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, 2001
COMMISSION NO. 0-22915

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

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

14701 ST. MARY'S LANE, SUITE 800 77079
Houston, Texas (Zip Code)
(Principal executive offices)

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.

[ ]

At March 20, 2002, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $25.6 million
based on the closing price of such stock on such date of $5.60.

At March 20, 2002, the number of shares outstanding of the registrant's Common
Stock was 14,140,549.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant's 2002 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, 2001.

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TABLE OF CONTENTS

PART I...................................................................... 2
Item 1. and Item 2. Business and Properties............................... 2
Item 3. Legal Proceedings................................................. 19
Item 4. Submission of Matters to a Vote of Security Holders............... 21
Executive Officers of the Registrant...................................... 21
PART II..................................................................... 21
Item 5. Market for Registrant's Common Stock and Related Shareholder
Matters................................................................ 21
Item 6. Selected Financial Data........................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................. 26
Item 7A. Qualitative and Quantitative Disclosures About Market Risk....... 36
Item 8. Financial Statements and Supplementary Data....................... 36
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure............................................... 36
PART III.................................................................... 36
Item 10. Directors and Executive Officers of the Registrant............... 36
Item 11. Executive Compensation........................................... 37
Item 12. Security Ownership of Certain Beneficial Owners and Management... 37
Item 13. Certain Relationships and Related Party Transactions............. 37
PART IV..................................................................... 37
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 37

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 operations are currently
focused primarily onshore in proven oil and gas producing trends along the Gulf
Coast, in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends. 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. Recognizing this change, the Company has aggressively sought to control
significant prospective acreage blocks for targeted 3-D seismic surveys. During
the period from 1996 through December 2001 the Company assembled over 400,000
gross acres under lease or option and acquired 52 3-D seismic surveys with over
2,700 square miles of 3-D data. In addition, the Company also has approximately
1,325 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 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
participates in 3-D group shoots, the Company typically seeks to obtain leases
or farm-ins rather than lease options. After the 3-D seismic data is processed
and analyzed, the Company seeks to retain such acreage as it deems to be
prospective and usually releases such acreage as it believed is not prospective.
As of December 31, 2001, the Company had 124,390 gross acres in Texas and
Louisiana under lease or option, most of which is covered by 3-D seismic data,
and 233,875 gross acres in Wyoming and Montana under lease or option. The
Company is continually analyzing and reprocessing 3-D seismic data in search of
prospects which the Company believes have a high probability of containing
natural gas or oil. From the 3-D data Carrizo has amassed a large drillsite
inventory, with as many as 250 gross wells that could be drilled over the next
five years, assuming sufficient capital resources. In addition, the Company
anticipates, based upon its past experience, that as its existing as 3-D seismic
data is further evaluated, additional prospects will be generated for drilling
beyond 2006.

Most of the Company's drilling targets in the past have been shallow (from
4,000 to 7,000 feet), normally pressured reservoirs that generally involve
moderate cost (typically $250,000 to $400,000 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 million to $4 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 but has in recent times retained 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, 2001, the Company operated 73 producing oil and gas wells, which
accounted for 41% of the 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
participated in the drilling of 31 gross test wells in Wyoming during 2002, all
of which encountered coal accumulations and are currently under evaluation to
determine if they are likely to result in commercial production of natural gas.
No proved reserves have been assigned to the coalbed methane properties as of
December 31, 2001.

The Company has experienced increases in reserves and EBITDA from its
inception in 1993 due to its 3-D based drilling and development activities. From
January 1, 1996 to December 31, 2001, the Company participated in the drilling
of 243 gross wells (72.2 net) with a commercial well success rate of
approximately 66%, excluding 31 gross (12 net) wells drilled by CCBM that are
currently under evaluation. This drilling success contributed to the Company's
total proved reserves as of December 31, 2001 of 59.0 Bcfe with a PV-10 Value of
$58.4 million. See "Oil and Natural Gas Properties." During 2001, the Company
added 16.2 Bcfe to proved reserves through drilling offset by 5.4 Bcfe of
production. EBITDA increased 8% from $19.6 million for the year ended December
31, 2000 to $21.1 million for the year ended December 31, 2001.

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 primarily along 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.

2

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 representing a specific
project area as compared to interpreting between widely separated two
dimensional vertical profiles. As a consequence, 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 can be 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.

The Company has 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 shares the costs and results of seismic
surveys. By participating in joint ventures and group shoots, the Company is
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. As of December 31, 2001,
the Company was actively involved in 48 project areas.

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 has 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
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 resulted from leads
developed by its project generation network that includes small, independent
"prospect generators", the Company's joint venture partners and the Company's
internal staff. The Company believes that it has been able to increase the
number of potential projects and reduce its costs through the use of these
outside sources of project generation. When identifying specific drillsites from
within a project area, the Company relies upon its 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 of
3-D projects in its core operating areas is a competitive advantage for the
Company. The Company's technical and operating employees have an average of 19
years of industry experience, in many cases with major and large independent oil
companies, including Shell Oil Company, 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,
2001, the Company operated 73 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.

3

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 seeks to integrate 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 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 connects and overlaps existing project area grids
continues to be acquired and integrated into the Company's prospect evaluations.
This further blurs the distinction between original 3-D project areas and, as a
result, geographical sub-grouping is used rather than the original project areas
for this focus area. The discussion clarifies this organizational framework and
highlights the project area and Wilcox area sub-groups where the majority of the
expected drilling will take place over the next 12 to 18 months.

3-D PROJECT SUMMARY CHART
As of December 31, 2001

- ----------

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

TEXAS - WILCOX AREAS

The Wilcox Central subgroup area contains the Cabeza Creek Project Area in
Goliad County along with the Higgins Project Area in Bee and Live Oak Counties,
Texas. The Wilcox South subgroup contains project areas in Duval, Webb, Zapata
and McMullen Counties, Texas. The Wilcox East subgroup contains project areas
primarily in Victoria, Fort Bend and Wharton Counties, as well as in Dewitt and
Lavaca Counties, Texas and includes the Company's Cologne Project Area and
Highway 59 Project Area. The prolific Wilcox trend in South Texas continues to
be a primary area of exploration and development focus for Carrizo. The Company
has a total of 1,162 square miles of 3-D seismic data that covers potential
Wilcox formation exploration and development targets.

4

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.

Wilcox Central - Goliad, Live Oak, Bee Counties

The Company drilled six wells within the central Wilcox area in 2001 with a
100% success rate. The Company continued its exploration activities and drilling
in the Cabeza Creek area, drilling three successful wells during 2001, including
a significant discovery well, the "Riverdale #2". Carrizo is the operator of the
well and owns a 68.75% working interest. The well commenced production in
October 2001 at a rate of approximately 9,000 Mcfe per day. Two additional
successful Wilcox wells have been drilled in the Cabeza Creek area since year
end. Two successful wells were also drilled during 2001 on the NE Weesatche
prospect area in Goliad County where the Company owns a 15.5% working interest.
The latest field extension well reached total depth in November 2001, logged 32
feet of Wilcox net pay and commenced production in January 2002 at a rate of
3,410 Mcfe per day. Currently the Company is participating in an 11,500 foot
test in Goliad County with the results expected in the second quarter 2002. If
successful, this well has the potential to have two additional follow up
locations. The Company has identified nine additional prospects that are drill
ready within the 10,781 net acre area that the Company plans to further evaluate
over the next 12 to 18 months.

Wilcox South - Duval, Webb, Zapata, McMullen Counties

The Company continues to develop prospects within its 474 square mile 3-D
database and is working to secure leases over the areas it believes have the
highest potential. Target intervals include Upper Wilcox through Lobo
formations. The Company plans to drill an initial test well in this area during
2002.

Wilcox East - Dewitt, Lavaca, Victoria, Fort Bend, Wharton Counties

The Company continues to develop prospects within its 311 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 is expected to begin in 2003.

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 1,385 square miles of 3D seismic data that covers development
potential within these Frio, Vicksburg and Yegua sands, 450 acres of which are
in the Matagorda, Ganado and Starr Project Areas. Several key areas are
discussed below which highlight areas of expected focus during 2002 and future
years.

Matagorda

The Matagorda area currently includes license to 98 square miles of 3-D
seismic and over 3,863 net acres of current leasehold. The Company continues to
have success in the area with two successful exploratory wells being drilled in
2001. These successful wells, the "Pitchfork Ranch #1" and the "Staubach #1"
both exhibited high reservoir quality and deliverability in the target Middle
and Lower Frio sands each having initial production rates of over 15 MMcfe per
day. While the Pitchfork Ranch well declined fairly rapidly, the most recent
well the "Staubach #1" in which Carrizo owns a 35% interest before payout, was a
significant discovery, reaching total depth in December 2001 and logging 36 feet
of net pay. The well commenced production in January 2002 at 2,094 Bbls and
4,769 Mcf (17,333 Mcfe) per day and as of March 25, 2002 was continuing to
produce at a rate of 2,000 Bbls and 5,500 Mcf per day. The first follow up well
targeting the same formations as the Staubach #1 well was spud on March 6, 2002,
at the far south end of the structure. On March 24, 2002, a subsidiary of the
Brigham Exploration Company, the operator of this well (the "Burkhart #1") in
the Matagorda area, reported a loss of surface control while drilling the well
and as of March 28, 2002, operations were underway to bring the well under
control. The Company owns a 35% working interest in the well and has liability
and well control insurance that it believes will be sufficient to cover any
liabilities to third parties and the cost to bring the well under control,
including, if necessary, the drilling of a replacement well. The production from
the Staubach #1 well has not been affected by the incident as the Staubach #1
well is currently producing from a deeper interval than that of the gas flow
from the Burkhart #1 well. Carrizo operates the northern portion of the 3-D
defined prospect area with a 55% working interest and plans to drill the initial
test well in this area in the third quarter of 2002. Four additional prospects
are drill-ready within current acreage control which the Company plans to
further evaluate within the next 18 months.

Ganado

The Ganado Project Area is located in Wharton County and targets both
normal pressured Frio and expanded Yegua prospect opportunities within the 32
square mile proprietary seismic dataset. Following initial drilling success in
the Frio, additional leases have been secured for further Frio drilling in 2002.
The deeper prospect opportunities continue to be studied, however no deeper
drilling is currently planned until 2003.

5

Starr

The Company has a non-exclusive license to 340 square miles of 3-D seismic
data which covers Frio and Vicksburg producing trends in Starr and Hildalgo
Counties, Texas. Carrizo is continuing to develop prospects from this data and
acquire leases, and plans to drill two additional wells in the next 12 to 18
months. Carrizo's working interest in its leases within this project area
averages approximately 50%.

SOUTHEAST TEXAS AREAS

Carrizo has acquired approximately 96 square miles of 3-D data over its
Southeast Texas project areas which are focused primarily on the Yegua 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 its 2002 drilling program.
Carrizo is considering additional purchases of 3-D data during 2002 in an
attempt to further exploit successful trends.

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, including two during
2001, have been successful. Carrizo plans to drill one or two additional wells
in the next 12 to 18 months. The Company's working interest in leases in this
project area ranges from 25% to 100% in these prospects.

Liberty

Carrizo has identified and leased prospects ranging from the Frio to the
Cook Mountain formations within the 52 square mile 3-D survey in the Liberty
Project Area in Liberty County, Texas. The Company drilled one successful Cook
Mountain and one unsuccessful Yegua well during 2001. Four wells are anticipated
to be drilled in 2002. The Company's average working interest in the leases in
the project area ranges from 40% to over 80%.

