10-Q 1 h96774e10-q.txt CARRIZO OIL & GAS, INC. - DATED 3/31/02 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended MARCH 31, 2002 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to _________ Commission File Number 000-22915. CARRIZO OIL & GAS, INC. (Exact name of registrant as specified in its charter) TEXAS 76-0415919 (State or other jurisdiction of (IRS Employer Identification No.) incorporation or organization) 14701 ST. MARY'S LANE, SUITE 800, HOUSTON, TX 77079 (Address of principal executive offices) (Zip Code) (281) 496-1352 (Registrant's telephone number) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes X. No __ The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of May 3, 2002, the latest practicable date, was 14,140,549. CARRIZO OIL & GAS, INC. FORM 10-Q FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002 INDEX
PART I. FINANCIAL INFORMATION PAGE Item 1. Consolidated Balance Sheets - As of December 31, 2001 and March 31, 2002 2 Consolidated Statements of Operations - For the three-month periods ended March 31, 2002 and 2001 3 Consolidated Statements of Cash Flows - For the three-month periods ended March 31, 2002 and 2001 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 10 PART II. OTHER INFORMATION Items 1-6. 18 SIGNATURES 20
CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (UNAUDITED)
December 31, March 31, ASSETS 2001 2002 ----------------- ----------------- CURRENT ASSETS: Cash and cash equivalents $3,235,712 $5,264,559 Accounts receivable, net of allowance for doubtful accounts of $480,000 at December 31, 2001 and March 31, 2002, respectively 8,111,482 5,561,208 Advances to operators 508,563 1,036,520 Deposits 47,901 48,124 Other current assets 599,882 592,941 ----------------- ----------------- Total current assets 12,503,540 12,503,352 PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and gas properties) 104,132,392 108,013,400 OTHER ASSETS 755,731 727,684 ----------------- ----------------- $117,391,663 $121,244,436 ================= ================= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade $10,263,176 $7,321,605 Accrued liabilities 347,778 838,558 Advances for joint operations 367,942 1,485,300 Current maturities of long-term debt 2,107,030 1,574,980 ------------------ ----------------- Total current liabilities 13,085,926 11,220,443 LONG-TERM DEBT 36,081,057 36,033,209 DEFERRED INCOME TAXES 5,020,576 5,120,115 COMMITMENTS AND CONTINGENCIES (Note 5) CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares of preferred stock authorized, of which 150,000 are shares designated as convertible participating shares, with 60,000 convertible participating shares issued and outstanding at March 31, 2002) (Note 6) Issued and outstanding - 5,790,736 Accrued dividends - 68,388 SHAREHOLDERS' EQUITY: Warrants (3,010,189 and 3,262,821 outstanding at December 31, 2001 and March 31, 2002, respectively) 765,047 780,047 Common stock, par value $.01, (40,000,000 shares authorized with 14,064,077 and 14,140,549 issued and outstanding at December 31, 2001 and March 31, 2002, respectively) (Note 7) 140,641 141,406 Additional paid in capital 62,735,659 63,059,900 Accumulated deficit (1,143,634) (1,073,969) Other comprehensive income 706,391 104,161 ----------------- ----------------- 63,204,104 63,011,545 ----------------- ----------------- $117,391,663 $121,244,436 ================= =================
The accompanying notes are an integral part of these consolidated financial statements. -2- CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
For the Three Months Ended March 31, ------------------------------------------- 2001 2002 -------------------- -------------------- OIL AND NATURAL GAS REVENUES $ 8,727,481 $4,026,893 COSTS AND EXPENSES: Oil and natural gas operating expenses 1,299,571 1,012,656 Depreciation, depletion and amortization 1,629,744 1,969,723 General and administrative 870,482 915,952 Stock option compensation (331,655) (42,035) ------------------ -------------------- Total costs and expenses 3,468,142 3,856,296 ------------------ -------------------- OPERATING INCOME 5,259,339 170,597 OTHER INCOME AND EXPENSES: Other income and expenses, net - 93,774 Interest income 120,501 20,027 Interest expense (749,781) (712,760) Interest expense, related parties (52,359) (55,244) Capitalized interest 802,140 768,004 ------------------ -------------------- INCOME BEFORE INCOME TAXES 5,379,840 284,398 INCOME TAXES (Note 4) 1,916,031 140,474 ------------------ -------------------- NET INCOME $ 3,463,809 $ 143,924 ================== ==================== DIVIDENDS AND ACCRETION OF DISCOUNT ON PREFERRED STOCK - (74,259) ================== ==================== NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 3,463,809 $ 69,665 ================== ==================== BASIC EARNINGS PER COMMON SHARE (Note 2) $ 0.25 $ 0.00 ================== ==================== DILUTED EARNINGS PER COMMON SHARE (Note 2) $ 0.21 $ 0.00 ================== ==================== DILUTED EARNINGS PER COMMON SHARE (Note 2) $ 0.21 $ 0.00 ================== ====================
The accompanying notes are an integral part of these consolidated financial statements. -3- CARRIZO OIL & GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Three Months Ended March 31, --------------------------- 2001 2002 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 3,463,809 $ 143,924 Adjustment to reconcile net income to net cash provided by operating activities- Depreciation, depletion and amortization 1,629,744 1,969,723 Discount accretion 21,315 21,399 Income from derivative instruments - (232,013) Interest payable in kind 314,155 331,464 Stock option compensation benefit (331,655) (42,036) Deferred income taxes 1,882,944 99,539 Changes in assets and liabilities- Accounts receivable (2,016,731) 2,550,274 Other assets 101,554 (7,234) Accounts payable, trade 10,203 (2,493,263) Other current liabilities (266,397) 162,599 ----------- ----------- Net cash provided by operating activities 4,808,941 2,504,376 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures, accrual basis (8,250,779) (5,808,731) Adjustment to cash basis 1,684,147 (123,302) Advances to operators 790,003 (527,957) Advances for joint operations 363,195 1,117,358 ----------- ----------- Net cash used in investing activities (5,413,434) (5,342,632) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from the sale of common stock 10,800 - Net proceeds from the sale of preferred stock - 5,784,865 Net proceeds from the sale of warrants - 15,000 Debt repayments (1,600,412) (932,762) ----------- ----------- Net cash provided by (used in) financing activities (1,589,612) 4,867,103 ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (2,194,105) 2,028,847 CASH AND CASH EQUIVALENTS, beginning of period 8,217,427 3,235,712 ----------- ----------- CASH AND CASH EQUIVALENTS, end of period $ 6,023,322 $ 5,264,559 =========== =========== SUPPLEMENTAL CASH FLOW DISCLOSURES: Cash paid for interest (net of amounts capitalized) $ - $ - =========== =========== Common stock issued for oil and gas property (Note 7) $ - $ 325,006 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. -4- CARRIZO OIL & GAS, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. ACCOUNTING POLICIES: The consolidated financial statements included herein have been prepared by Carrizo Oil & Gas, Inc. (the Company), and are unaudited, except for the balance sheet at December 31, 2001, which has been prepared from the audited financial statements at that date. The financial statements reflect the accounts of the Company and its subsidiary after elimination of all significant intercompany transactions and balances. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. 2. EARNINGS PER COMMON SHARE: Supplemental earning per share information is provided below:
