CARRIZO OIL & GAS INC - 10-Q Quarterly Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended MARCH 31, 2003
--------------

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the transition period from ________ to _________

Commission File Number 000-22915.

CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)

TEXAS 76-0415919
----- ----------
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)

14701 ST. MARY'S LANE, SUITE 800, HOUSTON, TX 77079
- --------------------------------------------- -----
(Address of principal executive offices) (Zip Code)

(281) 496-1352
--------------
(Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days.

YES [X] NO [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 126-2 of the Exchange Act).

YES [ ] NO [X]

The number of shares outstanding of the registrant's common stock, par value
$0.01 per share, as of May 1, 2003, the latest practicable date, was 14,200,716.

CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
INDEX

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

The accompanying notes are an integral part of these consolidated
financial statements.

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

The accompanying notes are an integral part of these consolidated
financial statements.

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

The accompanying notes are an integral part of these consolidated
financial statements.

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ACCOUNTING POLICIES:

The consolidated financial statements included herein have been prepared by
Carrizo Oil & Gas, Inc. (the Company), and are unaudited, except for the balance
sheet at December 31, 2002, which has been prepared from the audited financial
statements at that date. The financial statements reflect the accounts of the
Company and its subsidiary after elimination of all significant intercompany
transactions and balances. The financial statements reflect necessary
adjustments, all of which were of a recurring nature, and are in the opinion of
management necessary for a fair presentation. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been omitted pursuant to the
rules and regulations of the Securities and Exchange Commission (SEC). The
Company believes that the disclosures presented are adequate to allow the
information presented not to be misleading. The financial statements included
herein should be read in conjunction with the audited financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002.

2. EARNINGS PER COMMON SHARE:

Supplemental earnings per share information is provided below:

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Basic earnings per common share is based on the weighted average number of
shares of common stock outstanding during the periods. Diluted earnings per
common share is based on the weighted average number of common shares and all
dilutive potential common shares outstanding during the periods. The Company had
outstanding 189,833 and 149,833 stock options and 252,632 warrants during the
three months ended March 31, 2002 and 2003, respectively, which were
antidilutive and were not included in the calculation because the exercise price
of these instruments exceeded the underlying market value of the options and
warrants. At March 31, 2002 and 2003, the Company also had 1,052,632 and zero
shares, respectively, based on the assumed conversion of the Series B
Convertible Participating Preferred Stock, that were antidilutive and were not
included in the calculation.

3. LONG-TERM DEBT:

At December 31, 2002 and March 31, 2003, long-term debt consisted of the
following:

On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by the Mortgaged Properties, which include substantially all of the
Company's producing oil and gas properties, and is guaranteed by the Company's
subsidiary.

The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million, and the borrowing base as of October 31, 2002 was $13.0 million.
Each party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2002,
was $1.3 million. The quarterly borrowing base reduction effective January 31,
2003 was $1.8 million.

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On December 12, 2002, the Company entered into an Amended and Restated Credit
Agreement with Hibernia National Bank that provided additional availability
under the Hibernia Facility in the amount of $2.5 million which was structured
as an additional "Facility B" under the Hibernia Facility. As such, the total
borrowing base under the Hibernia Facility as of December 31, 2002 and March 31,
2003 was $15.5 million and $13.8 million, respectively, of which $8.5 million
was outstanding on December 31, 2002 and March 31, 2003 and $6.5 million is
currently drawn. The Facility B bore interest at LIBOR plus 3.375%, was secured
by certain leases and working interests in oil and natural gas wells and matured
on April 30, 2003.

If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.

If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.

For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.

The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of the Company's common or preferred
stock, speculative commodity transactions, and other matters.

At December 31, 2002 and March 31, 2003, amounts outstanding under the Hibernia
Facility totaled $8.5 million with an additional $4.3 million and $2.5 million,
respectively, under Facility A and $2.5 million under Facility B available for
future borrowings. No amounts under the Compass Facility were outstanding at
December 31, 2002. At December 31, 2002 and March 31, 2003, one letter of credit
was issued and outstanding under the Hibernia Facility in the amount of $0.2
million.

On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7.5 million to
RMG as consideration for certain interests in oil and natural gas leases held by
RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal
payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001
with the balance due December 31, 2004. The RMG note is secured solely by CCBM's
interests in the oil and natural gas leases in Wyoming and Montana. At December
31, 2002 and March 31, 2003, the outstanding principal balance of this note was
$5.3 million and $4.9 million, respectively.

In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, the Company entered a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. The Company has the option to acquire the equipment at the conclusion
of the lease for $1, under both leases. DD&A on the capital leases for the three
months ended March 31, 2002 and 2003 amounted to $6,000 and $10,000,
respectively, and accumulated DD&A on the leased equipment at December 31, 2002
and March 31, 2003 amounted to $28,000 and $38,000, respectively.

In December 1999, the Company consummated the sale of $22.0 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and
$8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2
million, $0.8 million, $0.8 million and $0.8 million principal amount of
Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of
the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006
Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC),
Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P.
Hamilton,

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respectively. The Subordinated Notes were sold at a discount of $0.7 million,
which is being amortized over the life of the notes. Interest payments are due
quarterly commencing on March 31, 2000. The Company may elect, for a period of
up to five years, to increase the amount of the Subordinated Notes for 60% of
the interest which would otherwise be payable in cash. As of December 31, 2002
and March 31, 2003, the outstanding balance of the Subordinated Notes had been
increased by $3.9 million and $4.3 million, respectively, for such interest paid
in kind.

