Carrizo Oil & Gas, Inc.
Filed 3/29/01
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, 2000
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 19, 2001, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant
was approximately $56.7 million based on the closing price of such stock on such date of $5.687.
At March 19, 2001, the number of shares outstanding of the registrant's Common Stock was 14,058,061.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2001 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, 2000.
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TABLE OF CONTENTS
PART I ................................................................... 2
Item 1. and Item 2. Business and Properties ............................ 20
Item 3. Legal Proceedings .............................................. 22
Item 4. Submission of Matters to a Vote of Security Holders ............ 22
Executive Officers of the Registrant ................................... 23
PART II .................................................................. 23
Item 5. Market for Registrant's Common Stock and Related Shareholder
Matters ........................................................ 25
Item 6. Selected Financial Data ........................................ 27
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations .......................................... 27
Item 7A. Qualitative and Quantitative Disclosures About Market Risk..... 34
Item 8. Financial Statements and Supplementary Data .................... 34
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure ....................................... 35
PART III ................................................................. 35
Item 10. Directors and Executive Officers of the Registrant ............ 35
Item 11. Executive Compensation ........................................ 35
Item 12. Security Ownership of Certain Beneficial Owners and
Management .................................................... 35
Item 13. Certain Relationships and Related Party Transactions .......... 35
PART IV .................................................................. 35
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K ...................................................... 35
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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
onshore in proven oil and gas producing trends along the Gulf Coast, primarily 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 2000 the Company assembled over 400,000 gross acres under lease or option and
acquired 51 3-D seismic surveys with over 2,100 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, 2000, the Company had 157,575 gross acres under lease or option, most of which is
covered by 3-D seismic data. 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 300 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 2005.
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 $3 million per completed well) and risk. The Company usually seeks to
sell a portion of these deeper prospects to reduce its exploration risk and financial exposure while still allowing the
Company to retain significant upside potential. The Company 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, 2000, the Company operated 67 producing oil and gas wells, which
accounted for 37 percent of the wells in which the Company had an interest.
The Company has experienced increases in reserves, production and EBITDA from its inception in 1993 due to its 3-D
based drilling and development activities. From January 1, 1996 to December 31, 2000, the Company participated in the
drilling of 218 gross wells (66.0 net) with a commercial well success rate of approximately 62 percent. This drilling success
contributed to the Company's total proved reserves as of December 31, 2000 of 49.4 Bcfe with a PV-10 Value of $88.8
million. See "Oil and Natural Gas Properties." During 2000, the Company added 4.2 Bcfe to proved reserves through
drilling, however total proved reserves also increased approximately 11.3 Bcfe, primarily as a result of improved oil and
natural gas prices, offset by 6.65 Bcfe of production. The Company's production increased 54 percent from 4,311 MMcfe
for the year ended December 31, 1999 to 6,651 MMcfe for the year ended December 31, 2000, and adjusted EBITDA
increased 283 percent from $4,921,000 for the year ended December 31, 1999 to $18,750,000 for the year ended
December 31, 2000 due primarily to higher production levels and significantly higher oil and gas sales prices.
Certain terms used herein relating to the oil and natural gas industry are defined in "Glossary of Certain Industry Terms"
below.
EXPLORATION APPROACH
The Company's strategy has been to rapidly accumulate large amounts of 3-D seismic data along 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.
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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, 2000, the Company was actively
involved in 48 project areas.
The Company's primary strategy for acreage acquisition is to obtain leasing options covering large geographic areas in
connection with 3-D seismic surveys. Prior to conducting proprietary surveys, the Company typically seeks to acquire
seismic permits that include 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 attempts to obtain these options covering at least 80 percent of the project area for proprietary
surveys. The size of these surveys has ranged from 10 to 80 square miles. When the Company participates in 3-D group
shoots, it generally seeks prospective leases as quickly as possible following interpretation of the survey. In connection with
some group shoots in which the Company believes that competition for acreage may be especially strong, the Company
may seek to obtain lease options or leases in prospective areas prior to the receipt or interpretation of 3-D seismic 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 18 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,
2000, the Company operated 67 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.
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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 overall inventory of seismic data and
prospects. It is difficult to categorize many of the 3-D projects because they were originally screened and selected for
multiple objectives. The discussion below however, highlights the project areas that include a majority of the expected
drilling targets over the next 12 to 18 months.
3-D PROJECT SUMMARY CHART
As of December 31, 2000
SQUARE 2001
MILES PLANNED
OF 3-D SEISMIC GROSS NET
FOCUS AREA 3-D PROJECT SEISMIC ACQUISITION ACREAGE ACREAGE
---------- ----------- ------- ----------- ------- -------
TEXAS WILCOX AREAS
Cabeza Creek 65 46 7,179 4,707
Buckeye 101 3,132 2,735
Higgins 66 2,229 1,670
Cologne 40 7,134 1,496
Wilcox South 385 64 936 468
TEXAS FRIO/VICKSBURG/YEGUA AREAS
Matagorda 98 50 7,847 4,148
Driscoll 84 6,192 1,479
Ganado 32 1,385 491
Starr 320 5,615 1,970
SOUTHEAST TEXAS AREAS
Cedar Point 30 5,665 1,336
Liberty 66 8,561 3,098
Rusk/Nacogdoches 0 42 15,352 6,186
LOUISIANA AREAS
West Bay 0 4 377 189
Larose 3 1,150 1,150
------- ---- -------- ------
Subtotal 1,290 206 72,754 31,123
OTHER PROJECTS (30 PROJECTS) 825 - 84,821 24,925
------- ---- -------- ------
Total 2,115 206 157,575 56,048
======= ==== ======== ======
OTHER PROJECTS - NONCORE AREAS(1) 1,325 -- --
======= ======== ======
(1) 3-D Seismic coverage in oil & gas producing basins outside areas of current leasehold activity.
TEXAS - WILCOX AREAS
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 991 square miles of 3-D seismic data that covers potential Wilcox formation development
opportunities, with license to obtain an additional 110 miles of 3-D data in the Wilcox areas in early 2001. Wilcox wells
often have relatively deeper
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targets with higher reserve potential and higher risk than many of the Company's other wells. 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 risks.
During the first quarter of 2000, the Company sold its interests in the Metro Project Area in DeWitt County, Texas for a
net sales price of approximately $5.1 million. The sale included the Company's 25 percent working interest in two
producing Wilcox wells with net production to the Company's interest of approximately 800 Mcfe per day as well as
associated leases in the area. The properties sold had a net PV-10 value to Carrizo's interest of $607,000 as of December
31, 1999.
Several key Wilcox project areas are discussed below and represent a significant portion of the expected 2001 and early
2002 drilling inventory.
Goliad County -- Cabeza Creek Project Area
The primary opportunities at the 65 square mile Cabeza Creek Project include exploitation of historical producing closures,
development of deeper objectives on proven structures and large deep exploration opportunities targeting known reservoir
intervals. The Company commenced drilling in the Cabeza Creek Project Area with two successful wells being drilled and
completed on the Wilcox J1 prospect in 2000. The Company is continuing structural and stratigraphic interpretation and
participated for a 15.5 percent working interest in the successful Luker #2 well on the NE Weesatche prospect in the
second half of 2000. This well, which logged approximately 53 feet of net pay in two Wilcox intervals, commenced
production in February 2001 at a rate of approximately 5,500 Mcfe per day from the lower pay interval. The well is also
being completed in the upper Wilcox pay zone in an attempt to increase the rate of production, and a second well is
planned for drilling in April 2001. Additional seismic data was acquired in the first quarter of 2001, bringing the total 3-D
seismic in the project area to 111 square miles. Five significant prospect areas have been identified with objective depths
between 9,000 and 16,000 feet, and have been targeted for drilling commencing midyear 2001. The average working
interest owned by Carrizo in the Cabeza Creek acreage is approximately 49 percent.
Live Oak County -- Buckeye Project Area
The 62 square mile Buckeye Project Area is centrally located in Carrizo's Wilcox area of interest in Bee and Live Oak
Counties, Texas, and includes a series of prospects targeting the Luling through Tom Lyne Wilcox sands. Additional 3-D
seismic data acquired in 2000 on adjoining acreage has increased the Company's total licensed seismic data to 101 square
miles in the area. The current focus of the Company has been on the expanded upper Wilcox formation, where an initial
test well spud in 2001 is currently drilling. If the well is successful, the Company believes that two additional closures in the
area could provide follow-up exploration and development potential. The average working interest owned by Carrizo in
the Buckeye acreage is approximately 46 percent.
Higgins Project Area
The Company's 66 square miles of licensed 3-D seismic data within the Higgins Project Area of Bee and Live Oak
Counties, Texas, has now been merged with the Buckeye Project Area seismic data to provide a 160 square mile
seamless dataset, and full interpretation of this integrated dataset is underway. The initial drilling is planned to commence in
April 2001 with a 14,200 foot Middle Wilcox test well. Carrizo is the operator and expects to have a 50% after casing
point working interest in this prospect well. Carrizo owns a 100 percent working interest in leases elsewhere in the project
area.
Cologne Wilcox Project Area
The Cologne Wilcox prospects are three large expanded Upper Wilcox structures in a single fault block within the 40
square mile Cologne Project Area in Victoria and Goliad Counties, Texas. The Company is currently evaluating well and
seismic data and integrating the results of two wells drilled in 2000 to evaluate two of the three Upper Wilcox structures.
Reservoir quality rock was encountered in both wells. The initial well showed significant potential, commencing production
at a rate of over 8,700 Mcfe per day and thereafter declining to a current rate of approximately 2,000 Mcfe per day. The
second well is still being evaluated. The potential of the accumulations and future plans are being considered, including
reprocessing of the 40 square mile proprietary seismic dataset. Carrizo expects to propose additional drilling as deemed
appropriate based on the evaluations. Carrizo has approximately a seven percent working interest in the initial test well and
approximately a 20 percent working interest in leases covering the other two prospect structures.
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Wilcox South Project Area
Carrizo's Wilcox South Project Area consists of 385 square miles of non-exclusive 3-D seismic license rights along the
southern and western limits of Carrizo's Wilcox area of interest in Duval, Webb and Zapata Counties, Texas, including a
non-inclusive license to 65 square miles of the data was acquired in early 2001. The Company has identified several
prospects and is working to secure leases over the areas it believes have the highest potential.
