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 JUNE 30, 2003
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[ ] 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 12b-2 of the Exchange Act).

YES [ ] NO [X]

The number of shares outstanding of the registrant's common stock, par value
$0.01 per share, as of August 1, 2003, the latest practicable date, was
14,237,217.

CARRIZO OIL & GAS, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 146,500 stock options and 252,632 warrants during the
three months ended June 30, 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.
The Company had outstanding 202,333 and 156,500 stock options and 252,632
warrants during the six months ended June 30, 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 June 30, 2002 and 2003, the Company also had zero and 1,202,791
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. INVESTMENT IN PINNACLE GAS RESOURCES, INC.

THE PINNACLE TRANSACTION

On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and
among the Company and its wholly-owned subsidiary, CCBM, Inc. ("CCBM"), Rocky
Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity
entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their
respective interests, having a estimated fair value of approximately $7.5
million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project
areas and (2) oil and gas reserves in the Bobcat project area to a newly formed
entity, Pinnacle Gas Resources, Inc., a Delaware corporation ("Pinnacle"). In
exchange for the contribution of these assets, CCBM and RMG each received 37.5%
of the common stock of Pinnacle ("Pinnacle Common Stock") as of the closing date
and options to purchase Pinnacle Common Stock ("Pinnacle Stock Options"). In
connection with the oil and natural gas leases contributed to Pinnacle, CCBM no
longer has a drilling obligation (see "General Overview" in the MDA for further
discussion).

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Simultaneously with the contribution of these assets, the CSFB Parties
contributed approximately $17.6 million of cash to Pinnacle in return for the
Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the
Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle
Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute
additional cash, under certain circumstances, of up to approximately $11.8
million to Pinnacle to fund future drilling, development and acquisitions. The
CSFB Parties currently have greater than 50% of the voting power of the Pinnacle
capital stock through their ownership of Pinnacle Common Stock and Pinnacle
Preferred Stock.

Currently, on a fully diluted basis, assuming that all parties exercised their
Pinnacle Warrants and Pinnacle Options, the CSFB Parties, CCBM and RMG would
have ownership interests of approximately 46.2%, 26.9% and 26.9%, respectively.
On a fully-diluted basis, assuming the additional $11.8 million of cash was
contributed by the CSFB Parties and all Pinnacle Warrants and Pinnacle Options
were exercised by all parties, the CSFB Parties would own 54.6% of Pinnacle and
CCBM and RMG would each own 22.7% of Pinnacle.

Immediately following the contribution and funding, Pinnacle used approximately
$6.2 million of the proceeds from the funding to acquire an approximate 50%
working interest in existing leases and approximately 36,529 gross acres
prospective for coalbed methane development in the Powder River Basin of Wyoming
from Gastar Exploration, Ltd. The leases include 95 producing coalbed methane
wells currently in the early stages of dewatering. These wells are producing at
a combined gross rate of approximately 2.5 MMcfd, or an estimated 1 MMcfd net to
Pinnacle. Pinnacle also agreed to fund up to $14.9 million of future drilling
and development costs on these properties on behalf of Gastar prior to December
31, 2005. The drilling and development work will be done under the terms of an
earn-in joint venture agreement between Pinnacle and Gastar. The majority of
these leases are part of, or adjacent to, the Bobcat project area. All of CCBM
and RMG's interests in the Bobcat project area, the only producing coalbed
methane property owned by CCBM prior to the transaction, were contributed to
Pinnacle. Pinnacle currently owns interests in approximately 131,000 gross acres
in the Powder River Basin.

Prior to and in connection with its contribution of assets to Pinnacle, CCBM
paid RMG approximately $1.8 million in cash as part of its outstanding purchase
obligation on the coalbed methane property interests CCBM previously acquired
from RMG. The approximate $1.2 million remaining balance of CCBM's obligation to
RMG is scheduled to be paid in monthly installments of approximately $52,805
through November 2004 and a balloon payment on December 31, 2004. The RMG note
is secured solely by CCBM's interests in the remaining oil and natural gas
leases in Wyoming and Montana. In connection with the Company's investment in
Pinnacle, the Company received a reduction in the principal amount of the RMG
note of approximately $1.5 million and relinquished the right to receive certain
revenues related to the properties contributed to Pinnacle.

CCBM continues its coalbed methane business activities and, in addition to its
interest in Pinnacle, owns direct interests in approximately 189,000 gross acres
of coalbed methane properties in the Castle Rock project area in Montana and the
Oyster Ridge project area in Wyoming, which were not contributed to Pinnacle.
CCBM and RMG will continue to conduct exploration and development activities on
these properties as well as pursue other potential acquisitions. The Bobcat
property was producing approximately 400 Mcfe of coalbed methane gas net to
CCBM's interest immediately prior to its contribution to Pinnacle. Other than
indirectly through Pinnacle, CCBM currently has no proved reserves of, and is no
longer receiving revenue from, coalbed methane gas.

ACCOUNTING AND TAX TREATMENT

For accounting purposes, the transaction will be treated as a reclassification
of a portion of CCBM's investments in the contributed properties. The property
contribution made by CCBM to Pinnacle is intended to be treated as a
tax-deferred exchange as constituted by property transfers under section 351(a)
of the Internal Revenue Code of 1986, as amended.

The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
("FIN 46"), in January 2003. FIN 46 requires the consolidation of certain types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. These entities are called "variable interest entities". The
provisions of FIN 46 are effective for the Company in the second quarter for new
transactions or entities formed in 2003 and in the third quarter for
transactions or entities formed prior to 2003.

If an entity is determined to be a "variable interest entity" ("VIE"), the
entity must be consolidated by the "primary beneficiary". The primary
beneficiary is the holder of the variable interests that absorbs a majority of
the variable interest entity's expected losses or receives a majority of the
entity's residual returns in the event no holder has a majority of the expected
losses. The determination of the primary beneficiary is based on projected cash
flows at the inception of the variable interests. Because Steven A. Webster,
Chairman of Carrizo, is also a managing director of Credit Suisse First Boston
("Related Parties in Pinnacle Transaction" below),

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Carrizo could be defined as the primary beneficiary if the projected cash flows
analysis indicated losses in excess of the equity invested. The initial
determination of whether an entity is a VIE is to be reconsidered only when one
or more of the following occur (1) the entity's governing documents or the
contractual arrangements among the parties involved change, (2) the equity
investment of some part thereof is returned to the investors, and other parties
become exposed to expected losses or (3) the entity undertakes additional
activities or acquires additional assets that increase the entity's expected
losses.

