby certify, to my knowledge, that: (1) the Company's Quarterly Report on Form 10-Q for the three months ended June 30, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 16, 2004 By: /s/ PAUL F. BOLING ----------------------- Paul F. Boling Vice President and Chief Financial Officer The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document. A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----