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 995 square miles of 3D seismic data that covers development
potential within these Frio, Vicksburg and Yegua sands. Several key areas are discussed below which highlight areas of
expected focus during 2001 and future years:
Matagorda Project Area
The Matagorda Project Area currently includes license to 98 square miles of 3-D seismic and over 4,148 net acres of
current leasehold. The area has been one of historical success for the Company with five successful wells drilled during
1999 and 2000 with current gross production of 19,000 Mcfe per day. The Company has recently reprocessed the 3-D
seismic dataset and is reevaluating its inventory of prospects in the area. This reevaluation delayed development drilling in
2000, however the Company is currently operating an 11,000 foot test well which reached total depth on March 24, 2001
and logged approximately 33 feet of apparent net pay in the Discorbis sands. The well is expected to commence
production in mid April 2001. Five wells are planned for 2001, including four wells in the 12,000 foot depth range as well
as a 15,000 foot wildcat Discorbis test well. The Company has a 58 percent working interest in the well presently being
completed and expects to have approximately a 50 percent working interest in the subsequent prospect wells.
Driscoll Project Area
The Driscoll Project Area consists of 84 square miles of proprietory 3-D seismic data with targets in the shallow Miocene
through Vicksburg sections in Jim Wells and Duval counties. Initial drilling of the Yegua opportunities is scheduled for
midyear 2001 with two prospect areas expected to be evaluated. Although the Miocene and Vicksburg have proven to be
difficult targets, detailed seismic modelling and evaluation is ongoing to prioritize the numerous apparent opportunities.
Carrizo has a weighted average working interest of approximately 30 percent in the leases in the project area.
Ganado Project Area
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 2001. The deeper prospect opportunities continue to be
studied, however no deeper drilling is currently planned until 2002.
Starr Project Area
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. The Company and its working interest partners have drilled 32
wells in the project area since 1996, resulting in 23 productive wells. Carrizo is continuing to develop prospects from this
data and acquire leases, and plans to drill at least two additional wells in 2001. Carrizo's working interest in its leases
within this project area averages approximately 50 percent.
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 these areas will constitute a significant portion of its 2001
and 2002 drilling programs. Carrizo is considering additional purchases of 3-D data during 2001 in an attempt to further
exploit successful trends.
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Cedar Point Project Area
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. Three of four wells drilled to date have been successful and are
currently producing approximately 11,000 Mcfe per day. Carrizo is the operator and owns 35 percent of a well currently
drilling which is expected to reach total depth around April 1, 2001, and plans to drill two additional wells in 2001. The
Company's working interest in leases in this project area ranges from 25 percent to 100 percent in these prospects.
Liberty Project Area
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. An initial Frio test well and an initial non-pressured
Yegua test well have both been successfully completed and are on production. Four wells are anticipated to be drilled in
2001, including two pressured Yegua wells and two Cook Mountain wells. The Company's average working interest in the
leases in the project area ranges from 40 to over 80 percent.
Rusk -- Nacogdoches Project Area
Carrizo has 6,186 net acres of leases in the Rusk -- Nacogdoches Project Area located in Rusk and Cherokee Counties,
Texas. The projects target the James Lime, Travis Peak, Pettet and Cotton Valley formations. There has been successful
James Lime horizontal drilling activity in nearby areas by others, in addition to vertical Travis Peak, James Lime and Pettet
production on leases adjacent to a portion of the Company's acreage. Carrizo has an average 58 percent working interest
in the leases in the project area. The Company is currently negotiating with adjacent leaseholders and holders of undivided
lease interests in an attempt to assemble horizontal drilling units. The Company is also evaluating the purchase of 3-D
seismic over a portion of the leasehold. It is anticipated that at one horizontal well will be drilled in 2001, with follow up
wells if the test well is a success.
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 percent. 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
2001. The Company expects it working interest in the project area wells to range from 25 to 50 percent depending on the
amount of acreage developed.
LaRose
The Larose East prospect targets the Lower Cris I sands which have been productive in other wells near the prospect
area, with the potential of additional shallower and deeper targets. The Company controls over 1,150 acres and 100% of
the prospect. Carrizo has secured the permits for an initial Company operated 15,000 foot test well planned during 2001.
If successful, two additional wells would be anticipated for full development of the prospect. Carrizo is evaluating the sale
of a portion of the prospect to an industry partner on a promoted basis.
CAMP HILL PROJECT
The Company owns interests in eight leases totaling approximately 900 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, 2000, the
project produced 81 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, 2000 averaged $18.49 per barrel ($3.08 per Mcfe). In response to high
fuel gas prices, steam injection was reduced in mid 2000. Because profitability increases when natural gas prices drop
relative to oil prices, the project is a natural hedge against decreases in natural gas prices relative to oil prices. The crude oil
produced, although viscous, commands a higher price (an average premium of $.75 per
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barrel during the year ended December 31, 2000) than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 2000, the Company had 6.21 million barrels of proved oil reserves in this project, with
839.4 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 92.5 percent in its
leases in this field and an average net revenue interest of 74.0 percent.
JONES BRANCH PROPERTIES
During November 1998, the Company acquired an interest in four oil and gas producing properties along with rights to
participate in certain exploration prospects (primarily in the Wilcox formation) in Wharton County, Texas, including
associated rights of access to certain 2-D and 3-D seismic data and related information. The Company has an average
working interest of 31.3 percent and an average net revenue interest of 23.7 percent in the properties.
OTHER PROJECT AREAS
In addition to the project areas described above, the Company has 30 additional project areas in various stages of
development as of December 31, 2000. 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, 2000 had acquired leases and seismic options in these areas covering 87,424 gross acres and
25,848 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 activities may not be successful, and if unsuccessful, such failure will have a material adverse
effect on the Company's results of
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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, 2000. The reserve data and the present value as of December 31, 2000 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, 2000, 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.
PROVED
RESERVES
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls) 1,017 5,380 6,397
Natural gas (MMcf) 10,351 641 10,992
Total proved reserves (MMcfe) 16,452 32,925 49,377
PV-10 Value(1) $74,437 $14,393 $88,830
(1) The PV-10 Value as of December 31, 2000 is pre-tax and was determined by using the December 31, 2000 sales
prices, which averaged $24.85 per Bbl of oil, $10.34 per Mcf of natural gas and $14.43 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").
In accordance with Commission regulations, the reserve reports used oil and natural gas prices in effect at December 31,
2000. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market
prices for oil and natural gas production subsequent to December 31, 2000. In particular, natural gas prices at December
31, 2000 were at or near their all-time highs. Natural gas prices have experienced significant volatility and since that time
prices for natural gas have fallen substantially. As of March 23, 2001, the price of natural gas had fallen to $5.23 per Mcf.
Decreases in the assumed commodity prices result in decreases in estimated future net revenues as well as in estimated
reserves. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated,
that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially
enforced.
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
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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.
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 impact of hedging activities.
YEAR ENDED DECEMBER 31,
----------------------------
1998 1999 2000
------ ------ ------
Production volumes
Oil (MBbls) 140 179 198
Natural gas (MMcf) 2,655 3,235 5,461
Natural gas equivalent (MMcfe) 3,495 4,311 6,651
Average sales prices
Oil (per Bbl) $12.30 $16.80 $27.81
Natural gas (per Mcf) 2.31 2.23 3.90
Natural gas equivalent (per Mcfe) 2.25 2.37 4.03
Average costs (per Mcfe)
Camp Hill operating expenses $ 2.35 $ 1.73 $ 3.08
Other operating expenses 0.69 0.66 0.59
Total operating expenses(1) 0.79 0.70 0.74
(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, 2000, the Company has incurred total gross development, exploration and
acquisition costs of approximately $106.7 million. Total exploration, development and acquisition activities from inception
through December 31, 2000 have resulted in the addition of approximately 62.2 Bcfe, net to the Company's interest, of
proved reserves at an average finding and development cost of $1.72 per Mcfe.
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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.
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1999 2000
-------- -------- --------
(IN THOUSANDS)
Acquisition costs
Unproved prospects $ 9,619 $ 4,166 $ 6,641
Proved properties 16,197 472 337
Exploration 10,429 3,163 7,843
Development 313 937 1,361
-------- -------- --------
Total costs incurred(1) $ 36,558 $ 8,738 $ 16,182
======== ======== ========
(1) Excludes capitalized interest on unproved properties of $291,496, $1,547,879 and $3,563,555 for the years ended
December 31, 1998, 1999 and 2000, respectively.
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the years ended December 31, 1998, 1999 and
2000. 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, 2000 has resulted in a commercial success rate of approximately 62 percent.
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1998 1999 2000
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Exploratory Wells
Productive 29 9.3 14 2.3 19 4.7
Nonproductive 24 7.0 12 1.6 15 3.4
----- ----- ----- ----- ----- -----
Total 53 16.3 26 3.9 34 8.1
===== ===== ===== ===== ===== =====
Development Wells
Productive 3 1.0 4 0.9 5 1.9
Nonproductive 1 -- 2 0.8 -- --
----- ----- ----- ----- ----- -----
Total 4 1.0 6 1.7 5 1.9
===== ===== ===== ===== ===== =====
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, 2000.
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COMPANY
OPERATED OTHER TOTAL
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Oil 47 43.7 29 8.9 76 52.6
Natural gas 20 11.3 85 22.2 105 33.5
----- ----- ----- ----- ----- -----
Total 67 55.0 114 31.1 181 86.1
===== ===== ===== ===== ===== =====
ACREAGE DATA
The following table sets forth certain information regarding the Company's developed and undeveloped lease acreage as of
December 31, 2000. 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.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL
------------------ ------------------- ------------------
GROSS NET GROSS NET GROSS NET
------- ------- ------- ------- ------- -------
Louisiana 306 41 2,041 1,436 2,347 1,477
Texas 53,234 18,832 101,994 35,739 155,228 54,571
------- ------- ------- ------- ------- -------
Total 53,540 18,873 104,035 37,175 157,575 56,048
======= ======= ======= ======= ======= =======
The table does not include 2,608 gross acres (605 net) that the Company had a right to acquire pursuant to various seismic
option agreements at December 31, 2000. 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 wells have not been drilled on the acreage within a period of three
years.
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".
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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.