LOUISIANA

West Bay

During 2000, a test well logged apparent pay in several zones and was
successfully completed in the Company's West Bay Project Area in Plaquemine
Parish Louisiana. After a unitization hearing, the Company's interest in the
currently producing zone was set at 12.7%. Carrizo is currently establishing pre
drill units for deeper objectives on the now proven structure. The trap
configuration and seismic signature appears to be similar for the lower
objectives as compared with the proven pay. Permitting is near completion for a
Company operated non-pressured test well expected to be drilled mid year 2002.
The Company expects its working interest in the project area wells to range from
25% to 50% depending on the amount of acreage developed and unitization results.

LaRose

The Company successfully drilled and completed the LaRose Prospect discovery
well, the "Louisiana Delta Farms #1" in Lafourche Parish, Louisiana in 2001.
This well, which Carrizo operates, logged over 100 feet of net pay in three Cris
I sand intervals at depths ranging from 13,500 feet to 15,300 feet. The well
tested at a gross rate of 11,650 Mcf of gas and 1,466 barrels of condensate
(20,446 Mcfe) per day with flowing tubing pressure of approximately 9,740 psi
from approximately 18 net feet of pay from the deepest sand interval. During the
fourth quarter, unitization hearings were completed, setting the Company's
working interest at 40%. While production was delayed pending construction of a
new pipeline, the well commenced production on March 25, 2002. The Company is
closely monitoring the well's performance and has steadily increased the
production rate since commencement to a rate of approximately 9,600 Mcf of
natural gas and 1,100 barrels of condensate per day (16,200 Mcfe per day) as of
March 28, 2002. Based upon the current performance of the well, the Company
expects to be able to increase the production rate to 18,000 to 20,000 Mcfe per
day by March 31, 2002. The Company currently holds approximately 1,240 gross
acres of leases in the LaRose Prospect area. An additional follow-up well is
planned for drilling during 2002.

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, 2001, the
project produced 71 barrels per day of 19 API gravity oil. The project produces
from a depth of 500 feet and utilizes 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, 2001 averaged $12.84 per barrel ($2.14 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

6

relative to oil prices. The crude oil produced, although viscous, commands a
higher price (an average premium of $.75 per barrel during the year ended
December 31, 2001) than West Texas intermediate crude due to its suitability as
a lube oil feedstock. As of December 31, 2001, the Company had 6.21 million
barrels of proved oil reserves in this project, with 771 MBbls of oil reserves
currently developed. The Company anticipates that it will drill additional wells
and increase 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 its leases 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% 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 intends to spend up to $5 million to drill and test coalbed methane
wells on this acreage over the next two to three years, 50% of which would be
spent pursuant to an obligation by Carrizo to fund $2.5 million of drilling
costs on behalf of RMG. During 2001, the Company participated in the drilling of
31 gross wells at a cost of $820,000, all of which encountered coal
accumulations and are currently under evaluation to determine if they are likely
to result in commercial production of natural gas. Coalbed methane wells
typically first produce water and then, as the water production declines, begin
producing methane gas. Eight wells, located in the Clearmont area of the PRB in
Wyoming in which the Company owns a 50% working interest, are currently being
dewatered in an effort to establish commercial production. No proved reserves
have been assigned to the project area as of December 31, 2001. In the event of
default by CCBM on the CCBM Note, RMG would be entitled to foreclose on the
undeveloped portion of the acreage.

OTHER PROJECT AREAS

In addition to the project areas described above, the Company has 20
additional project areas in various stages of development as of December 31,
2001. 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,
2001 had acquired leases and seismic options in these areas covering 69,548
gross acres and 23,667 net acres.

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 percent working interest in its drilling prospects.
References to Company property is 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

7

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,
2001. The reserve data and the present value as of December 31, 2001 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, 2001,
see the reserve reports included as exhibits to this 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 12 of Notes to Financial
Statements.

- ----------

(1) The PV-10 Value as of December 31, 2001 is pre-tax and was determined by
using the December 31, 2001 sales prices, which averaged $17.71 per Bbl of
oil, $2.76 per Mcf of natural gas and $9.20 per Bbl of NGL.

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 percent
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.

8

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 & 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 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, 2001, the Company has incurred total
gross development, exploration and acquisition costs of approximately $137
million. Total exploration, development and acquisition activities from
inception through December 31, 2001 have resulted in the addition of
approximately 77.0 Bcfe, net to the Company's interest, of proved reserves at an
average finding and development cost of $1.78 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.

9

- ----------

(1) Excludes capitalized interest on unproved properties of $1,547,879,
$3,563,555 and $3,170,754 for the years ended December 31, 1999, 2000 and
2001, respectively.

DRILLING ACTIVITY

The following table sets forth the drilling activity of the Company for the
years ended December 31, 1999, 2000 and 2001. 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, 2001 has resulted in a
commercial success rate of approximately 66 percent.

The above table excludes 31 gross (12 net) wells drilled by CCBM during
2001 that are currently being evaluated.

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, 2001.

ACREAGE DATA

The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 2001. 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.

10

The table does not include 4,212 gross acres (1,895 net) that the Company
had a right to acquire in Texas pursuant to various seismic option agreements at
December 31, 2001. 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 drilling obligations and other pre-determined 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 crude oil. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.

The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the

11

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 $759,000. 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 ($759,000) 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, $706,000 remained in accumulated
other comprehensive income.

Total oil purchased and sold under hedging arrangements during 1999, 2000
and 2001 were 45,200 Bbls, 87,900 Bbls and 18,000 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 1999, 2000 and 2001
were 2,050,000 MMBtu, 1,590,000 MMBtu and 3,087,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(412,000) and $(1,537,700) and $2,015,000 for 1999, 2000 and 2001,
respectively.

At December 31, 2001, the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2000, the Company had outstanding
hedge positions covering 1,710,000 MMBtu and 18,000 Bbls. These consisted of
1,080,000 MMBtu with a floor of $4.00 and a ceiling of $5.19 for January through
December 2001 production and 630,000 MMBtu at an average fixed price of $6.60
for January through March 2001 production. The 18,000 Bbls of oil hedges had a
floor of $30.00 and a ceiling of $32.28 for January through March 2001
production. These instruments had a fair market value of ($3,025,000) at
December 31, 2000.

At March 28, 2002, the Company had outstanding hedge positions covering
1,705,000 MMBtu of natural gas at an average fixed price of $3.19 for April 2002
through December 2002 production. The Company also had outstanding hedge
positions covering 18,200 Bbls of oil at an average fixed price of $24.65 for
April 2002 through June 2002 production and 54,900 Bbls of oil hedged under a
costless collar arrangement at a $22.00 floor and a $25.00 cap for April 2002
through September 2002 production.

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 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 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.

REGULATION

The availability of a ready market for oil and 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

12

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 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 percent 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
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 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 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. Beginning with passage by Congress of the NGPA,
the FERC adopted regulatory changes that have significantly altered the
transportation and marketing of natural gas. 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 open
access regulations to intrastate commerce.

Beginning in April 1992, the FERC issued Order No. 636 and a series of
related orders, which required interstate pipelines to 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 divested to a
marketing affiliate, which operates separately from the transporter and in
direct competition with other gas merchants. 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.

The courts have largely affirmed the significant features of Order No. 636
and the numerous related orders pertaining to individual pipelines. However,
some appeals remain pending and the FERC continues to review and modify its
regulations regarding the transportation of natural gas. For example, in 2000,
the FERC issued Order No. 637 which:

o lifts the cost-based cap on pipeline transportation rates in the
capacity release market until September 30, 2002, for short-term
releases of pipeline capacity of less than one year,

13

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 implements a number of new pipeline reporting requirements.

Order No. 637 also requires the Federal Energy Regulatory Commission 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.

In April 1999, the FERC issued Order No. 603, which implemented new
regulations governing the procedure for obtaining authorization to construct new
pipeline facilities. In September 1999, the FERC issued a related policy
statement establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates for service on new pipeline facilities based
solely on the costs associated with such new pipeline facilities. It remains to
be seen what effect the FERC's other activities will have on access to markets,
the fostering of competition and the cost of doing business.

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. 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 gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation 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 crude oil, condensate
and gas liquids by the Company are not currently 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, FERC reaffirmed the current index. 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

14

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 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 may result 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 been developing 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 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 believes
that it will be able to develop and implement these plans in the near future.
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.

15

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.

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, except to the extent described in Note 8 of the Notes to
the Consolidated Financial Statements with respect to certain Starr County
properties. 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 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, 2001, 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.

16

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 crude 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 crude 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 gas or, in the case of a dry hole, the 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 gas reserves not
classified as proved, to find a new reservoir in a field previously found to be
productive of oil or 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 crude oil or other liquid hydrocarbons.

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

17

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 crude oil, condensate or natural gas liquids.

MMBbls. One million barrels of crude 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 crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas. Prices have historically often
been higher or substantially higher for crude 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.

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

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

18

general and administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10 percent.

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 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.

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.

Settlement of Litigation. The Company, as one of three plaintiffs, filed a
lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD,
Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the
229th Judicial District Court of Duval County, Texas, for fraud and breach of
contract in connection with an agreement between plaintiffs and defendants
whereby the defendants were obligated to drill a test well in an area known as
the Slick Prospect in Duval County, Texas. The allegations of the Company in
this litigation were that BNP gave the Company inaccurate and incomplete
information on which the Company relied in making its decision not to
participate in the test well and the prospect, resulting in the loss of the
Company's interest in the lease, the test well and four subsequent wells drilled
in the prospect. The Company has sought to enforce its approximate 23.68%
interest in the prospect and sought damages or rescission, as well as costs and
attorneys' fees. The case was originally filed in Duval County, Texas on
February 25, 2000.

In mid March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations, and exemplary damages. The
case proceeded to trial before the Court (without a jury) on June 19, 2000 after
the plaintiffs' were found by the court to have failed to comply with procedural
requirements regarding the request for a jury. After several days of trial the
case was recessed and later resumed on September 5, 2000. The court at that time
denied the plaintiffs' motion for mistrial based on the court's denial of a jury
trial. The court also ordered that the defendants' counterclaims would be the
subject of a separate trial that would commence on December 11, 2000. The
parties proceeded to try issues related to the plaintiffs' claims on September
5, 2000. All parties rested on the plaintiffs' claims on September 13, 2000. The
court took the matter under advisement and has not yet announced a ruling.
Defendants filed a second amended answer and counterclaim and certain
supplemental responses to request for disclosure in which they stated that they
were seeking damages in the amount of $33.5 million by virtue of an alleged lost
sale of the subject properties, $17 million in alleged lost profits from other
prospective contracts, and unspecified incidental and consequential damages from
the alleged wrongful suspension of funds under their gas sales contract with the
gas purchaser on the properties, alleged damage to relationships with trade
creditors and financial institutions, including the inability to leverage the
Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval County,
Texas incurred in defending against plaintiffs' claims and for 40% of any
aggregate recovery in prosecuting their counterclaims. In subsequent testimony,
the defendants verbally alleged $26 million of damages by virtue of the alleged
lost sale of the properties (as opposed to the $33.5 million previously sought),
$7.5 million of damages by virtue of loss of a lease development opportunity and
$100 million of damages by virtue of the loss of a business opportunity related
to BNP's alleged inability to participate in a 3-D seismic project.

The Company had also alleged that BNP Petroleum Corporation, Seiskin
Interests, LTD and Pagenergy Company, LLC breached a contract with the
plaintiffs by obtaining oil and gas leases within an area restricted by that
contract. This breach of contract allegation

19

is the subject of an additional lawsuit by plaintiffs in the 165th District
Court in Harris County, Texas. The defendants took the position that the claim
must be tried in the Duval County case. The Duval County court, without issuing
a formal ruling, took the position that this claim should be included in the
Duval County case. The Company was seeking damages as a result of defendants'
actions as well as costs and attorneys' fees.