The Company is subject to certain covenants under the terms of the Subordinated
Notes securities purchase agreement, including but not limited to, (a)
maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director),
as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur
or allow liens, (iii) engage in mergers, consolidation, sales of assets and
acquisitions, (iv) declare dividends and effect certain distributions (including
restrictions on distributions upon the Common Stock), (v) engage in transactions
with affiliates and (vi) make certain repayments and prepayments, including any
prepayment of the subordinated debt, indebtedness that is guaranteed or
credit-enhanced by any affiliate of the Company, and prepayments that effect
certain permanent reductions in revolving credit facilities. EBITDA was part of
a negotiated covenant with the purchasers and is presented here as a disclosure
of the Company's covenant obligations.

At December 31, 2002 and March 31, 2003, the Company believes it was in
compliance with all of its debt covenants.

4. INCOME TAXES:

The Company provided deferred income taxes at the rate of 35%, which also
approximates its statutory rate, that amounted to $0.1 million and $1.6 million
for the three months ended March 31, 2002 and 2003, respectively.

5. COMMITMENTS AND CONTINGENCIES:

From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.

The operations and financial position of the Company continue to be affected
from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.

During August 2001, the Company entered into an agreement whereby the lessor
will provide to the Company up to $0.8 million in financing for production
equipment utilizing capital leases. At December 31, 2002 and March 31, 2003, two
leases in the amount of $0.5 million had been executed under this facility.

Pursuant to agreements entered into with RMG in June 2001, CCBM has an
obligation to fund $2.5 million of drilling costs on behalf of RMG. Through
March 31, 2003, CCBM had satisfied $1.7 million of the drilling obligation on
behalf of RMG.

6. CONVERTIBLE PARTICIPATING PREFERRED STOCK:

In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and Warrants to purchase Carrizo 252,632 shares of common stock for an
aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000
shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon
Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock
is convertible into common stock by the investors at a conversion price of $5.70
per share, subject to adjustments, and is initially convertible into 1,052,632
shares of common stock. Dividends on the Series B Preferred Stock will be
payable in either cash at a rate of 8% per annum or, at the Company's option, by
payment in kind of additional shares of the same series of preferred stock at a
rate of 10% per annum. At December 31, 2002 and March 31, 2003, the outstanding
balance of the Series B Preferred Stock has been increased by $0.5 million
(5,294 shares) for dividends paid in kind. The Series B Preferred Stock is
redeemable at varying prices in whole or in part at the holders' option after
three years or at the Company's option at any time. The Series B Preferred Stock
will also participate in any dividends declared on the common stock. Holders of
the Series B Preferred Stock will receive a liquidation preference upon the
liquidation of, or certain mergers or sales of substantially all assets
involving, the Company. Such holders will also have the option of receiving a
change of

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control repayment price upon certain deemed change of control transactions. The
warrants have a five-year term and entitle the holders to purchase up to 252,632
shares of Carrizo's common stock at a price of $5.94 per share, subject to
adjustments, and are exercisable at any time after issuance. The warrants may be
exercised on a cashless exercise basis.

Net proceeds of this financing were approximately $5.8 million and were used
primarily to fund the Company's ongoing exploration and development program and
general corporate purposes.

7. SHAREHOLDER'S EQUITY:

The Company issued 76,472 and 23,333 shares of common stock during the three
months ended March 31, 2002 and March 31, 2003, respectively. The shares issued
during the three months ended March 31, 2002 were partial consideration for the
acquisition of an interest in certain oil and natural gas properties and the
shares issued during the three months ended March 31, 2003 were the result of
the exercise of options granted under the Company's Incentive Plan.

In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation", which requires the Company to record
stock-based compensation at fair value. In December 2002, the FASB issued SFAS
No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure".
The Company has adopted the disclosure requirements of SFAS No. 148 and has
elected to record employee compensation expense utilizing the intrinsic value
method permitted under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees". The Company accounts for its
employees' stock-based compensation plan under APB Opinion No. 25 and its
related interpretations. Accordingly, any deferred compensation expense would be
recorded for stock options based on the excess of the market value of the common
stock on the date the options were granted over the aggregate exercise price of
the options. This deferred compensation would be amortized over the vesting
period of each option. Had compensation cost been determined consistent with
SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the
Company's net income (loss) and earnings per share would have been as follows:

Diluted earnings per share amounts for the three months ended March 31, 2002 and
2003 are based upon 16,233,807 and 16,311,251 shares, respectively, that include
the dilutive effect of assumed stock option and warrant conversions of 2,105,154
and 2,113,117, respectively.

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8. CHANGE IN ACCOUNTING PRINCIPLE:

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This Statement is effective for
fiscal years beginning after June 15, 2002, and the Company adopted the
Statement effective January 1, 2003. During the three months ended March 31,
2003, the Company recorded a cumulative effect of change in accounting principle
of $0.1 million, $0.4 million as proved properties and $0.5 million as a
liability for its plugging and abandonment expenses.

9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY:

The Company's operations involve managing market risks related to changes in
commodity prices. Derivative financial instruments, specifically swaps, futures,
options and other contracts, are used to reduce and manage those risks. The
Company addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. The Company
enters into swaps, options, collars and other derivative contracts to hedge the
price risks associated with a portion of anticipated future oil and natural gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at expiration or exchanged for physical delivery contracts. The
Company enters into the majority of its hedging transactions with two
counterparties and a netting agreement is in place with those counterparties.
The Company does not obtain collateral to support the agreements but monitors
the financial viability of counterparties and believes its credit risk is
minimal on these transactions. In the event of nonperformance, the Company would
be exposed to price risk. The Company has some risk of accounting loss since the
price received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of the
hedging transaction.