At December 31, 1999, the Company had 300,000 MMBtu and 30,200 Bbls of outstanding hedge positions (at an
average price of $2.33 per MMBtu and $25.60 per Bbl) for January through June 2000 production. 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. Total oil and natural gas
purchased and sold under such swap arrangements during the years ended December 31, 1998, 1999 and 2000 were 0
Bbls, 45,200 Bbls and 87,900 Bbls, respectively, and 1,760,000 MMBtu and 2,050,000 MMBtu, and 1,590,000
MMBtu respectively. Gains (losses) realized by the Company under such swap arrangements were $167,000,
($412,000), and ($1,537,000) for the years ended December 31, 1998, 1999 and 2000, respectively. The Company's
Board of Directors sets 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.
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, the
amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing
facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline in the areas in which the Company may conduct
operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to
produce oil and natural gas between owners in a common reservoir, control the amount
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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 was substantially modified by the Natural Gas Policy Act, 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 which
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 in 1985,
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 Federal Energy Regulatory Commission 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 Federal Energy Regulatory Commission continues to
review and modify its regulations regarding the transportation of natural gas. For example, the Federal Energy Regulatory
Commission issued Order No. 637 which:
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- 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,
- permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods,
- encourages, but does not mandate, auctions for pipeline capacity,
- requires pipelines to implement imbalance management services,
- restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow
orders, and
- implements a number of new pipeline reporting requirements.
Order No. 637 also requires the Federal Energy Regulatory Commission Staff to analyze whether the Federal Energy
Regulatory Commission should implement additional fundamental policy changes. These include whether to pursue
performance-based or other non-cost based ratemaking techniques and whether the Federal Energy Regulatory
Commission should mandate greater standardization in terms and conditions of service across the interstate pipeline grid.
In April 1999, the Federal Energy Regulatory Commission issued Order No. 603, which implemented new regulations
governing the procedure for obtaining authorization to construct new pipeline facilities. In September 1999, the Federal
Energy Regulatory Commission 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. Thus, in addition to "first sale"
deregulation, Congress also repealed incremental pricing requirements and gas use restraints previously applicable. There
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 last year;
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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 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
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facilities that could be the source of an oil spill into federal or state waters, including wetlands, to post a bond, letter of
credit or other form of financial assurance in amounts ranging from $10 million in specified state waters to $35 million in
federal outer continental shelf waters to cover costs that could be incurred by governmental authorities in responding to an
oil spill. Such financial assurances may be increased by as much as $150 million if a formal risk assessment indicates that
the increase is warranted. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.
Operations of the Company are also subject to the federal Clean Water Act ("CWA") and analogous state laws. In
accordance with the CWA, the state of Louisiana has issued regulations prohibiting discharges of produced water in state
coastal waters effective July 1, 1997. Pursuant to other requirements of the CWA, the EPA has adopted regulations
concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits,
participate in a group permit or seek coverage under an EPA general permit. While certain of its properties may require
permits for discharges of storm water runoff, the Company believes that it will be able to obtain, or be included under, such
permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material
effect on the Company. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide
varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the
ground.
The Company also is subject to a variety of federal, state and local permitting and registration requirements relating to
protection of the environment. Management believes that the Company is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing requirements will not have a material
adverse effect on the Company.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, craterings, pipe
failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal
pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. These
hazards and risks could result in substantial losses to the Company from, among other things, injury or loss of life, severe
damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup
responsibilities, regulatory investigation and penalties and suspension of operations. In addition, the Company may be liable
for environmental damages caused by previous owners of property purchased and leased by the Company. As a result,
substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or
eliminate the funds available for exploration, development or acquisitions or result in the loss of the Company's properties.
In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks
and losses. The Company does not carry business interruption insurance or protect against loss of revenues. There can be
no assurance that any insurance obtained by the Company will be adequate to cover any losses or liabilities. The Company
cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its
purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect
the Company's financial condition and operations. The Company may elect to self-insure if management believes that the
cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental
risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material
adverse effect on the financial condition and results of operations of the Company. The Company participates in a
substantial percentage of its wells on a nonoperated basis, which may limit the Company's ability to control the risks
associated with oil and natural gas operations.
TITLE TO PROPERTIES; ACQUISITION RISKS
The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally
accepted in the oil and natural gas industry. The Company's properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens which the Company believes do not materially
interfere with the use of or affect the value of such properties. As is customary in the industry in the case of undeveloped
properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local
records). Investigations, including a title opinion of local 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
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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, 2000, the Company had 35 full-time employees, including seven geoscientists and five engineers. The
Company believes that its relationships with its employees are good.
In order to optimize prospect generation and development, the Company utilizes the services of independent consultants
and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition
of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Field and
on-site production operation services, such as pumping, maintenance, dispatching, inspection and testings, are generally
provided by independent contractors. The Company believes that this use of third party service providers has enhanced its
ability to contain general and administrative expenses.
The Company depends to a large extent on the services of certain key management personnel, the loss of, any of which
could have a material adverse effect on the Company's operations. The Company does not maintain key-man life insurance
with respect to any of its employees.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to
herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and
in most instances are rounded to the nearest major multiple.
After payout. With respect to an oil or gas interest in a property, refers to the time period after which the costs to drill and
equip a well have been recovered.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to 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
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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.
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 been higher or substantially higher for crude oil than natural gas
on an energy equivalent basis.
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.
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Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind
casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion
intervals currently open in existing wells and able to produce to market.
Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing
equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes
of recovering proved undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or
from existing wells where a relatively major expenditure is required for recompletion.
PV-10 Value. The present value of estimated future revenues to be generated from the production of proved reserves
calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future
development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual discount rate of 10 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
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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 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 considered 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 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. The court also granted the 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
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would take the case under advisement. As of March 1, 2001, the court has not yet announced a ruling.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following
information is included in Part I of this Form 10-K.
The following table sets forth certain information with respect to executive officers of the Company:
NAME AGE POSITION
---- --- --------
S.P. Johnson IV 44 President and Chief Executive Officer
Frank A. Wojtek 45 Chief Financial Officer, Vice President,
Secretary and Treasurer
George F. Canjar 43 Vice President of Exploration Development
Kendall A. Trahan 50 Vice President of Land
J. Bradley Fisher 40 Vice President of Operations
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 is a Certified Professional
Landman and 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.
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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.
QUARTER ENDED HIGH LOW
------------------- --------- --------
March 31, 1999 1 11/16 1
June 30, 1999 2 1
September 30, 1999 2 1/4 1 1/2
December 31, 1999 2 1/8 1 3/8
March 31, 2000 4 1/8 1 11/16
June 30, 2000 7 1/4 2 7/8
September 30, 2000 14 5 1/4
December 31, 2000 12 3/8 7 7/8
There were approximately 44 shareholders of record (excluding brokerage firms and other nominees) of the Company's
Common Stock as of March 19, 2001.
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 December 15, 1999, the Company consummated the transactions (the "Financing") contemplated by a Securities
Purchase Agreement dated December 15, 1999 (the "Securities Purchase Agreement") among the Company, CB Capital
Investors, L.P. ("Chase"), Mellon Ventures, L.P. ("Mellon"), Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A.
Webster (excluding the Company (now known as J. P. Morgan Partners, LLC), the "Investors"). Such transactions
included (i) the payment by the Investors of an aggregate purchase price of $30,000,000, (ii) the sale of an aggregate of
$22,000,000 principal amount of 9 percent Senior Subordinated Notes due 2007 (the "Notes") to the Investors, (iii) the
sale of an aggregate of 3,636,364 shares of the Company's Common Stock for $2.20 per share to the Investors, (iv) the
sale of Warrants (the "Warrants") to purchase up to 2,760,189 shares of the Company's Common Stock (the "Warrant
Shares") at the exercise price of $2.20 per share, subject to adjustments, to the Investors, (v) the execution of the
Shareholders Agreement dated December 15, 1999 (the "Shareholders Agreement") among the Company, Chase,
Mellon, Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and
DAPHAM Partnership, L.P., (vi) the execution and delivery of the Warrant Agreement dated December 15, 1999 (the
"Warrant Agreement") among the Company, Chase, Mellon, Paul B. Loyd, Jr., Douglas A.P. Hamilton and Steven A.
Webster,
(vii) the execution of the Registration Rights Agreement dated December 15, 1999 ("Chase Registration Rights
Agreement") among the Company, Chase and Mellon,
(viii) the execution of the Amended and Restated Registration Rights Agreement dated December 15, 1999 ("Amended
Founders Registration Rights Agreement") 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., and (ix) the execution of a Compliance
Sideletter dated December 15, 1999 among the Company, Chase and Mellon (the "Compliance Sideletter").
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The Warrants are exercisable at any time prior to the expiration date on December 15, 2007 for the purchase of an
aggregate of 2,760,189 shares of Common Stock at an exercise price of $2.20 per share, subject to certain adjustments.
Each Warrant may be exercised by (i) paying the exercise price in cash or
(ii) on a cashless basis by exercising the Warrant for a number of net Warrant Shares equal to the number of Warrant
Shares issuable upon exercise of the Warrant minus the number of shares obtained by dividing (A) the product of the
exercise price times the number of net Warrant Shares issuable upon exercise of the Warrant by (B) the average market
price during the 4-day trading period preceding the date of exercise.
The number and kind of Warrant Shares issued and the exercise price are subject to adjustment in certain circumstances,
including (i) 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, (ii) 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 Warrant) of the Common Stock, subject to
certain exceptions, (iii) 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, (iv) 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 (v) the Company takes certain other actions affecting its Common
Stock.
The sale of the shares of Common Stock, the Notes and the 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.
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ITEM 6. SELECTED FINANCIAL DATA
The financial information of the Company set forth below for each of the five years ended December 31, 2000, 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.