For the Three Months Ended March 31, ------------------------------------------------------------------------------- Income Shares Per-Share Amount --------------------------- ------------------------ ------------------ 2001 2002 2001 2002 2001 2002 ----------- --------- ---------- ---------- ------ ------- Net Income $ 3,463,809 $ 143,924 Less: Dividends and Accretion of Discount on Preferred Shares - (74,259) ----------- --------- Basic Earnings per Share Net income available to common shareholders 3,463,809 69,665 14,057,928 14,128,653 $ 0.25 $ 0.00 ====== ========= Stock Options and Warrants - - 2,696,906 2,105,154 Diluted Earnings per Share ----------- --------- ---------- ----------- Net income available to common shareholders plus assumed conversions $ 3,463,809 $ 69,665 16,754,834 16,233,807 $ 0.21 $ 0.00 =========== ========= ========== =========== ====== =========
Net income per common share has been computed by dividing net income by the weighted average number of shares of common stock outstanding during the periods. The Company had outstanding 67,000 and 189,833 stock options and zero and 252,632 warrants during the three months ended March 31, 2001 and 2002, respectively, which were antidilutive and were not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants. At March 31, 2002, the Company also had 1,052,632 shares based on the assumed conversion of the Series B Convertible Participating Preferred Stock that were antidilutive and were not included in the calculation. -5- 3. LONG-TERM DEBT: At December 31, 2001 and March 31, 2002, long-term debt consisted of the following:
December 31, March 31, 2001 2002 ------------- ---------- Borrowing base facility $ 7,166,000 $ 6,626,000 Senior subordinated notes 21,635,252 21,952,830 Senior subordinated notes, related parties 2,403,916 2,439,202 Capital lease obligation 232,919 215,157 Non-recourse note payable to Rocky Mountain Gas, Inc. 6,750,000 6,375,000 ------------- ---------- 38,188,087 37,608,189 Less: current maturities (2,107,030) (1,574,980) ------------- ---------- $36,081,057 $36,033,209 =========== ===========
Carrizo amended its existing credit facility with Compass Bank ("Compass") in September 1998 to provide for a Term Loan under the facility (the "Term Loan") in addition to the then existing revolving credit facility limited by the Company's borrowing base (the "Borrowing Base Facility") which provided for a maximum loan amount of $25 million subject to Borrowing Base limitations. The Borrowing Base Facility was amended in March 1999 to provide for a maximum loan amount under such facility of $10 million. Substantially all of Carrizo's oil and natural gas property and equipment is pledged as collateral under this facility. The interest rate for both borrowings is calculated at a floating rate based on the Compass index rate or LIBOR plus 2%. The Company's obligations are secured by certain of its oil and gas properties and cash or cash equivalents included in the borrowing base. Certain members of the Board of Directors had provided collateral, primarily in the form of marketable securities, to secure the revolving credit loans. This collateral was released during April 2001. The Borrowing Base Facility and the Term Loan are referred to collectively as the "Company Credit Facility". Proceeds from the Borrowing Base portions of this credit facility have been used to provide funding for exploration and development activity. In April 2001, the maturity date of the Borrowing Base Facility was extended from February 2002 to April 2003. Under the Borrowing Base Facility, Compass, in its sole discretion, will make semiannual borrowing base determinations based upon the proved oil and natural gas properties of the Company. Compass may also redetermine the borrowing base and the monthly borrowing base reduction at any time at its discretion. The Company may also request borrowing base redeterminations in addition to the required semiannual reviews at the Company's cost. At December 31, 2001 and March 31, 2002, amounts outstanding under the Borrowing Base Facility totaled $7,166,000 and $6,626,000, respectively with an additional $620,000 and zero, respectively, available for future borrowings. The Borrowing Base totaled $7,786,000 and $6,850,000 at December 31, 2001 and March 31, 2002, respectively. The Borrowing Base Facility was also available for letters of credit, one of which has been issued for $224,000 at December 31, 2001 and March 31, 2002. The Borrowing Base facility was amended in November 2000 to provide up to $2 million of Guidance Line letters of credit (the "Guidance Line letters of credit") relating exclusively to the Company's outstanding hedge positions. At December 31, 2001 and March 31, 2002, the Company had no Guidance Line letters of credit outstanding. The Company is subject to certain covenants under the terms of the Company Credit Facility, including but not limited to (a) maintenance of specified tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly debt service of not less than 1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company Credit Facility also places restrictions on, among other things, (a) incurring additional indebtedness, guaranties, loans and liens, (b) changing the nature of business or business structure, (c) selling assets and (d) paying dividends. In March 1999, the Company Credit Facility was amended to decrease the required specified tangible net worth covenant. On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG as consideration for certain interest in oil and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $125,000 plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and gas leases in -6- Wyoming and Montana. At December 31, 2001 and March 31, 2002, the principal balance of this note was $6,750,000 and $6,375,000, respectively. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $243,369. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1. In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. (now known as J.P. Morgan Partners, LLC) which included certain members of the Board of Directors. The Company also sold Common Stock and Warrants to this investor group. The Subordinated Notes were sold at a discount of $688,761, which is being amortized over the life of the notes. Quarterly interest payments began on March 31, 2000. The Company may elect, for a period of up to five years to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2001 and March 31, 2002, the outstanding balance of the Subordinated Notes had been increased by $2,552,970 and $2,884,435, respectively, for such interest. The Company is subject to certain covenants under the terms under the Subordinated Notes securities purchase agreement, including but not limited to, (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) a limitation of its capital expenditures to a specified amount for the year ended December 31, 2000 and thereafter 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 appointed director). 4. INCOME TAXES: The Company provided deferred income taxes at the rate of 35%, which also approximates its statutory rate, that amounted to $1,882,944 and $99,539 for the three months ended March 31, 2001 and 2002, respectively. 5. COMMITMENTS AND CONTINGENCIES: From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in N. La Copita Prospect in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of their lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seek unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that the Company acted in good faith and intends to vigorously defend its position. The Company, along with GMT and other partners, are attempting to negotiate a settlement with ExxonMobil that would allow GMT et al (including the Company) to participate for their respective shares of a working interest in the Neblett unit, and would allow for the recovery of well costs. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its costs as a good faith trespasser. A complete loss of the lease in question would result in the loss to the Company of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with respect to these properties were included in the Company's reported proved reserves as of December 31, 2001 and March 31, 2002. At the time of shut in, the Neblett #1 well was producing at the rate of approximately 45 Mcfe per day, the Neblett #2 was producing at the rate of approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day, all net to the Company's interest. The Company believes that an unfavorable outcome in this matter would not have a material impact on its financial statements. The Company has recorded revenues only to the extent of well costs funded by the Company. -7- During November 2000, the Company entered into a one-year contract with Grey Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of drilling wells to a depth of approximately 18,000 feet. The contract provided for a dayrate of $12,000 per day. The rig was utilized primarily to drill wells in the Company's focus areas, including the Matagorda Project Area and the Cabeza Creek Project Area. The contract contained a provision which would allow the Company to terminate the contract early by tendering payment equal to one-half the dayrate for the number of days remaining under the term of the contract as of the date of termination. The contract commenced in February 2001 and expired in February 2002. Steven A. Webster, who is the Chairman of the Board of Directors of the Company, is a member of the Board of Directors of Grey Wolf, Inc. During August 2001, the Company entered into a one year agreement whereby the lessor will provide to the Company up to $800,000 in financing for production equipment utilizing capital leases. At December 31, 2001 and March 31, 2002, one lease in the amount of $243,369 had been executed under this facility. 6. CONVERTIBLE PARTICIPATING PREFERRED STOCK: In February 2002, the Company consummated the sale of $6 million of Convertible Participating Series B Preferred Stock and warrants to purchase Carrizo common stock to an investor group led by Mellon Ventures, Inc. which included Steven A. Webster, the Company's Chairman of the Board of Directors. The Series B Preferred Stock is convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustments, and is initially convertible into 1,052,632 shares of common stock. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of 8% per annum or, at the Company's option, by payment in kind of additional shares of the same series of preferred stock at a rate of 10% per annum. The financial statements at March 31, 2002 reflect an accrual for a dividend of 683.88 shares of Series B Preferred Stock. The Series B Preferred Stock is redeemable at varying prices in whole or in part at the holders' option after three years or at the Company's option at any time. The Series B Preferred Stock will also participate in any dividends declared on the common stock. Holders of the Preferred Stock will receive a liquidation preference upon the liquidation of, or certain mergers or sales of substantially all assets involving, the Company. Such holders will also have the option of receiving a change of control repayment price upon certain deemed change of control transactions. The warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo's common stock at a price of $5.94 per share, subject to adjustments, and are exercisable at any time after issuance. The warrants may be exercised on a cashless exercise basis. The approximately $5,800,000 proceeds of this financing are expected to be used primarily to fund the Company's ongoing exploration and development program. 7. COMMON STOCK: The Company issued 76,472 shares of common stock during the three months ended March 31, 2002 as part of the purchase of an interest in certain oil and gas properties. 8. CHANGE IN ACCOUNTING PRINCIPLE: In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities". This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument's fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for the Company beginning January 1, 2001 and was adopted by the Company on that date. In accordance with the current transition provisions of SFAS No. 133, the Company recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of its derivatives designated as cash flow hedging instruments at the date of adoption. Upon entering into a derivative contract, the Company designates the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and gas revenues when the forecasted -8- transaction occurs. All of the Company's derivative instruments at January 1, 2001 and December 31, 2001 and March 31, 2002 were designated and effective as cash flow hedges except for its positions with an affiliate of Enron Corp. discussed below. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and crude oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. Because of Enron's financial condition, the Company concluded that the derivatives contracts were no longer effective and thus did not qualify for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. For the quarter ended March 31, 2002, $232,000 was reclassified from other comprehensive income into oil and gas revenues. An allowance for the related asset totalling $759,000, net of tax of $409,000, was charged to other expense during the fourth quarter of 2001. At December 31, 2001 and March 31, 2002, $706,000, net of tax of $380,000, and $474,000 net of tax of $255,000, respectively, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. At March 31, 2002, the Company had recorded $370,000 of hedging losses in other comprehensive income, all of which is expected to be reclassified to earnings within the next twelve months. The amount ultimately reclassified to earnings will vary due to changes in the fair values of the derivatives designated as cash flow hedges prior to their settlement. Total oil and natural gas purchased and sold under swap arrangements during the three months ended March 31, 2001 and 2002 were 18,000 Bbls and zero Bbls, respectively, and 993,000 MMBtu and zero MMBtu, respectively. Losses realized by the Company under such swap arrangements were $1,013,000 and zero for the three months ended March 31, 2001 and 2002, respectively. At March 31, 2001, the Company had outstanding hedge positions covering 2,004,000 MMBtu and zero Bbls. The 2,004,000 MMBtu of natural gas hedges had an average floor of $4.73 and an average ceiling of $5.72 for April through December 2001 production. At March 31, 2002, the Company had outstanding hedge positions covering 1,705,000 MMBtu and 73,100 Bbls. The 1,705,000 of natural gas hedges had an average fixed price of $3.19 for April 2002 through December 2002 production. The oil hedges consisted of 18,200 Bbls at a fixed price of $24.65 for April 2002 through June 2002 production and 54,900 Bbls with a floor of $22.00 and a ceiling of $25.00 for April 2002 through September 2002 production. -9- ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is management's discussion and analysis of certain significant factors that have affected certain aspects of the Company's financial position and results of operations during the periods included in the accompanying unaudited financial statements. This discussion should be read in conjunction with the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the annual financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 and the unaudited financial statements included elsewhere herein. Unless otherwise indicated by the context, references herein to "Carrizo" or "Company" mean Carrizo Oil & Gas, Inc., a Texas corporation that is the registrant. GENERAL OVERVIEW The Company began operations in September 1993 and initially focused on the acquisition of producing properties. As a result of the increasing availability of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic data and options to lease substantial acreage in 1995 and began to drill its 3-D based prospects in 1996. The Company drilled 25 gross wells in the Gulf Coast region in 2001 and 4 gross wells through the three months ended March 31, 2002. The Company has budgeted to drill up to 16 gross wells (6.6 net) in the Gulf Coast region in 2002; however, the actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, Company cash flow, success of drilling programs, weather delays and other factors. If the Company drills the number of wells it has budgeted for 2002, depreciation, depletion and amortization, oil and gas operating expenses and production are expected to increase over levels incurred in 2001. The Company has typically retained the majority of its interests in shallow, normally pressured prospects and sold a portion of its interests in deeper, overpressured prospects. The Company has primarily grown through the internal development of properties within its exploration project areas, although the Company acquired properties with existing production in the Camp Hill Project in late 1993, the Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company made these acquisitions through the use of limited partnerships with Carrizo or Carrizo Production, Inc. as the general partner. In addition, in November 1998, the Company acquired assets in Wharton County, Texas in the Jones Branch project area for $3,000,000. During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM") as a wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane and develop such interests. CCBM plans to spend up to $5 million for drilling costs on these leases through December 2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of RMG, from whom the interests in the leases were acquired. CCBM drilled 31 gross wells (12.0 net) and incurred total drilling costs of $819,000 in 2001 and drilled eight gross wells (four net) and incurred total drilling costs of $306,000 through the three months ended March 31, 2002. These wells typically take up to 18 months to evaluate and determine whether or not they are successful. CCBM has budgeted to drill 30 gross (15 net) wells in 2002. In order to reduce its exposure to short-term fluctuations in the price of oil and natural gas, and not for speculation purposes, the Company periodically enters into hedging arrangements. The Company's hedging arrangements apply to only a portion of its production and provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, the Company's hedging arrangements limit the benefit to the Company of increases in the price of oil and natural gas. At March 31, 2002, the Company had recorded $370,000 of hedge losses in other comprehensive income, all of which is expected to be reclassified to current earnings within the next twelve months. The amount ultimately reclassified to earnings will vary due to changes in the fair value of the derivatives designated as cash flow hedges prior to their settlement. Total oil and natural gas purchased and sold under swap arrangements during the three months ended March 31, 2001 and 2002 were 18,000 Bbls and zero Bbls, respectively, and 993,000 MMBtu and zero MMBtu, respectively. Losses realized by the Company under such swap arrangements were $1,013,000 and zero for the three months ended March 31, 2001 and 2002, respectively. At March 31, 2001, the Company had outstanding hedge positions covering 2,004,000 MMBtu and zero Bbls. The 2,004,000 MMBtu of natural gas hedges had an average floor of $4.73 and an average ceiling of $5.72 for April through December 2001 production. At March 31, 2002, the Company had outstanding hedge positions covering 1,705,000 MMBtu and 73,100 Bbls. The 1,705,000 of natural gas hedges had an -10- average fixed price of $3.19 for April 2002 through December 2002 production. The oil hedges consisted of 18,200 Bbls at a fixed price of $24.65 for April 2002 through June 2002 production and 54,900 Bbls with a floor of $22.00 and a ceiling of $25.00 for April 2002 through September 2002 production. The Company's gas hedge prices are based on Houston Ship Channel prices. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. On January 1, 2001, the Company adopted Statement of Financial Standards No. 133. See Note 8 to the Financial Statements. In November 2001, the Company had no-cost collars with an affiliate of Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from December 2001 through December 2002. The value of these derivatives at that time was $759,000. Because of Enron's financial condition, the Company concluded that the derivatives contracts were no longer effective and thus did not qualify for hedge accounting treatment. As required by SFAS No. 133, the value of these derivative instruments as of November 2001 ($759,000) was recorded in accumulated other comprehensive income and will be reclassified into earnings over the original term of the derivative instruments. For the quarter ended March 31, 2002, $232,000 was reclassified from other comprehensive income into oil and gas revenues. An allowance for the related asset totalling $759,000, net of tax of $409,000, was charged to other expense during the fourth quarter of 2001. At December 31, 2001 and March 31, 2002, $706,000, net of tax of $380,000, and $474,000 net of tax of $255,000, respectively, remained in accumulated other comprehensive income related to the deferred gains on these derivatives. The Company uses the full-cost method of accounting for its oil and gas properties. Under this method, all acquisition, exploration and development costs, including any general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. The Company records depletion of its full-cost pool using the unit-of-production method. To the extent that such capitalized costs in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations. Primarily as a result of depressed oil and natural gas prices, and the resulting downward reserve quantities revisions, the Company recorded a ceiling test write-down of $20.3 million in 1998. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a ceiling writedown. Using prices in effect on December 31, 2001 the pretax writedown would have been approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown in future periods. A ceiling test write-down was not required for the three months ended March 31, 2002 and 2001. Once incurred, a write-down of oil and gas properties is not reversible at a later date. RESULTS OF OPERATIONS Three Months Ended March 31, 2002, Compared to the Three Months Ended March 31, 2001 Oil and natural gas revenues for the three months ended March 31, 2002 decreased 54% to $4,027,000 from $8,727,000 for the same period in 2001. Production volumes for natural gas during the three months ended March 31, 2002 decreased 5% to 1,098,616 from 1,161,050 for the same period in 2001. Average natural gas prices decreased 60% to $2.67 per Mcf in the first quarter of 2002 from $6.66 per Mcf in the same period in 2001. Production volumes for oil in the first quarter of 2002 increased 42% to 53,209 Bbls from 37,460 Bbls for the same period in 2001. Average oil prices decreased 23% to $20.50 per barrel in the first quarter of 2002 from $26.69 per barrel in the same period in 2001. The increase in oil production was due primarily to the commencement of production at the Staubach #1 and Riverdale #2 wells offset by the natural decline in production from other wells. The decrease in natural gas production was due primarily to the loss of production from the N. La Copita wells and the natural decline in production primarily at the initial Matagorda Project wells and Jones Branch wells offset by the commencement of production at the Staubach #1 and Riverdale #2 wells. Oil and natural gas revenues include the impact of hedging activities as discussed above under "General Overview". -11- The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the three months ended March 31, 2001 and 2002:
2002 Period Compared to 2001 Period March 31, --------------------------- -------------------------------- Increase % Increase 2001 2002 (Decrease) (Decrease) -------------------------------- ------------- ------------- Production volumes - Oil and condensate (Bbls) 37,460 53,209 15,749 42% Natural gas (Mcf) 1,161,050 1,098,616 (62,434) (5%) Average sales prices - (1) Oil and condensate (per Bbls) $ $26.69 $ 20.50 (6.19) (23%) Natural gas (per Mcf) 6.66 2.67 (3.99) (60%) Operating revenues - Oil and condensate $ 999,832 $1,090,726 $ 90,894 9% Natural gas 7,727,649 2,936,167 (4,791,482) (62%) ------------- ---------- ----------- Total $ 8,727,481 $4,026,893 $(4,700,588) (54%) ============= ========== ===========
------------------ (1) Includes impact of hedging activities. Oil and natural gas operating expenses for the three months ended March 31, 2002 decreased 22% to $1,013,000 from $1,300,000 for the same period in 2001 primarily due to lower severance taxes offset by higher ad valorem taxes and the addition of new production. Operating expenses per equivalent unit decreased 23% to $.71 per Mcfe in the first quarter of 2002 from $.94 per Mcfe in the same period in 2001 primarily as a result of lower severance taxes offset by higher ad valorem taxes. Depreciation, depletion and amortization (DD&A) expense for the three months ended March 31, 2002 increased 21% to $1,970,000 from $1,630,000 for the same period in 2001. This increase was due to increased production and additional seismic and drilling costs. General and administrative expense for the three months ended March 31, 2002 increased 5% to $916,000 from $870,000 for the same period in 2001 primarily as a result of the addition of staff to handle increased drilling and production activities. Income taxes decreased to $140,000 for the three months ended March 31, 2002 from $1,916,000 for the same period in 2001. Interest income for the three months ended March 31, 2002 decreased to $20,000 from $121,000 in the first quarter of 2001 primarily as a result of lower interest rates during the first quarter of 2002. Capitalized interest decreased to $768,000 in the first quarter of 2002 from $802,000 in the first quarter of 2001 primarily due to lower interest during the first quarter of 2002. Income before income taxes for the three months ended March 31, 2002 decreased to $285,000 from $5,380,000 in the same period in 2001. Net income for the three months ended March 31, 2002 decreased to $144,000 from $3,464,000 for the same period in 2001 primarily as a result of the factors described above. LIQUIDITY AND CAPITAL RESOURCES The Company has made and is expected to make oil and gas capital expenditures in excess of its net cash flow from operations in order to complete the exploration and development of its existing properties. The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the Company and to fund leasehold costs and geological and geophysical costs on its active exploration projects. While the Company believes that the current cash balances and anticipated 2002 operating cash flow will provide sufficient capital to carry out the Company's 2002 exploration plans, management of the Company continues to seek financing for its capital program from a variety of sources. No assurance can be given that the Company will be able to obtain additional financing on terms that would be acceptable to the Company. The Company's inability to obtain additional financing could have a material adverse effect on the Company. Without raising additional capital, the Company anticipates that it may be required to limit or defer its planned oil and gas -12- exploration and development program, which could adversely affect the recoverability and ultimate value of the Company's oil and gas properties. The Company's primary sources of liquidity have included proceeds from the 1997 initial public