In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts were no longer effective and thus did
not qualify for hedge accounting treatment. As required by SFAS No. 133, the
value of these derivative instruments as of November 2001 $(0.8 million) was
recorded in accumulated other comprehensive income and will be reclassified into
earnings over the original term of the derivative instruments. An allowance for
the related asset totalling $0.8 million, net of tax of $0.4 million, was
charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4
million, remained in accumulated other comprehensive income related to the
deferred gains on these derivatives. The remaining balance in other
comprehensive income was reported as oil and natural gas revenues in 2002 as the
terms of the original derivative expired.

As of December 31, 2002 and March 31, 2003, $0.4 million and $0.7 million, net
of tax of $0.2 million and $0.4 million, respectively, remained in accumulated
other comprehensive income related to the valuation of the Company's hedging
positions.

Total oil purchased and sold under swaps and collars during the three months
ended March 31, 2002 and 2003 were zero Bbls and 63,000 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars in the three months
ended March 31, 2002 and 2003 were zero MMBtu and 540,000 MMBtu, respectively.
The net losses realized by the Company under such hedging arrangements were zero
and $1.2 million for the three months ended March 31, 2002 and 2003,
respectively, and are included in oil and natural gas revenues.

At December 31, 2002 and March 31, 2003 the Company had the following
outstanding hedge positions:

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During April 2003, the Company entered into costless collar arrangements
covering 642,000 MMBtu of natural gas for April 2004 through October 2004
production with a floor of $4.00 and a ceiling of $5.20.

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ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management's discussion and analysis of certain significant
factors that have affected certain aspects of the Company's financial position
and results of operations during the periods included in the accompanying
unaudited financial statements. This discussion should be read in conjunction
with the discussion under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the annual financial statements
included in the Company's Annual Report on Form 10-K for the year ended December
31, 2002 and the unaudited financial statements included elsewhere herein.
Unless otherwise indicated by the context, references herein to "Carrizo" or
"Company" mean Carrizo Oil & Gas, Inc., a Texas corporation that is the
registrant.

GENERAL OVERVIEW

The Company began operations in September 1993 and initially focused on the
acquisition of producing properties. As a result of the increasing availability
of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic
data and options to lease substantial acreage in 1995 and began to drill its 3-D
based prospects in 1996. The Company drilled 25 gross wells in 2002 and four
gross wells through the three months ended March 31, 2003 in the Gulf Coast
region. The Company has budgeted to drill up to 27 gross wells (10.7 net) in the
Gulf Coast region in 2003; however, the actual number of wells drilled will vary
depending upon various factors, including the availability and cost of drilling
rigs, land and industry partner issues, Company cash flow, success of drilling
programs, weather delays and other factors. If the Company drills the number of
wells it has budgeted for 2003, depreciation, depletion and amortization, oil
and gas operating expenses and production are expected to increase over levels
incurred in 2002. The Company has typically retained the majority of its
interests in shallow, normally pressured prospects and sold a portion of its
interests in deeper, overpressured prospects.

The Company has primarily grown through the internal development of properties
within its exploration project areas, although the Company acquired properties
with existing production in the Camp Hill Project in late 1993, the Encinitas
Project in early 1995 and the La Rosa Project in 1996. The Company made these
acquisitions through the use of limited partnerships with Carrizo or Carrizo
Production, Inc. as the general partner. In addition, in November 1998, the
Company acquired assets in Wharton County, Texas in the Jones Branch project
area for approximately $3.0 million.

During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM") as a
wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil and
gas leases in Wyoming and Montana in areas prospective for coalbed methane and
develop such interests. The Company also acquired a 1,940 gross acre coalbed
methane property in Wyoming, the "Bobcat Project", for $0.7 million in cash and
common stock in July 2002. CCBM plans to spend up to $5.0 million for drilling
costs on these leases through December 2003, 50% of which would be spent
pursuant to an obligation to fund $2.5 million of drilling costs on behalf of
RMG, from whom the interests in the leases were acquired. Through March 31,
2003, CCBM has satisfied $1.7 million of its obligation on behalf of RMG. CCBM
has drilled or acquired 75 gross wells (28.0 net) and incurred total drilling
costs of $3.0 million through December 31, 2002 and drilled two gross wells (1.0
net) and incurred total drilling costs of $0.2 million during the three months
ended March 31, 2003. These wells typically take up to 18 months to evaluate and
determine whether or not they are successful. CCBM has budgeted to drill up to
50 gross (18 net) wells in 2003. The coalbed methane wells include 17 wells
acquired as a result of the Bobcat acquisition.

Of the approximately 55,000 net mineral acres held by CCBM as of March 31, 2003,
approximately 25,600 net mineral acres are located in the state of Montana. The
issuance of new coalbed methane drilling permits in Montana had been temporarily
halted pending a final Record of Decision for Montana's Environmental Impact
Statement ("EIS") to be issued by the Federal Bureau of Land Management ("BLM").
As expected, a final Record of Decision ("Decision") favorable to coalbed
methane development was issued on March 26, 2003. Based upon this favorable
Decision, the Company anticipates that new drilling permits may be issued soon
and new wells could again be drilled by coalbed methane industry participants in
Montana. Opponents of coalbed methane drilling in Montana could continue their
legal challenge, but the Company believes that the Decision will ultimately be
upheld which would allow new coalbed methane development to commence in Montana
as early as late 2003. RMG, CCBM's partner and project operator, holds
approximately 114 grandfathered drilling permits in Montana for acreage in which
CCBM also has an interest. Although the Company believes the Decision is an
important milestone, there can be no assurance when, if ever, any new permits
will be obtained or the timing thereof.

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The Company's operations involve managing market risks related to changes in
commodity prices. Derivative financial instruments, specifically swaps, futures,
options and other contracts, are used to reduce and manage those risks. The
Company addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. The Company
enters into swaps, options, collars and other derivative contracts to hedge the
price risks associated with a portion of anticipated future oil and natural gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at expiration or exchanged for physical delivery contracts. The
Company enters into the majority of its hedging transactions with two
counterparties and a netting agreement is in place with those counterparties.
The Company does not obtain collateral to support the agreements but monitors
the financial viability of counterparties and believes its credit risk is
minimal on these transactions. In the event of nonperformance, the Company would
be exposed to price risk. The Company has some risk of accounting loss since the
price received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of the
hedging transaction.