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1996 1997 1998 1999 2000
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues $ 5,195 $ 8,712 $ 7,859 $ 10,204 $ 26,834
Costs and expenses:
Oil and natural gas operating expenses 2,384 2,334 2,770 3,036 4,941
Depreciation, depletion and
amortization 1,136 2,358 3,952 4,301 7,170
Write-down of oil and gas properties -- -- 20,305 -- --
General and administrative 515 1,591 2,667 2,195 3,143
Stock option compensation expense -- -- -- -- 652
-------- -------- -------- -------- --------
Total costs and expenses 4,035 6,283 29,694 9,532 15,906
-------- -------- -------- -------- --------
Operating income (loss) 1,160 2,429 (21,835) 672 10,928
Interest expense (net of amounts capitalized and
interest income (80) (98) 285 13 579
Other income 20 -- -- -- 1,482
-------- -------- -------- -------- --------
Income (loss) before income taxes 1,100 2,331 (21,550) 685 12,989
Income tax expense (benefit)(1) -- 2,300 (2,218) (1,057) 1,004
-------- -------- -------- -------- --------
Net income (loss) before cumulative effect of change
in accounting principle 1,100 31 (19,332) 1,742 11,985
Cumulative effect of change in accounting principle -- -- -- (78) --
-------- -------- -------- -------- --------
Net income (loss)(1)(4) $ 1,100 $ 31 $(19,332) $ 1,664 $ 11,985
======== ======== ======== ======== ========
Basic earnings (loss) per share(1)(4) $ 0.15 $ -- $ (2.15) $ 2.00 $ 0.85
======== ======== ======== ======== ========
Diluted earnings (loss) per share(1)(4) $ 0.15 $ -- $ (2.15) $ 2.00 $ 0.74
======== ======== ======== ======== ========
Basic weighted average shares outstanding 7,476 8,639 10,375 10,544 14,028
Diluted weighted average shares
outstanding 7,545 8,810 10,375 10,546 16,256
STATEMENTS OF CASH FLOW DATA:
Net cash provided by operating activities $ 3,325 $ 3,068 $ 2,387 $ 2,200 $ 17,133
Net cash used in investing activities (8,221) (28,141) (37,178) (14,179) (16,438)
Net cash provided by (used in) financing activities 6,319 26,255 32,916 21,457 (3,823)
OTHER OPERATING DATA:
Adjusted EBITDA(2) $ 2,296 $ 4,787 $ 2,422 $ 4,921 $ 18,750
Operating cash flow(3) 2,236 4,689 2,707 4,986 19,329
Capital expenditures 9,480 32,234 36,570 10,286 19,746
Debt repayments(5) 2,084 20,409 7,950 8,174 3,923
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AS OF DECEMBER 31,
-----------------------------------------------------------
1996 1997 1998 1999 2000
-------- -------- -------- -------- --------
BALANCE SHEET DATA:
Working capital $ (1,025) $ (2,276) $ (5,204) $ 8,338 $ 6,433
Property and equipment, net 15,206 45,083 57,878 64,337 72,129
Total assets 18,869 53,658 64,988 83,666 93,000
Long-term debt, including current
maturities 9,684 7,950 12,056 37,170 34,556
Mandatorily redeemable preferred stock -- -- 30,731 -- --
Equity 4,596 32,895 11,202 40,853 52,939
(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 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. See Notes 2 and 4 to the Company's financial
statements. 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) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization and
other significant non-cash items.
(3) Operating cash flow represents cash flows from operating activities prior to changes in assets and liabilities.
(4) 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.
(5) 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, expected working or net revenue
interests, 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), 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 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
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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 57, 32 and 39 gross wells in 1998, 1999 and 2000 respectively. The Company has budgeted to drill 40 gross wells
(11.1 net) in 2001; 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 2001, depreciation,
depletion and amortization are expected to increase and oil and gas operating expenses are expected to increase over
levels incurred in 2000. 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. 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.
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. At December 31, 1998, the Company recorded a full cost ceiling test write down
of its oil and natural gas properties of $20.3 million primarily as a result of declines in product pricing and revisions to prior
estimates of proved reserves. Once incurred, a write-down of oil and gas properties is not reversible at a later date.
See "Recently Issued Accounting Pronouncements," for the expected effect on 2001 income of the adoption of SFAS No.
133 on January 1, 2001.
RESULTS OF OPERATIONS
Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999
Oil and natural gas revenues for 2000 increased 163 percent 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 percent to $3.90 per Mcf in 2000 from $2.23 per Mcf in 1999. Production volumes for oil
in 2000 increased 11 percent to 198.5
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29
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 above under "General Overview."
Average oil prices increased 66 percent 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:
2000 PERIOD
COMPARED TO 1999 PERIOD
DECEMBER 31, INCREASE % INCREASE
1999 2000 (DECREASE) (DECREASE)
----------- ----------- ----------- ----------
Production volumes-
Oil and condensate (Mbbls) 179.3 198.5 19.2 11%
Natural gas (MMcf) 3,235.0 5,460.6 2,225.6 69%
Average sales prices-(1)
Oil and condensate (per Bbl) $ 16.80 $ 27.81 $ 11.01 66%
Natural gas (per Mcf) 2.23 3.90 1.67 75%
Operating revenues-
Oil and condensate $ 2,975,998 $ 5,518,825 $ 2,542,827 85%
Natural gas 7,228,347 21,314,985 14,086,638 195%
----------- ----------- -----------
Total $10,204,345 $26,833,810 $16,629,465 163%
=========== =========== ===========
(1) Including impact of hedging.
Oil and natural gas operating expenses for 2000 increased 63 percent 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 $.82 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 percent 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 expense for 2000 increased 43 percent 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 percent 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 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.
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30
Net income for 2000 increased to $12.0 million from $1.7 million in 1999 as a result of the factors described above.
Year Ended December 31, 1999 Compared to the Year Ended December 31, 1998
Oil and natural gas revenues for 1999 increased 30 percent to $10.2 million from $7.9 million in 1998. Production volumes
for natural gas in 1999 increased 22 percent to 3,235.0 MMcf from 2,655.1 MMcf in 1998. Realized average natural gas
prices decreased 3 percent to $2.23 per Mcf in 1999 from $2.31 per Mcf in 1998. Production volumes for oil in 1999
increased 28 percent to 179.3 MBbls from 140.0 MBbls in 1998. The increase in oil production was due primarily to the
Jones Branch acquisition during the fourth quarter of 1998 and the completion of the Matagorda Project wells in the
second half of 1999. Natural gas production increased primarily as a result of the Jones Branch acquisition, the completion
of the Matagorda Project area wells and the Cedar Point Project Area well in the second half of 1999 offset by the natural
decline of existing wells.
Average oil prices increased 37 percent to $16.80 per barrel in 1999 from $12.30 per barrel in 1998.
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, 1998 and 1999:
1999 PERIOD
COMPARED TO 1998 PERIOD
DECEMBER 31, INCREASE % INCREASE
1998 1999 (DECREASE) (DECREASE)
----------- ----------- ----------- ----------
Production volumes-
Oil and condensate (Mbbls) 140.0 179.3 39.3 28%
Natural gas (MMcf) 2,655.1 3,235.0 579.9 22%
Average sales prices-(1)
Oil and condensate (per Bbl) $ 12.30 $ 16.80 $ 4.50 37%
Natural gas (per Mcf) 2.31 2.23 (0.08) (3)%
Operating revenues-
Oil and condensate $ 1,721,162 $ 2,975,998 $ 1,254,836 73%
Natural gas 6,137,340 7,228,347 1,091,007 18%
----------- ----------- -----------
Total $ 7,858,502 $10,204,345 $ 2,345,843 30%
=========== =========== ===========
(1) Including impact of hedging.
Oil and natural gas operating expenses for 1999 increased 10 percent to $3.0 million from $2.8 million in 1998. 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, 1998 offset by a reduction in costs on older producing fields. Operating expenses per equivalent unit
in 1999 decreased to $.70 per Mcfe from $.79 per Mcfe in 1998. The per unit cost decreased primarily as a result of the
addition of new wells with high production rates during 1999 and the implementation of cost control measures in certain oil
producing fields offset by decreased production of natural gas as wells naturally decline.
Depreciation, depletion and amortization ("DD&A") expense for 1999 increased nine percent to $4.3 million from $4.0
million in 1998. This increase was primarily due to the increased amortization of deferred loan costs, increased production
and additional seismic and drilling costs offset by the lower asset base resulting from the ceiling test write-down in the
fourth quarter of 1998.
Primarily as a result of quantity revisions and depressed commodity prices, the Company recorded a write-down of oil and
gas properties of $20.3 million in 1998. Prior to 1998 and during 1999 the Company was not required to record any such
write-downs.
General and administrative expense for 1999 decreased 18 percent to $2.2 million from $2.7 million for 1998 reflecting the
cost control measures implemented in the fourth quarter of 1998 and first quarter of 1999.
Other income, net of related expenses for the year ended December 31, 2000 consisted of a finder's fee received by the
Company in connection with the sale and purchase of a significant minority shareholder interest in Michael Petroleum
Corporation ("MPC") by Donaldson, Lufkin and Jenette. MPC is a privately -- held exploration and production company,
which focuses on the prolific gas producing Lobo Trend in South Texas, MPC recently emerged from Chapter 11 financial
restructuring. The Company elected to receive the fee in the form of 18,947 shares of common stock and as a result
received 1.9 percent of the outstanding common shares of MPC.
29
31
Interest expense, net of amounts capitalized, for 1999 increased 305 percent to $35,000 from $9,000 in 1998. This
increase was primarily due to higher interest expense in 1999 which was not available to be capitalized. The Company
expects future interest costs to increase as a result of its issuance of $22 million principal amount of Senior Subordinated
Notes in December 1999.
Income tax benefits decreased from $2.2 million to $1.1 million based on improvements in the results which influence future
taxable income. The Company also adjusted its valuation allowance in the fourth quarter of 1999 on net operating loss
carryforwards expected to be realized, which resulted in a deferred income tax benefit of $1.1 million.
Dividends and accretion of discount on preferred stock decreased to $2.4 million in 1999 from $2.9 in 1998 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 1999 increased to $1.7 million from a loss of $22.2 million in 1998 as a result of the factors described
above.
The redemption of the Company's mandatorily redeemable Preferred Stock resulted in a discount of $21,868,413 which is
included in net income available to common shareholders, net of stock dividends paid to the holders of the preferred stock
of $2,417,358.
LIQUIDITY AND CAPITAL RESOURCES
The Company has made and is expected to make oil and gas capital expenditures in excess of its net cash flow from
operations in order to complete the exploration and development of its existing properties.
The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the
Company and to fund leasehold costs and geological and geophysical cost on its exploration projects.
While the Company believes that current cash balances and anticipated 2001 operating cash flow will provide sufficient
capital to carry out the Company's 2001 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 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 and
2000 drilling program in return for participation in certain wells.
Cash flows provided by operations (after changes in working capital) were $2.4 million, $2.2 million and $17.1 million for
1998, 1999 and 2000, respectively. The decrease in cash flows provided by operations in 1999 as compared to 1998
was due primarily to the decrease in current liabilities offset by increases in commodity prices. 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 has budgeted capital expenditures in 2001 of approximately $22.0 million of which $4.4 is expected to be
used to fund 3-D seismic and land acquisitions and $17.6 million of which is expected to be used for drilling activities in the
Company's project areas. The Company has budgeted to drill approximately 40 gross wells (11.1 net) in 2001. 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
$36.6 million, $10.3 and $19.7 million for 1998, 1999 and 2000, respectively. The Company's drilling efforts resulted in
the successful completion of 32 gross wells (10.3 net) in 1998, 18 gross wells (3.2 net) in 1999 and 24 gross wells (6.6
net) in 2000.