We have determined that we should not consolidate Pinnacle, under FIN 46,
because our current projected cash flow analysis of Pinnacle's operations at
inception does not indicate that Pinnacle is not a VIE. Accordingly, our
investment in Pinnacle has been recorded using the equity method of accounting.

The reclassification of investments in contributed properties resulting from the
transaction with Pinnacle are reflected in accordance with the full cost method
of accounting in the Company's balance sheet included in this Form 10-Q for the
six months ended June 30, 2003.

RELATED PARTIES IN THE PINNACLE TRANSACTION

Steven A. Webster, Chairman of the Board of the Company, is also a managing
director of Credit Suisse First Boston Private Equity and is therefore a related
party to this transaction.

TRANSITION SERVICES AGREEMENT

The Company entered into a transition services agreement with Pinnacle pursuant
to which the Company will provide certain accounting, treasury, tax, insurance
and financial reporting functions to Pinnacle through the end of 2003 for a
monthly fee equal to our actual cost to provide such services. After December
31, 2003, the agreement will automatically renew on a quarterly basis unless one
of the parties gives notice of its intent to terminate the agreement.

Similarly, Pinnacle has also entered into a transition services agreement with
RMG to provide Pinnacle assistance in setting up operational accounting and
management systems for a monthly fee equal to the actual cost to provide such
services. After December 31, 2003, the agreement will automatically renew on a
quarterly basis unless one of the parties gives notice of its intent to
terminate the agreement.

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4. LONG-TERM DEBT

At December 31, 2002 and June 30, 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 mortgaged properties; which include substantially all of the
Company's producing oil and gas properties assets, and is guaranteed by the
Company's subsidiary.

The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million, and the borrowing base as of April 30, 2003 was $16.0 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. There was an increase in the borrowing base for the
quarter ended June 30, 2003 of $2.2 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 June 30,
2003 was $15.5 million and $16.0 million, respectively, of which $8.5 million
and $7.0 million was outstanding on December 31, 2002 and June 30, 2003,
respectively. 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

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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 June 30, 2003, amounts outstanding under the Hibernia
Facility totaled $8.5 million and $7.0 million, respectively, with an additional
$4.3 million and $9.0 million, respectively, under Facility A and $2.5 million
under Facility B at December 31, 2002 available for future borrowings. No
amounts under the Compass Facility were outstanding at December 31, 2002. At
December 31, 2002 and June 30, 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 was 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 June 30, 2003, the outstanding principal balance of this note was
$5.3 million and $1.2 million, respectively. In connection with the Company's
investment in Pinnacle (see Note 3), the Company received a reduction in the
principal amount of the RMG note of approximately $1.5 million and relinquished
the right to certain revenues related to the properties contributed to Pinnacle.

In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, the Company entered into a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. In May 2003, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.1 million. The lease
is payable in 36 monthly payments of $3,030 including interest at 5.5% per
annum. The Company has the option to acquire the equipment at the conclusion of
the lease for $1 under all of these leases. DD&A on the capital leases for the
three months ended June 30, 2002 and 2003 amounted to $8,000 and $20,000,
respectively. DD&A on the capital leases for the six months ended June 30, 2002
and 2003 amounted to $16,000 and $38,000 respectively, and accumulated DD&A on
the leased equipment at December 31, 2002 and June 30, 2003 amounted to $28,000
and $56,000, 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 June 30, 2003, the outstanding balance of the Subordinated Notes had
been increased by $3.9 million and $4.6 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 June 30, 2003, the Company believes it was in
compliance with all of its debt covenants.

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5. INCOME TAXES

The Company estimates its annual effective tax rate to be approximately 35%,
which also approximates its statutory rate. The Company provided deferred tax
expense of $0.6 million and $1.1 million for the three months ended June 30,
2002 and 2003, respectively, and $0.7 million and $2.7 million for the six
months ended June 30, 2002 and 2003, respectively.

6. 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 June 30, 2003, two
and three leases in the amount of $0.4 million and $0.5 million, respectively,
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 June
30, 2003, CCBM had satisfied $2.2 million of the drilling obligation on behalf
of RMG.

7. CONVERTIBLE PARTICIPATING PREFERRED STOCK

In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and Warrants to purchase 252,632 shares of Carrizo's 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 June 30, 2003, the outstanding
balance of the Series B Preferred Stock has been increased by $0.5 million
(5,294 shares) and $0.9 million (8,559 shares), respectively, for dividends paid
in kind. The Series B Preferred Stock is redeemable at varying prices in whole
or in part at the holders' option after three years or at the Company's option
at any time. The Series B Preferred Stock will also participate in any dividends
declared on the common stock. Holders of the Series B Preferred Stock will
receive a liquidation preference upon the liquidation of, or certain mergers or
sales of substantially all assets involving, the Company. Such holders will also
have the option of receiving a change of control repayment price upon certain
deemed change of control transactions. The warrants have a five-year term and
entitle the holders to purchase up to 252,632 shares of Carrizo's common stock
at a price of $5.94 per share, subject to adjustments, and are exercisable at
any time after issuance. The warrants may be exercised on a cashless exercise
basis.

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

8. SHAREHOLDER'S EQUITY

The Company issued 106,472 and 55,334 shares of common stock during the six
months ended June 30, 2002 and June 30, 2003, respectively. The shares issued
during the six months ended June 30, 2002 were partial consideration for the
acquisition of an interest in certain oil and natural gas properties and the
shares issued during the six months ended June 30, 2003 were the result of the
exercise of options granted under the Company's Incentive Plan.

