CARRIZO OIL & GAS INC - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
COMMISSION NO. 0-22915

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

Registrant's telephone number, including area code: (281) 496-1352

Securities Registered Pursuant to Section 12(g) of the Act:

COMMON STOCK, $.01 PAR VALUE

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 if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.

[X]

Indicate by check mark whether the registrant is an accelerated filer.

YES [ ] NO [X]

At June 28, 2002, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $21.0 million
based on the closing price of such stock on such date of $4.26.

At March 20, 2003, the number of shares outstanding of the registrant's
Common Stock was 14,200,716.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant's 2003 Annual
Meeting of Shareholders are incorporated by reference in Part III of this Form
10-K. Such definitive proxy statement will be filed with the Securities and
Exchange Commission not later than 120 days subsequent to December 31, 2002.

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TABLE OF CONTENTS

PART I

ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES

GENERAL

Carrizo Oil & Gas, Inc. ("Carrizo" or the "Company") is an independent oil
and gas company engaged in the exploration, development, exploitation and
production of natural gas and crude oil. The Company's current operations are
primarily focused onshore in proven oil and gas producing trends along the Gulf
Coast, in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends ("Gulf
Coast Core Areas").

The Company believes that the availability of economic onshore 3-D seismic
surveys has fundamentally changed the risk profile of oil and gas exploration in
these regions. During the period from 1996 through December 2001 the Company
acquired 52 3-D seismic surveys with over 2,700 square miles of 3-D data in the
Gulf Coast Core Areas. In late 2002 the Company acquired (or obtained the right
to acquire) an additional 2,750 square miles of 3-D seismic data in the Gulf
Coast Core Areas, including primarily either recently merged and reprocessed
data sets or data newly released to industry. The Company also acquired
additional 3-D seismic data during 2002 as a result of certain data licensing
swaps. The 2002 data acquisitions nearly double the amount of 3-D seismic data
the Company owns in the Gulf Coast Core Areas, and has led to the identification
of additional drilling prospects over which the Company is currently in the
process of acquiring additional lease acreage. These new data, if all are
acquired, will bring the Company's 3-D seismic database in the Gulf Coast Core
Areas to 6,732 square miles, which the Company believes is one of the largest
such databases owned by an independent exploration company in the region. The
Company also has approximately 1,840 square miles of 3-D data in non-core areas
in which the Company presently does not have active projects, but which the
Company is screening for potential drilling prospects. The Company continuously
analyzes and reprocesses the 3-D seismic data in search of prospects which the
Company believes have a high probability of containing natural gas or oil.

Historically, the Company aggressively sought to control significant
prospective acreage blocks for 3-D seismic surveys. The Company would typically
seek to acquire seismic permits from landowners that included options to lease
the acreage prior to conducting proprietary surveys. In other circumstances,
including when the Company participated in 3-D group shoots, the Company
typically sought to obtain leases or farm-ins rather than lease options. From
1996 through 2002, the Company assembled over 400,000 gross acres under lease or
option. After the 3-D seismic data was processed and analyzed, the Company
sought to retain such acreage as it deemed to be prospective and released
non-prospective acreage. As of December 31, 2002, the Company had 100,707 gross
acres in Texas and Louisiana under lease or lease option, most of which is
covered by 3-D seismic data, and 287,994 gross acres in Wyoming and Montana
under lease or option.

From the analysis and interpretation of the 3-D seismic data, Carrizo has
amassed a large drill-site inventory, with as many as 210 gross wells that could
be drilled over the next three to five years, assuming sufficient capital
resources. Most of the Company's drilling targets in prior years have been
shallow (from 4,000 to 7,000 feet), normally pressured reservoirs that generally
involve moderate cost (typically $0.3 million to $0.4 million per completed
well) and risk. Many of the Company's current drilling prospects are deeper,
over-pressured targets which have greater economic potential but generally
involve higher cost (typically $1.0 million to $4.0 million per completed well)
and risk. The Company usually seeks to sell a portion of these deeper prospects
to reduce its exploration risk and financial exposure while still allowing the
Company to retain significant upside potential. The Company has recently begun
to retain larger percentages of, and increased its exposure to, higher cost,
higher potential wells.

The Company operates the majority of its projects through the exploratory
phase but may relinquish operator status to qualified partners in the production
phase in order to focus resources on the higher-value exploratory phase. As of
December 31, 2002, the Company operated 85 producing oil and gas wells, which
accounted for 52% of the onshore Gulf Coast producing wells in which the Company
had an interest.

During 2001, the Company, through its wholly-owned subsidiary, CCBM, Inc.
("CCBM") acquired 50% of the working interests held by Rocky Mountain Gas, Inc.
("RMG") in approximately 107,000 net mineral acres prospective for coalbed
methane located in the Powder River Basin in Wyoming and Montana. The Company
has participated in the acquisition and/or drilling of 75 gross wells, all
of which encountered coal accumulations. Of these wells, 24 wells are currently
producing, 19 are in the dewatering phase and 36 wells are under evaluation to
determine if they are likely to result in commercial production of natural gas.
Proved reserves of 0.6 Bcfe are assigned to the Company's coalbed methane
properties as of December 31, 2002.

The Company has increased its oil and gas reserves from its inception in
1993 primarily due to its 3-D based drilling and development

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activities. From January 1, 1996 to December 31, 2002, the Company participated
in the drilling of 263 gross wells (82.2 net) with a commercial well success
rate of approximately 66%, excluding the 75 gross (28 net) coalbed methane wells
drilled by CCBM. This drilling success contributed to the Company's total proved
reserves as of December 31, 2002 of 63.2 Bcfe with a PV-10 Value of $83.6
million. See "Oil and Natural Gas Properties". During 2002, the Company added a
net 11.4 Bcfe to proved reserves, offset by 7.2 Bcfe of production. The Company
has financed the majority of its drilling activity through internal cash flow
generated primarily from oil and natural gas production sales revenue.

Certain terms used herein relating to the oil and natural gas industry are
defined in "Glossary of Certain Industry Terms" below.

EXPLORATION APPROACH

The Company's strategy has been to rapidly accumulate large amounts of 3-D
seismic data along primarily prolific, producing trends of the onshore Gulf
Coast, after obtaining options to lease areas covered by the data. The Company
then uses 3-D seismic data to identify or evaluate prospects before drilling the
prospects that fit its risk/reward criteria. The Company typically seeks to
explore in locations within its core areas of expertise that it believes have
(i) numerous accumulations of normally pressured reserves at shallow depths and
in geologic traps that are difficult to define without the interpretation of 3-D
seismic data and (ii) the potential for large accumulations of deeper,
over-pressured reserves.

As a result of the increased availability of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company has relied almost exclusively on the interpretation of
3-D seismic data in its exploration strategy. The Company generally does not
invest any substantial portion of the costs for an exploration well without
first interpreting 3-D seismic data. The principal advantage of 3-D seismic data
over traditional 2-D seismic analysis is that it affords the geoscientist the
ability to interpret a three dimensional cube of data as compared to
interpreting between widely separated two dimensional vertical profiles.
Consequently, the geoscientist is able to more fully and accurately evaluate
prospective areas, improving the probability of drilling commercially successful
wells in both exploratory and development drilling. The use of 3-D seismic
allows the geoscientist to identify and use areas of irregular sand geometry to
augment or replace structural interpretation in the identification of potential
hydrocarbon accumulations. Additionally, detailed analysis and correlation of
the 3-D seismic response to lithology and contained fluids assist geoscientists
in identifying and prioritizing drilling targets. Because 3-D analysis is
completed over an entire target area cube, shallow, intermediate and deep
objectives are analyzed. Additionally, the more precise structural definition
allowed by 3-D seismic data combined with integration of available well and
production data assists in the positioning of new development wells.

Historically, the Company sought to obtain large volumes of 3-D seismic
data either by participating in large seismic data acquisition programs either
alone or pursuant to joint venture arrangements with other energy companies, or
through "group shoots" in which the Company shared the costs and results of
seismic surveys. By participating in joint ventures and group shoots, the
Company was able to share the up-front costs of seismic data acquisition and
interpretation, thereby enabling it to participate in a larger number of
projects and diversify exploration costs and risks. Most of the Company's
operations are conducted through joint operations with industry participants.

The Company has also participated in 3-D data licensing swaps, whereby the
Company transfers license rights to certain proprietary 3-D data it owns in
exchange for license rights to other 3-D data within its core areas, thus
allowing the Company to obtain access to additional 3-D data within its Gulf
Coast Core Areas at either minimal or no out-of-pocket cash cost.

In late 2002, the Company acquired (or obtained the right to acquire) an
additional 2,750 square miles of 3-D seismic data in its Gulf Coast Core Areas.
These new data are primarily either recently merged and reprocessed data sets or
former proprietary data sets newly released to industry. Specific Company
operating areas to which new data were added as a result of the late 2002 data
acquisition include (1) 450 square miles of newly reprocessed 3-D data to the
Matagorda project area, (2) 167 square miles of newly released 3-D data to the
Liberty Project area, (3) 239 square miles to the Wilcox project area, and (4)
826 square miles of newly reprocessed 3-D data to the South Louisiana project
area. These data acquisitions consist of existing nonproprietary data sets
obtained from seismic companies at what the Company believes to be attractive
pricing.

The Company's primary strategy for acreage acquisition in prior years was
to obtain leasing options covering large geographic areas in connection with 3-D
seismic surveys. Prior to conducting proprietary surveys, the Company typically
sought to acquire seismic permits that included options to lease the acreage,
thereby ensuring the price and availability of leases on drilling prospects that
may result upon completing a successful seismic data acquisition program over a
project area. The Company generally attempted to obtain these options covering
at least 80% of the project area for proprietary surveys. The size of these
surveys ranged from 10 to 80 square miles. When the Company participated in 3-D
group shoots, it generally sought prospective leases as quickly as possible
following interpretation of the survey. In connection with some group shoots in
which the Company believed that competition for acreage was especially strong,
the Company sought to obtain lease options or leases in prospective areas prior
to the receipt or interpretation of 3-D seismic data. After receipt of and
interpretation of the 3-D seismic data, the Company generally seeks to retain

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only such acreage or leases as it deems to be prospective based upon the 3-D
results and the Company's interpretation. In more recent years, the Company has
focused less on conducting proprietary 3-D surveys, and has focused instead on
(1) the continual interpretation and evaluation of its existing 3-D seismic
database and the drilling of identified prospects on such acreage and (2) the
acquisition of existing non-proprietary 3-D data at reduced prices, in many
cases contiguous to or in areas nearby existing Company project areas where the
Company has extensive knowledge and subsequent acquisition of related acreage as
the Company deems to be prospective based upon its interpretation of such 3-D
data.

The Company maintains a flexible and diversified approach to project
identification by focusing on the estimated financial results of a project area
rather than limiting its focus to any one method or source for obtaining leads
for new project areas. The Company's current project areas result from leads
developed primarily by the Company's internal staff. Additionally, the Company
monitors competitor activity and reviews outside prospect generation by small,
independent "prospect generators", or the Company's joint venture partners. The
Company complements its exploratory drilling portfolio through the use of these
outside sources of project generation, and typically retains operation rights.
Specific drill-sites are typically chosen by the Company's own geoscientists.

OPERATING APPROACH

The Company's management team has extensive experience in the development
and management of exploration projects along the Texas and Louisiana Gulf Coast.
The Company believes that the experience of its management in the development,
processing and analysis of 3-D projects and data in the Gulf Coast Core Areas is
a competitive advantage for the Company. The Company's technical and operating
employees have an average of 20 years of industry experience, in many cases with
major and large independent oil companies, including Shell Oil Company, Arco,
Vastar Resources, Inc., Pennzoil Company and Tenneco Inc.

The Company generally seeks to obtain lease operator status and control
over field operations, and in particular seeks to control decisions regarding
3-D survey design parameters and drilling and completion methods. As of December
31, 2002, the Company operated 85 producing oil and natural gas wells.

The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to use
reliable, high quality, used equipment in place of new equipment to achieve cost
savings. The Company also seeks to minimize cycle time from drilling to hook-up
of wells, thereby accelerating cash flow and improving ultimate project
economics.

The Company seeks to use advanced production techniques to exploit and
expand its reserve base. Following the discovery of proved reserves, the Company
typically continues to evaluate its producing properties through the use of 3-D
seismic data to locate undrained fault blocks and identify new drilling
prospects and performs further reserve analysis and geological field studies
using computer aided exploration techniques. The Company has integrated its 3-D
seismic data with reservoir characterization and management systems through the
use of geophysical workstations which are compatible with industry standard
reservoir simulation programs.

SIGNIFICANT PROJECT AREAS

This section is an explanation and detail of some of the relevant project
groupings from the Company's overall inventory of seismic data and prospects. It
is difficult to uniquely categorize many of the 3-D projects because they were
originally screened and selected for multiple objectives. In the Texas Wilcox
Areas, additional 3-D data that connects and overlaps existing project area
grids continues to be acquired and integrated into the Company's prospect
evaluations and as such, a geographical subgrouping is now used to describe the
Company's areas of focus, rather than the original project area descriptions.
This discussion clarifies this organizational framework and highlights the
project areas where the majority of the expected drilling will take place over
the next 12 to 18 months.

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3-D PROJECT SUMMARY CHART
As of December 31, 2002

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(1) 3-D seismic coverage in oil & gas producing basins outside areas of current
leasehold activity.

(2) 2003 planned seismic additions are primarily 3-D seismic data, the rights
to which the Company acquired as part of a 2,750 square mile data purchase
in late 2002, that is expected to be delivered to the Company in 2003.

TEXAS -- WILCOX AREAS

The prolific Wilcox trend in South Texas continues to be a primary area of
exploration and development focus for Carrizo. The

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Company has a total of 1,793 square miles of 3-D seismic data that covers
potential Wilcox formation exploration and development targets. Wilcox prospects
occur at a variety of depths but are often relatively deeper targets with both
high reserve potential as well as higher well costs. While Carrizo operates
almost all of its Wilcox area projects, portions of these wells are typically
sold down to industry partners to reduce costs and offset exploration and
operational risk.

The Wilcox Central subgroup area contains Company project areas in Goliad,
Lavaca, Dewitt, and Bee Counties, Texas and includes the Cabeza Creek Project
Area. The Wilcox South subgroup contains projects in Duval, Live Oak, Webb,
Zapata and McMullen Counties, Texas. The Wilcox East subgroup contains projects
in Colorado, Jackson, Victoria, Fort Bend and Wharton Counties, Texas.