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 a dayrate of $12,000 per day. The rig is expected to be utilized primarily to drill wells in the
Company's focus areas, including the Matagorda Project Area and the Cabeza Creek Project Area. The contract contains
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. 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.
30
32
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 January 2002, 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 have provided collateral,
primarily in the form of marketable securities, to secure the revolving credit loans. As of March 1, 2001, the aggregate
amount of this collateral was approximately $3.3 million.
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 December 1997, the Company Credit Facility was amended to provide for a term loan of $3 million, bearing interest at
the Index Rate. The amount outstanding under the $3 million term loan as of December 31, 1998 was $3 million, which
was repaid in January 1999.
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 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 are 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, 2000,
the outstanding principal balance of the Term Loan was $5,260,000.
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, 1999, and 2000, outstanding revolving credit loans totaled $5,876,000 and $5,426,000, respectively, with
an additional $1,208,392 and $2,900,884, respectively, available for future borrowings. The outstanding amount of the
term loan was $7,000,000 and $5,260,000 at December 31, 1999 and 2000. 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, 1999 and 2000. 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 1999 and 2000 on the Company Credit Facility were 9 and 9 percent, respectively.
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
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33
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, 2000, the amount of Subordinated Notes was increased
by $1,227,325 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 under the related Securities Purchase Agreement, including
but not limited to, (a) maintenance of a specified Tangible Net Worth, (b) maintenance of a ratio of EBITDA (earnings
before interest, taxes depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less
than 1.00 to 1.00, and (c) limit its capital expenditures (as defined) to a specified amount for the year ended December 31,
2000, and thereafter to an amount equal to the Company's EBITDA for the immediately prior fiscal year (unless approved
by the Company's Board of Directors and a CB Capital Investors, L.P. director), as well as limits on the Company's ability
to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv)
declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v)
engage in transactions with affiliates
(vi) make certain repayments and prepayments, including any prepayment of the Company's Term Loan, any subordinated
debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect
certain permanent reductions in revolving credit facilities.
Of the approximately $29,000,000 net proceeds of this financing, $12,060,000 was used to fund the 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 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 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 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 Preferred Stock.
In December 1999, the Company consummated the repurchase of all the outstanding shares of 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.
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, 2000, the
Company had 35 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
32
34
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.
In September 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes
accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments
embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133, as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities --
Deferral of the Effective Date of SFAS No. 133" and SFAS No. 138 "Accounting for Certain Derivative Instruments and
Certain Hedging Activities - an Amendment of SFAS No. 133" is effective for fiscal years beginning after June 15, 2000.
Statement No. 133 amends, modifies and supercedes significantly all of the authoritative literature governing the accounting
for and disclosure of derivative financial instruments and hedging activities. The Company routinely enters into financial
instrument contracts to hedge price risks associated with the sale of crude oil and natural gas. Upon adoption of Statement
No. 133, the Company, on January 1, 2001, recorded a charge amounting to $2.0 million to other comprehensive income
relating to the value of hedge positions outstanding on that date.
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Company's revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or
obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of
oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to
continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively
minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of consumer product demand, weather
conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions
in the Middle East, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It
is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may
materially adversely affect the Company's financial condition, liquidity, and ability to finance planned capital expenditures
and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the
Company can produce economically. Oil and natural gas prices have declined in the recent past and there can be no
assurance that prices will recover or will not decline further. See "Business and Properties -- Marketing".
The Company periodically reviews the carrying value of its oil and natural gas properties under the full cost accounting
rules of the Commission. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the
present value of estimated future net revenues from proved reserves, discounted at 10 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
33
35
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.
In order to reduce its exposure to short-term fluctuations in the price of oil and natural gas, the Company periodically
enters into hedging arrangements. The Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose
the Company to risk of financial loss in certain circumstances, including instances where production is less than expected,
the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event
materially impacts oil or natural gas prices. In addition, the Company's hedging arrangements limit the benefit to the
Company of increases in the price of oil and natural gas. Total natural gas purchased and sold under swap arrangements
during the years ended December 31, 1998, 1999 and 2000 were 0 Bbls, 45,200 Bbls and 87,900 Bbls, respectively,
and 1,760,000 MMBtu, 2,050,000 MMBtu and 1,590,000 MMBtu, respectively. Income and (losses) realized by the
Company under such swap arrangements were $167,000, $(412,000) and ($1,537,000) for the years ended December
31, 1998, 1999 and 2000, respectively. At December 31, 1999, the Company had 300,000 MMBtu and 30,200 Bbls of
outstanding hedge positions (at an average price of $2.23 per MMBtu and $25.60 per Bbl) for January through June
2000. 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.
The Company's Board of Directors sets 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, Chief Financial Officer after consultation and concurrence by the President or 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. See "Business and Properties -- Marketing".
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 $2.7 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 $167,000,
($412,000) and ($1,537,000) or $0.09, ($0.18) and ($0.73) per MMBtu for the years ended December 31, 1998, 1999
and 2000, 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 2000 cash flow by approximately $306,000.
FINANCIAL INSTRUMENTS & DEBT MATURITIES. The Company's financial instruments consist of cash and cash
equivalents, accounts receivable, accounts payable, bank borrowings and Subordinated Notes payable. 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, 2000 and 1999, and were determined based upon interest rates currently available to the
Company for borrowings with similar terms. Maturities of the debt are $6,458,311 in 2001, $5,426,000 in 2002 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.
34
36
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to information under the caption "Proposal 1-Election of
Directors" and to the information under the caption "Section 16(a) Reporting Delinquencies" in the Company's definitive
Proxy Statement (the "2001 Proxy Statement") for its 2001 annual meeting of shareholders. The 2001 Proxy Statement
will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to
December 31, 2000.
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 2001 Proxy Statement, which will be filed
with the Commission not later than 120 days subsequent to December 31, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference to the 2001 Proxy Statement, which will be filed
with the Commission not later than 120 days subsequent to December 31, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference to the 2001 Proxy Statement which will be filed
with the Commission not later than 120 days subsequent to December 31, 2000.
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
+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) and 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).
+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
35
37
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.
+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).
+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 -- Limited Guaranty by Douglas A.P. Hamilton for the benefit
of 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, 1999).
+4.12 -- Notice of Final Agreement with respect to a term loan from
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, 1999).
+4.13 -- Limited Guaranty by Paul B. Loyd, Jr. for the benefit of
Compass Bank (Incorporated herein by reference to Exhibit
4.3 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999).
+4.14 -- Limited Guaranty by Steven A. Webster for the benefit of
Compass Bank (Incorporated herein by reference to Exhibit
4.4 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999).
+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
36
38
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).
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, 2000.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc.
as of December 31, 2000.
+ Incorporated by reference as indicated.
REPORTS ON FORM 8-K
On December 8, 2000 the Company filed a Current Report on Form 8-K to report under Item 5 thereof the settlement of
the Slick Prospect litigation.
37
39
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
CARRIZO OIL & GAS, INC.
By: /s/ FRANK A. WOJTEK
-------------------------------------
Frank A. Wojtek
Chief Financial Officer, Vice President,
Secretary and Treasurer
Date: March 28, 2001.
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.
NAME CAPACITY DATE
------------------------------- ------------------------------- --------------
/s/ S.P. JOHNSON IV President, Chief Executive March 28, 2001
------------------------------- Officer and Director
S.P. Johnson IV (Principal Executive Officer)
/s/ FRANK A. WOJTEK Chief Financial Officer, Vice March 28, 2001
------------------------------- President, Secretary, Treasurer
Frank A. Wojtek and Director (Principal
Financial Officer and Principal
Accounting Officer)
/s/ STEVEN A. WEBSTER Chairman of the Board March 28, 2001
-------------------------------
Steven A. Webster
/s/ CHRISTOPHER C. BEHRENS Director March 28, 2001
-------------------------------
Christopher C. Behrens
/s/ ARNOLD L. CHAVKIN Director March 28, 2001
-------------------------------
Arnold L. Chavkin
/s/ DOUGLAS A.P. HAMILTON Director March 28, 2001
-------------------------------
Douglas A.P. Hamilton
/s/ PAUL B. LOYD, JR. Director March 28, 2001
-------------------------------
Paul B. Loyd, Jr.
/s/ F. GARDNER PARKER Director March 28, 2001
-------------------------------
F. Gardner Parker
38
40
CARRIZO OIL & GAS, INC.
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Carrizo Oil & Gas, Inc. --
Report of Independent Public Accountants F-2
Balance Sheets, December 31, 1999 and 2000 F-3
Statements of Operations for the Years Ended December 31, 1998,
1999 and 2000 F-4
Statements of Shareholders' Equity for the Years Ended December 31,
1998, 1999 and 2000 F-5
Statements of Cash Flows for the Years Ended December 31, 1998,
1999 and 2000 F-6
Notes to Financial Statements F-7
F-1
41
]
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and
Board of Directors of
Carrizo Oil & Gas, Inc.:
We have audited the accompanying balance sheets of Carrizo Oil & Gas, Inc. (a Texas corporation) as of December 31,
1999 and 2000, and the related statements of operations, shareholders' equity and cash flows for each of the three years in
the period ended December 31, 2000. These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based on our 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 financial statements referred to above present fairly, in all material respects, the financial position of the
Company as of December 31, 1999 and 2000, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United
States.
As explained in Note 9 to the financial statements, effective January 1, 1999, the Company changed its method of
accounting for start up costs.
ARTHUR ANDERSEN LLP
Houston, Texas
March 15, 2001
F-2
42
CARRIZO OIL & GAS, INC.