On December 8, 2000 the Company entered into a Compromise and Settlement
Agreement ("Settlement Agreement") with the defendants with regard to the above
described litigation. Under the terms of the Settlement Agreement, the Company
and the defendants agreed to enter into an Agreed Order of Dismissal with
Prejudice of the litigation and, among other things, agreed as follows:

1. Should a co-plaintiff to the Duval County litigation secure a final
judgment (without regard to appeals, new trials or other such actions)
in the trial court in Duval County that results in such plaintiff
being entitled to recover a five percent or greater undivided interest
in the Slick Prospect, BNP will pay to Carrizo, at BNP's option,
either $500,000 or an amount equal to the judgment rendered in favor
of such plaintiff.

2. Should the defendants secure a final judgment (without regard to
appeals, new trials or other such actions) in the trial court in Duval
County against a co-plaintiff, the Company will be obligated to pay
BNP an amount equal to five percent of any percentage of the total
judgment apportioned to the Company in the case, such payment being
limited however to no more than five percent of 47.2 percent of the
total judgment entered in the case.

3. In the event the defendants and such co-plaintiff reach a full and
final settlement prior to the entry of a written final judgment in the
trial court in Duval County (including but not limited to any type of
agreed judgment or any agreement that such co-plaintiff will not be
ultimately liable to BNP for the full amount of any judgment rendered
in favor of the defendants), the obligations described in (1) and (2)
above will be null and void. Also, in the event BNP and such
co-plaintiff both only obtain take nothing judgments in the case, such
obligations will be null and void.

4. Both the Company and the defendants released each other from any and
all claims, demands, actions or causes of action relating to or
arising out of the litigation.

The case proceeded to trial on the counterclaims on December 11, 2000. BNP
presented evidence that its damages were in the amounts of $19.6 million for the
alleged lost sale of the properties, $35 million for loss of the lease
development opportunity, and $308 million for loss of the opportunity related to
participation in the 3-D seismic project. During the course of the trial, the
co-plaintiff presented its motion for summary judgment on the counterclaims
based on the doctrine of absolute judicial proceeding privilege. The court
partially granted the co-plaintiff's motion for summary judgment as it related
to the filing of a lis pendens, but denied it with regard to the other
allegations of BNP. The court also granted to co-plaintiff's plea in abatement
relating to the breach of contract allegation, ruling that the District Court in
Harris County has dominant jurisdiction of that issue. Upon completion of the
trial, the court announced that it would take the case under advisement. On
November 5, 2001, the court filed with the clerk a final judgment that had been
signed by the court on October 26, 2001. Pursuant to the terms of the judgment,
the Company, and its co-plaintiffs, take nothing on their claims against BNP and
are denied any recovery of their interests in the lease, the prospect, or the
wells of the Slick Prospect. Instead, the court confirmed title in the lease,
prospect, and wells in BNP's affiliate. In addition, the Company and its
co-defendants were found to have tortiously and maliciously interfered with two
different BNP contracts or prospective contracts and the business of BNP and its
affiliate, causing damages with respect to the loss of a sale and the loss of a
lease. Under the terms of the Settlement Agreement, the Company paid $472,000 to
BNP. The settlement amount, along with the related legal fees, has been included
as other expense in the accompanying financial statements.

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. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seek
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that the Company acted in good faith and intends
to vigorously defend our position. The Company, along with GMT and the other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a working interest in the Neblett unit, and would allow for the
recovery of well costs. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. A complete loss of the lease in
question would result in the loss to the Company of approximately .6 Bcfe of
reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved
reserves as of June 30, 2001. No reserves with respect to these properties were
included in the Company's reported proved reserves as of December 31, 2001. At
the time of shut in, the Neblett #1 well was producing at the rate of
approximately 45 Mcfe per day, the Neblett #2 well was producing at the rate of
approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate
of approximately 895 Mcfe per day, all net to the Company's interest. The
Company believes that an unfavorable outcome in this matter would not have a
material impact on its financial statements. The Company has recorded revenues
only to the extent of well costs funded by the Company.

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

None.

20

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, 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 also holds the positions of Vice President and Secretary /Treasurer
for Loyd and Associates, Inc. (a private financial consulting and investment
banking firm). Mr. Wojtek held the positions of Vice President and Chief
Financial Officer of Griffin-Alexander Drilling Company from 1984 to 1987,
Treasurer of Chiles-Alexander International Inc. from 1987 to 1989 and Vice
President and Chief Financial Officer of India Offshore Inc. from 1989 to 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.

George F. Canjar has been head of the Company's exploration activities since
joining the Company in July 1996 and was elected Vice President of Exploration
Development in June 1997. Prior thereto he worked for over 15 years for Shell
Oil Company and its overseas affiliates where he held various technical and
managerial positions, including Technical Manager-Geology & Petrophysics,
Section Head Geology & Seismology and Team Leader for numerous integrated
production, development, exploration and project execution groups. Mr. Canjar is
a Registered Petroleum Engineer, Registered Geologist and has a B.S. in
Geological Engineering from the Colorado School of Mines.

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. Prior to joining the company, Mr. Fisher spent 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.

21

- ----------
There were approximately 44 shareholders of record (excluding brokerage
firms and other nominees) of the Company's Common Stock as of March 20, 2002.

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 revolving line of credit with Compass Bank (the
"Company Credit Facility") and the terms of its 9 percent 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".

SALES OF UNREGISTERED SECURITIES

On February 20, 2002, the Company consummated the transactions (the "2002
Financing") contemplated by a Securities Purchase Agreement dated February 20,
2002 (the "2002 Securities Purchase Agreement") among the Company, Mellon
Ventures, L.P. ("Mellon") and Steven A. Webster (excluding the Company, the
"2002 Investors"). Such transactions included (i) the payment by the 2002
Investors of an aggregate purchase price of $6,000,000, (ii) the sale of 60,000
shares of Series B Convertible Participating Preferred Stock (the "Series B
Preferred Stock") the terms of which are set forth in the Statement of
Resolution Establishing a Series of Shares designated Series B Convertible
Participating Preferred Stock (the "Statement of Resolution") and which include
the right to convert such shares into Common Stock, par value $0.01 (the "Common
Stock") of the Company (the "Underlying Shares") at a price of $5.70 per share,
subject to adjustments, to the 2002 Investors pursuant to the terms of the 2002
Securities Purchase Agreement and (iii) the sale of warrants (the "2002
Warrants") to purchase up to 252,632 shares of the Company's Common Stock (the
"2002 Warrant Shares") at the exercise price of $5.94 per share, subject to
adjustments, to the 2002 Investors pursuant to the terms of the Warrant
Agreement dated February 20, 2002 (the "2002 Warrant Agreement") among the
Company, Mellon and Steven A. Webster, (iv) the execution of the Shareholders
Agreement dated February 20, 2002 (the "2002 Shareholders Agreement") among the
Company, Mellon, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster,
S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P., (v) the execution
of the Registration Rights Agreement dated February 20, 2002 ("2002 Registration
Rights Agreement") among the Company, Mellon and Steven A. Webster and (vi) the
execution of a Compliance Sideletter dated as of February 20, 2002 by and
between the Company and Mellon (the "2002 Compliance Sideletter").

The holders of the Series B Preferred Stock have the right, at each holders'
option, to convert all or a portion of such Series B Preferred Stock into the
number of fully paid and nonassessable shares of Common Stock convertible at any
time prior to the fourth business day preceding the Redemption Date (as defined
in the Statement of Resolutions) obtained by dividing (i) the product of (A)
$100 plus all cumulative and accrued dividends (whether or not earned or
declared) accumulated and unpaid on such share through the date of surrender of
such share of Series B Preferred Stock multiplied by (B) each share of Series B
Preferred Stock to be converted by (ii) the Conversion Price (as defined below).
"Conversion Price" is defined to mean the conversion price per share of the
Common Stock into which the Series B Preferred Stock is convertible, as such
Conversion Price may be adjusted pursuant to the Statement of Resolution. The
initial Conversion Price is $5.70.

The Conversion Price is subject to adjustment in certain circumstances,
including (a) if the Company pays a dividend in Common Stock or grants certain
rights to purchase securities, (b) if the Company subdivides, splits or
reclassifies its outstanding shares of Common Stock into a larger number of
shares of Common Stock or combines its outstanding shares of Common Stock into a
smaller number of shares of Common Stock, (c) if the Company pays certain
dividends or makes certain distributions to all holders of its Common Stock of
any shares of capital stock of the Company or its subsidiaries (other than
Common Stock) or evidences of its indebtedness or assets, including all equity
and debt, subject to certain exceptions, and (d) if, subject to certain
exclusions, the Company sells or issues Common Stock, options or convertible
securities without consideration or with a consideration per share of Common
Stock less than the Conversion Price, including in the first year a "full
ratchet" adjustment for issuances in excess of $5 million; provided, however,
that the Conversion Price as adjusted according to this subsection (d) will not
be less than $4.75, appropriately adjusted for stock splits, reverse stock
splits and similar recapitalizations (the "Floor Price").

22

The 2002 Warrants are exercisable at any time prior to the expiration date
on February 20, 2007 for the purchase of an aggregate of 252,632 shares of
Common Stock at an exercise price of $5.94 per share, subject to certain
adjustments. Each Warrant may be exercised by cash payment or on a "cashless
basis" by utilizing the average market price during the 4-day trading period
preceding the date of exercise.

The number and kind of 2002 Warrant Shares issued and the exercise price are
subject to adjustment in certain circumstances, including (a) if the Company
pays a dividend in Common Stock or distributes shares of its Common Stock,
subdivides, splits or reclassifies its outstanding shares of Common Stock into a
larger number of shares of Common Stock, or combines its outstanding shares of
Common Stock into a smaller number of shares of Common Stock, (b) if the Company
issues shares of Common Stock or securities exercisable or exchangeable for or
convertible into shares of Common Stock for no consideration or for less than
the market value (as specified in the 2002 Warrant Agreement) of the Common
Stock, subject to certain exceptions, provided that adjustments under this
clause may not result in the exercise price falling below the Floor Price, (c)
if the Company distributes any of its equity securities (other than Common Stock
or options) to the holders of the Common Stock on a pro rata basis, (d) if the
Company engages in a consolidation, merger or business combination, sells all of
its assets to another person or entity, or enters into certain capital
reorganizations or reclassifications of the capital stock of the Company or (e)
the Company takes certain other actions affecting its Common Stock.

The sale of the shares of Series B Preferred Stock and the 2002 Warrants
pursuant to the Securities Purchase Agreement is exempt from the registration
requirements of the Securities Act of 1933, as amended, by virtue of Section
4(2) thereof as a transaction not involving a public offering.

For additional information regarding the Series B Preferred Stock and the
2002 Financing, including the 2002 Securities Purchase Agreement, the Statement
of Resolution, the 2002 Shareholders Agreement, the 2002 Warrants, the 2002
Warrant Agreement, the 2002 Registration Rights Agreement and the 2002
Compliance Sideletter, see the Company's Current Report on Form 8-K dated
February 20, 2002, which is incorporated herein by reference. The rights of the
holders of Common Stock may be deemed to be limited by the securities issued and
agreements entered into in connection with the 2002 Financing.

The approximately $5,800,000 net proceeds of this financing are expected to
be used primarily to fund the Company's ongoing exploration and development
program.

ITEM 6. SELECTED FINANCIAL DATA

The financial information of the Company set forth below for each of the
five years ended December 31, 2001, has been derived from the audited combined
financial statements of the Company. The following table also sets forth certain
pro forma income taxes, net income and net income per share information. The
information should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the audited
financial statements of the Company and the related notes thereto included
elsewhere herein.