Wilcox Central -- Goliad, Lavaca, Dewitt, and Bee Counties

The Company was successful on six out of seven wells drilled within the
central Wilcox area during 2002 with drilling focused in the Cabeza Creek
Project Area. Two successful field extension wells to the "Riverdale #2"
discovery well were drilled during 2002, the "Riverdale #1" which commenced
production in May 2002 and the "Riverdale #3" well which commenced production in
August 2002. Carrizo is the operator of the wells and owns a 68.75% working
interest. The Company has eleven additional prospects that are drill-ready
within the 8,416 net acre area that the Company plans to further evaluate over
the next 12 to 18 months, including six wells expected to be drilled during
2003. The primary targets range from the Lower Wilcox to the expanded Upper
Wilcox between 12,000 and 16,000 feet. During 2003, the Company plans to
participate in a Lower Wilcox test well. The Company continues to develop
prospects within its 957 square mile central Wilcox 3-D database, and is working
to secure leases over the areas it believes have the highest potential.

Wilcox South -- Live Oak, Duval, Webb, Zapata, and McMullen Counties

The Company continues to develop prospects within its 562 square mile
southern Wilcox 3-D seismic database and is working to secure leases over areas
it believes have the highest potential. The primary targets include upper Wilcox
through Lobo formations. The Company was successful on both of the wells drilled
in the area during 2002, the "S. Marshall Jr. A-2123 #1" and "S. Marshall Jr.
A-2123 #2" wells in Duval County, both of which commenced sales in February
2003. The Company operates the wells and owns a 29.25% working interest. The
Company plans to drill at least one additional well in this area during 2003
near a recent discovery well drilled by a competitor.

Wilcox East -- Colorado, Jackson, Victoria, Fort Bend, and Wharton Counties

The Company continues to develop prospects within its 274 square mile 3-D
database and is working to secure leases over the areas it believes have the
highest potential. Targets range from the Lower Wilcox to expanded Upper Wilcox
between 12,000 and 16,000 feet. Depending upon the success of leasing efforts,
initial drilling could occur in late 2003 or 2004.

TEXAS FRIO/VICKSBURG/YEGUA AREAS

This combined area trend sometimes overlaps but is generally closer to the
Texas Gulf Coast than the Wilcox areas discussed above. In any particular target
or prospect, the Frio is usually a shallower formation, while the Yegua and
Vicksburg are generally relatively deeper formations. Across the Carrizo project
areas, prospect targets vary greatly in depth and area distribution. The Company
has a total of 2,102 miles of 3-D seismic data over these Frio, Vicksburg and
Yegua sands. Several key areas are discussed below which highlight areas of
expected focus during 2003 and future years.

Matagorda -- Matagorda County

The Matagorda Project Area currently includes license to 542 square miles
of 3-D seismic and 3,951 net acres of current leasehold in Matagorda County,
Texas. The Company continued its drilling success during 2002 in the Matagorda
Project Area with three successful wells. All three wells were drilled as
offsets to the field discovery well, the "Staubach #1" that commenced production
in January 2002 at over 17,000 Mcfe per day. The "Burkhart #1R" was completed
and commenced production in July 2002 at a gross rate of 1,500 barrels of oil
and 8,700 Mcf of natural gas (17,700 Mcfe) per day. Carrizo owns a 35% working
interest in the well. In July 2002, the Company spud the "Pauline Huebner A-382
#1" well which Carrizo operates and owns a 45% working interest. This well
commenced production in mid-November 2002 at a gross rate of approximately 1,800
barrels of oil and 5,000 Mcf of natural gas (approximately 15,800 Mcfe) per day.
The latest successful well, the "Matthes-Huebner #1" well, reached

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total depth of 12,500 feet on December 17, 2002, logged approximately 60 feet of
net pay in the Lower Frio section, and was the first well to have multiple pay
zones. Carrizo owns an approximate 32.21% working interest in the well which
commenced production in early January 2003 at a gross rate of approximately
2,518 barrels of oil and 7,700 Mcf of natural gas (22,800 Mcfe) per day. These
four wells are currently continuing to produce at a combined gross rate of
approximately 4,990 barrels of oil and 18,800 Mcf of natural gas (48,740 Mcfe)
per day, or 12,140 Mcfe/d net to the Company's interest. The Company plans to
drill four additional prospects within the next 12 months. Two of the planned
wells were spud during March 2003.

Wharton and Victoria Counties

The Wharton and Victoria County project areas target both normal pressured
Frio and expanded Yegua prospect opportunities identified on the Wharton County
and Victoria County, Texas 3-D seismic data sets that cover approximately 83
square miles. The Company plans to drill three normal pressured Frio wells in
these areas during 2003 retaining working interests as high as 51%. Although
relatively small prospects, these are seismic amplitude anomaly targets that are
expected to have relatively high chance of success.

SOUTHEAST TEXAS AREAS

Carrizo has now acquired approximately 587 square miles of 3-D data
(including 325 square miles of newly released data delivered in 2003) over its
Southeast Texas project areas which are focused primarily on the Frio, Yegua,
Cook Mountain and Vicksburg formations. The Liberty Project Area and Cedar Point
Project Area have proven to be successful for the Company and the Company
expects that the Liberty Project Area will constitute a significant portion of
the 2003 drilling program.

Liberty

Carrizo has identified and leased prospects ranging from the Frio to the
Cook Mountain formations within the 223 square miles of 3-D seismic in the
Liberty Project Area which, along with 60 square miles of newly released 3-D
seismic data acquired in early 2003, now covers significant areas of Liberty and
Hardin Counties, Texas. To date, the Company has been successful on four of six
wells drilled, including one Yegua well, one Frio well and two Cook Mountain
wells. The latest Cook Mountain test well drilled during the fourth quarter of
2002, the "Hankamer #1" well, logged approximately 40 feet of net pay in the
Cook Mountain interval and tested at a gross rate of 10,490 MCF of natural gas
and 772 barrels of oil (15,122 Mcfe). Carrizo operates the well and owns a 40%
working interest. Efforts to put the well online have been delayed due to
flooding late last year and the inability to connect to infrastructure, however,
the well is expected to commence production in early April 2003. Carrizo plans
to drill three additional wells in the Liberty Project Area during 2003.

Cedar Point

The Cedar Point Project Area is located in Chambers County, Texas, adjacent
to Trinity Bay. The 30 square mile 3-D survey targets the lower Frio and
Vicksburg formations. Five of six wells drilled to date have been successful.
Carrizo plans to drill an additional well in 2003. The Company's working
interest in leases in this project area is approximately 25%.

SOUTH TEXAS

LaSalle and McMullen Counties

The South Texas Project Area is located in LaSalle and McMullen Counties,
Texas. Analysis and interpretation of the 65 square mile proprietary 3-D seismic
survey has revealed two large Sligo Patch reef prospects. The Company believes
these prospects could hold significant potential, and expects to spud the first
test well in late 2003. The Company currently has an approximate 79% working
interest in these prospects, but expects to sell down a portion of its interest
to industry partners in order to mitigate the exploration risk and the Company's
financial exposure.

LOUISIANA

LaRose

During 2002, the Company successfully drilled and completed the "Louisiana
Delta Farms #2" well, offsetting the LaRose Prospect 2001 discovery well, the
"Louisiana Delta Farms #1", in Lafourche Parish, Louisiana. Carrizo operates the
wells and owns a 40% working interest. Through February 2003, the two wells have
produced over 4.5 Bcfe since commencement of production. The

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Company plans to participate in the drilling of three additional wells in areas
either near or within the LaRose Project Area during 2003. During 2002, the
Company acquired the rights to over 1,150 square miles of additional 3-D seismic
data in Louisiana for future potential prospect evaluation.

CAMP HILL PROJECT

The Company owns interests in eight leases totaling approximately 619 gross
acres in the Camp Hill field in Anderson County, Texas. The Company currently
operates seven of these leases. During the year ended December 31, 2002, the
project produced an average of 58 Bbls/d of 19 API gravity oil. The wells
produce from a depth of 500 feet and utilize a tertiary steam drive as an
enhanced oil recovery process. Although efficient at maximizing oil recovery,
the steam drive process is relatively expensive to operate because natural gas
or produced crude is burned to create the steam injectant. Lifting costs during
the year ended December 31, 2002 averaged $14.99 per barrel ($2.50 per Mcfe). In
response to high fuel gas prices, steam injection was reduced in mid 2000.
Because profitability increases when natural gas prices drop relative to oil
prices, the project is a natural hedge against decreases in natural gas prices
relative to oil prices. The oil produced, although viscous, commands a higher
price (an average premium of $1.00 per Bbl during the year ended December 31,
2002) than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 2002, the Company had 7.7 MBbls of proved oil
reserves in this project, with 750 MBbls of oil reserves currently developed.
The Company anticipates drilling additional wells and increasing steam injection
to develop the proved undeveloped reserves in this project, with the timing and
amount of expenditures depending on the relative prices of oil and natural gas.
The Company has an average working interest of 90% in this field and an average
net revenue interest of 74%.

WYOMING/MONTANA COALBED METHANE PROJECT AREA

The Company, through CCBM, acquired interests from RMG in certain oil and
gas leases covering 233,875 gross acres and 43,711 gross acres in options during
2001 in areas prospective for coalbed methane in the Powder River Basin ("PRB")
in southwestern Wyoming and Montana. The Company's working interest ranges from
6.25% to 50.00% in the leases. As consideration for the interests, CCBM paid RMG
$7.5 million in the form of a non-recourse promissory note (the "CCBM Note"),
secured solely by CCBM's interest in the undeveloped acreage. In addition, the
Company committed to spend up to $5.0 million to drill and test coalbed methane
wells on this acreage during 2001 through 2003, 50% of which would be spent
pursuant to an obligation by Carrizo to fund $2.5 million of drilling costs on
behalf of RMG. As of December 31, 2002, the Company has participated in the
acquisition and/or drilling of 75 gross wells (28 net) satisfying approximately
$3.0 million of the $5.0 million drilling commitment. All of the wells
encountered coal accumulations and are in various stages of development and/or
stages of production. Coalbed methane wells typically first produce water and
then, as the water production declines, begin producing methane gas at an
increasing rate. As the wells mature the production peaks and begins declining.

At the "Clearmont Project" in Wyoming, in which CCBM owns an average 50%
working interest, 32 wells have been drilled and completed to date, including 19
wells currently on pump in the dewatering stage of development. As there are
only a few other coalbed methane projects/wells in the immediate vicinity, the
dewatering process has taken longer than originally estimated. All of the wells
on pump are producing small amounts of gas consistent with expectations given
the current development stage of the project. The gas gathering, compression
facilities and sales pipeline are in place, and depending upon the progress of
the dewatering process, commercial production could commence in late 2003.

At the 1,940 gross acre "Bobcat Project" in Wyoming, in which CCBM owns an
average working interest of approximately 28%, gross production has reached a
level of over 2,600 Mcf/d, with wellhead prices in excess of $4.00 per Mcf. Many
of the 24 production wells in the project area are still in the dewatering stage
and as such, production is expected to increase in the months ahead. In addition
to the existing wells, the Company believes that there are numerous additional
potential drilling locations which could target the coal seams currently being
produced as well as three additional deeper prospective coal seams.

Of the 55,167 net mineral acres held by CCBM as of December 31, 2002,
approximately 25,600 net mineral acres are located in the state of Montana. The
issuance of new coalbed methane drilling permits in Montana has been temporarily
halted pending a final Record of Decision for Montana's Environmental Impact
Statement (EIS) which is expected to be issued by the Federal Bureau of Land
Management (BLM) in mid-year 2003. The Company anticipates a favorable outcome
and as a result new drilling permits could be issued soon and new wells could
again be drilled by coalbed methane industry participants in Montana. Opponents
of coalbed methane drilling in Montana could continue their legal challenge, but
the Company believes that the decision will ultimately be upheld which would
allow new coalbed methane development to commence in Montana as early as late
2003. RMG, CCBM's partner and project operator, holds approximately 114
grandfathered drilling permits in Montana for acreage in which CCBM also has an
interest. There can be no assurances when, if ever, any new permits will be
obtained.

OTHER PROJECT AREAS

In addition to the specific project areas described above, the Company has
15 additional active project areas in various stages of development as of
December 31, 2002. These project areas are located in the onshore Texas and
Louisiana Gulf Coast regions. The Company is in the process of evaluating and
acquiring interests with respect to most of these project areas and as of
December 31, 2002 had acquired leases in these areas covering 21,158 gross acres
and 5,406 net acres.

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WORKING INTEREST AND DRILLING IN PROJECT AREAS

The actual working interest that the Company will ultimately own in a well
will vary based upon several factors, including the depth, cost and risk of each
well relative to the Company's strategic goals, activity levels and budget
availability. From time to time some fraction of these wells may be sold to
industry partners either on a prospect by prospect basis or a program basis. In
addition, the company may also contribute acreage to larger drilling units
thereby reducing prospect working interest. The Company has, in the past,
retained less than 100% working interest in its drilling prospects. References
to Company interests are not intended to imply that the Company has or will
maintain any particular level of working interest.

Although the Company is currently pursuing prospects within the project
areas described above, there can be no assurance that these prospects will be
drilled at all or within the expected time frame. In some project areas, the
Company has budgeted for wells that are based upon statistical results of
drilling activities in other project areas; these wells are subject to greater
uncertainties than wells for which drillsites have been identified. The final
determination with respect to the drilling of any identified drillsites or
budgeted wells will be dependent on a number of factors, including (i) the
results of exploration efforts and the acquisition, review and analysis of the
seismic data, (ii) the availability of sufficient capital resources by the
Company and the other participants for the drilling of the prospects (not all of
which resources are currently available), (iii) the approval of the prospects by
other participants after additional data has been compiled, (iv) the economic
and industry conditions at the time of drilling, including prevailing and
anticipated prices for oil and natural gas and the availability of drilling rigs
and crews, (v) the financial resources and results of the Company and its
partners and (vi) the availability of leases on reasonable terms and permitting
for the prospect. There can be no assurance that these projects can be
successfully developed or that any identified drillsites or budgeted wells
discussed will, if drilled, encounter reservoirs of commercially productive oil
or natural gas. The Company may seek to sell or reduce all or a portion of its
interest in a project area or with respect to prospects or wells within a
project area.