BALANCE SHEETS
ASSETS
As of December 31,
-------------------------------
1999 2000
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents $ 11,345,618 $ 8,217,427
Accounts receivable, net of allowance for doubtful accounts of
$480,000 at December 31, 1999 and 2000, respectively 4,424,283 7,392,621
Advances to operators 1,266,770 1,756,396
Deposits 222,439 629,460
Other current assets 264,959 401,181
------------ ------------
Total current assets 17,524,069 18,397,085
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and gas properties) 64,336,738 72,128,589
INVESTMENT IN MPC -- 1,544,180
DEFERRED INCOME TAXES 820,252 --
OTHER ASSETS 985,315 930,059
------------ ------------
$ 83,666,374 $ 92,999,913
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 4,095,567 $ 3,353,570
Accrued liabilities 481,239 1,775,830
Advances for joint operations 1,066,203 376,190
Current maturities of long-term debt 3,542,742 6,458,310
------------ ------------
Total current liabilities 9,185,751 11,963,900
LONG-TERM DEBT 33,627,265 28,097,490
COMMITMENTS AND CONTINGENCIES (Note 7)
SHAREHOLDERS' EQUITY:
Warrants (3,010,189 outstanding at December 31, 1999 and 2000, respectively) 765,047 765,047
Common stock, par value $.01, (40,000,000 shares authorized with 14,011,364
and 14,055,061 issued and outstanding at December 31, 1999 and 2000,
respectively) 140,114 140,551
Additional paid in capital 62,608,343 62,708,100
Accumulated deficit (22,660,146) (10,675,175)
------------ ------------
40,853,358 52,938,523
------------ ------------
$ 83,666,374 $ 92,999,913
============ ============
The accompanying notes are an integral part of these financial statements.
F-3
43
CARRIZO OIL & GAS, INC.
STATEMENTS OF OPERATIONS
For the Year Ended December 31,
------------------------------------------------
1998 1999 2000
------------ ------------ ------------
OIL AND NATURAL GAS REVENUES $ 7,858,502 $ 10,204,345 $ 26,833,810
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below) 2,769,595 3,035,610 4,940,860
Depreciation, depletion and amortization 3,951,548 4,301,268 7,170,273
Write-down of oil and gas properties 20,305,448 -- --
General and administrative 2,667,234 2,195,364 3,143,283
Stock option compensation -- -- 651,741
------------ ------------ ------------
Total costs and expenses 29,693,825 9,532,242 15,906,157
------------ ------------ ------------
OPERATING INCOME (LOSS) (21,835,323) 672,103 10,927,653
OTHER INCOME AND EXPENSES:
Other income, net of related expenses -- -- 1,482,372
Interest income 293,736 47,494 592,310
Interest expense (300,083) (1,549,205) (3,372,916)
Interest expense, related parties -- (33,454) (203,642)
Capitalized interest 291,496 1,547,879 3,563,555
------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES (21,550,174) 684,817 12,989,332
INCOME TAX EXPENSE (BENEFIT) (2,218,027) (1,057,208) 1,004,361
------------ ------------ ------------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE (19,332,147) 1,742,025 11,984,971
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
NET OF INCOME TAXES -- (77,731) --
------------ ------------ ------------
NET INCOME (LOSS) $(19,332,147) $ 1,664,294 $ 11,984,971
============ ============ ============
DISCOUNT ON REDEMPTION OF PREFERRED STOCK -- 21,868,413 --
DIVIDENDS AND ACCRETION ON PREFERRED STOCK (2,940,625) (2,417,358) --
------------ ------------ ------------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS $(22,272,772) $ 21,115,349 $ 11,984,971
============ ============ ============
BASIC EARNINGS (LOSS) PER COMMON SHARE BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ (2.15) $ 2.01 $ 0.85
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES $ -- $ (0.01) $ --
------------ ------------ ------------
BASIC EARNINGS (LOSS) PER COMMON SHARE $ (2.15) $ 2.00 $ 0.85
============ ============ ============
DILUTED EARNINGS (LOSS) PER COMMON SHARE BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ (2.15) $ 2.01 $ 0.74
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
NET OF INCOME TAXES -- (0.01) --
------------ ------------ ------------
DILUTED EARNINGS (LOSS) PER COMMON SHARE $ (2.15) $ 2.00 $ 0.74
============ ============ ============
The accompanying notes are an integral part of these financial statements.
F-4
44
CARRIZO OIL & GAS, INC.
STATEMENTS OF SHAREHOLDERS' EQUITY
WARRANTS COMMON STOCK
----------------------------- ----------------------------
NUMBER AMOUNT SHARES AMOUNT
------------ ------------ ------------ ------------
BALANCE, January 1,
1998 -- $ -- 10,375,000 $ 103,750
Net loss -- -- -- --
Warrants issued 1,000,000 300,000 -- --
Dividends and accretion
on preferred shares -- -- -- --
Amortization of
deferred compensation -- -- -- --
------------ ------------ ------------ ------------
BALANCE, December 31,
1998 1,000,000 $ 300,000 10,375,000 $ 103,750
Net income -- -- -- --
Warrants issued 2,760,189 690,047 -- --
Warrants cancelled (750,000) (225,000) -- --
Common stock issued -- -- 3,636,364 36,364
Redemption of
preferred stock -- -- -- --
Dividends and accretion on
preferred stock
Amortization of deferred
compensation -- -- -- --
------------ ------------ ------------ ------------
BALANCE, December 31,
1999 3,010,189 $ 765,047 14,011,364 $ 140,114
Net income -- -- -- --
Common stock issued -- -- 43,697 437
------------ ------------ ------------ ------------
BALANCE, December 31,
2000 3,010,189 $ 765,047 14,055,061 $ 140,551
============ ============ ============ ============
ADDITIONAL
PAID IN ACCUMULATED DEFERRED SHAREHOLDERS'
CAPITAL DEFICIT COMPENSATION EQUITY
------------ ------------ ------------ -------------
BALANCE, January 1,
1998 $ 32,845,727 $ 365,690 $ (419,806) $ 32,895,361
Net loss -- (19,332,147) -- (19,332,147)
Warrants issued -- -- -- 300,000
Dividends and accretion
on preferred shares -- (2,940,625) -- (2,940,625)
Amortization of
deferred compensation -- -- 279,896 279,896
------------ ------------ ------------ ------------
BALANCE, December 31,
1998 $ 32,845,727 $(21,907,082) $ (139,910) $ 11,202,485
Net income -- 1,664,294 -- 1,664,294
Warrants issued -- -- -- 690,047
Warrants cancelled 225,000 -- -- --
Common stock issued 7,669,203 -- -- 7,705,567
Redemption of
preferred stock 21,868,413 -- -- 21,868,413
Dividends and accretion on
preferred stock (2,417,358) (2,417,358)
Amortization of deferred
compensation -- -- 139,910 139,910
------------ ------------ ------------ ------------
BALANCE, December 31,
1999 $ 62,608,343 $(22,660,146) $ -- $ 40,853,358
Net income -- 11,984,971 -- 11,984,971
Common stock issued 99,757 -- -- 100,194
------------ ------------ ------------ ------------
BALANCE, December 31,
2000 $ 62,708,100 $(10,675,175) $ -- $ 52,938,523
============ ============ ============ ============
The accompanying notes are an integral part of these financial statements.
F-5
45
CARRIZO OIL & GAS, INC.
STATEMENTS OF CASH FLOWS
For the Year Ended December 31,
----------------------------------------------
1998 1999 2000
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (loss) $(19,332,147) $ 1,664,294 $ 11,984,971
Adjustment to reconcile net income (loss) to net
cash provided by operating activities -
Depreciation, depletion and amortization 3,951,548 4,301,268 7,170,273
Discount accretion -- 3,537 81,853
Interest payable in kind -- 48,822 1,227,325
Stock option compensation -- -- 651,741
Other non-cash income -- -- (1,544,180)
Cumulative effect of change in accounting principle -- 77,731 --
Write-down of oil and gas properties 20,305,448 -- --
Deferred income taxes (2,300,267) (1,085,216) 902,160
Changes in assets and liabilities -
Accounts receivable (591,861) (196,918) (2,968,338)
Other current assets (8,981) (369,784) (625,151)
Other assets (249,175) (746,556) (236,190)
Accounts payable 416,447 26,580 (154,754)
Accrued liabilities 195,788 (1,523,298) 642,850
------------ ------------ ------------
Net cash provided by operating
activities 2,386,800 2,200,460 17,132,560
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - accrual basis (36,569,773) (10,286,305) (19,745,805)
Proceeds for sale of Metro Project -- -- 5,075,127
Adjustment to cash basis (1,233,970) (3,817,547) (587,243)
Advances to operators 625,911 (74,691) (489,626)
Advances for joint operations 387,420 678,783 (690,013)
------------ ------------ ------------
Net cash used in investing activities (36,790,412) (13,499,760) (16,437,560)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of common stock -- 7,705,567 100,194
Net proceeds from sale of preferred stock
and warrants 28,810,431 690,047 --
Net proceeds from debt issuance 12,056,000 31,235,257 --
Debt repayments (7,950,000) (8,173,609) (3,923,385)
Proceeds from related party notes -- 2,000,000 --
Redemption of preferred stock -- (12,000,000) --
------------ ------------ ------------
Net cash provided by (used in) financing
activities 32,916,431 21,457,262 (3,823,191)
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (1,487,181) 10,157,962 (3,128,191)
CASH AND CASH EQUIVALENTS, beginning of year 2,674,837 1,187,656 11,345,618
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, end of year $ 1,187,656 $ 11,345,618 $ 8,217,427
============ ============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ 8,587 $ 31,243 $ --
============ ============ ============
The accompanying notes are an integral part of these financial statements.
F-6
46
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS, COMBINATION AND OFFERING
NATURE OF OPERATIONS
Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its affiliates and predecessors, the Company) is an
independent energy company engaged in the exploration, development, exploitation and production of oil and natural gas.
Its operations are focused on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and Vicksburg trends.
The Company has acquired 2,115 square miles of 3-D seismic data as of December 31, 2000. Additionally, the Company
has assembled approximately 157,575 gross acres under lease or option as of December 31, 2000.
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.