In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts were no longer effective and thus did
not qualify for hedge accounting treatment. As required by SFAS No. 133, the
value of these derivative instruments as of November 2001 $(0.8 million) was
recorded in accumulated other comprehensive income and will be reclassified into
earnings over the original term of the derivative instruments. An allowance for
the related asset totalling $0.8 million, net of tax of $0.4 million, was
charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4
million, remained in accumulated other comprehensive income related to the
deferred gains on these derivatives. The remaining balance in other
comprehensive income was reported as oil and natural gas revenues in 2002 as the
terms of the original derivative expired.

As of December 31, 2002 and March 31, 2003, $0.4 million and $0.7 million, net
of tax of $0.2 million and $0.4 million, respectively, remained in accumulated
other comprehensive income related to the valuation of the Company's hedging
positions.

Total oil purchased and sold under swaps and collars during the three months
ended March 31, 2002 and 2003 were zero Bbls and 63,000 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars in the three months
ended March 31, 2002 and 2003 were zero MMBtu and 540,000 MMBtu, respectively.
The net losses realized by the Company under such hedging arrangements were zero
and $1.2 million for the three months ended March 31, 2002 and 2003,
respectively, and are included in oil and natural gas revenues.

At December 31, 2002 and March 31, 2003 the Company had the following
outstanding hedge positions:

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During April 2003, the Company entered into costless collar arrangements
covering 642,000 MMBtu of natural gas for April 2004 through October 2004
production with a floor of $4.00 and a ceiling of $5.20.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2003,
Compared to the Three Months Ended March 31, 2002

Oil and natural gas revenues for the three months ended March 31, 2003 increased
165% to $10.7 million from $4.0 million for the same period in 2002. Production
volumes for natural gas during the three months ended March 31, 2003 were
unchanged at 1.1 Bcf. Average natural gas prices increased 121% to $5.91 per Mcf
in the first quarter of 2003 from $2.67 per Mcf in the same period in 2002.
Production volumes for oil in the first quarter of 2003 increased 161% to 139
Bbls from 53 Bbls for the same period in 2002. Average oil prices increased 45%
to $29.74 per barrel in the first quarter of 2003 from $20.50 per barrel in the
same period in 2002. The increase in oil production was due primarily to the
commencement of production at the Burkhart #1R, Pauline Huebner A-382 #1,
Matthes Huebner #1 and Delta Farms #1 wells offset by the natural decline in
production from other wells. The natural gas production was unchanged primarily
due to the commencement of production at the Burkhart #1R, Pauline Huebner A-382
#1, Matthes Huebner #1 and Delta Farms #1 wells offset by the natural decline in
production at the Riverdale #2 and other wells. Oil and natural gas revenues
include the impact of hedging activities as discussed above under "General
Overview".

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
three months ended March 31, 2002 and 2003:

-14-

- ----------

(1) Includes impact of hedging activities.

Oil and natural gas operating expenses for the three months ended March 31, 2003
increased 70% to $1.7 million from $1.0 million for the same period in 2002
primarily due to higher severance taxes and other operating costs associated
with the addition of new production. Operating expenses per equivalent unit
increased 24% to $0.89 per Mcfe in the first quarter of 2003 from $0.71 per Mcfe
in the same period in 2002 primarily as a result of higher severance taxes.

Depreciation, depletion and amortization (DD&A) expense for the three months
ended March 31, 2003 increased 54% to $3.0 million from $2.0 million for the
same period in 2002. This increase was due to increased production and
additional seismic and drilling costs. General and administrative expense for
the three months ended March 31, 2003 increased 51% to $1.4 million from $0.9
million for the same period in 2002 primarily as a result of the addition of
contract staff to handle increased drilling and production activities, higher
compensation costs and higher insurance.

Income taxes increased to $1.7 million for the three months ended March 31, 2003
from $0.1 million for the same period in 2002 as a result of higher taxable
income based on the factors described above.

Interest income for the three months ended March 31, 2003 decreased to $18,000
from $20,000 in the first quarter of 2002 primarily as a result of lower
interest rates during the first quarter of 2003. Capitalized interest was $0.8
million in the first quarter of 2003 and 2002.

The Company adopted Financial Accounting Standards Board's Statement of
Financial Standards No. 143 "Accounting for Asset Retirement Obligations"
effective January 1, 2003 and recorded a cumulative effect of change in
accounting principle of $0.1 million in the three months ended March 31, 2003.

Income before income taxes for the three months ended March 31, 2003 increased
to $4.6 million from $0.3 million in the same period in 2002. Net income for the
three months ended March 31, 2003 increased to $2.8 million from $0.1 million
for the same period in 2002 primarily as a result of the factors described
above.

LIQUIDITY AND CAPITAL RESOURCES

The Company has made and is expected to make oil and gas capital expenditures in
excess of its net cash flows provided by operating activities in order to
complete the exploration and development of its existing properties. The Company
will require additional sources of financing to fund drilling expenditures on
properties currently owned by the Company and to fund leasehold costs and
geological and geophysical costs on its exploration projects.

While the Company believes that the current cash balances and anticipated 2003
cash provided by operating activities will provide sufficient capital to carry
out the Company's 2003 exploration plans, management of the Company continues to
seek financing for its capital program from a variety of sources. No assurance
can be given that the Company will be able to obtain additional financing on
terms that would be acceptable to the Company. The Company's inability to obtain
additional financing could have a material adverse

-15-

effect on the Company. Without raising additional capital, the Company
anticipates that it may be required to limit or defer its planned oil and gas
exploration and development program, which could adversely affect the
recoverability and ultimate value of the Company's oil and gas properties.