The success of the Company will be materially dependent upon the success of
its exploratory drilling program. Exploratory drilling involves numerous risks,
including the risk that no commercially productive oil or natural gas reservoirs
will be encountered. The cost of drilling, completing and operating wells is
often uncertain, and drilling operations may be curtailed, delayed or canceled
as a result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rights and the delivery of
equipment. Although the Company believes that its use of 3-D seismic data and
other advanced technologies should increase the probability of success of its
exploratory wells and should reduce average finding costs through elimination of
prospects that might otherwise be drilled solely on the basis 2-D seismic data,
exploratory drilling remains a speculative activity. Even when fully utilized
and properly interpreted, 3-D seismic data and other advanced technologies only
assist geoscientists in identifying subsurface structures and do not enable the
interpreter to know whether hydrocarbons are in fact present in such structures.
In addition, the use of 3-D seismic data and other advanced technologies
requires greater predrilling expenditures than traditional drilling strategies
and the Company could incur losses as a result of such expenditures. The
Company's future drilling activities may not be successful, and if unsuccessful,
such failure will have a material adverse effect on the Company's results of
operations and financial condition. There can be no assurance the Company's
overall drilling success rate or its drilling success rate for activity within a
particular project area will not decline. The Company may choose not to acquire
option and lease rights prior to acquiring seismic data and, in many cases, the
Company may identify a prospect or drilling location before seeking option or
lease rights in the prospect or location. Although the Company has identified or
budgeted for numerous drilling prospects, there can be no assurance that such
prospects will ever be leased or drilled (or drilled within the scheduled or
budgeted time frame) or that oil or natural gas will be produced from any such
prospects or any other prospects. In addition, prospects may initially be
identified through a number of methods, some of which do not include
interpretation of 3-D or other seismic data. Wells that are currently in the
Company's capital budget may be based upon statistical results of drilling
activities in other 3-D project areas that the Company believes are geologically
similar, rather than on analysis of seismic or other data. Actual drilling and
results are likely to vary from such statistical results and such variance may
be material. Similarly, the Company's drilling schedule may vary from its
capital budget because of future uncertainties, including those described above.
The description of a well as "budgeted" does not mean that the Company currently
has or will have the capital resources to drill the well. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations".

OIL AND NATURAL GAS RESERVES

The following table sets forth estimated net proved oil and natural gas
reserves of the Company and the PV-10 Value of such reserves as of December 31,
2002. The reserve data and the present value as of December 31, 2002 were
prepared by Ryder Scott Company and Fairchild & Wells, Inc., Independent
Petroleum Engineers. For further information concerning Ryder Scott's and
Fairchild's estimate of the proved reserves of the Company at December 31, 2002,
see the reserve reports included as exhibits to this

9

Annual Report on Form 10-K.
The PV-10 Value was prepared using constant prices as of the calculation date,
discounted at 10% per annum on a pretax basis, and is not intended to represent
the current market value of the estimated oil and natural gas reserves owned by
the Company. For further information concerning the present value of future net
revenue from these proved reserves, see Note 13 of Notes to Consolidated
Financial Statements.

- ----------

(1) The PV-10 Value as of December 31, 2002 is pre-tax and was determined by
using the December 31, 2002 sales prices, which averaged $29.16 per Bbl of
oil, $4.70 per Mcf of natural gas.

No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Securities and
Exchange Commission (the "Commission").

There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Annual Report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions concerning
future oil and natural gas prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of which may in
fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom
prepared by different engineers or by the same engineers but at different times
may vary substantially and such reserve estimates may be subject to downward or
upward adjustment based upon such factors. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. In addition, the 10% discount
factor, which is required by the Commission to be used in calculating discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and natural gas industry in
general.

In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Company conducts successful
exploration and development activities or acquires properties containing proved
reserves, or both, the proved reserves of the Company will decline as reserves
are produced. The Company's future oil and natural gas production is, therefore,
highly dependent upon its level of success in finding or acquiring additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investment to maintain or expand its asset base of
oil and natural gas reserves would be impaired. The failure of an operator of
the Company's wells to adequately perform operations, or such operator's breach
of the applicable agreements, could adversely impact the Company. In addition,
there can be no assurance that the Company's future exploration, development and
acquisition activities will result in additional proved reserves or that the
Company will be able to drill productive wells at acceptable costs. Furthermore,
although the Company's revenues could increase if prevailing prices for oil and
natural gas increase significantly, the Company's finding and development costs
could also increase. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations".

VOLUMES, PRICES AND OIL & NATURAL GAS OPERATING EXPENSE

The following table sets forth certain information regarding the production
volumes of, average sales prices received for and average production costs
associated with the Company's sales of oil and natural gas for the periods
indicated. The table includes the

10

cash impact of hedging activities and the
effect of certain hedge positions with an affiliate of Enron Corp. reclassified
as derivatives during November 2001.

- ----------

(1) Includes direct lifting costs (labor, repairs and maintenance, materials
and supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.

FINDING AND DEVELOPMENT COSTS

From inception through December 31, 2002, the Company has incurred total
gross development, exploration and acquisition costs of approximately $153.5
million. Total exploration, development and acquisition activities from
inception through December 31, 2002 have resulted in the addition of
approximately 82.5 Bcfe, net to the Company's interest, of proved reserves at an
average finding and development cost of $1.86 per Mcfe.

The Company's finding and development costs have historically fluctuated on
a year-to-year basis. Finding and development costs, as measured annually, may
not be indicative of the Company's ability to economically replace oil and
natural gas reserves because the recognition of costs may not necessarily
coincide with the addition of proved reserves.

DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES

The following table sets forth certain information regarding the gross
costs incurred in the purchase of proved and unproved properties and in
development and exploration activities.

- ----------

(1) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.

11

DRILLING ACTIVITY

The following table sets forth the drilling activity of the Company for the
years ended December 31, 2000, 2001 and 2002. In the table, "gross" refers to
the total wells in which the Company has a working interest and "net" refers to
gross wells multiplied by the Company's working interest therein. The Company's
drilling activity from January 1, 1996 to December 31, 2002 has resulted in a
commercial success rate of approximately 66%.

The above table excludes 75 gross (28 net) wells drilled or acquired by
CCBM through 2002. At December 31, 2002, the Company has ownership in 11 gross
(2.7 net) wells with dual completion in single bore holes.

PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which the Company owned an interest as of December 31, 2002.

ACREAGE DATA

The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 2002. Developed acres
refers to acreage within producing units and undeveloped acres refers to acreage
that has not been placed in producing units. Leases covering substantially all
of the undeveloped acreage in the following table will expire within the next
three years. In general, the Company's leases will continue past their primary
terms if oil or natural gas in commercial quantities is being produced from a
well on such leases.

The table does not include 4,441 and 723 gross acres (4,441 and 723 net)
that the Company had a right to acquire in Texas and Louisiana, respectively,
pursuant to various seismic option agreements at December 31, 2002. Under the
terms of its option agreements, the Company typically has the right for a period
of one year, subject to extensions, to exercise its option to lease the acreage
at predetermined terms. The Company's lease agreements generally terminate if
producing wells have not been drilled on the acreage within a period of three
years. Further, the table does not include 43,711 gross and 15,991 net acres in
Wyoming that the Company has the right to earn pursuant to certain

12

drilling obligations and other predetermined terms.

MARKETING

The Company's production is marketed to third parties consistent with
industry practices. Typically, oil is sold at the wellhead at field-posted
prices plus a bonus and natural gas is sold under contract at a negotiated price
based upon factors normally considered in the industry, such as distance from
the well to the pipeline, well pressure, estimated reserves, quality of natural
gas and prevailing supply/demand conditions.

The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of multiple
outlets near its production in the Texas and Louisiana Gulf Coast. The Company
takes an active role in determining the available pipeline alternatives for each
property based upon historical pricing, capacity, pressure, market
relationships, seasonal variances and long-term viability.

There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers. The
availability of a ready market for the Company's oil and natural gas production
depends on the proximity of reserves to, and the capacity of, oil and natural
gas gathering systems, pipelines and trucking or terminal facilities. The
Company delivers natural gas through gas gathering systems and gas pipelines
that it does not own. Federal and state regulation of natural gas and oil
production and transportation, tax and energy policies, changes in supply and
demand and general economic conditions all could adversely affect the Company's
ability to produce and market its oil and natural gas.

The Company from time to time markets its own production where feasible
with a combination of market-sensitive pricing and forward-fixed pricing.
Forward pricing is utilized to take advantage of anomalies in the futures market
and to hedge a portion of the Company's production deliverability at prices
exceeding forecast. All of such hedging transactions provide for financial
rather than physical settlement. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations-General Overview".

Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas sold in the
spot market due primarily to seasonality of demand and other factors beyond the
Company's control. Domestic oil prices generally follow worldwide oil prices,
which are subject to price fluctuations resulting from changes in world supply
and demand. The Company continues to evaluate the potential for reducing these
risks by entering into, and expects to enter into, additional hedge transactions
in future years. In addition, the Company may also close out any portion of
hedges that may exist from time to time as determined to be appropriate by
management.

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

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

In November 2001, the Company had costless collars with an affiliate of
Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts no longer qualified for hedge
accounting treatment. As required by SFAS No. 133, the value of these derivative
instruments as of November 2001 $(0.8 million)

13

was recorded in accumulated other comprehensive income and will be reclassified
into earnings over the original term of the derivative instruments. An allowance
for the related asset was charged to other expense. At December 31, 2001 and
2002, $0.7 million and none, respectively, remained in accumulated other
comprehensive income.

Total oil purchased and sold under hedging arrangements during 2000, 2001
and 2002 were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 2000, 2001 and 2002
were 1,590,000 MMBtu, 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(1.5 million) and $2.0 million and $(0.9 million) for 2000, 2001 and 2002,
respectively.

At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:

COMPETITION AND TECHNOLOGICAL CHANGES

The Company encounters competition from other oil and natural gas companies
in all areas of its operations, including the acquisition of exploratory
prospects and proven properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of its
competitors are large, well-established companies with substantially larger
operating staffs and greater capital resources than those of the Company and
which, in many instances, have been engaged in the oil and natural gas business
for a much longer time than the Company. Such companies may be able to pay more
for exploratory prospects and productive oil and natural gas properties and may
be able to identify, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources permit.
In addition, such companies may be able to expend greater resources on the
existing and changing technologies that the Company believes are and will be
increasingly important to the current and future success of oil and natural gas
companies. The Company's ability to explore for oil and natural gas prospects
and to acquire additional properties in the future will be dependent upon its
ability to conduct its operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment. The
Company believes that its exploration, drilling and production capabilities and
the experience of its management generally enable it to compete effectively.
Many of the Company's competitors, however, have financial resources and
exploration and development budgets that are substantially greater than those of
the Company, which may adversely affect the Company's ability to compete with
these companies.

The oil and natural gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive pressures
may force the Company to implement such new technologies at substantial cost. In
addition, other oil and natural gas companies may have greater financial,
technical and personnel resources that allow them to enjoy technological
advantages and may in the future allow them to implement new technologies before
the Company. There can be no assurance that the Company will be able to respond
to such competitive pressures and implement such technologies on a timely basis
or at an acceptable cost. One or more of the technologies currently utilized by
the Company or implemented in the future may become obsolete. In such case, the
Company's business, financial condition and results of operations could be
materially adversely affected. If the Company is unable to utilize the most
advanced commercially available technology, the Company's business, financial
condition and results of operations could be materially and adversely affected.

14

REGULATION

The availability of a ready market for oil and natural gas production
depends upon numerous factors beyond the Company's control. These factors
include regulation of oil and natural gas production, federal and state
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by well or proration unit, and the effects of
regulation on the amount of oil and natural gas available for sale, the
availability of adequate pipeline and other regulated transportation and
processing facilities and the marketing of competitive fuels. For example, a
productive natural gas well may be "shut-in" because of an oversupply of natural
gas or lack of an available natural gas pipeline in the areas in which the
Company may conduct operations. State and federal regulations generally are
intended to prevent waste of oil and natural gas, protect rights to produce oil
and natural gas between owners in a common reservoir, control the amount of oil
and natural gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are subject to the jurisdiction of
various federal, state and local agencies. The Company is also subject to
changing and extensive tax laws, the effects of which cannot be predicted. The
following discussion summarizes the regulation of the United States oil and gas
industry. The Company believes that it is in substantial compliance with the
various statutes, rules, regulations and governmental orders to which the
Company's operations may be subject, although there can be no assurance that
this is or will remain the case. Moreover, such statutes, rules, regulations and
government orders may be changed or reinterpreted from time to time in response
to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect the Company's
results of operations and financial condition. The following discussion is not
intended to constitute a complete discussion of the various statutes, rules,
regulations and governmental orders to which the Company's operations may be
subject.

Regulation of Oil and Natural Gas Exploration and Production. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells that may
be drilled in and the unitization or pooling of oil and natural gas properties.
In this regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units, and therefore more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and natural gas the Company can produce
from its wells and may limit the number of wells or the locations at which the
Company can drill. The regulatory burden on the oil and natural gas industry
increases the Company's costs of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended and reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas. Federal legislation
and regulatory controls have historically affected the price of natural gas
produced by the Company and the manner in which such production is transported
and marketed. Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission (the "FERC") regulates the interstate transportation and the sale in
interstate commerce for resale of natural gas. The FERC's jurisdiction over
interstate natural gas sales and transportation was substantially modified by
the Natural Gas Policy Act of 1978 (the "NGPA"), under which the FERC continued
to regulate the maximum selling prices of certain categories of natural gas sold
in "first sales" in interstate and intrastate commerce. Effective January 1,
1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas, including
all sales by the Company of its own production. As a result, all of the
Company's domestically produced natural gas may now be sold at market prices,
subject to the terms of any private contracts that may be in effect. The FERC's
jurisdiction over interstate natural gas transportation was not affected by the
Decontrol Act.

The Company's natural gas sales are affected by intrastate and interstate
gas transportation regulation. Following the passage by Congress of the NGPA,
the FERC adopted a series of regulatory changes that have significantly altered
the transportation and marketing of natural gas. Beginning with the adoption of
"open access" regulation in Order No. 436, issued in October 1985, these changes
were intended by the FERC to foster competition by, among other things,
transforming the role of interstate pipeline companies from wholesale marketers
of gas to the primary role of gas transporters. Through similar orders affecting
intrastate pipelines that provide similar interstate services, the FERC expanded
the impact of these open access regulations to intrastate commerce.

In April 1992, the FERC issued Order No. 636 and a series of related
orders, which among other things required interstate pipelines to "unbundle"
their gas merchant services from their transportation services, thereby further
enhancing their obligation to

15

provide open-access transportation on a not unduly discriminatory basis for all
natural gas shippers. All gas marketing by the pipelines was required to be
provided upstream at the wellhead, and, as a result, most pipelines divested
their merchant functions to a marketing affiliate, which operates separately
from the transporter and can participate in downstream sales markets on a
bundled basis, in direct competition with other gas merchants. Order No. 636
also established a mechanism that allows shippers to "release" their firm
capacity to other shippers, either temporarily or permanently, when it is not
needed by those shippers. Although Order No. 636 does not directly regulate the
Company's production and marketing activities, it does affect how buyers and
sellers gain access to the necessary transportation facilities and how natural
gas is sold in the marketplace.