THE COMBINATION
Carrizo was formed in 1993 and is the surviving entity after a series of combination transactions (the Combination)
consummated on August 11, 1997. The Combination included the following transactions: (a) Carrizo Production, Inc. (a
Texas corporation and an affiliated entity with ownership identical to Carrizo) was merged into Carrizo and the outstanding
shares of capital stock of Carrizo Production, Inc. were exchanged for an aggregate of 343,000 shares of Common Stock
of Carrizo (the Common Stock); (b) Carrizo acquired Encinitas Partners Ltd. (a Texas limited partnership of which
Carrizo Production, Inc. served as the general partner) as follows: Carrizo acquired from the shareholders who serve as
directors of Carrizo (the Founders) their limited partner interests in Encinitas Partners Ltd. for an aggregate consideration
of 468,533 shares of Common Stock and, on the same date, Encinitas Partners Ltd. was merged into Carrizo and the
outstanding limited partner interests in Encinitas Partners Ltd. were exchanged for an aggregate of 860,699 shares of
Common Stock; (c) La Rosa Partners Ltd. (a Texas limited partnership of which Carrizo served as the general partner)
was merged into Carrizo and the outstanding limited partner interests in La Rosa Partners Ltd. were exchanged for an
aggregate of 48,700 shares of Common Stock; and (d) Carrizo Partners Ltd. (a Texas limited partnership of which
Carrizo served as the general partner) was merged into Carrizo and the outstanding limited partner interests in Carrizo
Partners Ltd. were exchanged for an aggregate of 569,068 shares of Common Stock.
The Combination was accounted for as a reorganization of entities as prescribed by Securities and Exchange Commission
(SEC) Staff Accounting Bulletin 47 because of the high degree of common ownership among, and the common control of,
the combining entities. Accordingly, the accompanying financial statements were prepared using the historical costs and
results of operations of the affiliated entities up to the date of the Combination. There were no significant differences in
accounting methods or their application among the combining entities. All intercompany balances have been eliminated.
Certain reclassifications have been made to prior period amounts to conform to the current period's financial statement
presentation.
INITIAL PUBLIC OFFERING
Simultaneous with the Combination, the Company completed its initial public offering (the Offering) of 2,875,000 shares of
its Common Stock at a public offering price of $11.00 per share. The Offering provided the Company with proceeds of
approximately $28.1 million, net of expenses.
MANDATORILY REDEEMABLE PREFERRED STOCK
In January 1998, the Company consummated the sale of 300,000 shares of 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
F-7
47
primarily for oil and natural gas exploration and development activities in Texas and Louisiana. The 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 Preferred Stock. During 1999, the Company issued preferred stock
dividends to the holders of the Preferred Stock of 29,684.39 shares.
In December 1999, the Company consummated the repurchase of all the outstanding shares of 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 preferred stock of $2,417,358.
SALE OF SENIOR SUBORDINATED NOTES, COMMON STOCK AND WARRANTS
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. 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.
Of the approximately $29,000,000 net proceeds of this financing, $12,060,000 was used to fund the Enron Repurchase
described above and related expenses, $2,025,000 was used to repay the bridge loan extended to the Company by its
outside directors, $2,000,000 was used to repay a portion of the Compass Term Loan, $1,000,000 was used to repay a
portion of the Compass Borrowing Base Facility, and the Company used the remaining proceeds to fund the Company's
ongoing exploration and development program and general corporate purposes.
In December 1999, the Company consummated the repurchase of all the outstanding shares of 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.
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 1998, 1999 and 2000, the Company also capitalized as oil and
natural gas properties $279,896, $139,910 and none, respectively of deferred compensation related to stock options
granted to personnel directly associated with exploration activities. Additionally, the Company capitalized compensation
cost for employees working directly on exploration activities of $623,000, $581,000 and $886,000 in 1998, 1999 and
2000, 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 quarterly 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 1998, 1999 and 2000, was
$1.06, $1.00, and $1.03 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 cash flows from proved reserves, based on
current economic and
F-8
48
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 or 2000.
Primarily as a result of downward reserve quantity revisions combined with depressed oil and natural gas prices, the
Company recorded a ceiling test write-down of $20,305,448 in 1998.
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 $985,315 and $930,059 as of December 31, 1999 and 2000,
respectively, are being amortized over the term of the loans (through January 1, 2002 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.
HEDGING ACTIVITIES
The Company periodically enters into hedging arrangements to manage price risks related to oil and natural gas sales and
not for speculative purposes. The Company's hedging arrangements apply only to a portion of its production, provide only
partial price protection against declines in oil and natural gas prices and limit potential gains from future increases in prices.
For financial reporting purposes, gains and losses related to hedging are recognized as income with the hedged item when
the hedged transaction occurs. Should the necessary correlation between the hedged item and the designated hedging
instrument be lost, the future gain or loss would no longer be deferred and would be recognized in the period the
correlation is lost. Total oil and natural gas quantities sold under swap arrangements in 1998, 1999, and 2000 were 0 Bbls
of oil ("Bbls"), 45,200 Bbls and 87,900 Bbls, respectively, and 1,760,000 MMBtu of natural gas ("MMBtu"), 2,050,000
MMBtu, and 1,590,000 MMBtu, respectively. Hedging gains (losses) are included in oil and natural gas revenues and
amounted to $167,000, ($412,000) and ($1,537,000) for the years ended December 31, 1998, 1999 and 2000,
respectively. At December 31, 1999, the Company had 300,000 MMBtu and 30,200 Bbls of outstanding hedge positions
(at an average price of $2.33 per MMBtu and $25.60 per Bbl for January through June 2000 production.) The
instruments had a fair market value of $2,000 at December 31, 1999. 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. The instruments had a fair market value of ($3,025,000)
at December 31, 2000. The Company's Board of Directors sets 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.
F-9
49
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-10
50
EARNINGS PER SHARE
Supplemental earnings per share information is provided below:
FOR THE YEAR ENDED DECEMBER 31
-----------------------------------------------------------------------------------------
INCOME (LOSS) SHARES
-------------------------------------------- ------------------------------------------
1998 1999 2000 1998 1999 2000
------------ ------------ ------------ ------------ ------------ ------------
Net income (loss) before
cumulative effect of change
in accounting principle $(19,332,147) $ 1,742,025 $ 11,984,971
Plus: Discount on redemption
of preferred stock -- 21,868,413 --
Less: Dividends and
accretion on preferred stock (2,940,625) (2,417,358) --
------------ ------------ ------------
Basic earnings per share
before cumulative effect of
change in accounting principle
Net income (loss) available
to common shareholders (22,272,772) 21,193,080 11,984,971 10,375,000 10,544,365 14,028,176
Stock options and warrants -- -- -- -- 1,886 2,227,479
------------ ------------ ------------ ------------ ------------ ------------
Diluted earnings per share
before cumulative effect of
change in accounting principle
Net income (loss) available
to common shareholders
plus assumed conversions $(22,272,772) $ 21,193,080 $ 11,984,971 10,375,000 10,546,251 16,255,655
============ ============ ============ ============ ============ ============
Cumulative effect of change
in accounting principle $ -- $ (77,731) $ --
Basic earnings per share of
cumulative effect of change
in accounting principle
Net loss available to
common shareholders -- (77,731) -- 10,375,000 10,544,365 14,028,176
Stock options and warrants -- -- -- -- 1,886 2,227,479
------------ ------------ ------------ ------------ ------------ ------------
Diluted earnings per share of
cumulative effect of change
in accounting principle
Net loss available to
common shareholders
plus assumed conversions $ -- $ (77,731) $ -- 10,375,000 10,546,251 16,255,655
============ ============ ============ ============ ============ ============
Net income (loss) $(19,332,147) $ 1,664,294 $ 11,984,971
Plus: Discount on redemption
of preferred stock -- 21,868,413 --
Less: Dividends and accretion
on preferred stock (2,940,625) (2,417,358) --
------------ ------------ ------------
Basic earnings per share
Net income (loss) available to
common shareholders (22,272,772) 21,115,349 11,984,971 10,375,000 10,544,365 14,028,176
Stock options and warrants -- -- -- -- 1,886 2,227,479
------------ ------------ ------------ ------------ ------------ ------------
Diluted earnings per share
Net income (loss) available to
common shareholders plus
assumed conversions $(22,272,772) $ 21,115,349 $ 11,984,971 10,375,000 10,546,251 16,255,655
============ ============ ============ ============ ============ ============
FOR THE YEAR ENDED DECEMBER 31
--------------------------------------------
PER-SHARE AMOUNT
--------------------------------------------
1998 1999 2000
------------ ------------ ------------
Net income (loss) before
cumulative effect of change
in accounting principle
Plus: Discount on redemption
of preferred stock
Less: Dividends and
accretion on preferred stock
Basic earnings per share
before cumulative effect of
change in accounting principle
Net Income (loss) available
to common shareholders $ (2.15) $ 2.01 $ 0.85
============ ============ ============
Stock options and warrants
Diluted earnings per share
before cumulative effect of
change in accounting principle
Net Income (loss) available
to common shareholders
plus assumed conversions $ (2.15) $ 2.01 $ 0.74
============ ============ ============
Cumulative effect of change
in accounting principle
Basic earnings per share of
cumulative effect of change
in accounting principle
Net loss available to
common shareholders $ -- $ (0.01) $ --
============ ============ ============
Stock options and warrants
Diluted earnings per share of
cumulative effect of change
in accounting principle
Net loss available to
common shareholders
plus assumed conversions $ -- $ (0.01) $ --
============ ============ ============
Net income (loss)
Plus: Discount on redemption
of preferred stock
Less: Dividends and accretion
on preferred stock
Basic earnings per share
Net income (loss) available to
common shareholders $ (2.15) $ 2.00 $ 0.85
============ ============ ============
Stock options and warrants
Diluted earnings per share
Net income (loss) available to
common shareholders plus
assumed conversions $ (2.15) $ 2.00 $ 0.74
============ ============ ============
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 443,550, 799,620 and 149,000 stock options at December 31, 1998, 1999 and 2000, respectively that were
antidilutive. The Company also had outstanding 1,000,000 and 3,010,189 warrants at December 31, 1998 and 1999,
respectively 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.
CONTINGENCIES
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it
is
F-11
51
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
In September 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes
accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments
embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133, as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities --
Deferral of the Effective Date of SFAS No. 133" and SFAS No. 138 "Accounting for Certain Derivative Instruments and
Certain Hedging Activities - an Amendment of SFAS No. 133" is effective for fiscal years beginning after June 15, 2000.
Statement No. 133 amends, modifies and supercedes significantly all of the authoritative literature governing the accounting
for and disclosure of derivative financial instruments and hedging activities. The Company routinely enters into financial
instrument contracts to hedge price risks associated with the sale of oil and natural gas. Upon adoption of Statement No.
133, the Company, on January 1, 2001, recorded a charge amounting to $2.0 million to other comprehensive income
relating to the value of hedge positions outstanding on that date.
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 percent of the outstanding common shares of
MPC, which is accounted for as a cost basis investment. Steven A. Webster, who is the Chairman of the Board of the
Company, is also a Managing Director of Global Energy Partners Ltd., a merchant banking affiliate of DLJ which makes
investments in energy companies, and joined the Board of Directors of MPC in connection with the transaction.