The Company's primary sources of liquidity have included proceeds from the 1997
initial public offering, from the December 1999 sale of Subordinated Notes,
Common Stock and Warrants, the 2002 sale of shares of Series B Convertible
Participating Preferred Stock and Warrants, the 1998 sale of shares of Series A
Preferred Stock and Warrants, funds generated by operations, equity capital
contributions, borrowings (primarily under revolving credit facilities) and the
Palace Agreement that provided a portion of the funding for the Company's 1999,
2000, 2001 and 2002 drilling program in return for participation in certain
wells.

Cash flows provided by operating activities were $2.5 million and $6.3 million
for the three months ended March 31, 2002 and 2003, respectively. The increase
in cash flows provided by operating activities in 2003 as compared to 2002 was
due primarily to additional revenue as a result of higher oil and natural gas
prices and higher oil and condensate production offset by the increase of
working capital during the first quarter of 2003.

The Company has budgeted capital expenditures for the year ended December 31,
2003 of approximately $27.2 million of which $6.9 million is expected to be used
to fund 3-D seismic surveys and land acquisitions and $20.3 million of which is
expected to be used for drilling activities in the Company's project areas. The
Company has budgeted to drill up to approximately 27 gross wells (10.7 net) in
the Gulf Coast region and up to 50 gross (18 net) CCBM coalbed methane wells in
2003. The actual number of wells drilled and capital expended is dependent upon
available financing, cash flow, availability and cost of drilling rigs, land and
partner issues and other factors.

The Company has continued to reinvest a substantial portion of its cash flows
into increasing its 3-D supported drilling prospect portfolio, improving its 3-D
seismic interpretation technology and funding its drilling program. Oil and gas
capital expenditures were $4.0 million for the three months ended March 31,
2003, which included $1.1 million of capitalized interest and general and
administrative costs. The Company's drilling efforts in the Gulf Coast region
resulted in the successful completion of 17 gross wells (6.0 net) during the
year ended December 31, 2002 and two gross wells (0.1 net) during the three
months ended March 31, 2003. Of the 77 gross wells (29 net) drilled or acquired
by CCBM through March 31, 2003, 24 gross wells (8 net) are currently producing
and 53 gross wells (21 net) are awaiting evaluation before a determination can
be made as to their success.

CCBM plans to spend up to $5.0 million for drilling costs during the period from
June 2001 through December 2003, 50% of which would be spent pursuant to an
obligation to fund $2.5 million of drilling costs on behalf of RMG. Through
March 31, 2003, CCBM has satisfied $1.7 million of its drilling obligations on
behalf of RMG.

FINANCING ARRANGEMENTS

On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by the Mortgaged Properties, which include substantially all of the
Company's producing oil and gas properties, and is guaranteed by the Company's
subsidiary.

The borrowing base will be determined by Hibernia National Bank at least
semi-annually on October 31 and April 30. The initial borrowing base was $12.0
million, and the borrowing base as of October 31, 2002 was $13.0 million. Each
party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2002,
was $1.3 million. The quarterly borrowing base reduction effective January 31,
2003 was $1.8 million.

On December 12, 2002, the Company entered into an Amended and Restated Credit
Agreement with Hibernia National Bank that provided additional availability
under the Hibernia Facility in the amount of $2.5 million which was structured
as an additional "Facility B" under the Hibernia Facility. As such, the total
borrowing base under the Hibernia Facility as of December 31, 2002 and March 31,
2003 was $15.5 million and $13.8 million, respectively, of which $8.5 million
was outstanding on December 31, 2002 and March 31, 2003 and $6.5 million is
currently drawn. The Facility B bore interest at LIBOR plus 3.375%, was secured
by certain leases and working interests in oil and natural gas wells and matured
on April 30, 2003.

-16-

If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.

If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.

For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.

The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of the Company's common or preferred
stock, speculative commodity transactions, and other matters.

At December 31, 2002 and March 31, 2003, amounts outstanding under the Hibernia
Facility totaled $8.5 million with an additional $4.3 million and $2.5 million,
respectively, under Facility A and $2.5 million under Facility B available for
future borrowings. No amounts under the Compass Facility were outstanding at
December 31, 2002. At December 31, 2002 and March 31, 2003, one letter of credit
was issued and outstanding under the Hibernia Facility in the amount of $0.2
million.

On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7.5 million to
RMG as consideration for certain interests in oil and natural gas leases held by
RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal
payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001
with the balance due December 31, 2004. The RMG note is secured solely by CCBM's
interests in the oil and natural gas leases in Wyoming and Montana. At December
31, 2002 and March 31, 2003, the outstanding principal balance of this note was
$5.3 million and $4.9 million, respectively.

In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, the Company entered a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. The Company has the option to acquire the equipment at the conclusion
of the lease for $1, under both leases. DD&A on the capital leases for three
months ended March 31, 2002 and 2003 amounted to $6,000 and $10,000,
respectively, and accumulated DD&A on the leased equipment at December 31, 2002
and March 31, 2003 amounted to $28,000 and $38,000, respectively.

In December 1999, the Company consummated the sale of $22.0 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and
$8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2
million, $0.8 million, $0.8 million and $0.8 million principal amount of
Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of
the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006
Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC),
Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P.
Hamilton, respectively. The Subordinated Notes were sold at a discount of $0.7
million, which is being amortized over the life of the notes. Interest payments
are due quarterly commencing on March 31, 2000. The Company may elect, for a
period of up to five years, to increase the amount of the Subordinated Notes for
60% of the interest which would otherwise be payable in cash. As of December 31,
2002 and March 31, 2003, the outstanding balance of the Subordinated Notes had
been increased by $3.9 million and $4.3 million, respectively, for such interest
paid in kind.