23

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(1) On May 16, 1997, Carrizo and a number of affiliated entities were combined
with the Company in a series of transactions in connection with its initial
public offering (the "Combination Transactions"). Prior to that date,
Carrizo and those other entities were not required to pay federal income
taxes due to their status as partnerships or Subchapter S corporations. The
amounts shown

24

reflect pro forma income taxes that represent federal income taxes which
would have been reported under Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes," had Carrizo and such entities been
tax-paying entities during each of the periods presented. Management of the
Company believes that EBITDA and operating cash flow may provide additional
information about the Company's ability to meet its future requirements for
debt service, capital expenditures and working capital. EBITDA and operating
cash flow are financial measures commonly used in the oil and 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 excludes some, but not all, items that affect net
income and because operating cash flow excludes changes in assets and
liabilities and these measures may vary among companies, the EBITDA and
operating cash flow data presented above may not be comparable to similarly
titled measures of other companies.

(2) Operating cash flow represents cash flows from operating activities prior to
changes in assets and liabilities.

(3) 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 $21,868,413.

(4) 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, efforts to regain control
of the Burkhart #1 well and sufficiency of insurance for liabilities and costs
in connection with the Burkhart #1 well, 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, 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.

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 32, 39 and 25 gross wells in the
Gulf Coast region in 1999, 2000 and 2001 respectively. The Company has budgeted
to drill 16 gross wells (6.6 net) in 2002 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
2002, depreciation, depletion and amortization are expected to increase and oil
and gas operating expenses are expected to increase over levels incurred in
2001. The Company has typically retained the majority of its interests in
shallow, normally pressured prospects and sold a portion of its interests in
deeper, over-pressured prospects.

The financial statements set forth herein are prepared on the basis of a
combination of Carrizo and the entities that were a party to the Combination
Transactions. Carrizo and the entities combined with it in the Combination
Transactions were not required to pay federal income taxes due to their status
as partnerships or Subchapter S corporations, which are not subject to federal
income taxation.

25

Instead, taxes for such periods were paid by the shareholders and partners of
such entities. On May 16, 1997, Carrizo terminated its status as an S
corporation and thereafter became subject to federal income taxes. In accordance
with SFAS No. 109, "Accounting for Income Taxes," the Company established a
deferred tax liability in the second quarter of 1997, resulting in a noncash
charge to income of approximately $1.6 million.

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 $3,000,000.

During the second quarter of 2001, the Company formed CCBM, Inc. ("CCBM") as
a wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil
and gas leases in Wyoming and Montana in areas prospective for coalbed methane
and develop such interests. CCBM plans to spend up to $5 million for drilling
costs on these leases through December 2003, 50 percent of which would be spent
pursuant to an obligation to fund $2.5 million of drilling costs on behalf of
RMG, from whom the interests in the leases were acquired. CCBM drilled 31 gross
wells (12.0 net) and incurred total drilling costs of $819,000 through December
31, 2001. These wells typically take up to 18 months to evaluate and determine
whether or not they are successful. CCBM has budgeted to drill 30 gross (15 net)
wells in 2002.

Prior to the Offering, Carrizo conducted its oil and natural gas operations
directly, with industry partners and through the following affiliated entities:
Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd.,
Carrizo Partners Ltd. and Placedo Partners Ltd. Concurrently with the closing of
the Offering, Combination Transactions were closed. The Combination Transactions
consisted of the following: (i) Carrizo Production, Inc. merged into Carrizo;
(ii) Carrizo acquired Encinitas Partners Ltd. in two steps: (a) Carrizo acquired
the limited partner interests in Encinitas Partners Ltd. held by certain of the
Company's directors and (b) Encinitas Partners Ltd. merged into Carrizo; (iii)
La Rosa Partners Ltd. merged into Carrizo; and (iv) Carrizo Partners Ltd. merged
into Carrizo. As a result of the merger of Carrizo and Carrizo Partners Ltd.,
Carrizo became the owner of all of the partnership interest in Placedo Partners
Ltd.

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 percent 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 ceiling
writedown. Using prices in effect on December 31, 2001 the ceiling writedown
would have been approximately $700,000. Because of the volatility of oil and gas
prices, no assurance can be given that the Company will not experience a ceiling
test writedown in future periods. Once incurred, a write-down of oil and gas
properties is not reversible at a later date.

RESULTS OF OPERATIONS

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 4,431.9 MMcf from 5,460.6 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 159.7 MBbls from 198.5 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 "Volatility of Oil and Natural Gas
Prices".

Average oil prices decreased 13% to $24.28 per barrel in 2001 from $27.81
per barrel 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:

26

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(1) Including cash 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 eight percent 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 $759,000 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.

Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999

Oil and natural gas revenues for 2000 increased 163% to $26.8 million from
$10.2 million in 1999. Production volumes for natural gas in 2000 increased 69
percent to 5,460.6 MMcf from 3,235.0 MMcf in 1999. Realized average natural gas
prices increased 75% to $3.90 per Mcf in 2000 from $2.23 per Mcf in 1999.
Production volumes for oil in 2000 increased 11% to 198.5 MBbls from 179.3 MBbls
in 1999. Oil and natural gas production increased primarily as a result of the
commencement of production from the Cabeza Creek Project wells, additional
Matagorda Project wells, the Cedar Point Project wells, the North La Copita
Project wells, the West Bay Project well and higher than anticipated production
from wells in which the Company had a back-in working interest after payout,
offset by the natural decline of existing wells. Oil and natural gas revenues
include the impact of hedging activities as discussed below under "Volatility
of Oil and Gas Prices."

27

Average oil prices increased 66% to $27.81 per barrel in 2000 from $16.80
per barrel in 1999.

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, 1999 and 2000:

- ----------

(1) Including cash impact of hedging.

Oil and natural gas operating expenses for 2000 increased 63% to $4.9
million from $3.0 million in 1999. 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, 1999 offset by a reduction in costs on older
producing fields. Operating expenses per equivalent unit in 2000 increased to
$.74 per Mcfe from $.70 per Mcfe in 1999. The per unit cost increased primarily
as a result of an increase in severance taxes, increased costs at the Camp Hill
Project and decreased production of natural gas as wells naturally decline
offset by the addition of new wells with high production rates during 2000.

Depreciation, depletion and amortization ("DD&A") expense for 2000 increased
67% to $7.2 million from $4.3 million in 1999. This increase was primarily due
to the increased amortization of deferred loan costs, increased production and
additional seismic and drilling costs offset by the sale of the Metro Project in
the second quarter of 2000.

General and administrative ("G&A") expense for 2000 increased 43% to $3.1
million from $2.2 million for 1999. The increase in G&A was due primarily to the
addition of staff to handle increased drilling and production activities. Stock
option compensation expense for 2000 is a non-cash charge resulting from the
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 2000 decreased 63% to
$13,003 from $35,000 in 1999. This decrease was primarily due to higher interest
cost in 1999 which was not available to be capitalized.

Income taxes changed from a $1.1 million benefit in 1999 to a $1.0 million
expense in 2000 based on improvements in the results which influence taxable
income. The Company also adjusted its valuation allowance during 2000 on net
operating loss carryforwards expected to be realized. This change in estimate
resulted in a deferred income tax benefit adjustment of $3.6 million which
reduced the Company's effective tax rate to eight percent in 2000.

Dividends and accretion of discount on preferred stock decreased to none in
2000 from $2.4 million in 1999 as a result of the redemption of preferred stock
in the fourth quarter of 1999. As a result of this redemption, no such future
charges will be accrued.

Net income for 2000 increased to $12.0 million from $1.7 million in 1999 as
a result of the factors described above.

LIQUIDITY AND CAPITAL RESOURCES

The Company has made and is expected to make oil and gas capital
expenditures in excess of its net cash flow from operations in order to complete
the exploration and development of its existing properties.

28

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 2002
operating cash flow will provide sufficient capital to carry out the Company's
2002 exploration plans, management of the Company continues to seek financing
for its capital program from a variety of sources. No assurance can be given
that the Company will be able to obtain additional financing on terms that would
be acceptable to the Company. The Company's inability to obtain additional
financing could have a material adverse effect on the Company. Without raising
additional capital, the Company anticipates that it may be required to limit or
defer its planned oil and gas exploration and development program, which could
adversely affect the recoverability and ultimate value of the Company's oil and
gas properties.

The Company's primary sources of liquidity have included proceeds from the
1997 initial public offering, 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 1999, 2000
and 2001 drilling program in return for participation in certain wells.

Cash flows provided by operations (after changes in working capital) were
$2.2 million, $17.1 million and $24.0 million for 1999, 2000 and 2001,
respectively. The increase in cash flows provided by operations in 2001 as
compared to 2000 was due primarily to the increase in trade accounts payable.
The increase in cash flows provided by operations in 2000 as compared to 1999
was due primarily to increases in production and commodity prices.

The Company budgeted capital expenditures in 2002 of approximately $17.7
million of which $2.8 million is expected to be used to fund 3-D seismic surveys
and land acquisitions and $14.9 million of which is expected to be used for
drilling activities in the Company's project areas. The Company has budgeted to
drill approximately 16 gross wells (seven net) in the Gulf Coast region and 30
gross (15 net) CCBM coalbed methane wells in 2002. The actual number of wells
drilled and capital expended is dependent upon available financing, cash flow,
availability and cost of drilling rigs, land and partner issues and other
factors.

The Company has continued to reinvest a substantial portion of its cash
flows into increasing its 3-D prospect portfolio, improving its 3-D seismic
interpretation technology and funding its drilling program. Oil and gas capital
expenditures were $10.3 million, $19.7 and $38.2 million for 1999, 2000 and
2001, respectively. The Company's drilling efforts resulted in the successful
completion of 18 gross wells (3.2 net) in 1999, 24 gross wells (6.6 net) in 2000
and 20 gross wells (5.9 net) in 2001 in the Gulf Coast region. All of the 31
gross wells (12 net) drilled by CCBM 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.

FINANCING ARRANGEMENTS

In connection with the 1997 initial public offering, Carrizo entered into an
amended revolving credit facility with Compass Bank (the "Company Credit
Facility"), to provide for a maximum loan amount of $25 million, subject to
borrowing base limitations. The principal outstanding is due and payable in
April 2003, with interest due monthly. The Company Credit Facility was amended
in March 1999 to provide for a maximum loan amount under such facility of $10
million. The interest rate on all revolving credit loans is calculated, at the
Company's option, at a floating rate based on the Compass index rate or LIBOR
plus 2 percent. The Company's obligations are secured by substantially all of
its oil and gas properties and cash or cash equivalents included in the
borrowing base. Certain members of the Board of Directors had provided
collateral, primarily in the form of marketable securities, to secure the
revolving credit loans. This collateral was released during April 2001.

Under the Company Credit Facility, Compass, in its sole discretion, will
make semiannual borrowing base determinations based upon the proved oil and
natural gas properties of the Company. Compass may also redetermine the
borrowing base and the monthly borrowing base reduction at any time at its
discretion. The Company may also request borrowing base redeterminations in
addition to the required semiannual reviews at the Company's cost.

In September 1998, the Company Credit Facility was further amended to
provide for an additional $7 million Term Loan bearing interest at the Index
Rate, of which $7 million was borrowed in the fourth quarter of 1998. In March
1999, the Company Credit

29

Facility was further amended to increase the $7 million Term Loan by $2 million.
In December 1999, $2 million principal amount of the Term Loan was repaid with
proceeds from the sale from the Subordinated Notes, Common Stock and Warrants.