In February 2000, the FERC issued Order No. 637 which:

o lifted the cost-based cap on pipeline transportation rates in the
capacity release market on an experimental basis until September
30, 2002, for short-term releases of pipeline capacity of less
than one year (the FERC did not renew this program),

o permits pipelines to file for authority to charge different
maximum cost-based rates for peak and off-peak periods,

o encourages, but does not mandate, auctions for pipeline capacity,

o requires pipelines to implement imbalance management services,

o restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders, and

o expands the opportunities for shippers to "segment" their
capacity into multiple parts, and implements a number of new
pipeline reporting requirements.

Order No. 637 also requires the FERC's Staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether to
pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid. Order No. 637 was largely
affirmed by the courts, and most pipelines' tariff filings to implement the
requirements of Order No. 637 have been accepted by the FERC and placed into
effect. Finally, in July 2002, the FERC commenced an inquiry into whether it
should make changes to its policy of allowing pipelines in certain circumstances
to charge "negotiated rates" for their services including negotiated rates tied
to various natural gas commodity market indices.

As a result of these changes, sellers and buyers of natural gas have gained
direct access to the particular pipeline services they need and are better able
to conduct business with a larger number of counterparties. The Company believes
these changes generally have improved the Company's access to markets while, at
the same time, substantially increasing competition in the natural gas
marketplace. It remains to be seen, however, what effect the FERC's other
activities will have on access to markets, the fostering of competition and the
cost of doing business. The Company cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt, or what effect
subsequent regulations may have on the Company's activities.

In the past, Congress has been very active in the area of natural gas
regulation. However, as discussed above, the more recent trend has been in favor
of deregulation or "lighter handed" regulation and the promotion of competition
in the gas industry. There regularly are other legislative proposals pending in
the Federal and state legislatures which, if enacted, would significantly affect
the petroleum industry. At the present time, it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on the Company.
Similarly, and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue, or what the
ultimate effect will be on the Company's sales of gas, cannot be predicted.

The Company owns certain natural gas pipelines that it believes meet the
standards the FERC has used to establish a pipeline's status as a gatherer not
subject to FERC jurisdiction under the NGA. State regulation of gathering
facilities generally includes various safety, environmental, and in some
circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. Natural gas gathering may receive greater regulatory
scrutiny at both state and federal levels in the post-Order No. 636 environment.

Oil Price Controls and Transportation Rates. Sales of oil, condensate and
natural gas liquids by the Company are not currently

16

regulated and are made at market prices. The price the Company receives from the
sale of these products may be affected by the cost of transporting the products
to market. Much of that transportation is through interstate common carrier
pipelines. Effective as of January 1, 1995, the FERC implemented regulations
generally grandfathering all previously approved interstate transportation rates
and establishing an indexing system for those rates by which adjustments are
made annually based on the rate of inflation, subject to certain conditions and
limitations. These regulations may tend to increase the cost of transporting oil
and natural gas liquids by interstate pipeline, although the annual adjustments
may result in decreased rates in a given year. These regulations have generally
been approved on judicial review. Every five years, the FERC must examine the
relationship between the annual change in the applicable index and the actual
cost changes experienced in the oil pipeline industry. The first such review was
completed in 2000 and on December 14, 2000, the FERC reaffirmed the current
index. Following a successful court challenge of these orders by an association
of oil pipelines, on February 24, 2003 the FERC acting on remand increased the
index slightly for the current five year period, effective July 2001. The
Company is not able at this time to predict the effects of these regulations, if
any, on the transportation costs associated with oil production from the
Company's oil producing operations.

Environmental Regulations. The Company's operations are subject to numerous
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands within wilderness, wetlands and other protected areas, require
remedial measures to mitigate pollution from former operations, such as pit
closure and plugging abandoned wells, and impose substantial liabilities for
pollution resulting from production and drilling operations. Public interest in
the protection of the environment has increased dramatically in recent years.
The trend of more expansive and stricter environmental legislation and
regulations applied to the oil and natural gas industry could continue,
resulting in increased costs of doing business and consequently affecting
profitability. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes more stringent and costly waste
handling, disposal and cleanup requirements, the business and prospects of the
Company could be adversely affected.

The Company generates wastes that may be subject to the federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S.
Environmental Protection Agency ("EPA") and various state agencies have limited
the approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by the Company's oil and natural gas
operations that are currently exempt from treatment as "hazardous wastes" may in
the future be designated as "hazardous wastes," and therefore be subject to more
rigorous and costly operating and disposal requirements.

The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Although
the Company believes that it has used good operating and waste disposal
practices, prior owners and operators of these properties may not have used
similar practices, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by the Company or on or
under locations where such wastes have been taken for disposal. In addition,
many of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the Company's
control. These properties and the wastes disposed thereon may be subject to the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
RCRA and analogous state laws as well as state laws governing the management of
oil and natural gas wastes. Under such laws, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.

CERCLA, also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.

The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that have resulted in the gradual imposition of
certain pollution control requirements with respect to air emissions from the
operations of the Company. The EPA and states have developed and continue to
develop regulations to implement these requirements. The Company may be required
to incur certain capital expenditures in the next several years for air
pollution control equipment in connection with maintaining or obtaining
operating permits and

17

approvals addressing other air emission-related issues. However, the Company
does not believe its operations will be materially adversely affected by any
such requirements.

Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure ("SPCC") and response plans relating
to the possible discharge of oil into surface waters. The Company has
acknowledged the need for SPCC plans at certain of its properties and has
developed and implemented these plans. The Oil Pollution Act of 1990, ("OPA")
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. The OPA subjects owners of facilities
to strict joint and several liability for all containment and cleanup costs and
certain other damages arising from a spill, including, but not limited to, the
costs of responding to a release of oil to surface waters. The OPA also requires
owners and operators of offshore facilities that could be the source of an oil
spill into federal or state waters, including wetlands, to post a bond, letter
of credit or other form of financial assurance in amounts ranging from $10
million in specified state waters to $35 million in federal outer continental
shelf waters to cover costs that could be incurred by governmental authorities
in responding to an oil spill. Such financial assurances may be increased by as
much as $150 million if a formal risk assessment indicates that the increase is
warranted. Noncompliance with OPA may result in varying civil and criminal
penalties and liabilities. Operations of the Company are also subject to the
federal Clean Water Act ("CWA") and analogous state laws. In accordance with the
CWA, the state of Louisiana has issued regulations prohibiting discharges of
produced water in state coastal waters effective July 1, 1997. Pursuant to other
requirements of the CWA, the EPA has adopted regulations concerning discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an EPA
general permit. While certain of its properties may require permits for
discharges of storm water runoff, the Company believes that it will be able to
obtain, or be included under, such permits, where necessary, and make minor
modifications to existing facilities and operations that would not have a
material effect on the Company. Like OPA, the CWA and analogous state laws
relating to the control of water pollution provide varying civil and criminal
penalties and liabilities for releases of petroleum or its derivatives into
surface waters or into the ground.

The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect on
the Company.

As further described in "Wyoming/Montana Coalbed Methane Project Area", the
issuance of new coalbed methane drilling permits in Montana has been temporarily
halted pending a final Record of Decision by the Federal Bureau of Land
Management.

OPERATING HAZARDS AND INSURANCE

The oil and natural gas business involves a variety of operating hazards
and risks such as well blowouts, craterings, pipe failures, casing collapse,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
formations with abnormal pressures, pipeline ruptures or spills, pollution,
releases of toxic gas and other environmental hazards and risks. These hazards
and risks could result in substantial losses to the Company from, among other
things, injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
cleanup responsibilities, regulatory investigation and penalties and suspension
of operations. In addition, the Company may be liable for environmental damages
caused by previous owners of property purchased and leased by the Company. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
exploration, development or acquisitions or result in the loss of the Company's
properties. In accordance with customary industry practices, the Company
maintains insurance against some, but not all, of such risks and losses. The
Company does not carry business interruption insurance or protect against loss
of revenues. There can be no assurance that any insurance obtained by the
Company will be adequate to cover any losses or liabilities. The Company cannot
predict the continued availability of insurance or the availability of insurance
at premium levels that justify its purchase. The occurrence of a significant
event not fully insured or indemnified against could materially and adversely
affect the Company's financial condition and operations. The Company may elect
to self-insure if management believes that the cost of insurance, although
available, is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. The occurrence of an
event not fully covered by insurance could have a material adverse effect on the
financial condition and results of operations of the Company. The Company
participates in a substantial percentage of its wells on a nonoperated basis,
which may limit the Company's ability to control the risks associated with oil
and natural gas operations.

TITLE TO PROPERTIES; ACQUISITION RISKS

The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. As is customary in the industry
in the case of undeveloped properties, little investigation of record title is
made at the time of acquisition (other than a preliminary review of local
records). Investigations, including a title opinion of local

18

counsel, are generally made before commencement of drilling operations. The
Company's revolving credit facility is secured by substantially all of its oil
and natural gas properties.

The successful acquisition of producing properties requires an assessment
of recoverable reserves, future oil and natural gas prices, operating costs,
potential environmental and other liabilities and other factors. Such
assessments are necessarily inexact and their accuracy inherently uncertain. In
connection with such an assessment, the Company performs a review of the subject
properties that it believes to be generally consistent with industry practices,
which generally includes on-site inspections and the review of reports filed
with various regulatory entities. Such a review, however, will not reveal all
existing or potential problems nor will it permit a buyer to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every well, and
structural and environmental problems are not necessarily observable even when
an inspection is undertaken. Even when problems are identified, the seller may
be unwilling or unable to provide effective contractual protection against all
or part of such problems. There can be no assurances that any acquisition of
property interests by the Company will be successful and, if unsuccessful, that
such failure will not have an adverse effect on the Company's future results of
operations and financial condition.

EMPLOYEES

At December 31, 2002, the Company had 36 full-time employees, including six
geoscientists and six engineers. The Company believes that its relationships
with its employees are good.

In order to optimize prospect generation and development, the Company
utilizes the services of independent consultants and contractors to perform
various professional services, particularly in the areas of 3-D seismic data
mapping, acquisition of leases and lease options, construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testings, are generally provided by independent contractors. The
Company believes that this use of third party service providers has enhanced its
ability to contain general and administrative expenses.

The Company depends to a large extent on the services of certain key
management personnel, the loss of, any of which could have a material adverse
effect on the Company's operations. The Company does not maintain key-man life
insurance with respect to any of its employees.

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used
herein. All volumes of natural gas referred to herein are stated at the legal
pressure base of the state or area where the reserves exist and at 60 degrees
Fahrenheit and in most instances are rounded to the nearest major multiple.

After payout. With respect to an oil or gas interest in a property, refers
to the time period after which the costs to drill and equip a well have been
recovered.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.

Bbls/d. Stock tank barrels per day.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of oil, condensate or natural gas liquids.

Before payout. With respect to an oil or gas interest in a property, refers
to the time period before which the costs to drill and equip a well have been
recovered.

Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of
oil or natural gas or, in the case of a dry hole, the

19

reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.

Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

Farm-in or farm-out. An agreement where under the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out".

Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

Finding costs. Costs associated with acquiring and developing proved oil
and natural gas reserves which are capitalized by the Company pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling and
completing wells.

Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBbls/d. One thousand barrels of oil or other liquid hydrocarbons per day.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One thousand cubic feet of natural gas per day.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million British Thermal Units.

Mmcf. One million cubic feet.

MMcf/d. One million cubic feet per day.

MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which
approximates the relative energy content of oil, condensate and natural gas
liquids as compared to natural gas. Prices have historically often been higher
or substantially higher for oil than natural gas on an energy equivalent basis,
although there have been periods in which they have been lower or substantially
lower.

Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells.

Net Revenue Interest. The operating interest used to determine the owner's
share of total production.

Normally pressured reservoirs. Reservoirs with a formation-fluid pressure
equivalent to 0.465 psi per foot of depth from the

20

surface. For example, if the formation pressure is 4,650 psi at 10,000 feet,
then the pressure is considered to be normal.

Over-pressured reservoirs. Reservoirs subject to abnormally high pressure
as a result of certain types of subsurface formations.

Petrophysical study. Study of rock and fluid properties based on well log
and core analysis.

Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.

Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.

PV-10 Value. The present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with Securities
and Exchange Commission guidelines, net of estimated production and future
development costs, using prices and costs as of the date of estimation without
future escalation, without giving effect to non-property related expenses such
as general and administrative expenses, debt service, future income tax expense
and depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.

Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.

3-D seismic data. Three-dimensional pictures of the subsurface created by
collecting and measuring the intensity and timing of sound waves transmitted
into the earth as they reflect back to the surface.

Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.

Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.

21

Workover. Operations on a producing well to restore or increase production.

ITEM 3. LEGAL PROCEEDINGS

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

In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. The Company, along
with GMT and other partners, reached a final settlement with ExxonMobil on
February 11, 2003. Under the terms of the settlement, the Company recovered the
balance its drilling costs (approximately $0.1 million) and certain other costs
and retained no further interest in the property. No reserves with respect to
these properties were included in the Company's reported proved reserves as of
December 31, 2001 and 2002.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

EXECUTIVE OFFICERS OF THE REGISTRANT

Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this Form 10-K.

The following table sets forth certain information with respect to
executive officers of the Company:

Set forth below is a description of the backgrounds of each of the
executive officers of the Company:

S.P. Johnson IV has served as the President, Chief Executive Officer and a
director of the Company since December 1993. Prior to that, he worked 15 years
for Shell Oil Company. His managerial positions included Operations
Superintendent, Manager of Planning and Finance and Manager of Development
Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in
Mechanical Engineering from the University of Colorado.

Frank A. Wojtek has served as the Chief Financial Officer ("CFO"), Vice
President, Secretary, Treasurer and a director of the Company since 1993. In
addition, from 1992 to 1997, Mr. Wojtek was the Assistant to the Chairman of the
Board of Reading & Bates Corporation ("Reading & Bates") (an offshore drilling
company). Mr. Wojtek has also been Vice President and Secretary /Treasurer for
Loyd and Associates, Inc. (a private financial consulting and investment banking
firm) since 1989. Mr. Wojtek held the positions of Vice President and CFO of
Griffin-Alexander Drilling Company from 1984 to 1987, Treasurer of
Chiles-Alexander International Inc. from 1987 to 1989 and Vice President and CFO
of India Offshore Inc. from 1989 to

22

1992, all of which are companies in the offshore drilling industry. Mr. Wojtek
is a Certified Public Accountant and holds a B.B.A. in Accounting from the
University of Texas.