-17-

The Company is subject to certain covenants under the terms of the Subordinated
Notes securities purchase agreement, including but not limited to, (a)
maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director),
as well as limits on the Company's ability to (i) incur indebtedness, (ii) incur
or allow liens, (iii) engage in mergers, consolidation, sales of assets and
acquisitions, (iv) declare dividends and effect certain distributions (including
restrictions on distributions upon the Common Stock), (v) engage in transactions
with affiliates and (vi) make certain repayments and prepayments, including any
prepayment of the subordinated debt, indebtedness that is guaranteed or
credit-enhanced by any affiliate of the Company, and prepayments that effect
certain permanent reductions in revolving credit facilities. EBITDA was part of
a negotiated covenant with the purchasers and is presented here as a disclosure
of our covenant obligations.

In February 2002, the Company consummated the sale of 60,000 shares of Series B
Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common Stock for
an aggregate purchase price of $6.0 million. The Company sold $4.0 million and
$2.0 million of Series B Preferred Stock and 168,422 and 84,210 Warrants to
Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B
Preferred Stock is convertible into Common Stock by the investors at a
conversion price of $5.70 per share, subject to adjustment, and is initially
convertible into 1,052,632 shares of Common Stock. The approximately $5.8
million net proceeds of this financing were used to fund the Company's ongoing
exploration and development program and general corporate purposes.

Dividends on the Series B Preferred Stock will be payable in either cash at a
rate of 8% per annum or, at the Company's option, by payment in kind of
additional shares of the Series B Preferred Stock at a rate of 10% per annum. At
December 31, 2002 and March 31, 2003 the outstanding balance of the Series B
Preferred Stock had been increased by $0.5 million (5,294 shares) for dividends
paid in kind. In addition to the foregoing, if the Company declares a cash
dividend on the Common Stock of the Company, the holders of shares of Series B
Preferred Stock are entitled to receive for each share of Series B Preferred
Stock a cash dividend in the amount of the cash dividend that would be received
by a holder of the Common Stock into which such share of Series B Preferred
Stock is convertible on the record date for such cash dividend. Unless all
accrued dividends on the Series B Preferred Stock shall have been paid and a sum
sufficient for the payment thereof set apart, no distributions may be paid on
any Junior Stock (which includes the Common Stock) (as defined in the Statement
of Resolutions for the Series B Preferred Stock) and no redemption of any Junior
Stock shall occur other than subject to certain exceptions.

The Series B Preferred Stock is required to be redeemed by the Company at any
time after the third anniversary of the initial issuance of the Series B
Preferred Stock (the "Issue Date") upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). The
Company may redeem the Series B Preferred Stock after the third anniversary of
the Issue Date, at a price per share equal to the Purchase Price/Dividend
Preference and, prior to that time, at varying preferences to the Purchase
Price/Dividend Purchase. "Purchase Price/Dividend Preference" is defined to
mean, generally, $100 plus all cumulative and accrued dividends on such share of
Series B Preferred Stock.

In the event of any dissolution, liquidation or winding up or certain mergers or
sales or other disposition by the Company of all or substantially all of its
assets (a "Liquidation"), the holder of each share of Series B Preferred Stock
then outstanding will be entitled to be paid out of the assets of the Company
available for distribution to its shareholders, the greater of the following
amounts per share of Series B Preferred Stock: (i) $100 in cash plus all
cumulative and accrued dividends and (ii) in certain circumstances, the
"as-converted" liquidation distribution, if any, payable in such Liquidation
with respect to each share of Common Stock.

Upon the occurrence of certain events constituting a "Change of Control" (as
defined in the Statement of Resolutions), the Company is required to make an
offer to each holder of Series B Preferred Stock to repurchase all of such
holder's Series B Preferred Stock at an offer price per share of Series B
Preferred Stock in cash equal to 105% of the Change of Control Purchase Price,
which is generally defined to mean $100 plus all cumulative and accrued
dividends.

The 2002 Warrants have a five-year term and entitle the holders to purchase up
to 252,632 shares of Carrizo's Common Stock at a price of $5.94 per share,
subject to adjustment, and are exercisable at any time after issuance. For
accounting purposes, the 2002 Warrants were recorded at a value of $0.06 per
2002 Warrant.

EFFECTS OF INFLATION AND CHANGES IN PRICE

The Company's results of operations and cash flows are affected by changing oil
and gas prices. If the price of oil and gas increases (decreases), there could
be a corresponding increase (decrease) in the operating cost that the Company is
required to bear for operations, as well as an increase (decrease) in revenues.
Inflation has had a minimal effect on the Company.

-18-

CRITICAL ACCOUNTING POLICIES

The following summarizes several of our critical accounting policies:

Use of Estimates

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from these estimates.

Oil and Natural Gas Properties

Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and natural gas properties. The Company capitalized
compensation costs for employees working directly on exploration activities of
$0.2 million and $0.3 million for the three months ended March 31, 2002 and
2003, respectively. Maintenance and repairs are expensed as incurred.

Oil and natural gas properties are amortized based on the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the projects
can be determined or until they are impaired. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties are impaired, the amount
of impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and,
where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage values. The depletion rate per thousand cubic feet equivalent
(Mcfe) for the three months ended March 31, 2002 and 2003 was $1.35 and $1.57
respectively.

Dispositions of oil and natural gas properties are accounted for as adjustments
to capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves.