Certain members of the Board of Directors have guaranteed the Term Loan. As
currently amended pursuant to an amendment dated December 1999, interest on the
Term Loan is payable monthly, bearing interest at the Index Rate. Principal
payments on the Term Loan were due in consecutive monthly installments in the
amount $290,000 each, beginning July 1, 2000 through December 1, 2000, and
thereafter in the amount of $440,000, beginning January 1, 2001 until the Term
Loan Maturity Date, when the entire principal balance, plus interest, is
payable. Term Loan Maturity Date means the earlier of: (1) the date of closing
of the issuance of additional equity of the Company, if the net proceeds of such
issuance are sufficient to repay in full the Term Loan; (2) the date of closing
of the issuance of convertible subordinated debt of the Company, if the proceeds
of such issuance are sufficient to repay in full the Term Loan; (3) the date of
repayment of the revolving credit loans and the termination of the revolving
commitment; and (4) July 1, 2001. As of December 31, 2001, the principal balance
of the Term Loan had been repaid.

The Company is subject to certain covenants under the terms of the Company
Credit Facility, including but not limited to (a) maintenance of specified
tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest,
taxes, depreciation and amortization) to quarterly debt service of not less than
1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company
Credit Facility also places restrictions on, among other things, (a) incurring
additional indebtedness, guaranties, loans and liens, (b) changing the nature of
business or business structure, (c) selling assets and (d) paying dividends.

Proceeds of the revolving credit loans have been used to provide funding for
exploration and development activity. At December 31, 2000, and 2001,
outstanding revolving credit loans totaled $5,426,000 and $7,166,000,
respectively, with an additional $2,900,884 and $620,000, respectively,
available for future borrowings. The outstanding amount of the Term Loan was
$5,260,000 and none at December 31, 2000 and 2001. The Company Credit Facility
also provides for the issuance of letters of credit, one of which has been
issued for $224,000 at December 31, 2000 and 2001. The Borrowing Base facility
was amended in November 2000 to provide up to $2 million of Guidance Line
letters of credit (the "Guidance Line letters of credit") relating exclusively
to the Company's outstanding hedge positions. At December 31, 2000, the Company
had one Guidance Line letter of credit outstanding amounting to $180,000. The
weighted average interest rates for 2000 and 2001 on the Company Credit Facility
were 9 and 7 percent, respectively.

On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company
("CCBM"), issued a non-recourse promissory note payable in the amount of
$7,500,000 to RMG as consideration for certain interest in oil and gas leases
held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly
principal payments of $125,000 plus interest at eight percent per annum
commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is
secured solely by CCBM's interests in the oil and gas leases in Wyoming and
Montana.

In December 2001, the Company entered into a capital lease agreement secured
by certain production equipment in the amount of $243,369. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6 percent per annum. The Company has the option to acquire the equipment at
the conclusion of the lease for $1.

Estimated maturities of long-term debt are $2,107,030 in 2002, $8,205,391
in 2003, $3,836,498 in 2004 and the remainder in 2007.

In November 1999, Messrs. Hamilton, Webster and Loyd provided a bridge loan
in the amount of $2,000,000, to the Company, secured by certain oil and natural
gas properties. This bridge loan bore interest at 14 percent per annum. Also in
consideration for the bridge loan, the Company assigned to Messrs. Hamilton,
Webster, and Loyd an aggregate 1.0 percent overriding royalty interest ("ORRI")
in the Huebner #1 and Fondren Letulle #1 wells (combined with the prior
assignment, a 2 percent overriding royalty interest), a .8794 percent ORRI in
Neblett #1 (N. La Copita), a 1.0466 percent ORRI in STS 104-5 #1, a 1.544
percent ORRI in USX Hematite #1, a 2.0 percent ORRI in Huebner #2 and a 2.0
percent 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 million principal
amount of 9 percent Senior Subordinated Notes due 2007 (the "Subordinated
Notes") to an investor group led by CB Capital Investors, L.P. which included
certain members of the Board of Directors. The Subordinated Notes were sold at a
discount of $688,761 which is being amortized over the life of the notes.
Interest is payable quarterly beginning March 31, 2000. The Company may elect,
for a period of five years, to increase the amount of the Subordinated Notes for
up to 60 percent of the interest which would otherwise be payable in cash. For
the year ended December 31, 2001, the amount of Subordinated Notes was increased
by $1,282,295 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 sale was made to an investor
group led by CB Capital Investors, L.P. which included certain members of the
Board of Directors. The Warrants have an exercise price of $2.20 per share and
expire in December 2007.

The Company is subject to certain covenants under the terms 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

30

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 Company's Term Loan, any subordinated debt, indebtedness that
is guaranteed or credit-enhanced by any affiliate of the Company, and
prepayments that effect certain permanent reductions in revolving credit
facilities.

Of the approximately $29,000,000 net proceeds of this financing, $12,060,000
was used to fund the Enron Repurchase described below and related expenses,
$2,025,000 was used to repay the bridge loan extended to the Company by its
outside directors, $2 million was used to repay a portion of the Compass Term
Loan, $1 million was used to repay a portion of the Compass Borrowing Base
Facility, and the 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
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.

In February 2002, the Company consummated the sale of 60,000 shares of
Series B Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common
Stock for an aggregate purchase price of $6,000,000 to an investor group led by
Mellon Ventures, L.P. which included Steven A. Webster, the Company's Chairman
of the Board of Directors. The Series B Preferred Stock is convertible into
Common Stock by the investors at a conversion price of $5.70 per share, subject
to adjustment, and is initially convertible into 1,052,632 shares of Common
Stock. The approximately $5,800,000 net proceeds of this financing 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 eight percent 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 ten
percent per annum. 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 a
offer to each holder of Series B Preferred Stock to repurchase all of such
holder's Series B Preferred Stock at an offer price per share of Series B
Preferred Stock in cash equal to 105% of the Change of Control Purchase Price,
which is generally defined to mean $100 plus all cumulative and accrued
dividends.

31

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, 2001, 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, 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. In addition, the Company has only limited
experience operating and managing field operations, and there can be no
assurances that the Company will be successful in doing so. 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.

On June 29, 2001, the FASB approved its proposed SFAS No. 141, ("FAS
141") "Business Combinations," and SFAS No. 142 ("FAS 142"), "Goodwill and Other
Intangible Assets." Under FAS 141, all business combinations should be accounted
for using the purchase method of accounting; use of the pooling-of-interests
method is prohibited. The provisions of the statement will apply to all business
combinations initiated after June 30, 2001.

FAS 142 will apply to all acquired intangible assets whether acquired
singly, as part of a group, or in a business combination. The statement will
supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible
Assets," and will carry forward provisions in APB Opinion No. 17 related to
internally developed intangible assets. Adoption of FAS 142 will result in
ceasing amortization of goodwill. All of the provisions of the statement should
be applied in fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial
position at that date, regardless of when those assets were initially
recognized. The Company does not have any goodwill or intangible assets recorded
as of December 31, 2001 and does not expect the adoption of this standard to
have a material impact on its financial position or results of operations.

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 liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset. 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. The Company is currently evaluating the effect
of adopting Statement No. 143 on its financial statements and has not determined
the timing of adoption and does not expect the adoption of this standard to have
a material impact on its financial position or results of operations.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144 addresses the
financial accounting and reporting for the impairment or disposal of long-lived
assets. SFAS No. 144 supersedes SFAS No. 121 but retains its fundamental
provisions for the (a) recognition/measurement of impairment of long-lived
assets to be held and used and (b) measurement of long-lived assets to be
disposed of by sale. SFAS 144 also supercedes the accounting/reporting
provisions of APB Opinion No. 30 for segments of a business to be disposed of
but retains the requirement to report discontinued operations separately from
continuing operations and extends that reporting to a component of an entity
that either has been disposed of or is classified as held for sale. SFAS No. 144
is effective for the Company beginning in 2002. The Company is currently
evaluating the impact of this new standard.

CRITICAL ACCOUNTING POLICIES

OIL AND NATURAL GAS PROPERTIES

Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and gas properties. During 1999, the Company also capitalized
as oil and natural gas properties $139,910 of deferred compensation related to
stock options granted to personnel directly associated with exploration
activities. No deferred compensation cost was capitalized in 2000 or 2001.
Additionally, the Company capitalized compensation costs for employees working
directly on exploration activities of $581,000, $886,000 and $1,021,000 in 1999,
2000 and 2001, respectively.

Oil and natural gas properties are amortized based on the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the projects
can be determined or until impairment occurs. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties are impaired, the amount
of impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and,
where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage values. The depletion rate per thousand cubic feet equivalent
(Mcfe) for 1999, 2000 and 2001, was $1.00, $1.03 and $1.15, respectively.

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

The net capitalized costs of proved oil and gas properties are subject to a
"ceiling test," which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves,
based on current economic and operating conditions. If net capitalized costs
exceed this limit, the excess is charged to operations through depreciation,
depletion and amortization. No write-down of the Company's oil and natural gas
assets was necessary in 1999, 2000 or 2001. Based on oil and gas prices in
effect on December 31, 2001, the unamortized cost of oil and gas properties
exceeded the cost center ceiling. As permitted by full cost accounting rules,
improvements in pricing subsequent to December 31, 2001 removed the necessity to
record a ceiling writedown. Using prices in effect on December 31, 2001 the
pretax writedown would have been approximately $700,000. Because of the
volatility of oil and gas prices, no assurance can be given that the Company
will not experience a ceiling test writedown in future periods.

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

STOCK-BASED COMPENSATION

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

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

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

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

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

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates. Significant
estimates include depreciation, depletion and amortization of proved oil and
natural gas properties and future income taxes. Oil and natural gas reserve
estimates, which are the basis for unit-of-production depletion and the ceiling
test, are inherently imprecise and are expected to change as future information
becomes available.

CONCENTRATION OF CREDIT RISK

Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.

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

32

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 percent. 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. On December 31, 1998, the Company recorded a full cost ceiling test
write down of its oil and natural gas properties of $20.3 million because its
carrying cost of proved reserves was in excess of the present value of estimated
future net revenues from those reserves. If additional write-downs are required,
they would result in additional charges to earnings, but would not impact cash
flow from operating activities. 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 "ceiling" writedown. Using prices in effect on December 31, 2001 the
"ceiling" writedown would have been approximately $700,000.

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

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

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 $759,000. 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 ($759,000) 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, $706,000 remained in accumulated
other comprehensive income.

Total oil purchased and sold under hedging arrangements during 1999, 2000
and 2001 were 45,200 Bbls, 87,900 Bbls and 18,000 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 1999, 2000 and 2001
were 2,050,000 MMBtu, 1,590,000 MMBtu and 3,087,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(412,000) and $(1,537,700) and $2,015,000 for 1999, 2000 and 2001,
respectively.

At December 31, 2001, the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2000, the Company had outstanding
hedge positions covering 1,710,000 MMBtu and 18,000 Bbls. These consisted of
1,080,000 MMBtu with a floor of $4.00 and a ceiling of $5.19 for January through
December 2001 production and 630,000 MMBtu at an average fixed price of $6.60
for January through March 2001 production. The 18,000 Bbls of oil hedges had a
floor of $30.00 and a ceiling of $32.28 for January through March 2001
production. These instruments had a fair market value of ($3,025,000) at
December 31, 2000.

At March 28, 2002, the Company had outstanding hedge positions covering
1,705,000 MMBtu of natural gas at an average fixed price of $3.19 for April
2002 through December 2002 production. The Company also had outstanding hedge
positions covering 18,200 Bbls. of oil at an average fixed price of $24.65 for
April 2002 through June 2002 production and 54,900 Bbls of oil hedged under a
costless collar arrangement at a $22.00 floor and a $25.00 cap for April 2002
through September 2002 production.