offering, from the December 1999 sale of Subordinated Notes, Common Stock and Warrants, the 2002 sale of shares of Series B Convertible Participating Preferred Stock and Warrants, the 1998 sale of shares of Series A Preferred Stock and Warrants, funds generated by operations, equity capital contributions, borrowings (primarily under revolving credit facilities) and the Palace Agreement that provided a portion of the funding for the Company's 1999, 2000, 2001 and 2002 drilling program in return for participation in certain wells. Cash flows provided by operations (after changes in working capital) were $4,809,000 and $2,504,000 for the three months ended March 31, 2001 and 2002, respectively. The decrease in cash flows provided by operations in 2002 as compared to 2001 was due primarily to additional revenue as a result of higher oil and natural gas prices during the first quarter of 2001. The Company has budgeted capital expenditures for the year ended December 31, 2002 of approximately $17.7 million of which $2.8 million is expected to be used to fund 3-D seismic surveys and land acquisitions and $14.9 million of which is expected to be used for drilling activities in the Company's project areas. The Company has budgeted to drill up to approximately 16 gross wells (6.6 net) in the Gulf Coast region and up to 30 gross (15 net) CCBM coalbed methane wells in 2002. The actual number of wells drilled and capital expended is dependent upon available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. The Company has continued to reinvest a substantial portion of its cash flows into increasing its 3-D supported drilling prospect portfolio, improving its 3-D seismic interpretation technology and funding its drilling program. Oil and gas capital expenditures were $5.8 million for the three months ended March 31, 2002, which included $926,000 of capitalized interest and general and administrative costs. The Company's drilling efforts in the Gulf Coast region resulted in the successful completion of 20 gross wells (5.9 net) during the year ended December 31, 2001 and 4 gross wells (1.9 net) during the three months ended March 31, 2002. All of the 39 gross wells (16 net) drilled by CCBM are awaiting evaluation before a determination can be made as to their success. FINANCING ARRANGEMENTS In connection with Carrizo's initial public offering in 1997, Carrizo entered into an amended revolving credit facility with Compass Bank (the "Company Credit Facility"), to provide for a maximum loan amount of $25 million, subject to borrowing base limitations. The principal outstanding is due and payable in April 2003, with interest due monthly. The Company Credit Facility was amended in March 1999 to provide for a maximum loan amount under such facility of $10 million. The interest rate on all revolving credit loans is calculated, at the Company's option, at a floating rate based on the Compass index rate or LIBOR plus 2%. The Company's obligations are secured by substantially all of its oil and gas properties and cash or cash equivalents included in the borrowing base. Under the Company Credit Facility, Compass, in its sole discretion, will make semiannual borrowing base determinations based upon the proved oil and natural gas properties of the Company. Compass may also redetermine the borrowing base and the monthly borrowing base reduction at any time at its discretion. The Company may also request borrowing base redeterminations in addition to the required semiannual reviews at the Company's cost. The Company is subject to certain covenants under the terms of the Company Credit Facility, including but not limited to (a) maintenance of specified tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly debt service of not less than 1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company Credit Facility also places restrictions on, among other things, (a) incurring additional indebtedness, guaranties, loans and liens, (b) changing the nature of business or business structure, (c) selling assets and (d) paying dividends. Proceeds of the revolving credit loans have been used to provide funding for exploration and development activity. At December 31, 2001 and March 31, 2002, outstanding revolving credit loans totaled $7,166,000 and $6,626,000, respectively, with an additional $620,000 and zero, respectively, available for future borrowings. The Company Credit Facility also provides for the issuance of letters of credit, one of which has been issued for $224,000 at December 31, 2001 and March 31, 2002. The Borrowing Base facility was amended in November 2000 to provide up to $2 million of Guidance Line letters of credit (the "Guidance Line letters of credit") relating exclusively to the Company's outstanding hedge positions. At December 31, 2001 and March 31, 2002, the Company had no Guidance Line letters of credit outstanding. The Company is seeking to refinance the Company Credit Facility and has entered into a commitment letter with a bank for a replacement facility. The commitment letter contemplates a new credit facility with an increased borrowing base and extended maturity as compared to the current Company Credit Facility. The commitment letter is subject to several conditions and in any event there can be no assurance as to the final terms of, or whether the Company will enter into, any new credit facility. -13- On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company ("CCBM"), issued a non-recourse promissory note payable in the amount of $7,500,000 to RMG as consideration for certain interest in oil and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal payments of $125,000 plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM's interests in the oil and gas leases in Wyoming and Montana. In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $243,369. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1. In December 1999, the Company consummated the sale of $22 million principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. (now JPMorgan Partners) which included certain members of the Board of Directors. The Subordinated Notes were sold at a discount of $688,761 which is being amortized over the life of the notes. Interest is payable quarterly beginning March 31, 2000. The Company may elect, for a period of five years, to increase the amount of the Subordinated Notes for up to 60% of the interest which would otherwise be payable in cash. The Subordinated Notes were increased by $2,552,970 and $2,884,435 for such interest as of December 31, 2001 and March 31, 2002, respectively. Concurrent with the sale of the notes, the Company consummated the sale of 3,636,364 shares of Common Stock at a price of $2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's Common Stock at an exercise price of $2.20 per share. For accounting purposes, the Warrants are valued at $0.25 per Warrant. The Warrants have an exercise price of $2.20 per share and expire in December 2007. The Company is subject to certain covenants under the terms under the related Securities Purchase Agreement, including but not limited to, (a) maintenance