The net capitalized costs of proved oil and natural gas properties are subject
to a "ceiling test", which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves,
based on current economic and operating conditions. If net capitalized costs
exceed this limit, the excess is charged to operations through depreciation,
depletion and amortization. No write-down of the Company's oil and natural gas
assets was necessary for the three months ended March 31, 2002 or 2003. Based on
oil and natural gas prices in effect on December 31, 2001, the unamortized cost
of oil and natural gas properties exceeded the cost center ceiling. As permitted
by full cost accounting rules, improvements in pricing subsequent to December
31, 2001 removed the necessity to record a write-down. Using prices in effect on
December 31, 2001 the pretax write-down would have been approximately $0.7
million. Because of the volatility of oil and natural gas prices, no assurance
can be given that the Company will not experience a write-down in future
periods.

Depreciation of other property and equipment is provided using the straight-line
method based on estimated useful lives ranging from five to 10 years.

Oil and Natural Gas Reserve Estimates

The process of estimating quantities of proved reserves is inherently uncertain,
and the reserve data included in this document are estimates prepared by the
Company. Reserve engineering is a subjective process of estimating underground
accumulations of hydrocarbons that cannot be measured in an exact manner. The
process relies on interpretation of available geologic, geophysical, engineering
and production data. The extent, quality and reliability of this data can vary.
The process also requires certain economic assumptions regarding drilling and
operating expense, capital expenditures, taxes and availability of funds. The
SEC mandates some of these assumptions such as oil and natural gas prices and
the present value discount rate.

Proved reserve estimates prepared by others may be substantially higher or lower
than the Company's estimates. Because these estimates depend on many
assumptions, all of which may differ from actual results, reserve quantities
actually recovered may be

-19-

significantly different than estimated. Material revisions to reserve estimates
may be made depending on the results of drilling, testing, and rates of
production.

It should not be assumed that the present value of future net cash flows is the
current market value of the Company's estimated proved reserves. In accordance
with SEC requirements, the Company based the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.

The Company's rate of recording depreciation, depletion and amortization expense
for proved properties is dependent on the Company's estimate of proved reserves.
If these reserve estimates decline, the rate at which the Company records these
expenses will increase.

Derivative Instruments and Hedging Activities

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities". This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS No. 133 was effective
for the Company beginning January 1, 2001 and was adopted by the Company on that
date. In accordance with the current transition provisions of SFAS No. 133, the
Company recorded a cumulative effect transition adjustment of $2.0 million (net
of related tax expense of $1.1 million) in accumulated other comprehensive
income to recognize the fair value of its derivatives designated as cash flow
hedging instruments at the date of adoption.

Upon entering into a derivative contract, the Company designates the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at December 31, 2002 and March 31, 2003 were
designated and effective as cash flow hedges.

When hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the derivative will continue to be carried on the
balance sheet at its fair value and gains and losses that were accumulated in
other comprehensive income will be recognized in earnings immediately. In all
other situations in which hedge accounting is discontinued, the derivative will
be carried at fair value on the balance sheet with future changes in its fair
value recognized in future earnings.

The Company typically uses fixed rate swaps and costless collars to hedge its
exposure to material changes in the price of natural gas and oil. The Company
formally documents all relationships between hedging instruments and hedged
items, as well as its risk management objectives and strategy for undertaking
various hedge transactions. This process includes linking all derivatives that
are designated cash flow hedges to forecasted transactions. The Company also
formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.

The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.

Income Taxes

Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes", deferred income taxes are recognized at each
yearend for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.

-20-

Contingencies

Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.

VOLATILITY OF OIL AND NATURAL GAS PRICES

The Company's revenues, future rate of growth, results of operations, financial
condition and ability to borrow funds or obtain additional capital, as well as
the carrying value of its properties, are substantially dependent upon
prevailing prices of oil and natural gas. Historically, the markets for oil and
natural gas have been volatile, and such markets are likely to continue to be
volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of foreign imports and overall economic conditions. It is impossible to
predict future oil and natural gas price movements with certainty. Declines in
oil and natural gas prices may materially adversely affect the Company's
financial condition, liquidity, and ability to finance planned capital
expenditures and results of operations. Lower oil and natural gas prices also
may reduce the amount of oil and natural gas that the Company can produce
economically. Oil and natural gas prices have declined in the recent past and
there can be no assurance that prices will recover or will not decline further.

The Company typically uses fixed rate swaps and costless collars to hedge its
exposure to material changes in the price of natural gas and oil. The Company
formally documents all relationships between hedging instruments and hedged
items, as well as its risk management objectives and strategy for undertaking
various hedge transactions. This process includes linking all derivatives that
are designated cash flow hedges to forecasted transactions. The Company also
formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.

The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.

In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts were no longer effective and thus did
not qualify for hedge accounting treatment. As required by SFAS No. 133, the
value of these derivative instruments as of November 2001 $(0.8 million) was
recorded in accumulated other comprehensive income and will be reclassified into
earnings over the original term of the derivative instruments. An allowance for
the related asset totalling $0.8 million, net of tax of $0.4 million, was
charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4
million, remained in accumulated other comprehensive income related to the
deferred gains on these derivatives. The remaining balance in other
comprehensive income was reported as oil and natural gas revenues in 2002 as the
terms of the original derivative expired.

As of December 31, 2002 and March 31, 2003, $0.4 million and $0.7 million, net
of tax of $0.2 million and $0.4 million, respectively, remained in accumulated
other comprehensive income related to the valuation of the Company's hedging
positions.

Total oil purchased and sold under swaps and collars during the three months
ended March 31, 2002 and 2003 were zero Bbls and 63,000 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars in the three months
ended March 31, 2002 and 2003 were zero MMBtu and 540,000 MMBtu, respectively.
The net losses realized by the Company under such hedging arrangements were zero
and $1.2 million for the three months ended March 31, 2002 and 2003,
respectively, and are included in oil and natural gas revenues.