33

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 crude 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 percent 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 (losses) realized by the
Company related to these instruments were ($412,000), ($1,537,000) and
$2,015,000 or ($0.18), ($0.73) and $0.63 per MMBtu for the years ended December
31, 1999, 2000, and 2001,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 percent fluctuation in short-term interest rates
would have impacted 2001 cash flow by approximately $38,000.

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, 2001 and 2000, and were
determined based upon interest rates currently available to the Company for
borrowings with similar terms. Maturities of the debt are $2,107,000 in 2002,
$8,205,391 in 2003, $3,836,498 in 2004 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

Arnold L. Chavkin resigned as a director of the Company, effective March 11,
2002. Bryan Martin has been elected as a director of the Company. Mr. Martin is
a Principal with JP Morgan Partners, LLC.

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 "2002 Proxy Statement") for its 2002
annual meeting of shareholders. The 2002 Proxy Statement will be filed with the
Securities and Exchange Commission (the "Commission") not later than 120 days
subsequent to December 31, 2001.

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 2002 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2001.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this item is incorporated herein by reference to
the 2002 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2001.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The information required by this item is incorporated herein by reference to
the 2002 Proxy Statement which will be filed with the Commission not later than
120 days subsequent to December 31, 2001.

34

PART IV

ITEM 14. 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.

(a)(3) EXHIBITS

EXHIBIT INDEX

EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
+2.1 -- Combination Agreement by and among the Company, Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd.,
Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P.
Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of
June 6, 1998 (Incorporated herein by reference to Exhibit 2.1 to
the Company's Registration Statement on Form S-1 (Registration No.
333-29187)).

+3.1 -- Amended and Restated Articles of Incorporation of the Company
(Incorporated herein by reference to Exhibit 3.1 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1998).

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

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

+4.1 -- First Amended, Restated, and Combined Loan Agreement between the
Company and Compass Bank dated August 28, 1998 (Incorporated herein
by reference to Exhibit 4.1 to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1998).

+4.2 -- First Amendment to First Amended, Restated, and Combined Loan
Agreement between the Company and Compass Bank dated December 23,
1998 (Incorporated herein by reference to Exhibit 4.2 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1998).

+4.3 -- Second Amendment to First Amended, Restated, and Combined Loan
Agreement between the Company and Compass Bank dated December 30,
1998 (Incorporated herein by reference to Exhibit 4.3 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1998).

+4.4 -- Fourth Amendment to First Amended, Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30,
1999).

+4.5 -- Fifth Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31,
1999).

+4.6 -- Sixth Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31,
1999).

+4.7 -- Seventh Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31,
1999).

+4.8 -- Eighth Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank.
(Incorporated herein by reference to Exhibit 4.8 to the Company's
Annual Report of From 10-K for the year ended December 31, 2000).

+4.9 -- Ninth Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 99.10 to the Company's
Current Report on Form 8-K dated December 15, 1999).

35

+4.10 -- Tenth Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30,
2000).

+4.11 -- Eleventh Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31,
2001).

+4.12 -- Twelfth Amendment to First Amended Restated, and Combined Loan
Agreement by and between Carrizo Oil & Gas, Inc. and Compass Bank
(Incorporated herein by reference to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30,
2001).

+4.13 -- Letter Agreement Regarding Participation in the Company's 2001
Seismic and Acreage Program, dated May 1, 2001 (Incorporated herein
by reference to Exhibit 4.1 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2001).

+4.14 -- Amendment No. 1 to the Letter Agreement Regarding Participation
in the Company's 2001 Seismic and Acreage Program, dated June 1,
2001 (Incorporated herein by reference to Exhibit 4.2 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2001).

+4.15 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM,
Inc. (Incorporated herein by reference to Exhibit 4.3 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2001).

+10.1 -- Amended and Restated Incentive Plan of the Company effective as
of February 17, 2000 (Incorporated herein by reference to Exhibit
10.3 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000).

+10.2 -- Employment Agreement between the Company and S.P. Johnson IV
(Incorporated herein by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

+10.3 -- Employment Agreement between the Company and Frank A. Wojtek
(Incorporated herein by reference to Exhibit 10.3 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

+10.4 -- Employment Agreement between the Company and Kendall A. Trahan
(Incorporated herein by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

+10.5 -- Employment Agreement between the Company and George Canjar
(Incorporated herein by reference to Exhibit 10.5 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).

+10.6 -- 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).

+10.7 -- 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)).

+10.8 -- 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)).

+10.9 -- 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).

+10.10 -- 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).

+10.11 -- 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).

+10.12 -- 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).

+10.13 -- 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).

+10.14 -- 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).

+10.15 -- 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).

36

+10.16 -- 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).

+10.17 -- 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).

+10.18 -- 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).

+10.19 -- 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).

+10.20 -- 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).

+10.21 -- 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).

+10.22 -- 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).

+10.23 -- 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).

+10.24 -- 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).

+10.25 -- 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).

+10.26 -- 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 Arthur Andersen 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, 2001.

99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of
December 31, 2001.

99.3 -- Letter to the Securities and Exchange Commission regarding
Arthur Andersen LLP.

- ----------
+ Incorporated by reference as indicated.

REPORTS ON FORM 8-K

On December 17, 2001 the Company filed a Current Report on Form 8-K to
disclose the status of certain hedging arrangements with Enron North America
Corp.

37

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: April 1, 2002.

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.

38

CARRIZO OIL & GAS, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

F-1

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 Standard 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-2

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

ASSETS

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

F-3

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

F-4

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

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

F-5

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

F-6

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. The financial statements
reflect the accounts of the Company and its subsidiary after elimination of all
significant intercompany transactions and balances. Its operations are focused
on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and
Vicksburg trends. The Company has acquired 2,768 square miles of 3-D seismic
data and has assembled approximately 128,602 gross acres under lease or option
in the Gulf Coast region as of December 31, 2001. Also, the Company, through
CCBM Inc. (a wholly-owned subsidiary) acquired interests in certain oil and gas
leases in Wyoming and Montana in areas prospective for coalbed methane. CCBM
Inc. plans to spend up to $5 million for drilling costs on these leases through
December 2003, 50% of which would be spent pursuant to an obligation to fund
$2.5 million of drilling costs on behalf of Rocky Mountain Gas, Inc. ("RMG"),
from whom the interests in the leases were acquired.

The exploration for oil and 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 gas properties.

F-7

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

OIL AND NATURAL GAS PROPERTIES

Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and gas properties. During 1999, the Company also capitalized
as oil and natural gas properties $139,910 of deferred compensation related to
stock options granted to personnel directly associated with exploration
activities. No deferred compensation cost was capitalized in 2000 or 2001.
Additionally, the Company capitalized compensation costs for employees working
directly on exploration activities of $581,000, $886,000 and $1,021,000 in 1999,
2000 and 2001, respectively.

Oil and natural gas properties are amortized based on the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the projects
can be determined or until impairment occurs. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties are impaired, the amount
of impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and,
where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage values. The depletion rate per thousand cubic feet equivalent
(Mcfe) for 1999, 2000 and 2001, was $1.00, $1.03 and $1.15, respectively.

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

The net capitalized costs of proved oil and gas properties are subject to a
"ceiling test," which limits such costs to the estimated present value,
discounted at a 10 percent 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 1999, 2000 or 2001. Based on oil and gas
prices in effect on December 31, 2001, the unamortized cost of oil and gas
properties exceeded the cost center ceiling. As permitted by full cost
accounting rules, improvements in pricing subsequent to December 31, 2001
removed the necessity to record a ceiling writedown. Using prices in effect on
December 31, 2001 the pretax writedown would have been approximately $700,000.
Because of the volatility of oil and gas prices, no assurance can be given that
the Company will not experience a ceiling test writedown in future periods.

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

FINANCING COSTS

Long-term debt financing costs included in other assets of $930,059 and
$755,731 as of December 31, 2000 and 2001, respectively, are being amortized
using the effective yield method over the term of the loans (through April 1,
2003 for a credit facility and through December 15, 2007 for subordinated notes
payable).

STATEMENTS OF CASH FLOWS

For statement of cash flow purposes, all highly liquid investments with
original maturities of three months or less are considered to be cash
equivalents.

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 long-term debt (except the subordinated notes
payable) approximates fair value as the individual borrowings bear interest at
floating market interest rates.

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.

F-8

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

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

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

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

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates. Significant
estimates include depreciation, depletion and amortization of proved oil and
natural gas properties and future income taxes. Oil and natural gas reserve
estimates, which are the basis for unit-of-production depletion and the ceiling
test, are inherently imprecise and are expected to change as future information
becomes available.

CONCENTRATION OF CREDIT RISK

Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.

F-9

EARNINGS PER SHARE

Supplemental earnings per share information is provided below:

F-10

Net income (loss) per common share has been computed by dividing net income
(loss) by the weighted average number of shares of Common Stock outstanding
during the periods. The Company had outstanding 799,620, 149,000 and 79,500
stock options at December 31, 1999, 2000 and 2001, respectively, that were
antidilutive. The Company also had outstanding 3,010,189 warrants at December
31, 1999 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.

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. Costs to remedy or defend against such
contingencies are charged to the liability, if one exists, or otherwise to
income.

NEW ACCOUNTING PRONOUNCEMENTS

On June 29, 2001, the FASB approved its proposed SFAS No. 141, "Business
Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Under
SFAS 141, all business combinations should be accounted for using the purchase
method of accounting; use of the pooling-of-interests method is prohibited. The
provisions of the statement will apply to all business combinations initiated
after June 30, 2001.

SFAS 142 will apply to all acquired intangible assets whether acquired
singly, as part of a group, or in a business combination. The statement will
supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible
Assets," and will carry forward provisions in APB Opinion No. 17 related to
internally developed intangible assets. Adoption of SFAS 142 will result in
ceasing amortization of goodwill. All of the provisions of the statement should
be applied in fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial
position at that date, regardless of when those assets were initially
recognized. The Company does not have any goodwill or intangible assets recorded
as of December 31, 2001 and does not expect the adoption of this standard to
have a material impact on its financial position or results of operations.

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 liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset. 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. The Company is currently evaluating the effect
of adopting SFAS No. 143 on its financial statements and has not determined
the timing of adoption.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144 addresses the
financial accounting and reporting for the impairment or disposal of long-lived
assets. SFAS No. 144 supersedes SFAS No. 121 but retains its fundamental
provisions for the (a) recognition/measurement of impairment of long-lived
assets to be held and used and (b) measurement of long-lived assets to be
disposed of by sale. SFAS 144 also supercedes the accounting/reporting
provisions of APB Opinion No. 30 for segments of a business to be disposed of
but retains the requirement to report discontinued operations separately from
continuing operations and extends that reporting to a component of an entity
that either has been disposed of or is classified as held for sale. SFAS No. 144
is effective for the Company beginning in 2002. The Company is currently
evaluating the impact of this new standard.

3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION:

In 2000 the Company received a finder's fee valued at $1,544,180 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 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 expects to receive total cash
proceeds of between $5.5 and $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.

4. PROPERTY AND EQUIPMENT

At December 31, 2000 and 2001, property and equipment consisted of the
following:

F-11

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
$44,416,146 of unproved property costs at December 31, 2001 being excluded from
the amortizable base, $4,231,137, $4,498,294 and $11,251,050 were incurred in
1999, 2000 and 2001, respectively. 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 percent 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, 2000 and 2001, the tax effects of these temporary
differences resulted principally from the following:

F-12

The net deferred income tax asset 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. 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 $9.0 million
which begin expiring in 2012.