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

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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:

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Diluted earnings per share amounts for the three months ended June 30, 2002 and
2003 are based upon 17,269,545 and 16,595,815 shares, respectively, that include
the dilutive effect of assumed stock option and warrant conversions of 3,118,534
and 2,384,642, respectively. Diluted earnings per share amounts for the six
months ended June 30, 2002 and 2003 are based upon 16,982,887 and 16,464,990
shares, respectively, that include the dilutive effect of assumed stock options
and warrant conversions of 2,842,993 and 2,260,300, respectively.

9. 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.

10. 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.

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As of December 31, 2002 and June 30, 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 June 30, 2002 and 2003 were 45,500 Bbls and 63,300 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars during the three
months ended June 30, 2002 and 2003 were 728,000 MMBtu and 819,000 MMBtu,
respectively. Total oil purchased and sold under swaps and collars during the
six months ended June 30, 2002 and 2003 were 45,500 Bbls and 126,300 Bbls,
respectively. Total natural gas purchased and sold under swaps and collars
during the six months ended June 30, 2002 and 2003 were 1,538,000 MMBtu and
1,349,000 MMBtu, respectively. The net losses realized by the Company under such
hedging arrangements were $0.4 million and $0.4 million for the three months
ended June 30, 2002 and 2003, respectively, and are included in oil and natural
gas revenues. The net losses realized by the Company under such hedging
arrangements were $0.4 million and $1.7 million for the six months ended June
30, 2002 and 2003, respectively, and are included in oil and natural gas
revenues.

At December 31, 2002 and June 30, 2003 the Company had the following outstanding
hedge positions:

During July 2003, the Company entered into swap arrangements covering 36,800
Bbls of oil for August 2003 through October 2003 production with a fixed price
of $30.00.

In addition to the hedge positions above, during the second quarter of 2003, the
Company acquired options to sell 6,000 MMBtu of natural gas per day for the
period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. The Company acquired these options to protect its cash
position against potential margin calls on certain natural gas derivatives due
to large increases in the price of natural gas. These options have been
classified as derivatives. As of June 30, 2003, these options have been adjusted
to their estimated fair market value of approximately $28,000 and a charge for
the adjustment of $91,000 has been included in other income and expense for the
three months ended June 30, 2003.

11. NEW ACCOUNTING PRONOUNCEMENTS

Effective July 1, 2003, we will adopt SFAS 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". This
standard will not have a material impact on our consolidated financial
statements.

-15-

The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
("FIN 46"), in January 2003. FIN 46 requires the consolidation of certain types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. The Company has identified no transactions or related entities
that required consolidation under this interpretation.

Currently, the FASB and representatives of the SEC accounting staff are engaged
in discussions on the issue of whether SFAS 141, "Business Combinations" and
SFAS 142, "Goodwill and Other Intangibles", which were effective June 30, 2001,
called for mineral rights held under a lease or other contractual arrangement to
be classified on the balance sheet as intangible assets and accompanied by
specific footnote disclosures. Historically, oil and gas companies, including
the Company, have included these costs with all other oil and gas property costs
in Property, Plant, and Equipment on the consolidated balance sheet.

In the event this interpretation is adopted, a substantial portion of the
acquisition costs of oil and gas properties would be required to be classified
on the balance sheet as an intangible asset. The Company believes this
interpretation would not have a material effect on our results of operations for
the periods presented or in the future as these intangible assets would be
depleted using the units of production method in a manner consistent with the
method currently used to calculate depletion, depreciation, and amortization
expense ("DD&A") on those assets.

12. SUBSEQUENT EVENTS

EXCHANGE TRANSACTION ON JULY 31, 2003

Pursuant to an exchange election provided in a letter agreement, dated May 1,
2001, with certain participants in the Carrizo 2001 Seismic and Acreage Program
(the "2001 Program"), the Company is issuing to such participants, who have
exercised their election, approximately 168,000 shares of its common stock in
exchange for the participants' entire interest in the 2001 Program, including
approximately 350 square miles of 3D seismic data and working interests in
certain producing properties. The exchange transaction is effective on July 31,
2003 and will be valued using the close price of the Company's stock on that
date, for a total of approximately $1.2 million.

AWARDED ACREAGE IN THE NORTH SEA ON JULY 31, 2003

The Company has been awarded seven acreage blocks, consisting of one
"Traditional" and six "Promote" licenses, in the United Kingdom's 21st Round of
Licensing. The awarded blocks, to explore for oil and natural gas totaling
approximately 209,000 acres, are located within mature producing areas of the
Central and Southern North Sea in water depths of 30 to 270 feet. The Company
plans to promote these interests to other parties experienced in drilling and
operating in this province. G&G costs will be incurred to maximize the value of
our retained interest. The Company's estimated project commitments for the next
two years are $0.7 million comprised of $0.3 million for seismic data, $0.1
million for leasehold costs and $0.1 million for data processing in 2003 and
$0.2 million for seismic data purchases in 2004. The Promote licenses do not
have drilling commitments and the Traditional license would be cancelled after
two years if the Company or its assignee elects not to commit to drilling a
well.

-16-

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 16 gross
wells through the six months ended June 30, 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 planned 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 June 30, 2003,
CCBM has satisfied $2.2 million of its $2.5 million 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 (one net) and incurred total drilling costs of $0.4 million during the six
months ended June 30, 2003. These wells typically take up to 18 months to
evaluate and determine whether or not they are successful. CCBM had budgeted to
drill up to 50 gross (18 net) wells in 2003 before the Pinnacle transaction
discussed below. CCBM no longer has a drilling obligation in connection with the
properties contributed to Pinnacle. Accordingly, CCBM has no plans to drill any
coalbed methane wells in the second half of 2003. The coalbed methane wells
include 17 wells acquired as a result of the Bobcat acquisition. CCBM
contributed its interests in leasehold acreage and 59 gross wells (24 net) to
Pinnacle in June 2003.