Jeremy T. Greene was elected Vice President of Exploration in August 2002.
From September 2000 to August 2002 he was the Deepwater Gulf of Mexico Division
Specialist for EOG Resources, Inc. He spent the previous 17 years with Vastar
Resources, Inc., ARCO, and ARCO International where he held various technical
and managerial positions, including Director of Joint Ventures Onshore Gulf
Coast, Director of Geophysical Interpretation Research, and Eastern Deepwater
Exploration Manager, including the position of Eastern Area Deepwater
Exploration Manager for Vastar Resources, Inc. from August 1997 to September
2000. Mr. Greene received his B.S. in Geophysical Engineering from the Colorado
School of Mines, and his M.S. in Geophysics from the University of Texas at
Austin.

Kendall A. Trahan has been head of the Company's land activities since
joining the Company in March 1997 and was elected Vice President of Land of the
Company in June 1997. From 1994 to February 1997, he served as a Director of
Joint Ventures Onshore Gulf Coast for Vastar Resources, Inc. From 1982 to 1994,
he worked as an Area Landman and then a Division Landman and Director of
Business Development for Arco Oil & Gas Company. Prior to that, Mr. Trahan
served as a Staff Landman for Amerada Hess Corporation and as an independent
Landman. He holds a B.S. degree from the University of Southwestern Louisiana.

J. Bradley Fisher has served as Vice President of Operations since July
2000 and General Manager of Operations from April 1998 to June 2000. Prior to
joining the Company, Mr. Fisher was the Vice President of Engineering and
Operations for Tri-Union Development Corp. from August 1997 to April 1998. He
spent the prior 14 years with Cody Energy and its predecessor Ultramar Oil & Gas
Limited where he held various managerial and technical positions, last serving
as Senior Vice President of Engineering and Operations. Mr. Fisher hold a B.S.
degree in Petroleum Engineering from Texas A&M University.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS

The Company's common stock, par value $0.01 per share (the "Common Stock"),
has been publicly traded through the Nasdaq National Market tier of The Nasdaq
Stock Market under the symbol CRZO since the Company's initial public offering
(the "Offering") effective August 6, 1997. The following table sets forth the
quarterly high and low bid prices for each indicated quarter.

There were approximately 48 shareholders of record (excluding brokerage
firms and other nominees) of the Company's Common Stock as of March 19, 2003.

The Company has not paid any dividends in the past and does not intend to
pay cash dividends on its Common Stock in the foreseeable future. The Company
currently intends to retain any earnings for the future operation and
development of its business, including exploration, development and acquisition
activities. The Company's credit agreement with Hibernia National Bank and the
terms of its 9% Senior Subordinated Notes, restrict the Company's ability to pay
dividends. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources".

ITEM 6. SELECTED FINANCIAL DATA

The financial information of the Company set forth below for each of the
five years ended December 31, 2002, has been derived from the audited
consolidated financial statements of the Company. The information should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Company's consolidated financial statements
and related notes included in Item 8. Financial Statements and Supplementary
Data.

23

24

- ----------

(1) Net income for the year ended December 31, 1999 excludes, and earnings per
share for the year ended December 31, 1999 includes, the discount on the
redemption of the Company's Preferred Stock in the amount of $21.9 million.

(2) Management of the Company believes that EBITDA, as defined, may provide
additional information about the Company's ability to meet its future
requirements for debt service, capital expenditures and working capital.
EBITDA, as defined, is a financial measure commonly used in the oil and
natural gas industry and should not be considered in isolation or as a
substitute for net income, operating income, cash flows from operating
activities or any other measure of financial performance presented in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. Because EBITDA, as defined,
excludes some, but not all, items that affect net income, the EBITDA
presented above may not be comparable to similarly titled measures of other
companies. The following is a reconciliation of EBITDA, as defined, to net
income:

(3) Debt repayments include amounts refinanced.

Forward Looking Statements. The statements contained in all parts of this
document, (including any portion attached hereto) including, but not limited to,
those relating to the Company's schedule, targets, estimates or results of
future drilling, including the number, timing and results of wells, budgeted
wells, increases in wells, the timing and risk involved in drilling follow-up
wells, expected working or net revenue interests, planned expenditures,
prospects budgeted and other future capital expenditures, risk profile of oil
and gas exploration, acquisition of 3-D seismic data (including number, timing
and size of projects), planned evaluation of prospects, probability of prospects
having oil and natural gas, expected production or reserves, increases in
reserves, acreage, working capital requirements, hedging activities, the ability
of expected sources of liquidity to implement its business strategy, future
hiring, future exploration activity, production rates, potential drilling
locations targeting coal seams, the outcome of a final Record of Decision by the
Federal Bureau of Land Management relating to new coalbed methane drilling
permits in Montana and related legal challenges, timing of new coalbed methane
development in Montana, all and any other statements regarding future
operations, financial results, business plans and cash needs and other
statements that are not historical facts are forward looking statements. When
used in this document, the words "anticipate", "budgeted", "targeted",
"potential", "estimate", "expect", "may", "project", "believe" and similar
expressions 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 its limited operating history, technological
changes, significant capital requirements of the Company, the potential impact
of government regulations, adverse regulatory determinations, including those
related to coalbed methane drilling in Montana, litigation, competition, the
uncertainty of reserve information and future net revenue estimates, property
acquisition risks, industry partner issues, availability of equipment, weather
and other factors detailed herein and in the Company's 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.

25

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

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 39, 25 and 20 gross wells in the
Gulf Coast region in 2000, 2001 and 2002 respectively. The Company has budgeted
to drill 27 gross wells (10.7 net) in 2003 in the Gulf Coast region; 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 are expected to increase and oil
and gas operating expenses 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, over-pressured prospects.

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

During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM")
as a wholly-owned subsidiary. CCBM was formed to acquire interests in certain
oil and gas leases in Wyoming and Montana in areas prospective for coalbed
methane and develop such interests. The Company also acquired a 1,940 gross acre
coalbed methane property in Wyoming, the "Bobcat Project", for $0.7 million in
cash and common stock in July 2002. CCBM plans to spend up to $5.0 million for
drilling costs on these leases through December 2003, 50% of which would be
spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf
of RMG, from whom the interests in the leases were acquired. Through December
31, 2002, CCBM has satisfied $1.5 million of its drilling obligations on behalf
of RMG. CCBM has drilled or acquired 75 gross wells (28 net) and incurred
total drilling costs of $3.0 million through December 31, 2002. These wells
typically take up to 18 months to evaluate and determine whether or not they are
successful. CCBM has budgeted to drill up to 50 gross (18 net) wells in 2003.
The coalbed methane wells include 17 wells acquired as a result of the Bobcat
acquisition.

The Company uses the full-cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including any general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit-of-production method. To
the extent that such capitalized costs in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10 discount rate) of estimated future net after-tax cash
flows from proved oil and gas reserves, such excess costs are charged to
operations. Based on oil and gas prices in effect on December 31, 2001, the
unamortized cost of oil and gas properties exceeded the cost center ceiling. As
permitted by full cost accounting rules, improvements in pricing subsequent to
December 31, 2001 removed the necessity to record a write-down. Using prices in
effect on December 31, 2001 the write-down would have been approximately $0.7
million. Because of the volatility of oil and gas prices, no assurance can be
given that the Company will not experience a write-down in future periods. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date.

RESULTS OF OPERATIONS

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Oil and natural gas revenues for 2002 increased 2% to $26.8 million from
$26.2 million in 2001. Production volumes for natural gas in 2002 increased 8%
to 4,801 MMcf from 4,432 MMcf in 2001. Realized average natural gas prices
decreased 31% to $3.50 per Mcf in 2002 from $5.04 per Mcf in 2001. Production
volumes for oil in 2002 increased 151% to 401 MBbls from 160 MBbls in 2001. The
increase in oil production was due primarily to the commencement of production
at the Delta Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset
by the natural decline in production of other older wells. The increase in
natural gas production was due primarily to the commencement of production at
the Delta Farms #1, Riverdale #2, Staubach #1, Burkhart #1R and Pauline Huebner
A-382 #1 wells offset by the natural decline in production at other wells,
primarily from the initial Matagorda County Project wells. Oil and natural gas
revenues include the impact of hedging activities as discussed below under
"Volatility of Oil and Gas Prices".

Average oil prices increased 3% to $24.94 per bbl in 2002 from $24.28 per
bbl in 2001.

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 2001 and 2002:

26

- ----------

(1) Including the impact of hedging.

Oil and natural gas operating expenses for 2002 increased 19% to $4.9
million from $4.1 million in 2001. Oil and natural gas operating expenses
increased primarily as a result of the addition of new oil and gas wells drilled
and completed since December 31, 2001 and higher ad valorem taxes. Operating
expenses per equivalent unit in 2002 decreased to $0.68 per Mcfe from $0.77 per
Mcfe in 2001. The per unit cost decreased primarily as a result of the addition
of higher production rate, lower cost per unit wells offset by an increase in ad
valorem taxes and decreased production of natural gas as wells naturally
decline.

Depreciation, depletion and amortization ("DD&A") expense for 2002
increased 63% to $10.6 million from $6.5 million in 2001. This increase was
primarily due to increased production and the additional seismic and drilling
costs added to the proved property cost base.

General and administrative ("G&A") expense for 2002 increased 24% to $4.1
million from $3.3 million for 2001. The increase in G&A was due primarily to the
addition of contract staff to handle increased drilling and production
activities and higher insurance costs.

Interest income for 2002 decreased to $0.1 million from $0.3 million in
2001 primarily as a result of lower interest rates during 2002. Capitalized
interest decreased to $3.1 million in 2002 from $3.2 million in 2001 primarily
due to lower interest costs during 2002.

Income taxes decreased to $2.8 million in 2002 from $5.3 million in 2001.

Dividends and accretion of discount on preferred stock increased to $0.6
million in 2002 from none in 2001 as a result of the sale of preferred stock in
the first quarter of 2002.

Net income for 2002 decreased to $4.8 million from $9.5 million in 2001
primarily as a result of the factors described above.

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

Oil and natural gas revenues for 2001 decreased 2% to $26.2 million from
$26.8 million in 2000. Production volumes for natural gas in 2001 decreased 19%
to 4,432 MMcf from 5,461 MMcf in 2000. Realized average natural gas prices
increased 29% to $5.04 per Mcf in 2001 from $3.90 per Mcf in 2000. Production
volumes for oil in 2001 decreased 20% to 160 MBbls from 199 MBbls in 2000. The
decrease in oil production was due to the natural decline in production
primarily at the Jones Branch wells and the initial Matagorda Project wells
offset by the commencement of production of the Pitchfork Ranch well. The
decrease in natural gas production was due primarily to the sale of the Metro
Project during 2000 and the natural decline in production primarily at the
initial Matagorda Project wells offset by the commencement of production at the
additional Cedar Point Project wells, the West Bay Project well and the
Pitchfork Ranch well. Oil and natural gas revenues include the cash effect of
hedging activities as discussed below under

27

"Volatility of Oil and Natural Gas Prices".

Average oil prices decreased 13% to $24.28 per bbl in 2001 from $27.81 per
bbl in 2000.

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 2000 and 2001:

- ----------

(1) Including the impact of hedging.

Oil and natural gas operating expenses for 2001 decreased 16% to $4.1
million from $4.9 million in 2000. Oil and natural gas operating expenses
decreased primarily as a result of the lower production taxes and the
implementation of cost reduction measures in fields with decreased production.
Operating expenses per equivalent unit in 2001 increased to $0.77 per Mcfe from
$0.74 per Mcfe in 2000. The per unit cost increased primarily as a result of an
increase in severance taxes and decreased production of natural gas as wells
naturally decline.

Depreciation, depletion and amortization ("DD&A") expense for 2001
decreased 9% to $6.5 million from $7.2 million in 2000. This decrease was
primarily due to the seismic and drilling costs added to the proved property
cost base.

General and administrative ("G&A") expense for 2001 increased 6% to $3.3
million from $3.1 million for 2000. The increase in G&A was due primarily to the
addition of staff to handle increased drilling and production activities. Stock
option compensation expense is a non-cash charge resulting from a decrease
during 2001 and an increase during the last six months of 2000 in the stock
price underlying the stock options that were repriced in February 2000.

Interest expense, net of amounts capitalized, for 2001 decreased 47% to
$7,000 from $13,003 in 2000.

Income taxes increased to $5.3 million in 2001 from $1.0 million in 2000.
The increase was the result of an adjusted valuation allowance during 2000 on
net operating loss carryforwards expected to be realized that resulted in a
deferred income tax benefit adjustment of $3.6 million which reduced the
Company's effective tax rate to 8% in 2000.

Other income for the year ended December 31, 2001 included a gain on the
sale of an investment in Michael Petroleum Corporation ("MPC") of $3.9 million
offset by (1) a charge and related legal expenses of $1.4 million in respect of
the final settlement of litigation with BNP Petroleum Corporation and (2) a
non-cash valuation allowance of $0.8 million relating to certain hedge
arrangements with Enron North America Corp.

Net income for 2001 decreased to $9.5 million from $12.0 million in 2000 as
a result of the factors described above.

28

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 cost on its exploration projects.

While the Company believes that 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 natural gas exploration and
development program, which could adversely affect the recoverability and
ultimate value of the Company's oil and natural gas properties.

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

Cash flows provided by operating activities were $17.1 million, $24.0
million and $19.9 million for 2000, 2001 and 2002, respectively. The increase in
cash flows provided by operating activities in 2001 as compared to 2000 was due
primarily to the increase in trade accounts payable and the one-time gain on the
sale of an investment in MPC. The decrease in cash flows provided by operating
activities in 2002 as compared to 2001 was due primarily to the one-time gains
on the sale of an investment in MPC in 2001.

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

The Company has continued to reinvest a substantial portion of its cash
flows into increasing its 3-D prospect portfolio, improving its 3-D seismic
interpretation technology and funding its drilling program. Oil and gas capital
expenditures were $19.7 million, $38.2 million and $26.7 million for 2000, 2001
and 2002, respectively. The Company's drilling efforts resulted in the
successful completion of 24 gross wells (6.6 net) in 2000 and 20 gross wells
(5.9 net) in 2001 and 17 gross wells (6.0 net in 2002) in the Gulf Coast region.
Of the 75 gross wells (28 net) drilled or acquired by CCBM, 24 gross wells (8
net) are currently producing and 51 gross wells (20 net) are awaiting evaluation
before a determination can be made as to their success.