of a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) limit its capital expenditures to a specified amount for the year ended December 31, 2000, and thereafter 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 appointed director), as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates (vi) make certain repayments and prepayments, including any prepayment of the Company's Term Loan, any subordinated debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect certain permanent reductions in revolving credit facilities. Of the approximately $29,000,000 net proceeds of this financing, $12,060,000 was used to fund the repurchase from certain Enron Corporation affiliates of all the outstanding shares of Series A Preferred Stock and 750,000 Warrants and related expenses, $2,025,000 was used to repay the bridge loan extended to the Company by its outside directors, $2 million was used to repay a portion of the Compass Term Loan, $1 million was used to repay a portion of the Compass Borrowing Base Facility, and the Company expects the remaining proceeds were used to fund the Company's ongoing exploration and development program and general corporate purposes. In February 2002, the Company consummated the sale of 60,000 shares of Series B Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common Stock for an aggregate purchase price of $6,000,000 to an investor group led by Mellon Ventures, L.P. which included Steven A. Webster, the Company's Chairman of the Board of Directors. The Series B Preferred Stock is convertible into Common Stock by the investors at a conversion price of $5.70 per share, subject to adjustment, and is initially convertible into 1,052,632 shares of Common Stock. The approximately $5,800,000 net proceeds of this financing are expected to be used to fund the Company's ongoing exploration and development program and general corporate purposes. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of 8% per annum or, at the Company's option, by payment in kind of additional shares of the Series B Preferred Stock at a rate of 10% per annum. The financial statements at March 31, 2002 reflect an accrual for a dividend of 683.88 shares of Series B Preferred Stock. In addition to the foregoing, if the Company declares a cash dividend on the Common Stock of the Company, the holders of shares of Series B Preferred Stock are entitled to receive for each share of Series B Preferred Stock a cash dividend in the amount of the cash dividend that would be received by a holder of the Common Stock into which such share of Series B Preferred Stock is convertible on the record date for such cash dividend. Unless all accrued dividends on the Series B Preferred Stock shall have been paid and a sum sufficient for the payment thereof set apart, no distributions may be paid on any Junior Stock (which includes the Common Stock) (as defined in the Statement of Resolutions for the Series B Preferred Stock) and no redemption of any Junior Stock shall occur other than subject to certain exceptions. -14- The Series B Preferred Stock is required to be redeemed by the Company at any time after the third anniversary of the initial issuance of the Series B Preferred Stock (the "Issue Date") upon request from any holder at a price per share equal to Purchase Price/Dividend Preference (as defined below). The Company may redeem the Series B Preferred Stock after the third anniversary of the Issue Date, at a price per share equal to the Purchase Price/Dividend Preference and, prior to that time, at varying preferences to the Purchase Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus all cumulative and accrued dividends on such share of Series B Preferred Stock. In the event of any dissolution, liquidation or winding up or certain mergers or sales or other disposition by the Company of all or substantially all of its assets (a "Liquidation"), the holder of each share of Series B Preferred Stock then outstanding will be entitled to be paid out of the assets of the Company available for distribution to its shareholders, the greater of the following amounts per share of Series B Preferred Stock: (i) $100 in cash plus all cumulative and accrued dividends and (ii) in certain circumstances, the "as-converted" liquidation distribution, if any, payable in such Liquidation with respect to each share of Common Stock. Upon the occurrence of certain events constituting a "Change of Control" (as defined in the Statement of Resolutions), the Company is required to make a offer to each holder of Series B Preferred Stock to repurchase all of such holder's Series B Preferred Stock at an offer price per share of Series B Preferred Stock in cash equal to 105% of the Change of Control Purchase Price, which is generally defined to mean $100 plus all cumulative and accrued dividends. The 2002 Warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share, subject to adjustment, and are exercisable at any time after issuance. For accounting purposes, the 2002 Warrants are valued at $0.06 per 2002 Warrant. EFFECTS OF INFLATION AND CHANGES IN PRICE The Company's results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that the Company is required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on the Company. CRITICAL ACCOUNTING POLICIES Oil and Natural Gas Properties Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company proportionally consolidates its interests in oil and gas properties. Additionally, the Company capitalized compensation costs for employees working directly on exploration activities of $276,000 and $214,000 for the three months ended March 31, 2001 and 2002. Oil and natural gas properties are amortized based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. Unevaluated properties are evaluated periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per thousand cubic feet equivalent (Mcfe) for the three months ended March 31, 2001 and 2002, was $1.10 and $1.35, respectively. Dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The net capitalized costs of proved oil and gas properties are subject to a "ceiling test," which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net revenues from proved reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company's oil and natural gas assets was necessary for the three months ended March 31, 2001 and 2002. Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a ceiling writedown. Using prices in effect on December 31, 2001 the pretax writedown would have been -15- approximately $700,000. Because of the volatility of oil and gas prices, no assurance can be given that the Company will not experience a ceiling test writedown in future periods. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years. Stock-Based Compensation The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations. Under this method, the Company records no compensation expense for stock options granted when the exercise price of those options is equal to or greater than the market price of the Company's common stock on the date of grant. Repriced options are accounted for as compensatory options using variable accounting treatment. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock. Variable plan accounting is applied to the repriced options until the options are exercised, forfeited, or expired unexercised. Derivative Instruments and Hedging Activities In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities". This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument's fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for the Company beginning January 1, 2001 and was adopted by the Company on that date. In accordance with the current transition provisions of SFAS No. 133, the Company recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of its derivatives designated as cash-flow hedging instruments at the date of adoption. Upon entering into a derivative contract, the Company designates the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and gas revenues when the forecasted transaction occurs. All of the Company's derivative instruments at January 1, 2001 and December 31, 2001 were designated and effective as cash flow hedges except for its positions with an affiliate of Enron Corp. discussed in Note 12 to the Consolidated Financial Statements. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings. The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and crude oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. The Company's Board of Directors sets all of the Company's hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. -16- Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Significant estimates include depreciation, depletion and amortization of proved oil and natural gas properties and future income taxes. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, are inherently imprecise and are expected to change as future information becomes available. Concentration of Credit Risk Substantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables. -17 PART II. OTHER INFORMATION Item 1 - Legal Proceedings From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in N. La Copita in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of their lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seeks unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that the Company acted in good faith and intends to vigorously defend its position. The Company, along with GMT and other partners, are attempting to negotiate a settlement with ExxonMobil that would allow GMT et al (including the Company) to participate for their respective shares of a working interest in the Neblett unit, and would allow for the recovery of well costs. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its costs as a good faith trespasser. A complete loss of the lease in question would result in the loss to the Company of approximately .6 Bcfe of reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved reserves as of June 30, 2001. No reserves with respect to these properties were included in the Company's reported proved reserves as of December 31, 2001 and March 31, 2002. At the time of shut in, the Neblett #1 well was producing at a rate of approximately 45 Mcfe per day, the Neblett #2 well was producing at the rate of approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate of approximately 895 Mcfe per day, all net to the Company's interest. The Company believes that an unfavorable outcome in this matter would not have a material impact on its financial statements. The Company has recorded revenues only to the extent of well costs funded by the Company. Item 2 - Changes in Securities and Use of Proceeds In February 2002 the Company consummated the sale of Series B Preferred Stock and the 2002 Warrants. See Part II, Item 7 of the Company's annual report on Form 10-K for the year ended December 31, 2001, "Management's Discussion and Analysis of Financial Conditions and Results of Operations - Financing Arrangements" in this report and "Certain Transactions" in the Company's proxy statement for the 2002 annual meeting. In December 2001, the Company issued 2,750 shares of Common Stock to Heartland Resources, Inc. for previous assignments of mineral leases. In January, 2002, the Company issued 76,472 shares of Common Stock to several individuals as part of the purchase of an interest in certain oil and gas properties. Each of the sales of shares is exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a transaction not involving a public offering. Item 3 - Defaults Upon Senior Securities None Item 4 - Submission of Matters to a Vote of Security Holders None Item 5 - Other Information FORWARD LOOKING STATEMENTS The statements contained in all parts of this document, including, but not limited to, those relating to the Company's schedule, targets, estimates or results of future drilling, budgeted wells, increases in wells, budgeted and other future capital expenditures, use of offering proceeds, outcome and effects of litigation, recovery of well costs in litigation, expected production or -18- reserves, increases in reserves, acreage working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words "anticipate," "estimate," "expect," "may," "project," "believe" and similar expression are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company's dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to, limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather and other factors detailed in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 and other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. Item 6 - Exhibits and Reports on Form 8-K Exhibits
Exhibit Number Description ------ ----------- +2.1 -- Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of September 6, 1997 (incorporated herein by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-29187)). +3.1 -- Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). +3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (incorporated herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A (Registration No. 000-22915) Amendment No. 2 (incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999) and Amendment No. 3 (Incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated February 20, 2002). +3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other rights thereof (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated February 20, 2002).
+ Incorporated herein by reference as indicated. Reports on Form 8-K On February 27, 2002, the Company filed a Current Report on Form 8-K to disclose the closing of the sale of convertible participating Series B Preferred Stock and 2002 Warrants. On April 12, 2002, the Company filed a Current Report on Form 8-K to disclose the change in the Company's independent public accountants. -19- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. Carrizo Oil & Gas, Inc. (Registrant) Date: May 10, 2002 By: /s/S. P. Johnson, IV -------------------------------------------- President and Chief Executive Officer (Principal Executive Officer) Date: May 10, 2002 By: /s/Frank A. Wojtek -------------------------------------------- Chief Financial Officer (Principal Financial and Accounting Officer) -20-