During the second quarter of 2003, CCBM contributed its interests in (1) leases
in the Clearmont, Kirby, Arvada and Bobcat project area and (2) oil and gas
reserves in the Bobcat project area to a newly formed entity, Pinnacle Gas
Resources, Inc. ("Pinnacle"). In exchange for the contribution of these assets,
CCBM received common stock of Pinnacle as of the closing date and options to
purchase Pinnacle common stock. See "The Pinnacle Transaction" later in this
section for a complete description of this transaction. The Company retained its
interests in approximately 189,000 gross acres in the Castle Rock project area
in Montana and the Oyster Ridge project area in Wyoming.

Pursuant to an exchange election provided in a letter agreement, dated May 1,
2001, with certain participants in the Carrizo 2001 Seismic and Acreage Program
(the "2001 Program"), the Company is issuing to such participants, who have
exercised their election, approximately 168,000 shares of its common stock in
exchange for the participants' program interest in the 2001 Program, including
approximately 350 square miles of 3D seismic data and working interests in
certain producing properties. The exchange transaction is effective on July 31,
2003 and will be valued using the close price of the Company's stock on that
date, or approximately $1.2 million.

-17-

The Company has been awarded seven acreage blocks, consisting of one
"Traditional" and six "Promote" licenses, in the United Kingdom's 21st Round of
Licensing. The awarded blocks, to explore for oil and natural gas totaling
approximately 209,000 acres, are located within mature producing areas of the
Central and Southern North Sea in water depths of 30 to 270 feet. The Company
plans to promote these interests to other parties experienced in drilling and
operating in this province. G&G costs will be incurred to maximize the value of
our retained interest. The Company's estimated project committments for the next
two years are $0.7 million comprised of $0.3 million for seismic data, $0.1
million for leasehold costs and $0.1 million for data processing in 2003 and
$0.2 million for seismic data purchases in 2004. The Promote licenses do not
have drilling commitments and the Traditional license would be cancelled after
two years if the Company or its assignee elects not to commit to drilling a
well.

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

As of December 31, 2002 and June 30, 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 June 30, 2002 and 2003 were 45,500 Bbls and 63,300 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars during the three
months ended June 30, 2002 and 2003 were 728,000 MMBtu and 819,000 MMBtu,
respectively. Total oil purchased and sold under swaps and collars during the
six months ended June 30, 2002 and 2003 were 45,500 Bbls and 126,300 Bbls,
respectively. Total natural gas purchased and sold under swaps and collars
during the six months ended June 30, 2002 and 2003 were 1,538,000 MMBtu and
1,349,000 MMBtu, respectively. The net losses realized by the Company under such
hedging arrangements were $0.4 million and $0.4 million for the three months
ended June 30, 2002 and 2003, respectively, and are included in oil and natural
gas revenues. The net losses realized by the Company under such hedging
arrangements were $0.4 million and $1.7 million for the six months ended June
30, 2002 and 2003, respectively, and are included in oil and natural gas
revenues.

-18-

At December 31, 2002 and June 30, 2003 the Company had the following outstanding
hedge positions:

- ----------
(1) Includes impact of hedging activities.

Oil and natural gas operating expenses for the three months ended June 30, 2003
increased 32% to $1.8 million from $1.3 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 47% to $1.05 per Mcfe in the second quarter of 2003 from $0.71 per
Mcfe in the same period in 2002 primarily as a result of the natural production
decline of existing wells, the addition of the Delta Farms #2 (a relatively
higher operating cost well) and higher severance taxes.

Depreciation, depletion and amortization (DD&A) expense for the three months
ended June 30, 2003 was unchanged at $2.6 million as compared to the same period
in 2002. DD&A was unchanged due to decreased production offset by expenses
resulting from additional seismic and drilling costs. General and administrative
expense for the three months ended June 30, 2003 increased 11% to $1.3 million
from $1.1 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.

Interest income for the three months ended June 30, 2003 increased to $22,000
from $8,000 in the second quarter of 2002 primarily as a result of higher cash
balances during the second quarter of 2003. Capitalized interest in the second
quarter of 2003 decreased to $0.7 million from $0.8 million in the second
quarter of 2002.

Income taxes increased to $1.1 million for the three months ended June 30, 2003
from $0.6 million for the same period in 2002 as a result of higher taxable
income based on the factors described above.

Income before income taxes for the three months ended June 30, 2003 increased to
$3.1 million from $1.7 million in the same period in 2002. Net income for the
three months ended June 30, 2003 increased to $2.0 million from $1.1 million for
the same period in 2002 primarily as a result of the factors described above.

Six Months Ended June 30, 2003,
Compared to the Six Months Ended June 30, 2002

Oil and natural gas revenues for the six months ended June 30, 2003 increased
80% to $19.5 million from $10.8 million for the same period in 2002. Production
volumes for natural gas during the six months ended June 30, 2003 decreased 14%
to 2.1 Bcf from 2.4 Bcf for the same period in 2002. Average natural gas prices
increased 88% to $5.78 per Mcf in the first six months of 2003 from $3.08 per
Mcf in the same period in 2002. Production volumes for oil in the first six
months of 2003 increased 74% to 258 Bbls from 148 Bbls for the same period in
2002. Average oil prices increased 26% to $29.04 per barrel in the first six
months of 2003 from $22.97 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 Hankamer #1 wells
offset by the natural decline in production from other wells. The decrease in
natural gas production was primarily due to a workover at the Delta Farms #1,
the natural decline in production at the Staubach #1, Riverdale #2 and other
wells offset by the commencement of production at the Burkhart #1R, Pauline
Huebner A-382 #1, Matthes Huebner #1 and Hankamer #1 wells. Oil and natural gas
revenues include the impact of hedging activities as discussed above under
"General Overview".

-20-

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the six
months ended June 30, 2002 and 2003:

- ----------
(2) Includes impact of hedging activities.

Oil and natural gas operating expenses for the six months ended June 30, 2003
increased 48% to $3.5 million from $2.4 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 35% to $0.96 per Mcfe in the first six months of 2003 from $0.71 per
Mcfe in the same period in 2002 primarily as a result of the natural decline in
production on older wells and the addition of the Delta Farms #2, a relatively
higher cost well.

Depreciation, depletion and amortization (DD&A) expense for the six months ended
June 30, 2003 increased 22% to $5.6 million from $4.6 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 six
months ended June 30, 2003 increased 28% to $2.7 million from $2.1 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.