During November 2000, the Company entered into a one-year contract with
Grey Wolf, Inc. for utilization of a 1,500 horsepower drilling rig capable of
drilling wells to a depth of approximately 18,000 feet. The contract, which
commenced in March 2001, provides for a dayrate of $12,000 per day. The rig was
utilized primarily to drill wells in the Company's focus areas, including the
Matagorda Project Area and the Cabeza Creek Project Area. The contract contained
a provision which would allow the Company to terminate the contract early by
tendering payment equal to one-half the dayrate for the number of days remaining
under the term of the contract as of the date of termination. The contract
expired in February 2002. Steven A. Webster, who is the Chairman of the Board of
Directors of the Company, is a member of the Board of Directors of Grey Wolf,
Inc.

CCBM plans to spend up to $5.0 million for drilling costs through December
2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million
of drilling costs on behalf of RMG. Through December 31, 2002, CCBM has
satisfied $1.5 million of its drilling obligations on behalf of RMG.

FINANCING ARRANGEMENTS

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

29

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

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

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

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

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

The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
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, 2001, amounts outstanding under the Compass Facility
totaled $7.2 million with an additional $0.6 million available for future
borrowings. At December 31, 2002, amounts outstanding under the Hibernia
Facility totaled $8.5 million with an additional $4.3 million available for
future borrowings. At December 31, 2001, one letter of credit was issued and
outstanding under the Compass Facility in the amount of $0.2 million. At
December 31, 2002, 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 to
Rocky Mountain Gas, Inc. ("RMG") as consideration for certain interests in oil
and gas leases held by RMG in Wyoming and Montana. The RMG note is payable in
41-monthly principal payments of $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 gas leases in Wyoming and
Montana. At December 31, 2001 and 2002, the outstanding principal balance of
this note was $6.8 million and $5.3 million, respectively.

In December 2001, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.2 million. The lease
is payable in one payment of $11,323 and 35 monthly payments of $7,549 including
interest at 8.6% per annum. In October 2002, the Company entered a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.

30

The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. Under both leases the Company has the option to acquire the equipment
at the conclusion of the lease for $1.

Estimated maturities of long-term debt are $1.6 million in 2003, $3.9
million in 2004, $8.5 million in 2005 and the remainder in 2007.

In November 1999, Messrs. Hamilton, Webster and Loyd provided a bridge loan
in the amount of $2.0 million, to the Company, secured by certain oil and
natural gas properties. This bridge loan bore interest at 14% per annum. Also in
consideration for the bridge loan, the Company assigned to Messrs. Hamilton,
Webster, and Loyd an aggregate 1.0% overriding royalty interest ("ORRI") in the
Huebner #1 and Fondren Letulle #1 wells (combined with the prior assignment, a
2% overriding royalty interest), a .8794% ORRI in Neblett #1 (N. La Copita), a
1.0466% ORRI in STS 104-5 #1, a 1.544% ORRI in USX Hematite #1, a 2.0% ORRI in
Huebner #2 and a 2.0% ORRI in Burkhart #1. On December 15, 1999 the bridge loan
was repaid in its entirety with proceeds from the sale of Common Stock,
Subordinated Notes and Warrants. Such overriding royalty interests are limited
to the well bore and proportionately reduced to the Company's working interest
in the well.

In December 1999, the Company consummated the sale of $22.0 million
principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated
Notes"). The Subordinated Notes were sold at a discount of $0.7 million, which
is being amortized over the life of the notes. Interest is payable quarterly
beginning March 31, 2000. The Company may elect, for a period of five years, to
increase the amount of the Subordinated Notes for up to 60% of the interest
which would otherwise be payable in cash. The amount of Subordinated Notes was
increased by $1.4 million and $1.3 million as of December 31, 2002 and 2001,
respectively, for such interest. Concurrent with the sale of the notes, the
Company consummated the sale of 3,636,364 shares of Common Stock at a price of
$2.20 per share and Warrants to purchase up to 2,760,189 shares of the Company's
Common Stock at an exercise price of $2.20 per share. For accounting purposes,
the Warrants are valued at $0.25 per Warrant. The Warrants have an exercise
price of $2.20 per share and expire in December 2007. The Company sold $17.6
million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal
amount of Subordinated Notes; 2,909,091, 363,636, 121,212, 121,212 and 121,212
shares of the Company's common stock and 2,208,151, 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 Company is subject to certain covenants under the terms of the related
Securities Purchase Agreement, including but not limited to, (a) maintenance of
a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings
before interest, taxes depreciation and amortization) to quarterly Debt Service
(as defined in the agreement) of not less than 1.00 to 1.00, and (c) limit its
capital expenditures to a specified amount for the year ended December 31, 2000,
and thereafter to an amount equal to the Company's EBITDA for the immediately
prior fiscal year, as well as limits on the Company's ability to (i) incur
indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation,
sales of assets and acquisitions, (iv) declare dividends and effect certain
distributions (including restrictions on distributions upon the Common Stock),
(v) engage in transactions with affiliates (vi) make certain repayments and
prepayments, including any prepayment of the subordinated debt, indebtedness
that is guaranteed or credit-enhanced by any affiliate of the Company, and
prepayments that effect certain permanent reductions in revolving credit
facilities.

Of the approximately $29.0 million net proceeds of this financing, $12.0
million was used to fund the Enron Repurchase described below and related
expenses, $2.0 million was used to repay the bridge loan extended to the Company
by its outside directors, $2.0 million was used to repay a portion of the
Compass Term Loan, $1.0 million was used to repay a portion of the Compass
Borrowing Base Facility, and the remaining proceeds were used to fund the
Company's ongoing exploration and development program and general corporate
purposes.

In January 1998, the Company consummated the sale of 300,000 shares of
Series A Preferred Stock and Warrants to purchase 1,000,000 shares of Common
Stock to affiliates of Enron Corp. The net proceeds received by the Company from
this transaction were approximately $28.8 million and were used primarily for
oil and natural gas exploration and development activities in Texas and
Louisiana and to repay related indebtedness. The Series A Preferred Stock
provided for annual cumulative dividends of $9.00 per share, payable quarterly
in cash or, at the option of the Company until January 15, 2002, in additional
shares of Series A Preferred Stock. Dividend payments for the 12 months ended
December 31, 1999 were made by the issuance of an additional 22,508.23 shares of
Series A Preferred Stock.

In December 1999, the Company consummated the repurchase of all the
outstanding shares of Series A Preferred Stock and 750,000 Warrants for $12.0
million. At the same time, the Company reduced the exercise price of the
remaining 250,000 Warrants from $11.50 per share to $4.00 per share.

31

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 the outstanding balance of the Series B Preferred Stock had
been increased by $0.5 million (5,294 shares) for dividends paid in kind. In
addition to the foregoing, if the Company declares a cash dividend on the Common
Stock of the Company, the holders of shares of Series B Preferred Stock are
entitled to receive for each share of Series B Preferred Stock a cash dividend
in the amount of the cash dividend that would be received by a holder of the
Common Stock into which such share of Series B Preferred Stock is convertible on
the record date for such cash dividend. Unless all accrued dividends on the
Series B Preferred Stock shall have been paid and a sum sufficient for the
payment thereof set apart, no distributions may be paid on any Junior Stock
(which includes the Common Stock) (as defined in the Statement of Resolutions
for the Series B Preferred Stock) and no redemption of any Junior Stock shall
occur other than subject to certain exceptions.

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

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

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

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

ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY

The Company's growth has placed, and is expected to continue to place, a
significant strain on the Company's financial, technical, operational and
administrative resources. The Company has relied in the past and expects to
continue to rely on project partners and independent contractors that have
provided the Company with seismic survey planning and management, project and
prospect generation, land acquisition, drilling and other services. At December
31, 2002, the Company had 36 full-time employees. There will be additional
demands on the Company's financial, technical, operational and administrative
resources and continued reliance by the Company on project partners and
independent contractors, and these strains on resources, additional demands and
continued reliance may negatively affect the Company. The Company's ability to
grow will depend upon a number of factors, including its ability to obtain
leases or options on properties for 3-D seismic surveys, its ability to acquire
additional 3-D seismic data, its ability to identify and acquire new exploratory
sites, its ability to develop existing sites, its ability to continue to retain
and attract skilled personnel, its ability to maintain or enter into new
relationships with project partners and independent contractors, the results of
its drilling program, hydrocarbon prices, access to capital and other factors.
Although the Company intends to continue to upgrade its technical, operational
and administrative resources and to increase its ability to provide internally
certain of the services previously provided by outside sources, there can be no
assurance that it will be successful in doing so or that it will be able to
continue to maintain or enter into new relationships with project partners and
independent contractors. The failure of the Company to continue to upgrade its
technical,

32

operational and administrative resources or the occurrence of unexpected
expansion difficulties, including difficulties in recruiting and retaining
sufficient numbers of qualified personnel to enable the Company to expand its
seismic data acquisition and drilling program, or the reduced availability of
project partners and independent contractors that have historically provided the
Company seismic survey planning and management, project and prospect generation,
land acquisition, drilling and other services, could have a material adverse
effect on the Company's business, financial condition and results of operations.
Any increase in the Company's activities as an operator will increase its
exposure to operating hazards. See "Business and Properties -- Operating Hazards
and Insurance". The Company's lack of capital will also constrain its ability to
grow and achieve its business strategy. There can be no assurance that the
Company will be successful in achieving growth or any other aspect of its
business strategy.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
obligations of tangible long-lived assets in the period in which it is incurred.
When the asset is placed in service, a liability is recorded and a corresponding
asset is recorded. Accretion of the liability is recognized each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. On January 1, 2003, the Company recorded $0.7 million as
proved properties and $0.6 million as a liability for its plugging and
abandonment expenses.

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 will adopt the
Statement effective January 1, 2003.

The Company has adopted the disclosure requirements of SFAS No. 148,
"Accounting for Stock Based Compensation -- Transition and Disclosure", issued
in December 2002, effective with its December 31, 2002 consolidated financial
statements and related footnotes.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The following summarizes several of our critical accounting policies. See
a complete list of significant accounting policies in Note 2 to the
Consolidated Financial Statements.

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
$0.9 million, $1.0 million and $1.0 million in 2000, 2001 and 2002,
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 2000, 2001 and 2002
was $1.03, $1.15 and $1.41 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 in 2000, 2001 or 2002. 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 writedown 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

33

write-down in future periods.

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

Oil and Natural Gas Reserve Estimates

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

Proved reserve estimates prepared by others may be substantially higher or
lower than 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.

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

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

34

Derivative Instruments and Hedging Activities

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

Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). Changes in the fair value of a cash flow hedge are recorded
in other comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at January 1, 2001, December 31, 2001 and
December 31, 2002 were designated and effective as cash flow hedges except for
its positions with an affiliate of Enron Corp. discussed in Note 12.

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.

35

Income Taxes

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

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.
See "Business and Properties -- Marketing".

The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of this ceiling test generally requires pricing
future revenue at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time. The
Company may be required to write-down the carrying value of its oil and natural
gas properties when oil and natural gas prices are depressed or unusually
volatile. Once incurred, a write-down of oil and natural gas properties is not
reversible at a later date. Based on oil and gas prices in effect on December
31, 2001, the unamortized cost of our oil and gas properties exceeded the cost
center ceiling. In accordance with 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 write-down would
have been approximately $0.7 million.

The Company typically uses fixed rate swaps and costless collars to hedge
its exposure to material changes in the price of natural

36

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

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

In November 2001, the Company had no-cost collars with an affiliate of
Enron Corp., designated as hedges, covering 2,553,000 MMBtu of gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts were no longer effective and thus did
not qualify for hedge accounting treatment. As required by SFAS No. 133, the
value of these derivative instruments as of November 2001 $(0.8 million) was
recorded in accumulated other comprehensive income and will be reclassified into
earnings over the original term of the derivative instruments. An allowance for
the related asset totaling $0.8 million, net of tax of $0.4 million, was charged
to other expense. At December 31, 2001 and 2002, $0.7 million and none, net of
tax of $0.4 million and none, respectively, remained in accumulated other
comprehensive income related to the deferred gains on these derivatives.

Total oil purchased and sold under hedging arrangements during 2000, 2001
and 2002 were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 2000, 2001 and 2002
were 1,590,000 MMBtu and 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The
net gains and (losses) realized by the Company under such hedging arrangements
were $(1.5 million), $2.0 million and $(0.9 million) for 2000, 2001 and 2002,
respectively, and are included in oil and gas revenues.

At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK

COMMODITY RISK. The Company's major market risk exposure is the commodity
pricing applicable to its oil and natural gas production. Realized commodity
prices received for such production are primarily driven by the prevailing
worldwide price for oil and spot prices applicable to natural gas. The effects
of such pricing volatility have been discussed above, and such volatility is
expected to continue. A 10% fluctuation in the price received for oil and gas
production would have an approximate $2.6 million impact on the Company's annual
revenues and operating income.

To mitigate some of this risk, the Company engages periodically in certain
limited hedging activities but only to the extent of buying protection price
floors. Costs and any benefits derived from these price floors are accordingly
recorded as a reduction or increase, as applicable, in oil and gas sales revenue
and were not significant for any year presented. The costs to purchase put
options are amortized over the option period. The Company does not hold or issue
derivative instruments for trading purposes. Income and

37

(losses) realized by the Company related to these instruments were $(1.5
million), $2.0 million and $(0.9 million) or $(0.73), $0.63, and $(0.12) per
MMBtu for the years ended December 31, 2000, 2001, and 2002, respectively.

INTEREST RATE RISK. The Company's exposure to changes in interest rates
results from its floating rate debt. In regards to its Revolving Credit
Facility, the result of a 10% fluctuation in short-term interest rates would
have impacted 2002 cash flow by approximately $32,000.

FINANCIAL INSTRUMENTS & DEBT MATURITIES. The Company's financial
instruments consist of cash and cash equivalents, accounts receivable, accounts
payable, bank borrowing, Subordinated Notes payable and Series B Redeemable
Preferred Stock. The carrying amounts of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair values of the bank and vendor
borrowings approximate the carrying amounts as of December 31, 2002 and 2001,
and were determined based upon interest rates currently available to the Company
for borrowings with similar terms. Maturities of the debt are $1.6 million in
2003, $3.9 million in 2004, $8.5 million in 2005 and the balance in 2007.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The response to this item is included elsewhere in this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this item is incorporated by reference to
information under the caption "Proposal 1-Election of Directors" and to the
information under the caption "Section 16(a) Reporting Delinquencies" in the
Company's definitive Proxy Statement (the "2003 Proxy Statement") for its 2003
annual meeting of shareholders. The 2003 Proxy Statement will be filed with the
Securities and Exchange Commission (the "Commission") not later than 120 days
subsequent to December 31, 2002.

Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference
to the 2003 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2002.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information concerning our equity compensation plan at December 31, 2002 is
as follows:

38

Other information required by this item is incorporated herein by reference
to the 2003 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2002.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The information required by this item is incorporated herein by reference
to the 2003 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2002.

ITEM 14. CONTROLS AND PROCEDURES

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

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1) FINANCIAL STATEMENTS

The response to this item is submitted in a separate section of this
report.

(a)(2) FINANCIAL STATEMENT SCHEDULES

All schedules and other statements for which provision is made in the
applicable regulations of the Commission have been omitted because they are not
required under the relevant instructions or are inapplicable.

39

(a)(3) EXHIBITS

EXHIBIT INDEX

40

+10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster,
Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.8 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).

+10.10 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs.
Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

+10.11 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by reference to Exhibit 99.3
to the Company's Current Report on Form 8-K dated January 8, 1998).

+10.12 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).

+10.13 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to
Exhibit 99.1 to the Company's Current Report on Form 8-K dated December 15, 1999).

+10.14 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures,
L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K
dated December 15, 1999).

+10.15 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P.,
Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.3 to
the Company's Current Report on Form 8-K dated December 15, 1999).

+10.16 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8- K dated
December 15, 1999).

+10.17 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd Jr.,
Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15,
1999).

+10.18 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures,
L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated December
15, 1999).

+10.19 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated December 15, 1999).

+10.20 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated December 15, 1999).

+10.21 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated June 29, 2001
(Incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).

+10.22 -- Securities Purchase Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated
February 20, 2002).

+10.23 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P., Paul B. Loyd, Jr.,
Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated February 20,
2002).

+10.24 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster
(including Warrant Certificate) (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report
on Form 8-K dated February 20, 2002).

+10.25 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated
February 20, 2002).

+10.26 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures, L.P. (Incorporated herein
by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated February 20, 2002).

+10.27 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated February 20, 2002).

+10.28 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated February 20, 2002).

41

21.1 -- Subsidiaries of the Company.

23.1 -- Consent of Ernst & Young LLP

23.2 -- Consent of Ryder Scott Company Petroleum Engineers.

23.3 -- Consent of Fairchild & Wells, Inc.

99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2002.

99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2002.

99.3 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers for CCBM, Inc. as of December 31, 2002.

99.4 -- Notice Regarding Consent of Arthur Andersen LLP.

- ----------

+ Incorporated by reference as indicated.

REPORTS ON FORM 8-K

None.

42

CARRIZO OIL & GAS, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

F-1

REPORT OF INDEPENDENT AUDITORS

The Board of Directors and Shareholders of
Carrizo Oil & Gas, Inc.

We have audited the accompanying consolidated balance sheet of Carrizo Oil
& Gas, Inc. as of December 31, 2002, and the related consolidated statements of
operations, shareholders' equity and cash flows for the year then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The consolidated financial statements of Carrizo Oil & Gas, Inc. as
of December 31, 2001 and for the two years then ended, were audited by other
auditors who have ceased operations and whose report dated March 20, 2002,
expressed an unqualified opinion on those statements, before the revisions
described in Note 5.

We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 consolidated financial statements referred to
above present fairly, in all material respects, the financial position of the
Company as of December 31, 2002, and the results of its operations and its cash
flows for the year then ended, in conformity with accounting principles
generally accepted in the United States.

As discussed above, the consolidated financial statements of the Company as
of December 31, 2001 and for the two years then ended were audited by other
auditors who have ceased operations. As described in Note 5, the Company revised
the reported amounts of certain temporary differences at December 31, 2001. We
audited the adjustments described in Note 5 that were applied to revise the
reported amounts of temporary differences in the 2001 consolidated financial
statements. Our procedures included (a) agreeing the revised temporary
differences to the Company's underlying records obtained from management, and
(b) testing the mathematical accuracy of the revisions to the temporary
differences. In our opinion, such adjustments are appropriate and have been
properly applied. However, we were not engaged to audit, review, or apply any
procedures to the 2001 consolidated financial statements of the Company other
than with respect to such adjustments and, accordingly, we do not express an
opinion or any other form of assurance on the 2001 consolidated financial
statements taken as a whole.

ERNST & YOUNG LLP

Houston, Texas
March 14, 2003

F-2

THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. AS
DESCRIBED IN NOTE 5 TO CARRIZO'S CONSOLIDATED FINANCIAL STATEMENTS AS OF
DECEMBER 31, 2002, THE FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2001
REFERRED TO IN THIS REPORT HAVE BEEN REVISED SUBSEQUENT TO THE DATE OF THE
REPORT TO REFLECT REVISIONS TO TEMPORARY DIFFERENCES IN THE RECOGNITION OF
INCOME AND EXPENSES FOR FINANCIAL REPORTING PURPOSES AND FOR TAX PURPOSES. THE
REVISIONS HAVE BEEN REPORTED ON BY ERNST & YOUNG LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and
Board of Directors of
Carrizo Oil & Gas, Inc.:

We have audited the accompanying consolidated balance sheets of Carrizo Oil
& Gas, Inc. (a Texas corporation) as of December 31, 2000 and 2001, and the
related consolidated statements of operations, shareholders' equity and cash
flows for each of the three years in the period ended December 31, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of the Company
as of December 31, 2000 and 2001, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.

As explained in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities to conform with Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." Additionally, as explained in Note 10 to the consolidated financial
statements, effective January 1, 1999, the Company changed its method of
accounting for start up costs.

ARTHUR ANDERSEN LLP

Houston, Texas
March 20, 2002

F-3

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

ASSETS

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

F-4

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

F-5

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

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

F-6

F-7

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

F-8

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF OPERATIONS

Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its
subsidiary, affiliates and predecessors, the Company) is an independent energy
company formed in 1993 and is engaged in the exploration, development,
exploitation and production of oil and natural gas. Its operations are focused
on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and
Vicksburg trends. The Company, through CCBM Inc. (a wholly-owned subsidiary)
("CCBM") acquired interests in certain oil and natural gas leases in Wyoming and
Montana in areas prospective for coalbed methane. CCBM has an obligation to fund
$2.5 million of drilling costs on behalf of Rocky Mountain Gas, Inc. ("RMG"),
from whom the interests in the leases were acquired. Through December 31, 2002,
CCBM has satisfied $1.5 million of its drilling obligations on behalf of RMG.

The exploration for oil and natural gas is a business with a significant
amount of inherent risk requiring large amounts of capital. The Company intends
to finance its exploration and development program through cash from operations,
existing credit facilities or arrangements with other industry participants.
Should the sources of capital currently available to the Company not be
sufficient to explore and develop its prospects and meet current and near-term
obligations, the Company may be required to seek additional sources of financing
which may not be available on terms acceptable to the Company. This lack of
additional financing could force the Company to defer its planned exploration
and development drilling program which could adversely affect the recoverability
and ultimate value of the Company's oil and natural gas properties.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statement are presented in accordance with
generally accepted accounting principles in the United States. The consolidated
financial statements include the accounts of the Company and its subsidiary. All
intercompany accounts and transactions have been eliminated in consolidation.

CRITICAL ACCOUNTING POLICIES AND 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 consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting periods. Actual results could differ from these estimates.

The Company believes the following critical accounting policies affect its
more significant judgements and estimates used in the preparation of its
consolidated financial statements:

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
$0.9 million, $1.0 million and $1.0 million in 2000, 2001 and 2002,
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 Mcfe for

F-9

2000, 2001 and 2002 was $1.03, $1.15 and $1.41 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 in 2000, 2001 or 2002. Based on oil and natural
gas prices in effect on December 31, 2001, the unamortized cost of oil and
natural gas properties exceeded the cost center ceiling. As permitted by full
cost accounting rules, improvements in pricing subsequent to December 31, 2001
removed the necessity to record a write-down. Using prices in effect on December
31, 2001 the pretax write-down would have been approximately $0.7 million.
Because of the volatility of oil and natural gas prices, no assurance can be
given that the Company will not experience a write-down in future periods.

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

OIL AND NATURAL GAS RESERVE ESTIMATES

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

Proved reserve estimates prepared by others may be substantially higher or
lower than 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.

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

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

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include highly liquid investments with maturities
of three months or less when purchased.

REVENUE RECOGNITION AND NATURAL GAS IMBALANCES

The Company follows the sales method of accounting for revenue recognition
and natural gas imbalances, which recognizes over and under lifts of natural gas
when sold, to the extent sufficient natural gas reserves or balancing agreements
are in place. Natural gas sales volumes are not significantly different from the
Company's share of production.

FINANCING COSTS

Long-term debt financing costs of $0.8 million and $0.8 million are included
in other assets as of December 31, 2001 and 2002, respectively, are being
amortized using the effective yield method over the term of the loans (through
January 31, 2005 for a credit facility and through December 15, 2007 for
subordinated notes payable).

F-10

SUPPLEMENTAL CASH FLOW INFORMATION

The statement of cash flows for the year ended December 31, 2002 does not
reflect the following non-cash transactions: the $2.5 million of seismic data
acquisitions, the acquisition $0.5 million in oil and natural gas properties
through the issuance of common stock, and the $0.6 million reduction of oil and
natural gas properties for the amount of insurance recoveries expected to be
received related to difficulties encountered in the drilling of a well.

FINANCIAL INSTRUMENTS

The Company's recorded financial instruments consist of cash, receivables,
payables and long-term debt. The carrying amount of cash, receivables and
payables approximates fair value because of the short-term nature of these
items. The carrying amount of bank debt approximates fair value as this
borrowing bears interest at floating market interest rates. The fair value of
the Subordinated Notes payable and the RMG note at December 31, 2002 was $32.6
million and $5.6 million, respectively. Fair values for the Subordinated Notes
payable and the RMG note were determined based upon interest rates available to
the Company at December 31, 2002 with similar terms.

STOCK-BASED COMPENSATION

The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees" and related interpretations.
Under this method, the Company records no compensation expense for stock options
granted when the exercise price of those options is equal to or greater than the
market price of the Company's common stock on the date of grant. Repriced
options are accounted for as compensatory options using variable accounting
treatment. Under variable plan accounting, compensation expense is adjusted for
increases or decreases in the fair market value of the Company's common stock.
Variable plan accounting is applied to the repriced options until the options
are exercised, forfeited, or expire unexercised.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). Changes in the fair value of a cash flow hedge are recorded
in other comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at January 1, 2001, December 31, 2001 and
December 31, 2002 were designated and effective as cash flow hedges except for
its positions with an affiliate of Enron Corp. discussed in Note 12.

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

F-11

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.

CONCENTRATION OF CREDIT RISK

Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables. Derivative
contracts subject the Company to concentration of credit risk. The Company
transacts the majority of its derivative contracts with two counterparties. The
Company does not require collateral from its customers.

MAJOR CUSTOMERS

The Company sold oil and natural gas production representing more than 10%
of its oil and natural gas revenues for the year ended December 31, 2001 to
Cokinos Natural Gas Company (17%); for the year ended December 31, 2002 to
Cokinos Natural Gas Company (12%) and Discovery Producer Services, LLC (10%).
Because alternate purchasers of oil and natural gas are readily available, the
Company believes that the loss of any of its purchasers would not have a
material adverse effect on the financial results of the Company.

F-12

EARNINGS PER SHARE

Supplemental earnings per share information is provided below:

F-13

Basic earnings per common share has been computed by dividing net income by
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 period. The Company had outstanding 149,000, 79,500 and 172,333 stock
options at December 31, 2000, 2001 and 2002, respectively, that were
antidilutive. The Company had outstanding 252,632 warrants at December 31, 2002
that were antidilutive. These antidilutive stock options and warrants were not
included in the calculation because the exercise price of these instruments
exceeded the underlying market value of the options and warrants as of the dates
presented. The Company had 1,145,515 convertible preferred shares at December
31, 2002 that were antidilutive and were not included in the calculation.

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.

NEW ACCOUNTING PRONOUNCEMENTS

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 will adopt the
Statement effective January 1, 2003. On January 1, 2003, the Company recorded
$0.4 million as proved properties and $0.5 million as a liability for its
plugging and abandonment expenses.

The Company has adopted the disclosure requirements of SFAS No. 148,
"Accounting for Stock Based Compensation - Transition and Disclosure", issued in
December 2002, effective with its December 31, 2002 consolidated financial
statements and related footnotes.

3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION:

In 2000 the Company received a finder's fee valued at $1.5 million from
affiliates of Donaldson, Lufkin & Jenrette ("DLJ") in connection with their
purchase of a significant minority shareholder interest in Michael Petroleum
Corporation ("MPC"). MPC is a privately held exploration and production company
which focuses on the prolific natural gas producing Lobo Trend in South Texas.
The minority shareholder interest in MPC was purchased by entities affiliated
with DLJ. The Company elected to receive the fee in the form of 18,947 shares of
common stock, 1.9% of the outstanding common shares of MPC, which, until its
sale in 2001, was accounted for as a cost basis investment. Steven A. Webster,
who is the Chairman of the Board of the Company, and a Managing Director of
Global Energy Partners Ltd., a merchant banking affiliate of DLJ which makes
investments in energy companies, joined the Board of Directors of MPC in
connection with the transaction.

In 2001, the Company agreed to sell its interest in MPC pursuant to an
agreement between MPC and its shareholders for the sale of a majority interest
in MPC to Calpine Natural Gas Company. The Company received total cash proceeds
of $5.7 million, of which $5.5 million was paid to the Company during the third
quarter of 2001, resulting in a financial statement gain of $3.9 million being
reflected in the third quarter 2001 financial results. The remaining amounts
will be paid in 2003.

4. PROPERTY AND EQUIPMENT

At December 31, 2001 and 2002, property and equipment consisted of the
following:

F-14

Oil and natural gas properties not subject to amortization consist of the
cost of unevaluated leaseholds, seismic costs associated with specific
unevaluated properties, exploratory wells in progress, and secondary recovery
projects before the assignment of proved reserves. These unproved costs are
reviewed periodically by management for impairment, with the impairment
provision included in the cost of oil and natural gas properties subject to
amortization. Factors considered by management in its impairment assessment
include drilling results by the Company and other operators, the terms of oil
and natural gas leases not held by production, production response to secondary
recovery activities and available funds for exploration and development. Of the
$42.0 million of unproved property costs at December 31, 2002 being excluded
from the amortizable base, $2.7 million, $11.7 million and $6.3 million were
incurred in 2000, 2001 and 2002, respectively and $21.3 million was incurred in
prior years. These costs are primarily seismic and lease acquisition costs. The
Company expects it will complete its evaluation of the properties representing
the majority of these costs within the next two to five years.