6. LONG-TERM DEBT

At December 31, 2000 and 2001, long-term debt consisted of the following:

Carrizo amended its existing credit facility with Compass Bank ("Compass")
in September 1998 to provide for a Term Loan under the facility (the "Term
Loan") in addition to the then existing revolving credit facility limited by the
Company's borrowing base (the "Borrowing Base Facility") which provided for a
maximum loan amount of $25 million subject to Borrowing Base limitations. The
Borrowing Base Facility was amended in March 1999 to provide for a maximum loan
amount under such facility of $10 million. Substantially all of Carrizo's oil
and natural gas property and equipment is pledged as collateral under this
facility. The interest rate for both borrowings is calculated at a floating rate
based on the Compass index rate or LIBOR plus 2 percent. The Company's
obligations are secured by certain of its oil and gas properties and cash or
cash equivalents included in the borrowing base. The Borrowing Base Facility and
the Term Loan are referred to collectively as the "Company Credit Facility".
Proceeds from the Borrowing Base portions of this credit facility have been used
to provide funding for exploration and development activity.

Under the Borrowing Base Facility, Compass, in its sole discretion, will
make semiannual borrowing base determinations based upon the proved oil and
natural gas properties of the Company. Compass may also redetermine the
borrowing base and the monthly borrowing base reduction at any time at its
discretion. The Company may also request borrowing base redeterminations in
addition to the required semiannual reviews at the Company's cost.

At December 31, 2000 and 2001, amounts outstanding under the Borrowing Base
Facility totaled $5,426,000 and $7,166,000, respectively, with an additional
$2,676,884 and $620,000, respectively, available for future borrowings. The
Borrowing Base totaled $8,010,000 at December 31, 2001. The Borrowing Base
Facility was also available for letters of credit, one of which has been issued
for $224,000 at December 31, 2000 and 2001. The Borrowing Base facility was
amended in November 2000 to provide up to $2 million of Guidance Line letters of
credit (the "Guidance Line letters of credit") relating exclusively to the
Company's outstanding hedge positions. At December 31, 2000, the Company had one
Guidance Line letter of credit outstanding amounting to $180,000 and no Guidance
Line letters of credit outstanding at December 31, 2001. The weighted average
interest rate for 2000 and 2001 on the Facility was nine and seven percent,
respectively.

F-13

The Term Loan was initially due and payable upon maturity in September 1999.
In March 1999, the maturity date of the Term Loan was amended to provide for
twelve monthly installments of $750,000 beginning January 1, 2000. The repayment
terms were also amended to provide for $1.74 million of principal due ratably
over the last six months of 2000, $2.64 million of principal due ratably over
the first six months of 2001, and the balance due in July 2001. Certain members
of the Board of Directors had guaranteed the Term Loan. The Term Loan was repaid
during September 2001.

The Company is subject to certain covenants under the terms of the Company
Credit Facility, including but not limited to (a) maintenance of specified
tangible net worth, (b) a ratio of quarterly EBITDA (earnings before interest,
taxes, depreciation and amortization) to quarterly debt service of not less than
1.25 to 1.00, and (c) a specified minimum amount of working capital. The Company
Credit Facility also places restrictions on, among other things, (a) incurring
additional indebtedness, guaranties, loans and liens, (b) changing the nature of
business or business structure, (c) selling assets and (d) paying dividends. In
March 1999, the Company Credit Facility was amended to decrease the required
specified tangible net worth covenant. The Company is currently in compliance
with the covenants under the Company Credit Facility.

On June 29, 2001, CCBM, Inc. a wholly owned subsidiary of the Company
("CCBM"), issued a non-recourse promissory note payable in the amount of
$7,500,000 to RMG as consideration for certain interest in oil and gas leases
held by RMG in Wyoming and Montana. The RMG note is payable in 41-monthly
principal payments of $125,000 plus interest at eight percent 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, the principal balance of this note was
$6,750,000.

In December 2001, the Company entered into a capital lease agreement secured
by certain production equipment in the amount of $243,369. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6 percent per annum. The Company has the option to acquire the equipment at
the conclusion of the lease for $1.

In November 1999, certain members of the Board of Directors provided a
bridge loan in the amount of $2,000,000 to the Company secured by certain oil
and natural gas properties. This bridge loan bore interest at 14 percent per
annum. Also, in consideration for the bridge loan, the Company assigned to those
members of the Board of Directors an Overriding Royalty Interest in certain of
the Company's producing properties. The bridge loan was repaid from the proceeds
of the sale of Subordinated Notes, Common Stock and Warrants in 1999.

In December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an
investor group led by CB Capital Investors, L.P. (now known as JP Morgan
Partners, LLC) which included certain members of the Board of Directors. As
discussed in Note 9, the Company also sold Common Stock and Warrants to this
investor group. The Subordinated Notes were sold at a discount of $688,761,
which is being amortized over the life of the notes. Quarterly interest payments
began on March 31, 2000. The Company may elect to increase the amount of the
Subordinated Notes for 60 percent of the interest which would otherwise be
payable in cash. For the years ended December 31, 2000 and 2001, the amount of
the Subordinated Notes was increased by $1,227,325 and $1,282,295 for such
interest. Such Senior Subordinated Notes had a fair market value at December 31,
2001 of approximately $24 million.

The Company is subject to certain covenants under the terms of the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures (as defined) to a
specified amount for the year ended December 31, 2000 and thereafter equal to
the Company's EBITDA for the immediately prior fiscal year (unless approved by
the Company's Board of Directors and a CB Capital Investors, L.P. director). The
Company is currently in compliance with the covenants under the Subordinated
Notes.

Estimated maturities of long-term debt are $2,107,030 in 2002, $8,205,391 in
2003, $3,836,498 in 2004 and the remainder in 2007.

During 1999, Carrizo restructured certain current accounts payable into
vendor notes, extending the payment dates through 2001. Such notes totaled
$1,198,310 and none at December 31, 2000 and 2001, respectively, and bear
interest at rates of 8 percent to 10 percent. The weighted average interest
rates of such notes was 9 percent in 2000.

F-14

7. MANDATORILY REDEEMABLE PREFERRED STOCK

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. A portion of the proceeds
were used to repay indebtedness. The remaining proceeds were used primarily for
oil and natural gas exploration and development activities in Texas and
Louisiana. 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. During
1999, the Company issued preferred stock dividends to the holders of the Series
A Preferred Stock of 29,684.39 shares.

In December 1999, the Company consummated the repurchase of all the
outstanding shares of Series A Preferred Stock and 750,000 Warrants for $12
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. This
repurchase at a discount resulted in a credit of $21,868,413 which was included
in 1999 net income available to common shareholders, net of stock dividends paid
to the holders of the Series A Preferred Stock of $2,417,358.

8. 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.

Settlement of Litigation. The Company, as one of three plaintiffs, filed a
lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD,
Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the
229th Judicial District Court of Duval County, Texas, for fraud and breach of
contract in connection with an agreement between plaintiffs and defendants
whereby the defendants were obligated to drill a test well in an area known as
the Slick Prospect in Duval County, Texas. The allegations of the Company in
this litigation were that BNP gave the Company inaccurate and incomplete
information on which the Company relied in making its decision not to
participate in the test well and the prospect, resulting in the loss of the
Company's interest in the lease, the test well and four subsequent wells drilled
in the prospect. The Company has sought to enforce its approximate 23.68%
interest in the prospect and sought damages or rescission, as well as costs and
attorneys' fees. The case was originally filed in Duval County, Texas on
February 25, 2000.

In mid March 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations, and exemplary damages. The
case proceeded to trial before the Court (without a jury) on June 19, 2000 after
the plaintiffs' were found by the court to have failed to comply with procedural
requirements regarding the request for a jury. After several days of trial the
case was recessed and later resumed on September 5, 2000. The court at that time
denied the plaintiffs' motion for mistrial based on the court's denial of a jury
trial. The court also ordered that the defendants' counterclaims would be the
subject of a separate trial that would commence on December 11, 2000. The
parties proceeded to try issues related to the plaintiffs' claims on September
5, 2000. All parties rested on the plaintiffs' claims on September 13, 2000. The
court took the matter under advisement. Defendants filed a second amended answer
and counterclaim and certain supplemental responses to request for disclosure in
which they stated that they were seeking damages in the amount of $33.5 million
by virtue of an alleged lost sale of the subject properties, $17 million in
alleged lost profits from other prospective contracts, and unspecified
incidental and consequential damages from the alleged wrongful suspension of
funds under their gas sales contract with the gas purchaser on the properties,
alleged damage to relationships with trade creditors and financial institutions,
including the inability to leverage the Slick Prospect, and attorneys' fees at
prevailing hourly rates in Duval County, Texas incurred in defending against
plaintiffs' claims and for 40 percent of any aggregate recovery in prosecuting
their counterclaims. In subsequent testimony, the defendants verbally alleged
$26 million of damages by virtue of the alleged lost sale of the properties (as
opposed to the $33.5 million previously sought), $7.5 million of damages by
virtue of loss of a lease development opportunity and $100 million of damages by
virtue of the loss of a business opportunity related to BNP's alleged inability
to participate in a 3-D seismic project.

On December 8, 2000 the Company entered into a Compromise and Settlement
Agreement ("Settlement Agreement") with the defendants with regard to the above
described litigation. Under the terms of the Settlement Agreement, the Company
and the defendants agreed to enter into an Agreed Order of Dismissal with
Prejudice of the litigation and, among other things, agreed as follows:

1. Should a co-plaintiff to the Duval County litigation secure a final
judgment (without regard to appeals, new trials or other such actions) in
the trial court in Duval County that results in such plaintiff being
entitled to recover a five percent or greater undivided interest in the
Slick Prospect, BNP will pay to Carrizo, at BNP's option, either $500,000
or an amount equal to the judgment rendered in favor of such plaintiff.

2. Should the defendants secure a final judgment (without regard to appeals,
new trials or other such actions) in the trial court in Duval County
against a co-plaintiff, the Company will be obligated to pay BNP an amount
equal to five percent of any percentage of the total judgment apportioned
to the Company in the case, such payment being limited however to no more
than five percent of 47.2% of the total judgment entered in the case.

3. In the event the defendants and such co-plaintiff reach a full and final
settlement prior to the entry of a written final judgment in the trial
court in Duval County (including but not limited to any type of agreed
judgment or any agreement that such co-plaintiff will not be ultimately
liable to BNP for the full amount of any judgment rendered in favor of the
defendants), the obligations described in (1) and (2) above will be null
and void. Also, in the event BNP and such co-plaintiff both only obtain
take nothing judgments in the case, such obligations will be null and void.

F-15

4. Both the Company and the defendants released each other from any and all
claims, demands, actions or causes of action relating to or arising out of
the litigation.

The case proceeded to trial on the counterclaims on December 11, 2000 in the
Duval County court. BNP presented evidence that its damages were in the amounts
of $19.6 million for the alleged lost sale of the properties, $35 million for
loss of the lease development opportunity, and $308 million for loss of the
opportunity related to participation in the 3-D seismic project. During the
course of the trial, the co-plaintiff presented its motion for summary judgment
on the counterclaims based on the doctrine of absolute judicial proceeding
privilege. The court partially granted the co-plaintiff's motion for summary
judgment as it related to the filing of a lis pendens, but denied it with regard
to the other allegations of BNP on November 12, 2001 in final settlement of the
litigation. Upon completion of the trial, the court announced that it would take
the case under advisement.