Interest income for the six months ended June 30, 2003 increased to $40,000 from
$28,000 in the first six months of 2002 primarily as a result of higher cash
balances during the first quarter of 2003. Capitalized interest was $1.5 million
in the first six months of 2003 and 2002.

Income taxes increased to $2.8 million for the six months ended June 30, 2003
from $0.8 million for the same period in 2002 as a result of higher taxable
income based on the factors described above.

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 six months ended June 30, 2003.

Income before income taxes for the six months ended June 30, 2003 increased to
$7.7 million from $2.0 million in the same period in 2002. Net income for the
six months ended June 30, 2003 increased to $4.9 million from $1.2 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.

-21-

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 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 $4.1 million and $15.1 million
for the six months ended June 30, 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 six months 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 no 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 $14.1 million for the six months ended June 30, 2003,
which included $2.2 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 14 gross wells (4.2 net) during the six months
ended June 30, 2003. Of the 77 gross wells (29 net) drilled or acquired by CCBM
through June 30, 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.

THE PINNACLE TRANSACTION

OVERVIEW

On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and
among the Company and its wholly-owned subsidiary, CCBM, Inc. ("CCBM"), Rocky
Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity
entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their
respective interests, having a estimated fair value of approximately $7.5
million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project
areas and (2) oil and gas reserves in the Bobcat project area to a newly formed
entity, Pinnacle Gas Resources, Inc., a Delaware corporation ("Pinnacle"). In
exchange for the contribution of these assets, CCBM and RMG each received 37.5%
of the common stock of Pinnacle ("Pinnacle Common Stock") as of the closing date
and options to purchase Pinnacle Common Stock ("Pinnacle Stock Options"). In
connection with the oil and natural gas leases contributed to Pinnacle, CCBM no
longer has a drilling obligation (see "General Overview" in the MDA for further
discussion).

Simultaneously with the contribution of these assets, the CSFB Parties
contributed approximately $17.6 million of cash to Pinnacle in return for the
Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the
Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle
Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute
additional cash, under certain circumstances, of up to approximately $11.8
million to Pinnacle to fund future drilling, development and acquisitions. The
CSFB Parties currently have greater than 50% of the voting power of the Pinnacle
capital stock through their ownership of Pinnacle Common Stock and Pinnacle
Preferred Stock.

-22-

Currently, on a fully diluted basis, assuming that all parties exercised their
Pinnacle Warrants and Pinnacle Options, the CSFB Parties, CCBM and RMG would
have ownership interests of approximately 46.2%, 26.9% and 26.9%, respectively.
On a fully-diluted basis, assuming the additional $11.8 million of cash was
contributed by the CSFB Parties and all Pinnacle Warrants and Pinnacle Options
were exercised by all parties, the CSFB Parties would own 54.6% of Pinnacle and
CCBM and RMG would each own 22.7% of Pinnacle.

Immediately following the contribution and funding, Pinnacle used approximately
$6.2 million of the proceeds from the funding to acquire an approximate 50%
working interest in existing leases and approximately 36,529 gross acres
prospective for coalbed methane development in the Powder River Basin of Wyoming
from Gastar Exploration, Ltd. The leases include 95 producing coalbed methane
wells currently in the early stages of dewatering. These wells are producing at
a combined gross rate of approximately 2.5 MMcfd, or an estimated 1 MMcfd net to
Pinnacle. Pinnacle also agreed to fund up to $14.9 million of future drilling
and development costs on these properties on behalf of Gastar prior to December
31, 2005. The drilling and development work will be done under the terms of an
earn-in joint venture agreement between Pinnacle and Gastar. The majority of
these leases are part of, or adjacent to, the Bobcat project area. All of CCBM
and RMG's interests in the Bobcat project area, the only producing coalbed
methane property owned by CCBM prior to the transaction, were contributed to
Pinnacle. Pinnacle currently owns interests in approximately 131,000 gross acres
in the Powder River Basin.

Prior to and in connection with its contribution of assets to Pinnacle, CCBM
paid RMG approximately $1.8 million in cash as part of its outstanding purchase
obligation on the coalbed methane property interests CCBM previously acquired
from RMG. The approximate $1.2 million remaining balance of CCBM's obligation to
RMG is scheduled to be paid in monthly installments of approximately $52,805
through November 2004 and a balloon payment on December 31, 2004. The RMG note
is secured solely by CCBM's interests in the remaining oil and natural gas
leases in Wyoming and Montana. In connection with the Company's investment in
Pinnacle, the Company received a reduction in the principal amount of the RMG
note of approximately $1.5 million and relinquished the right to receive certain
revenues related to the properties contributed to Pinnacle.

CCBM continues its coalbed methane business activities and, in addition to its
interest in Pinnacle, owns direct interests in approximately 189,000 gross acres
of coalbed methane properties in the Castle Rock project area in Montana and the
Oyster Ridge project area in Wyoming, which were not contributed to Pinnacle.
CCBM and RMG will continue to conduct exploration and development activities on
these properties as well as pursue other potential acquisitions. The Bobcat
property was producing approximately 400 Mcfe of coalbed methane gas net to
CCBM's interest immediately prior to its contribution to Pinnacle. Other than
indirectly through Pinnacle, CCBM currently has no proved reserves of, and is no
longer receiving revenue from, coalbed methane gas.

Accounting and Tax Treatment

For accounting purposes, the transaction will be treated as a reclassification
of a portion of CCBM's investments in the contributed properties. The property
contribution made by CCBM to Pinnacle is intended to be treated as a
tax-deferred exchange as constituted by property transfers under section 351(a)
of the Internal Revenue Code of 1986, as amended.

The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
("FIN 46"), in January 2003. FIN 46 requires the consolidation of certain types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. These entities are called "variable interest entities". The
provisions of FIN 46 are effective for the Company in the second quarter for new
transactions or entities formed in 2003 and in the third quarter for
transactions or entities formed prior to 2003.