At December 31, 2002 and March 31, 2003 the Company had the following
outstanding hedge positions:

-21-

During April 2003, the Company entered into costless collar arrangements
covering 642,000 MMBtu of natural gas for April 2004 through October 2004
production with a floor of $4.00 and a ceiling of $5.20.

FORWARD LOOKING STATEMENTS

The statements contained in all parts of this document, including, but not
limited to, those relating to the Company's schedule, targets, estimates or
results of future drilling, budgeted wells, increases in wells, budgeted and
other future capital expenditures, use of offering proceeds, outcome and effects
of litigation, expected production or reserves, increases in reserves, acreage
working capital requirements, hedging activities, the ability of expected
sources of liquidity to implement its business strategy, the timing and results
of the issuance of new drilling permits for coalbed methane drilling in Montana
and any other statements regarding future operations, financial results,
business plans and cash needs and other statements that are not historical facts
are forward looking statements. When used in this document, the words
"anticipate," "estimate," "expect," "may," "project," "believe" and similar
expression are intended to be among the statements that identify forward looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, those relating to the Company's dependence on its exploratory
drilling activities, the volatility of oil and natural gas prices, the need to
replace reserves depleted by production, operating risks of oil and natural gas
operations, the Company's dependence on its key personnel, factors that affect
the Company's ability to manage its growth and achieve its business strategy,
risks relating to, limited operating history, technological changes, significant
capital requirements of the Company, the potential impact of government
regulations, litigation, competition, the uncertainty of reserve information and
future net revenue estimates, property acquisition risks, availability of
equipment, weather and other factors detailed in the Company's Annual Report on
Form 10-K for the year ended December 31, 2002 and other filings with the
Securities and Exchange Commission. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual outcomes may vary materially from those indicated.

-22-

ITEM 3A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information regarding our exposure to certain market risks, see
"Quantitative and Qualitative Disclosures about Market Risk" in Item 7A of our
Annual Report on Form 10-K for the year ended December 31, 2002 except for the
Company's hedging activity subsequent to December 31, 2002 as described above in
"Volatility of Oil and Natural Gas Prices". There have been no material changes
to the disclosure regarding our exposure to certain market risks made in the
Annual Report. For additional information regarding our long-term debt, see Note
3 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part
I of this Quarterly Report on Form 10-Q.

-23-

ITEM 4 - CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including the Chief Executive Officer and Chief Financial and
Accounting Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based on that evaluation, the Chief Executive Officer and the Chief
Financial and Accounting Officer concluded that the Company's disclosure
controls and procedures are effective in timely alerting them to material
information relating to the Company (including its consolidated subsidiaries)
required to be included in the Company's periodic filings with the Securities
and Exchange Commission. Subsequent to the date of their evaluation, there were
no significant changes in the Company's internal controls or in other factors
that could significantly affect the internal controls, including any corrective
actions with regard to significant deficiencies and material weaknesses.

-24-

PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

From time to time, the Company is party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial position or results
of operations of the Company.

Item 2 - Changes in Securities and Use of Proceeds

None

Item 3 - Defaults Upon Senior Securities

None

Item 4 - Submission of Matters to a Vote of Security Holders

None

Item 5 - Other Information

None.

Item 6 - Exhibits and Reports on Form 8-K

Exhibits

Exhibit
Number Description

+2.1 -- Combination Agreement by and among the Company, Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa Partners
Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A.
Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A.
Wojtek dated as of September 6, 1997 (incorporated herein by
reference to Exhibit 2.1 to the Company's Registration Statement
on Form S-1 (Registration No. 333-29187)).

+3.1 -- Amended and Restated Articles of Incorporation of the Company
(incorporated herein by reference to Exhibit 3.1 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1997).

+3.2 -- Amended and Restated Bylaws of the Company, as amended by
Amendment No. 1 (incorporated herein by reference to Exhibit 3.2
to the Company's Registration Statement on Form 8-A
(Registration No. 000-22915) Amendment No. 2 (incorporated
herein by reference to Exhibit 3.2 to the Company's Current
Report on Form 8-K dated December 15, 1999) and Amendment No. 3
(Incorporated herein by reference to Exhibit 3.1 to the
Company's Current Report on Form 8-K dated February 20, 2002).

+3.3 -- Statement of Resolution dated February 20, 2002 establishing the
Series B Convertible Participating Preferred Stock providing for
the designations, preferences, limitations and relative rights,
voting, redemption and other rights thereof (Incorporated herein
by reference to Exhibit 99.2 to the Company's Current Report on
Form 8-K dated February 20, 2002).

99.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.

99.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.

+ Incorporated herein by reference as indicated.

Reports on Form 8-K

None.

-25-

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.

Carrizo Oil & Gas, Inc.
(Registrant)

Date: May 12, 2003 By: /s/ S. P. Johnson, IV
--------------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)

Date: May 12, 2003 By: /s/ Frank A. Wojtek
--------------------------------------------
Chief Financial Officer
(Principal Financial and Accounting Officer)

-26-

CERTIFICATIONS

Principal Executive Officer

I, S.P. Johnson IV, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil
& Gas, Inc.

2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:

a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons fulfilling the equivalent function);

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and

b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated
in this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: May 12, 2003 /s/ S.P. Johnson, IV
------------------------------------
S.P. Johnson, IV
Chief Executive Officer

-27-

Principal Financial Officer

I, Frank A. Wojtek, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil
& Gas, Inc.

2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:

a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons fulfilling the equivalent function);

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and

b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated
in this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of
our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: May 12, 2003 /s/ Frank A. Wojtek
------------------------------------------
Vice President and Chief Financial Officer

-28-

EXHIBIT INDEX

+ Incorporated herein by reference as indicated.