On November 5, 2001, the court filed with the clerk a final judgment that had
been signed by the court on October 26, 2001. Pursuant to the terms of the
judgment, the Company, and its co-plaintiffs, take nothing on their claims
against BNP and are denied any recovery of their interests in the lease, the
prospect, or the wells of the Slick Prospect. Instead, the court confirmed title
in the lease, prospect, and wells in BNP's affiliate. In addition, the Company
and its co-defendants were found to have tortiously and maliciously interfered
with two different BNP contracts or prospective contracts and the business of
BNP and its affiliate, causing damages with respect to the loss of a sale and
the loss of a lease. Under the terms of the Settlement Agreement, the Company
paid $472,000 to BNP. The settlement amount, along with the related legal fees,
has been included as other expense in the accompanying financial statements.

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. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seek
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that the Company acted in good faith and intends
to vigorously defend its position. The Company, along with GMT and the other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a working interest in the Neblett unit, and would allow for the
recovery of well costs. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. A complete loss of the lease in
question would result in the loss to the Company of approximately .6 Bcfe of
reported proved reserves as of December 31, 2000 or .9 Bcfe of reported proved
reserves as of June 30, 2001. No reserves with respect to these properties were
included in the Company's reported proved reserves as of December 31, 2001. At
the time of shut in, the Neblett #1 well was producing at the rate of
approximately 45 Mcfe per day, the Neblett #2 well was producing at the rate of
approximately 90 Mcfe per day and the Neblett #3 well was producing at the rate
of approximately 895 Mcfe per day, all net to the Company's interest. The
Company believes that an unfavorable outcome in this matter would not have a
material impact on its financial statements. The Company has recorded revenues
only to the extent of well costs funded by the Company.

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

During August 2001, the Company entered into an agreement whereby the lessor
will provide to the Company up to $800,000 in financing for production equipment
utilizing capital leases. At December 31, 2001, one lease in the amount of
$243,369 had been executed under this facility.

At December 31, 2001, the Company was obligated under a noncancelable
operating lease for office space. Rent expense for the years ended December 31,
1999, 2000 and 2001 was $108,700, $207,000 and $207,000, respectively. The
Company is obligated for remaining lease payments of $225,000 per year through
December 31, 2004.

9. SHAREHOLDERS' EQUITY

In December 1999, in connection with the sale of the Subordinated Notes (see
Note 6) the Company consummated the sale of 3,636,364 shares of its 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 valued at $0.25 per Warrant to an investor group led
by CB Capital Investors, L.P. (now known as J.P. Morgan Partners, LLC) which
included certain members of the Board of Directors. The Warrants have an
exercise price of $2.20 per share and expire December 2007.

F-16

In connection with its initial public offering, the Company recorded
deferred compensation related to the March 1997 stock option agreement as
additional paid-in capital and an offsetting contra-equity account. This
compensation accrual is based on the difference between the option price and the
fair value of Carrizo's Common Stock when the options were granted (using an
estimate of the initial public offering Common Stock price as an estimate of
fair value). The deferred compensation was amortized in the period in which the
options vest, which resulted in $139,910 being recorded in the year ended
December 31, 1999.

The following table summarizes information for the options outstanding at
December 31, 2001:

In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the 'Incentive Plan"). The Company accounts for this plan under APB
Opinion No. 25 "Accounting For Stock Issued to Employees" ("APB No. 25"), under
which no compensation cost has been recognized on options which have exercise
prices at least equal to the market price of the stock on the date of the grant.
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 1999, 2000 and 2001: risk free interest rate of 6.81 percent, 6.66
percent and 4.93 percent, respectively, expected dividend yield of 0 percent,
expected life of 10 years and expected volatility of 70.0 percent, 70.8 percent
and 80.7 percent, respectively.

The Company may grant options ("Incentive Plan Options") to purchase up to
1,500,000 shares under the Incentive Plan and has granted options on 1,466,500
shares through December 31, 2001. Through December 31, 2001, 43,963 stock
options had been exercised. A summary of the status of the Company's stock
options at December 31, 1999, 2000 and 2001 is presented in the table below:

F-17

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 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

F-18

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, 2000 and 2001 amounted to $651,741 and $(557,566),
respectively.

10. CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE

On January 1, 1999 the Company adopted the American Institute of Certified
Public Accountants Statement of Position ("SOP") 98-5, which provides guidance
on the accounting for start up costs. SOP 98-5 requires that start up costs be
expensed as incurred. The cumulative effect of this change in accounting
principle to write off unamortized organization costs totaled $77,731 in 1999.

11. RELATED-PARTY TRANSACTIONS

In September 1998 and March 1999 certain members of the Board of Directors
guaranteed a portion of the Company's outstanding indebtedness, provided a
bridge loan of $2 million which was repaid in December 1999, and purchased a
portion of the Subordinated Notes payable.

During the year ended December 31, 1999, the Company incurred drilling costs
in the amount of $130,742 with R&B Falcon Corporation. Messrs. Loyd, Webster,
Hamilton and Chavkin were members of the Board of Directors of both the Company
and R&B Falcon Corporation ("R&B"). In addition, Mr. Loyd was Chairman of the
Board, President and Chief Executive Officer of R&B and Mr. Webster was the Vice
Chairman of R&B. It is management's opinion that these transactions were
performed at prevailing market rates. There were no transactions with R&B during
the year ended December 31, 2000.

During the year ended December 31, 2001, the Company incurred drilling costs
in the amount of $6.3 million 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.

During the year ended 2001, the Company participated in the drilling of two
wells that were operated by a subsidiary of Brigham Exploration Company. Mr.
Webster is a member of the Board of Directors of Brigham Exploration Company
("Brigham"). The terms of the operating agreement between Carrizo and Brigham
are consistent with standard industry practices.

See Notes 6 and 13 for a discussion of the December 1999 and February 2002
financings with parties that included members of the Company's Board of
Directors.

12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of gas production from
December 2001 through December 2002. The value of these derivatives at that time
was $759,000. Because of Enron's financial condition, the Company concluded that
the derivatives contracts were no longer effective and thus did not qualify for
hedge accounting treatment. As required by SFAS No. 133, the value of these
derivative instruments as of November 2001 ($759,000) was recorded in
accumulated other comprehensive income and will be reclassified into earnings
over the original term of the derivative instruments. An allowance for the
related asset totaling $759,000, net of tax of $409,000, was charged to other
expense. At December 31, 2001, $706,000, net of tax of $380,000, remained in
accumulated other comprehensive income related to the deferred gains on these
derivatives.

Total oil purchased and sold under hedging arrangements during 1999, 2000
and 2001 were 45,200 Bbls, 87,900 Bbls and 18,000 Bbls, respectively. Total
natural gas purchased and sold under hedging arrangements in 1999, 2000 and 2001
were 2,050,000 MMBtu, 1,590,000 MMBtu and 3,087,000 MMBtu, respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$(412,000) and $(1,537,700) and $2,015,000 for 1999, 2000 and 2001,
respectively, and are included in oil and gas revenues.

At December 31, 2000, the Company had outstanding hedge positions covering
1,710,000 MMBtu and 18,000 Bbls. These consisted of 1,080,000 MMBtu with a floor
of $4.00 and a ceiling of $5.19 for January through December 2001 production and
630,000 MMBtu at an average fixed price of $6.60 for January through March 2001
production. The 18,000 Bbls of oil hedges had a floor of $30.00 and a ceiling of
$32.28 for January through March 2001 production. These instruments had a fair
market value of ($3,025,000) at December 31, 2000. At December 31, 2001, the
Company had no derivative instruments outstanding designated as hedge positions.

13. SUBSEQUENT EVENTS

In February 2002, the Company consummated the sale of $6 million of
Convertible Participating Series B Preferred Stock and warrants to purchase
Carrizo common stock to an investor group led by Mellon Ventures, Inc. which
included Steven A. Webster, the Company's Chairman of the Board of Directors.
The Series B Preferred Stock is convertible into common stock by the investors
at a conversion price of $5.70 per share, subject to adjustments, and is
initially convertible into 1,052,632 shares of common stock. Dividends on the
Series B Preferred Stock will be payable in either cash at a rate of eight
percent 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 ten percent per annum.
The Series B Preferred Stock is redeemable at varying prices in whole or in part
at the holders' option after three years or at the Company's option at any time.
The Series B Preferred Stock will also participate in any dividends declared on
the common stock. Holders of the Preferred Stock will receive a liquidation
preference upon the liquidation of, or certain mergers or sales of substantially
all assets involving, the Company. Such holders will also have the option of
receiving a change of control repayment price upon certain deemed change of
control transactions. The warrants have a five-year term and entitle the holders
to purchase up to 252,632 shares of Carrizo's common stock at a price of $5.94
per share, subject to adjustments, and are exercisable at any time after
issuance. The warrants may be exercised on a cashless exercise basis.

The approximately $5,800,000 proceeds of this financing are expected to be
used primarily to fund the Company's ongoing exploration and development
program.

Event (unaudited) subsequent to the date of the auditor's report. On
March 24, 2002, a subsidiary of the Brigham Exploration Company, the operator of
the "Burkhart #1" well in the Company's Matagorda Project Area in Matagorda
County, Texas reported a loss of surface control while drilling the well, and as
of March 28, 2002, operations were underway to bring the well under control. The
Company owns a 35% working interest in the well. The Company has liability and
well control insurance that it believes will be sufficient to cover any
liabilities to third parties and the cost to bring the well under control,
including, if necessary, the drilling of a replacement well.

14. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND 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."

F-19

COSTS INCURRED

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

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(1) Excludes capitalized interest on unproved properties of $1,547,879,
$3,563,555 and $3,170,754 for the years ended December 31, 1999, 2000 and
2001, 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, 2000 and 2001,
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.

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:

F-20

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:

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 1999, 2000 and 2001 future cash flows
were $23.40, $24.85 and $17.71 for oil, respectively and $2.35, $10.34 and $2.76
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 percent
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:

F-21

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-22

SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)

(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-23

EXHIBIT INDEX

F-24

2001 (Incorporated herein by reference to Exhibit 4.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001).
+4.14 -- Amendment No. 1 to the Letter Agreement Regarding Participation
in the Company's 2001 Seismic and Acreage Program, dated June 1,
2001 (Incorporated herein by reference to Exhibit 4.2 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001).
+4.15 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM,
Inc. (Incorporated herein by reference to Exhibit 4.3 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001).
+10.1 -- Amended and Restated Incentive Plan of the Company effective as
of February 17, 2000 (Incorporated herein by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 2000).
+10.2 -- Employment Agreement between the Company and S.P. Johnson IV
(Incorporated herein by reference to Exhibit 10.2 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.3 -- Employment Agreement between the Company and Frank A. Wojtek
(Incorporated herein by reference to Exhibit 10.3 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.4 -- Employment Agreement between the Company and Kendall A. Trahan
(Incorporated herein by reference to Exhibit 10.4 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.5 -- Employment Agreement between the Company and George Canjar
(Incorporated herein by reference to Exhibit 10.5 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.6 -- 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).
+10.7 -- 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)).
+10.8 -- 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)).
+10.9 -- 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).
+10.10 -- 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).
+10.11 -- 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).
+10.12 -- 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).
+10.13 -- 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).
+10.14 -- 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).
+10.15 -- 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).
+10.16 -- 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).
+10.17 -- 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).
+10.18 -- 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).
+10.19 -- Purchase and Sale Agreement by and between Rocky Mountain Gas,
Inc. and CCBM, Inc., dated June 29, 2001

F-25

(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).
+10.20 -- 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).
+10.21 -- 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).
+10.22 -- 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).
+10.23 -- 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).
+10.24 -- 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).
+10.25 -- 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).
+10.26 -- 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 Arthur Andersen 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, 2001.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of
December 31, 2001.
99.3 -- Letter to the Securities and Exchange Commission regarding
Arthur Andersen LLP.

- ----------
+ Incorporated by reference as indicated.

F-26