If an entity is determined to be a "variable interest entity" ("VIE"), the
entity must be consolidated by the "primary beneficiary". The primary
beneficiary is the holder of the variable interests that absorbs a majority of
the variable interest entity's expected losses or receives a majority of the
entity's residual returns in the event no holder has a majority of the expected
losses. The determination of the primary beneficiary is based on projected cash
flows at the inception of the variable interests. Because Steven A. Webster,
Chairman of Carrizo, is also a managing director of Credit Suisse First Boston
("Related Parties in Pinnacle Transaction" below), Carrizo could be defined as
the primary beneficiary if the projected cash flows analysis indicated losses in
excess of the equity invested. The initial determination of whether an entity is
a VIE is to be reconsidered only when one or more of the following occur (1) the
entity's governing documents or the contractual arrangements among the parties
involved change, (2) the equity investment of some part thereof is returned to
the investors, and other parties become exposed to expected losses or (3) the
entity undertakes additional activities or acquires additional assets that
increase the entity's expected losses.

-23-

We have determined that we should not consolidate Pinnacle, under FIN 46,
because our current projected cash flow analysis of Pinnacle's operations at
inception does not indicate that the Pinnacle is not a VIE. Accordingly, our
investment in Pinnacle has been recorded using the equity method of accounting.

The reclassification of investments in contributed properties resulting from the
transaction with Pinnacle are reflected in accordance with the full cost method
of accounting in the Company's balance sheet included in this Form 10-Q for the
six months ended June 30, 2003.

Related Parties in the Pinnacle Transaction

Steven A. Webster, Chairman of the Board of the Company, is also a managing
director of Credit Suisse First Boston Private Equity and is therefore a related
party to this transaction.

Transition Services Agreement

The Company entered into a transition services agreement with Pinnacle pursuant
to which the Company will provide certain accounting, treasury, tax, insurance
and financial reporting functions to Pinnacle through the end of 2003 for a
monthly fee equal to our actual cost to provide such services. After December
31, 2003, the agreement will automatically renew on a quarterly basis unless one
of the parties gives notice of its intent to terminate the agreement.

Similarly, Pinnacle has also entered into a transition services agreement with
RMG to provide Pinnacle assistance in setting up operational accounting and
management systems for a monthly fee equal to the actual cost to provide such
services. After December 31, 2003, the agreement will automatically renew on a
quarterly basis unless one of the parties gives notice of its intent to
terminate the agreement.

Area of Mutual Interest Agreement

The Company, CCBM, RMG, RMG's majority shareholder U.S. Energy Corp. ("U.S.
Energy") and the CSFB Parties also entered into an area of mutual interest
agreement covering the Powder River Basin in Wyoming and Montana (but excluding
most of Powder River County, Montana) providing that Pinnacle has the right
until June 23, 2008 to acquire at cost from the Company, CCBM, RMG and U.S.
Energy any interest in oil and gas leases or mineral interests that such parties
may have acquired in the covered area, subject to specified exceptions.

Securityholders' Agreement

The Company, the CSFB Parties, CCBM, RMG, U.S. Energy, Peter G. Schoonmaker and
Gary W. Uhland (the "Securityholders") and Pinnacle also entered into a
Securityholders' Agreement (the "Securityholders' Agreement").

The Securityholders' Agreement provides for an initial eight person board of
directors, which initially would include four directors nominated by the CSFB
Parties and two nominated by each of CCBM and RMG, subject to change as their
respective ownership percentages change.

In the Securityholders' Agreement, the Securityholders grant to each other a
right of first offer and co-sale rights.

If the CSFB Parties propose to sell all of their Pinnacle Shares to a third
party, under certain circumstances the CSFB parties may require the other
Securityholders to include all of their Pinnacle Shares in such sale. In such a
sale, the Pinnacle Preferred Stock will have a preferred right to receive an
amount equal to the Liquidation Value (as defined below) per share plus accrued
and unpaid dividends prior to the holders of shares of Pinnacle Common Stock and
common stock equivalents.

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Under the Securityholders' Agreement, Pinnacle grants the Securityholders
pre-emptive rights to purchase certain securities in order to maintain their
proportionate ownership of Pinnacle.

The Securityholders' Agreement also generally provides for multiple demand
registration rights with respect to the Pinnacle Common Stock in favor of the
CSFB Parties and piggyback certain registration rights for each of CCBM and RMG
subject to the satisfaction of specified conditions.

Pinnacle Stock Options

The same number of Pinnacle Stock Options were issued to both CCBM and RMG in
two tranches. CCBM and RMG each have a continuing option (the "Tranche A"
option) to purchase up to 25,000 shares of common stock at a purchase price of
$100 per share, with a price escalation of 10% per annum, compounded quarterly.
In addition, CCBM and RMG, each have another continuing option (the "Tranche B"
option) to purchase up to 25,000 additional shares of common stock at a purchase
price of $100 per share, with a price escalation of 20% per annum, compounded
quarterly. The Tranche B option cannot be exercised until all 25,000 shares are
first purchased under the Tranche A option.

Pinnacle Preferred Stock

The Pinnacle Preferred Stock generally has the right to vote together with the
Pinnacle Common Stock and has a class vote on specified matters, including
certain extraordinary transactions.

In the event of any dissolution, liquidation, or winding up by Pinnacle, the
holder of each share of Pinnacle Preferred Stock will be entitled to be paid
$100 per share out of the assets of Pinnacle available for distribution to its
shareholders (the "Liquidation Value").

Dividends on the Pinnacle Preferred Stock will be payable either in cash at a
rate of 10.5% per annum through June 23, 2011 and then 12.5% thereafter or, at
Pinnacle's option, by payment in kind of additional shares of the Pinnacle
Preferred Stock. For each additional share of Pinnacle Preferred Stock
distributed to a holder as an in kind dividend, Pinnacle will also deliver to
such holder one Pinnacle Warrant, which will have an exercise price equal to the
exercise price of the outstanding Pinnacle Warrants on the date of such
distribution.