5. INCOME TAXES

All of the Company's income is derived from domestic activities. Actual
income tax expense differs from income tax expense computed by applying the U.S.
federal statutory corporate rate of 35% to pretax income as follows:

Deferred income tax provisions result from temporary differences in the
recognition of income and expenses for financial reporting purposes and for tax
purposes. At December 31, 2001 and 2002, the tax effects of these temporary
differences resulted principally from the following:

F-15

The December 31, 2001 deferred income tax asset relating to the net
operating loss carry forward and the deferred income tax liability relating to
oil and natural gas acquisition, exploration and development costs deducted for
tax purposes in excess of financial statement DD&A have been revised to reflect
the 2001 results of operations as a reduction of the deferred income tax asset
relating to the net operating loss carry forward. This revision adjustment
resulted in a $1.4 million decrease in the deferred income tax asset relating to
net operating loss carry forward and a corresponding decrease to the deferred
income tax liability relating to oil and natural gas acquisition, exploration
and development costs deducted for tax purposes in excess of financial statement
DD&A. The net effect of these revisions resulted in no change to the net
deferred income tax liability as reflected on the December 31, 2001 balance
sheet.

The net deferred income tax liability is classified as follows:

Realization of the net deferred tax asset is dependent on the Company's
ability to generate taxable earnings in the future. The Company believes it will
generate taxable income in the NOL carryforward period. As such management
believes that it is more likely than not that its deferred tax assets will be
fully realized. The Company has net operating loss carryforwards totaling
approximately $7.0 million, which begin expiring in 2012.

6. LONG-TERM DEBT

At December 31, 2001 and 2002, long-term debt consisted of the following:

F-16

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 substantially all of the Company's assets and is guaranteed by the
Company's subsidiary.

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

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

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

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

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

The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
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

F-17

pledges and mortgages, change of control, repurchase or redemption for cash of
the Company's common or preferred stock, speculative commodity transactions, and
other matters.

At December 31, 2001, amounts outstanding under the Compass Facility
totaled $7.2 million, with an additional $0.6 million available for future
borrowings. At December 31, 2002, amounts outstanding under the Hibernia
Facility totaled $8.5 million, with an additional $4.3 million available for
future borrowings. No amounts under the Compass Facility were outstanding at
December 31, 2002. At December 31, 2001, one letter of credit was issued and
outstanding under the Compass Facility in the amount of $0.2 million. At
December 31, 2002, one letter of credit was issued and outstanding under the
Hibernia Facility in the amount of $0.2 million.

On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company
("CCBM"), issued a non-recourse promissory note payable in the amount of $7.5
million to RMG as consideration for certain interests in oil and natural gas
leases held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly
principal payments of $0.1 million plus interest at 8% per annum commencing July
31, 2001 with the balance due December 31, 2004. The RMG note is secured solely
by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. At
December 31, 2001 and 2002, the outstanding principal balance of this note was
$6.8 million and $5.3 million, respectively.

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

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, 2001 and 2002, the outstanding balance of the Subordinated Notes
had been increased by $2.6 million and $3.9 million, respectively, for such
interest paid in kind.

The Company is subject to certain covenants under the terms under the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan Partners, LLC appointed director).

Estimated maturities of long-term debt are $1.6 million in 2003, $3.9
million in 2004, $8.5 million in 2005 and the remainder in 2007. At December 31,
2002, the Company believes it was in compliance with all of its debt covenants.

7. SEISMIC OBLIGATION PAYABLE

In 2002 the Company acquired (or obtained the right to acquire) certain
seismic data in its core areas in the Texas and Louisiana Gulf Coast regions.
Under the terms of the acquisition agreements, the Company is required to make
monthly payments of $0.1 million through March 2004 and additional payments
totalling $0.8 million are due in April 2004.

8. CONVERTIBLE PARTICIPATING PREFERRED STOCK:

In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and Warrants to purchase Carrizo 252,632 shares of common stock for an
aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000
shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon
Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock
is convertible into common stock by the investors at

F-18

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, the
outstanding balance of the Series B Preferred Stock has been increased by $0.5
million (5,294 shares) for dividends paid in kind. The Series B Preferred Stock
is redeemable at varying prices in whole or in part at the holders' option after
three years or at the Company's option at any time. The Series B Preferred Stock
will also participate in any dividends declared on the common stock. Holders of
the Series B Preferred Stock will receive a liquidation preference upon the
liquidation of, or certain mergers or sales of substantially all assets
involving, the Company. Such holders will also have the option of receiving a
change of 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.

9. 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.

In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. The Company, along
with GMT and other partners, reached a final settlement with ExxonMobil on
February 11, 2003. Under the terms of the settlement, the Company recovered the
balance of its drilling costs (approximately $0.1 million) and certain other
costs and retained no further interest in the property. No reserves with respect
to these properties were included in the Company's reported proved reserves as
of December 31, 2001 and 2002.

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, two leases
in the amount of $0.5 million had been executed under this facility.

At December 31, 2002, the Company was obligated under a noncancelable
operating lease for office space. Rent expense for the years ended December 31,
2000, 2001 and 2002 was $0.2 million. The Company is obligated for remaining
lease payments of $0.2 million per year through December 31, 2004.

CCBM has an obligation to fund $2.5 million of drilling costs on behalf of
RMG. Through December 31, 2002, CCBM has satisfied $1.5 million of its drilling
obligations on behalf of RMG.

10. SHAREHOLDERS' EQUITY

The Company issued 9,016 and 113,306 shares of common stock valued at
$28,000 and $0.5 million for the years ended December

F-19

31, 2001 and 2002, respectively. Of these shares, 106,472 were issued as partial
consideration for the acquisition of interests in certain oil and natural gas
properties during 2002.

The following table summarizes information for the options outstanding at
December 31, 2002:

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

The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 2000, 2001 and 2002: risk free interest rate of 6.7%, 4.9% and
4.8%, respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 70.8%, 80.7% and 77.7% respectively.

The Company may grant options ("Incentive Plan Options") to purchase up to
1,850,000 shares under the Incentive Plan and has

F-20

granted options on 1,566,000 shares through December 31, 2002. Through December
31, 2002, 56,797 stock options had been exercised. A summary of the status of
the Company's stock options at December 31, 2000, 2001 and 2002 is presented in
the table below:

In March of 2000, the FASB issued Interpretation No. 44 "Accounting for
Certain Transactions involving Stock Compensation - an interpretation of APB No.
25" ("the Interpretation") which was effective July 1, 2000 and clarifies the
application of APB No. 25 for certain issues associated with the issuance or
subsequent modifications of stock compensation. For certain modifications,
including stock option repricings made subsequent to December 15, 1998, the
Interpretation requires that variable plan accounting be

F-21

applied to those modified awards prospectively from July 1, 2000. This requires
that the change in the intrinsic value of the modified awards be recognized as
compensation expense. On February 17, 2000, Carrizo repriced certain employee
and director stock options covering 348,500 shares of stock with a weighted
average exercise price of $9.13 to a new exercise price of $2.25 through the
cancellation of existing options and issuance of new options at current market
prices. Subsequent to the adoption of the Interpretation, the Company is
required to record the effects of any changes in its stock price over the
remaining vesting period through February 2010 on the corresponding intrinsic
value of the repriced options in its results of operations as compensation
expense until the repriced options either are exercised or expire. Stock option
compensation expense (benefit) relating to the repriced options for the years
ended December 31, 2001 and 2002 amounted to $(0.6 million) and $(0.1 million),
respectively.

11. RELATED-PARTY TRANSACTIONS

During the years ended December 31, 2001 and 2002, the Company incurred
drilling costs in the amount of $6.3 million and $2.9 million, respectively,
with Grey Wolf Drilling. Mr. Webster is the Chairman of the Board of Carrizo and
a member of the Board of Directors of Grey Wolf Drilling. It is management's
opinion that these transactions with Grey Wolf were performed at prevailing
market rates.

At December 31, 2002, the Company had outstanding related party accounts
receivable, payable and advances for joint operations balances of $1.2 million,
$1.2 million and $0.3 million, respectively.

During the years ended December 31, 2001 and 2002, the Company participated
in the drilling of two wells and one well, respectively, that were operated by a
subsidiary of Brigham Exploration Company. During the year ended December 31,
2002, Brigham Exploration Company ("Brigham") participated in the drilling of
two wells operated by the Company. Mr. Webster is a member of the Board of
Directors of Brigham. Mr. Webster is also a managing director of a merchant
banking affiliate of the beneficial owner of approximately 35% of the common
stock of the parent company of Brigham Oil and Gas, LP. The terms of the
operating agreements between the Company and Brigham are consistent with
standard industry practices.

During the year ended December 31, 2002, the Company sold a 2% working
interest in certain leases in Matagorda County, TX to Mr. Webster. The terms of
the sale were the same as other sales of working interests in the same leases to
industry partners.

See Notes 6 and 8 for a discussion of the Subordinated Notes and Series B
Preferred Stock, respectively, with parties that include members of the
Company's Board of Directors.

In December 1999, the Company reduced the exercise price of certain
warrants originally issued to affiliates of Enron Corp. in January 1998. There
were 250,000 warrants that expire in January 2005 to purchase the Company's
common stock at $4.00 per share outstanding as of December 31, 2001 and 2002.

12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

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

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

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

F-22

Total oil purchased and sold under swaps and collars during 2000, 2001 and
2002 were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total natural
gas purchased and sold under swaps and collars in 2000, 2001 and 2002 were
1,590,000 MMBtu and 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(1.5 million), $2.0 million and $(0.9 million) for 2000, 2001 and 2002,
respectively, and are included in oil and natural gas revenues.

At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:

13. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

The following disclosures provide unaudited information required by SFAS
No. 69, "Disclosures About Oil and Gas Producing Activities".

COSTS INCURRED

Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:

- ----------

(1) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.

OIL AND NATURAL GAS RESERVES

Proved reserves are estimated quantities of oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2001 and
2002, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company and Fairchild & Wells, Inc.,
independent petroleum engineers. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission.

F-23

The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:

STANDARDIZED MEASURE

The standardized measure of discounted future net cash flows relating to the
Company's ownership interests in proved oil and natural gas reserves as of
year-end is shown below:

F-24

Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Average prices used in computing year end 2000, 2001 and 2002 future cash flows
were $24.85, $17.71 and $29.16 for oil, respectively and $10.34, $2.76 and $4.70
for natural gas, respectively. Future operating expenses and development costs
are computed primarily by the Company's petroleum engineers by estimating the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves at the end of the year, based on year end costs and
assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for tax
basis and availability of applicable tax assets. A discount factor of 10% was
used to reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties. An
estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the
time value of money and the risks inherent in reserve estimates.

CHANGE IN STANDARDIZED MEASURE

Changes in the standardized measure of future net cash flows relating to
proved oil and natural gas reserves are summarized below:

Sales of oil and natural gas, net of oil and natural gas operating
expenses, are based on historical pretax results. Sales of oil and natural gas
properties, extentions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pretax
discounted basis, while the accretion of discount is presented on an after-tax
basis.

F-25

SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)

(1) The sum of individual quarterly net income per common share may not agree
with year-to-date net income per common share as each period's computation
is based on the weighted average number of common shares outstanding during
that period.

F-26

SIGNATURES

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

CARRIZO OIL & GAS, INC.

By: /s/ FRANK A. WOJTEK
-------------------------------------
Frank A. Wojtek
Chief Financial Officer, Vice President,
Secretary and Treasurer

Date: March 28, 2003.

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

CERTIFICATIONS

PRINCIPAL EXECUTIVE OFFICER

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

1. I have reviewed this annual report on Form 10-K of Carrizo Oil & Gas, Inc.;

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

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

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

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

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

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

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

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

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

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

Date: March 31, 2003 /s/ S.P. JOHNSON, IV
----------------------------------------
S.P. Johnson, IV,
President and Chief Executive Officer

PRINCIPAL FINANCIAL OFFICER

I, Frank A. Wojtek, certify that:

1. I have reviewed this annual report on Form 10-K of Carrizo Oil & Gas, Inc.;

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

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

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

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

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

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

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

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

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

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

Date: March 31, 2003 /s/ FRANK A. WOJTEK
----------------------------------------
Frank A. Wojtek
Chief Financial Officer

EXHIBIT INDEX

+10.8 -- Indemnification Agreement between the Company and each of its directors and executive officers (Incorporated
herein by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31,
1998).

+10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster,
Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.8 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).

+10.10 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs.
Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

+10.11 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by reference to Exhibit 99.3
to the Company's Current Report on Form 8-K dated January 8, 1998).

+10.12 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).

+10.13 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to
Exhibit 99.1 to the Company's Current Report on Form 8-K dated December 15, 1999).

+10.14 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures,
L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K
dated December 15, 1999).

+10.15 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P., Mellon Ventures, L.P.,
Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated herein by reference to Exhibit 99.3 to
the Company's Current Report on Form 8-K dated December 15, 1999).

+10.16 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report on Form 8- K dated
December 15, 1999).

+10.17 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd Jr.,
Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15,
1999).

+10.18 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors, L.P. and Mellon Ventures,
L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated December
15, 1999).

+10.19 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated December 15, 1999).

+10.20 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated December 15, 1999).

+10.21 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated June 29, 2001
(Incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).

+10.22 -- Securities Purchase Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated
February 20, 2002).

+10.23 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P., Paul B. Loyd, Jr.,
Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P.
(Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated February 20,
2002).

+10.24 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster
(including Warrant Certificate) (Incorporated herein by reference to Exhibit 99.4 to the Company's Current Report
on Form 8-K dated February 20, 2002).

+10.25 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated
February 20, 2002).

+10.26 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures, L.P. (Incorporated herein
by reference to Exhibit 99.6 to the Company's Current Report on Form 8-K dated February 20, 2002).

+10.27 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated February 20, 2002).

+10.28 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference to Exhibit 99.8 to the
Company's Current Report on Form 8-K dated February 20, 2002).

21.1 -- Subsidiaries of the Company.

23.1 -- Consent of Ernst & Young LLP

23.2 -- Consent of Ryder Scott Company Petroleum Engineers.

23.3 -- Consent of Fairchild & Wells, Inc.

99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2002.

99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2002.

99.3 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers for CCBM, Inc. as of December 31, 2002.

99.4 -- Notice Regarding Consent of Arthur Andersen LLP.

- ----------

+ Incorporated by reference as indicated.