On or after July 1, 2005, Pinnacle may redeem all or any portion of the Pinnacle
Preferred Stock (provided, that if any Pinnacle Warrants are still outstanding,
Pinnacle may redeem all but a single share) at a premium to the Liquidation
Value if redeemed on or at any time after July 1, 2009.

The Pinnacle Preferred Stock is required to be redeemed by Pinnacle upon (1)
specified changes of control or (2) specified events of default at a price per
share, with respect to a redemption pursuant to clause (1) above, equal to 101%
of the Liquidation Value and, with respect to a redemption pursuant to clause
(2) above, prior to June 30, 2005, equal to 110% of the Liquidation Value and,
thereafter, equal to the Applicable Optional Redemption Price.

Pinnacle Warrants

The Pinnacle Warrants entitle the holders to purchase up to 130,000 shares of
Pinnacle Common Stock at a price of $100 per share and are exercisable at any
time until June 30, 2013. The Pinnacle Warrants can be exercised in cash, by
tender of the Pinnacle Preferred Stock and on a cashless net exercise basis. The
Pinnacle Warrants are subject to certain adjustments, including, in certain
cases, an adjustment of the exercise price to equal the lowest price at which
Pinnacle Common Stock is sold if such shares are sold below the then-current
exercise price.

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.

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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 April 30, 2003 was $16.0 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. There was an increase in the borrowing base for the
quarter ended June 30, 2003 of $2.2 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 June 30,
2003 was $15.5 million and $16.0 million, respectively, of which $8.5 million
and $7.0 million was outstanding on December 31, 2002 and June 30, 2003,
respectively. 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 June 30, 2003, amounts outstanding under the Hibernia
Facility totaled $8.5 million and $7.0 million, respectively, with an additional
$4.3 million and $8.8 million, respectively, under Facility A and $2.5 million
under Facility B at December 31, 2002 available for future borrowings. No
amounts under the Compass Facility were outstanding at December 31, 2002. At
December 31, 2002 and June 30, 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 was 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 June 30, 2003, the outstanding principal balance of this note was
$5.3 million and $1.2 million, respectively. In connection with the Company's
investment in Pinnacle, the Company received a reduction in the principal amount
of the RMG note of approximately $1.5 million and relinquished the right to
receive certain revenues related to the properties contributed to Pinnacle.

-26-

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. In May 2003, the Company entered into a capital lease agreement
secured by certain production in the amount of $0.1 million. The lease is
payable in 36 monthly payments of $3,030 including interest at 5.5% per annum.
The Company has the option to acquire the equipment at the conclusion of the
lease for $1, under all of these leases. DD&A on the capital leases for six
months ended June 30, 2002 and 2003 amounted to $8,000 and $20,000,
respectively, and accumulated DD&A on the leased equipment at December 31, 2002
and June 30, 2003 amounted to $28,000 and $56,000, 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 June 30, 2003, the outstanding balance of the Subordinated Notes had
been increased by $3.9 million and $4.6 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 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 June 30, 2003 the outstanding balance of the Series B
Preferred Stock had been increased by $0.5 million (5,294 shares) and $0.9
million (8,559 shares), respectively, 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.

-27-

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.

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
$0.4 million and $0.7 million for the six months ended June 30, 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 six months ended June 30, 2002 and 2003 was $1.39 and $1.50
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 six months ended June 30, 2002 or

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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.

Currently, the FASB and representatives of the SEC accounting staff are engaged
in discussions on the issue of whether SFAS 141, "Business Combinations" and
SFAS 142, "Goodwill and Other Intangibles", which were effective June 30, 2001,
called for mineral rights held under a lease or other contractual arrangement to
be classified on the balance sheet as intangible assets and accompanied by
specific footnote disclosures. Historically, oil and gas companies, including
the Company, have included these costs with all other oil and gas property costs
in Property, Plant, and Equipment on the consolidated balance sheet.

In the event this interpretation is adopted, a substantial portion of the
acquisition costs of oil and gas properties would be required to be classified
on the balance sheet as an intangible asset. The Company believes this
interpretation would not have a material effect on our results of operations for
the periods presented or in the future as these intangible assets would be
depleted using the units of production method in a manner consistent with the
method currently used to calculate depletion, depreciation, and amortization
expense ("DD&A") on those assets.

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 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 change, the rate at which the Company records these
expenses will change.

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

-29-

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 June 30, 2003 were designated and effective as cash flow
hedges except certain options described below under "Volatility of Oil and
Natural Gas Prices".

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 year
end for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.

Contingencies

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

VOLATILITY OF OIL AND NATURAL GAS PRICES

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

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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.

As of December 31, 2002 and June 30, 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 June 30, 2002 and 2003 were 45,500 Bbls and 63,300 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars during the three
months ended June 30, 2002 and 2003 were 728,000 MMBtu and 819,000 MMBtu,
respectively. Total oil purchased and sold under swaps and collars during the
six months ended June 30, 2002 and 2003 were 45,500 Bbls and 126,300 Bbls,
respectively. Total natural gas purchased and sold under swaps and collars
during the six months ended June 30, 2002 and 2003 were 1,538,000 MMBtu and
1,349,000 MMBtu, respectively. The net losses realized by the Company under such
hedging arrangements were $0.4 million and $0.4 million for the three months
ended June 30, 2002 and 2003, respectively, and are included in oil and natural
gas revenues. The net losses realized by the Company under such hedging
arrangements were $0.4 million and $1.7 million for the six months ended June
30, 2002 and 2003, respectively, and are included in oil and natural gas
revenues.

At December 31, 2002 and June 30, 2003 the Company had the following outstanding
hedge positions:

During July 2003, the Company entered into swap arrangements covering 36,800
Bbls of oil for August 2003 through October 2003 production with a fixed price
of $30.00.

In addition to the hedge positions above, during the second quarter of 2003, the
Company acquired options to sell 6,000 MMBtu of natural gas per day for the
period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000.

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The Company acquired these options to protect its cash position against
potential margin calls on certain natural gas derivatives due to large increases
in the price of natural gas. These options have been classified as derivatives.
As of June 30, 2003, these options have been adjusted to their estimated fair
market value of approximately $28,000 and a charge for the adjustment of $91,000
has been included in other income and expense for the three months ended June
30, 2003.

NEW ACCOUNTING PRONOUNCEMENTS

Effective July 1, 2003, we will adopt SFAS 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". This
standard will not have a material impact on our consolidated financial
statements.

The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
("FIN 46"), in January 2003. FIN 46 requires the consolidation of certain types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. The Company has identified no transactions or related entities
that required consolidation under this interpretation.

Currently, the FASB and representatives of the SEC accounting staff are engaged
in discussions on the issue of whether SFAS 141, "Business Combinations" and
SFAS 142, "Goodwill and Other Intangibles", which were effective June 30, 2001,
called for mineral rights held under a lease or other contractual arrangement to
be classified on the balance sheet as intangible assets and accompanied by
specific footnote disclosures. Historically, oil and gas companies, including
the Company, have included these costs with all other oil and gas property costs
in Property, Plant, and Equipment on the consolidated balance sheet.

In the event this interpretation is adopted, a substantial portion of the
acquisition costs of oil and gas properties would be required to be classified
on the balance sheet as an intangible asset. The Company believes this
interpretation would not have a material effect on our results of operations for
the periods presented or in the future as these intangible assets would be
depleted using the units of production method in a manner consistent with the
method currently used to calculate depletion, depreciation, and amortization
expense ("DD&A") on those assets.

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, level of risk and
capital involved in the North Sea project area, the application of FIN 46 to
Pinnacle, 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 in the United States and elsewhere, 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.

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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
4 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part
I of this Quarterly Report on Form 10-Q.

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ITEM 4 - CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of June 30, 2003 to provide reasonable assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms.

There has been no change in our internal controls over financial reporting that
occurred during the three months ended June 30, 2003 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.

-34-

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

Pursuant to an exchange election provided in a letter agreement, dated
May 1, 2001, with certain participants in the Carrizo 2001 Seismic and Acreage
Program (the "2001 Program"), the Company is issuing to such participants, who
have exercised their election, approximately 168,000 shares of its common stock
in exchange for the participants' entire interest in the 2001 Program, including
approximately 350 square miles of 3D seismic data and working interests in
certain producing properties. The exchange transaction is effective on July 31,
2003 and will be valued using the close price of the Company's common stock on
that date, for a total of approximately $1.2 million. Such transaction was
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 any
public offering.

Item 3 - Defaults Upon Senior Securities

None.

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

At the Annual Meeting of Carrizo Oil & Gas, Inc. held on May 23, 2003,
there were represented by person or by proxy 13,879,926 shares out of 14,200,716
entitled to vote as of the record date, constituting a quorum.

The matters submitted to a vote of shareholders were (1) the reelection
of Steven A. Webster, Christopher C. Behrens, Bryan R. Martin, Douglas A.P.
Hamilton, Paul B. Loyd, Jr., F. Gardner Parker, S.P. Johnson IV and Frank A.
Wojtek as directors, (2) the approval of an amendment to the incentive plan to
provide for additional stock option grants to the chairman and members of
certain committee of the Board of Directors and (3) the approval of the
appointment of Ernst & Young LLP as Independent Public Accountants for the
fiscal year ended December 31, 2003. With respect to the election of directors,
the following number of votes were cast for the nominees: 13,554,530 for Mr.
Webster and 325,396 withheld; 13,554,530 for Mr. Behrens and 325,396 withheld;
13,554,330 for Mr. Martin and 325,596 withheld; 13,554,530 for Mr. Hamilton and
325,396 withheld; 7,611,358 for Mr. Loyd and 325,596 withheld; 13,553,810 for
Mr. Parker and 326,116 withheld; 13,519,805 for Mr. Johnson and 360,121
withheld; and 13,554,530 for Mr. Wojtek and 325,396 withheld. There were no
abstentions in the election of directors. With respect to the amendment to the
incentive plan, 10,991,953 votes were cast for the amendment, 464,794 votes were
against and 7,340 votes abstained. With respect to the appointment of Ernst &
Young LLP as Independent Public Accountants, 13,860,068 votes were cast for the
appointment, 10,882 votes were against, and 8,976 votes abstained.

Item 5 - Other Information

On August 14, 2003, the Company announced the appointment of Paul F.
Boling as Vice President and Chief Financial Officer, Secretary and Treasurer of
the Company. Frank A. Wojtek left the Company to pursue other interests.

Paul F. Boling, age 49, joined Carrizo as Chief Financial Officer, Vice
President, Secretary and Treasurer on August 12, 2003. From 2001 to 2003, Mr.
Boling was the Global Controller for Resolution Performance Products, LLC., an
international epoxy resins manufacturer. From 1990 to 2001, Mr. Boling served in
a number of financial and managerial positions with Cabot Oil & Gas Corporation,
serving most recently as Vice President, Finance. Mr. Boling is a CPA and holds
a B.B.A. from Baylor University.

Item 6 - Exhibits and Reports on Form 8-K

Exhibits

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Hamilton and Frank A. Wojtek dated as of September 6, 1997
(incorporated herein by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

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

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

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

10.1 -- Contribution and Subscription Agreement dated June 23, 2003 by
and among Pinnacle Gas Resources, Inc., CCBM, Inc., Rocky
Mountain Gas, Inc. and the CSFB Parties listed therein.

10.2 -- Transition Services Agreement dated June 23, 2003 by and between
the Company and Pinnacle Gas Resources, Inc.

31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.

31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.

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

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

+ Incorporated herein by reference as indicated.

Reports on Form 8-K

The Company filed a Current Report on Form 8-K on April 29,
2003 (information furnished not filed) and a Current Report on Form 8-K
on May 8, 2003 (information furnished not filed).

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SIGNATURES

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

Carrizo Oil & Gas, Inc.
(Registrant)

Date: August 14, 2003 By: /s/S. P. Johnson, IV
--------------------------------------------
President and Chief Executive Officer
(Principal Executive Officer)

Date: August 14, 2003 By: /s/Paul F. Boling
--------------------------------------------
Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

-37-

EXHIBIT INDEX

+ Incorporated herein by reference as indicated.