4. PROPERTY AND EQUIPMENT
At December 31, 1999 and 2000, property and equipment consisted of the following:
DECEMBER 31,
--------------------------------
1999 2000
------------- -------------
Proved oil and natural gas properties $ 57,719,508 $ 73,427,767
Unproved oil and natural gas properties 38,145,486 36,994,563
Other equipment 308,402 343,723
------------- -------------
Total property and equipment 96,173,396 110,766,053
Accumulated depreciation, depletion and amortization (31,836,658) (38,637,464)
------------- -------------
Property and equipment, net $ 64,336,738 $ 72,128,589
============= =============
Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds, undesignated
seismic costs, 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 $36,994,563 of unproved property costs at December
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52
31, 2000 being excluded from the amortizable base, $16,995,636, $4,238,828 and $5,899,657 were incurred in 1998,
1999 and 2000, respectively. The Company expects it will complete its evaluation of the properties representing the
majority of these costs within the next two 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:
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1999 2000
----------- ----------- -----------
Provision at the statutory tax rate $(7,624,801) $ 212,480 $ 4,546,265
State taxes 82,240 28,008 102,201
Increase (decrease) in valuation allowance pertaining
to expected net operating loss utilization 5,324,534 (1,297,696) (3,644,105)
----------- ----------- -----------
Income tax provision (benefit) $(2,218,027) $(1,057,208) $ 1,004,361
=========== =========== ===========
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, 1999 and 2000, the tax effects of these temporary differences
resulted principally from the following:
AS OF DECEMBER 31,
----------------------------
1999 2000
----------- -----------
Deferred income tax assets:
Oil and gas property basis
differentials $ 4,717,765 $ 4,223,724
Net operating loss carryforward 4,941,894 3,613,677
Valuation allowance (3,644,105) --
----------- -----------
6,015,554 7,837,401
Deferred income tax liabilities:
Intangible drilling costs 3,616,437 4,509,771
Capitalized interest 784,894 1,625,710
Depletion 529,007 1,518,864
----------- -----------
4,930,338 7,654,345
----------- -----------
Net deferred income tax asset $ 1,085,216 $ 183,056
=========== ===========
The net deferred income tax asset is classified as follows:
AS OF DECEMBER 31,
-------------------------
1999 2000
---------- ----------
Other current assets $ 264,964 $ 183,056
Deferred income taxes 820,252 --
---------- ----------
$1,085,216 $ 183,056
========== ==========
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 $10.3 million which begin expiring in 2012.
6. LONG-TERM DEBT
At December 31, 1999 and 2000, long-term debt consisted of the following:
F-13
53
AS OF DECEMBER 31,
------------------------------
1999 2000
------------ ------------
Credit facility:
Borrowing base facility $ 5,876,000 $ 5,426,000
Term loan facility 7,000,000 5,260,000
Senior subordinated notes 19,226,082 20,462,797
Senior subordinated notes, related parties 2,136,230 2,208,693
Vendor notes payable 2,931,695 1,198,310
------------ ------------
37,170,007 34,555,800
Less: current maturities (3,542,742) (6,458,310)
------------ ------------
$ 33,627,265 $ 28,097,490
============ ============
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, 1999 and 2000, amounts outstanding under the Borrowing Base Facility totaled $5,876,000 and
$5,426,000, respectively, with an additional $1,208,392 and $2,676,884, respectively, available for future borrowings.
The Borrowing Base totaled $8,326,884 at December 31, 2000. The Borrowing Base Facility was also available for
letters of credit, one of which has been issued for $224,000 at December 31, 1999 and 2000. 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 rate for 1999 and
2000 on the Facility was 9 percent. Certain members of the Board of Directors have provided $3.3 million in collateral
primarily in the form of marketable securities to secure the Borrowing Base Facility.
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 have guaranteed the Term Loan. At December 31, 2000, $5,260,000 was outstanding under the
Term Loan.
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.
In November 1999, certain members of the Board of Directors provided a bridge loan in the amount of $2,000,000 to the
Company
F-14
54
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 percent Senior Subordinated
Notes due 2007 (the "Subordinated Notes") to an investor group led by CB Capital Investors, L.P. (now known as J.P.
Morgan Partners, LLC) which included certain members of the Board of Directors. As discussed in Note 8, 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 year ended December 31, 2000, the amount of the Subordinated Notes was
increased by $1,227,325 for such interest. Such Senior Subordinated Notes had a fair market value at December 31,
2000 of approximately $23 million.
The Company is subject to certain covenants under the terms under the Subordinated Notes securities purchase
agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes,
depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures (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 $6,458,310 in 2001, $5,426,000 in 2002 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 $2,931,695 and $1,198,310 at December 31, 1999 and 2000, respectively, and bear
interest at rates of 8 percent to 10 percent. The weighted average interest rates of such notes was 9 percent in 1999 and
2000, respectively.
7. 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 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
F-15
55
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 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 considered 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 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. The court also granted the 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. As of March 1, 2001, the court has not yet announced a ruling.
While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have
a materially adverse effect in the financial position or results of operations of 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, which is expected to
commence in late December 2000, provides for a dayrate of $12,000 per day. The rig is expected to be utilized primarily
to drill wells in the Company's focus areas, including the Matagorda Project Area and the Cabeza Creek Project Area.
The contract contains 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.
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.
At December 31, 2000, the Company was obligated under a noncancelable operating lease for office space. Rent expense
for the years ended December 31, 1998, 1999 and 2000 was $108,700, $108,700 and $207,000, respectively. The
Company is obligated for remaining lease payments of $225,000 per year through December 31, 2004.
8. 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.
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.
F-16
56
On July 19, 1996, and March 1, 1997, the Company entered into separate stock option agreements (the "Pre-IPO
Options") with two executives of Carrizo whereby such employees were granted the option to purchase 138,825 shares
and 83,295 shares of Carrizo Common Stock, respectively, at an exercise price of $3.60 per share. The options vested
ratably through August 1, 1998, and March 1, 1999, respectively. The Company did not record any compensation
expense related to the July, 1996 options because the related exercise price was at or above the estimated fair value of
Carrizo's Common Stock at the time such options were granted.
The following table summarizes information for the options outstanding at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------ ------------------------
Weighted
Number of Average Weighted Number of Weighted
Options Remaining Average Options Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices at 12/31/00 Life in Years Price at 12/31/00 Price
---------------------------- ----------- ------------- -------- ----------- --------
$1.75-2.25 732,803 9.03 $ 2.19 22,136 $ 1.90
$3.14-3.60 312,120 6.91 $ 3.54 219,120 $ 3.60
$5.17-8.00 161,500 8.81 $ 6.97 46,000 $ 6.44
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, 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:
1998 1999 2000
------------ ------------ ------------
Net income (loss) available
to common shareholders
As reported $(22,272,772) $ 21,115,349 $ 11,984,971
Pro forma $(23,020,534) $ 20,292,252 $ 11,487,013
Diluted earnings (loss) per share
As reported $ (2.15) $ 2.00 $ 0.74
Pro forma $ (2.22) $ 1.94 $ 0.71
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 1998, 1999 and 2000: risk free interest rate of 5.81 percent, 6.81 percent and
6.66 percent respectively, expected dividend yield of 0 percent, expected life of 10 years and expected volatility of 80.6
percent, 70.0 percent and 70.8 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 1,206,423 shares through December 31, 2000. Through December 31, 2000, 43,697 stock
options had been exercised. A summary of the status of the Company's stock options at December 31, 1998, 1999 and
2000 is presented in the table below:
F-17
57
1998
---------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
-------- -------- -----------
Outstanding at beginning of year 472,120 $ 7.52 $3.60-11.00
Granted (Incentive Plan Options) 193,500 $ 6.20 $ 6.00-6.88
-------- --------
Outstanding at end of year 665,620 $ 6.63 $3.60-11.00
======== ========
Exercisable at end of year 277,688 $ 5.80
======== ========
Weighted average of fair value of
options granted during the year $ 3.00
========
1999
--------------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year 665,620 $ 6.63 $3.60 - 11.00
Granted (Incentive Plan Options) 206,500 $ 1.98 $ 1.75 - 2.00
Expired (Incentive Plan Options) (45,000) $ 4.06 $ 2.00 - 6.88
---------- --------
Outstanding at end of year 827,120 $ 6.01 $1.75 - 11.00
========== ========
Exercisable at end of year 446,286 $ 6.70
========== ========
Weighted average of fair value of
options granted during the year $ 1.34
==========
2000
--------------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year 827,120 $ 6.01 $1.75 - 11.00
Granted (Incentive Plan Options) 425,000 $ 3.85 $ 2.20 - 8.00
Exercised (Pre-IPO Options) (3,000) $ 3.60 3.60
Exercised (Incentive Plan Options) (40,697) $ 2.20 $ 2.00 - 6.00
Expired (Incentive Plan Options) (2,000) $ 3.50 $ 3.50
---------- --------
Outstanding at end of year 1,206,423 $ 5.20 $2.00 - 11.00
========== ========
Exercisable at end of year 474,625 $ 3.79
========== ========
Weighted average of fair value of
options granted during the year $ 2.94
==========
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 options 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 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
F-18
58
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 option either are exercised or expire. Stock option compensation
expense relating to the repriced options for the year ended December 31, 2000 amounted to $651,741.
9. 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.
10. BUSINESS COMBINATION
During the fourth quarter of 1998, Carrizo acquired from Hall Houston Oil Company, Hall Houston 1996 Exploration and
Development Facility Overriding Trust and Hall Houston Oil Company Employee Royalty Trust (referred to collectively as
"Hall Houston") certain proved oil and gas properties located in Wharton County, Texas (the Hall Houston Properties
Acquisition) for approximately $3 million.
The Hall Houston Properties Acquisition was accounted for under the purchase method of accounting and, accordingly,
the purchase cost was recorded as evaluated oil and gas properties. The results of operations of the acquired Hall Houston
properties are included in the results of operations beginning on the date acquired. The following table reflects certain
unaudited pro forma information for the periods presented as if the Hall Houston Properties Acquisition had occurred on
January 1, 1998.
YEAR ENDED
DECEMBER 31,
1998
--------------
Pro forma revenues $ 9,198,212
==============
Pro forma net income (loss) $ (18,523,141)
==============
Pro forma net income (loss) per share:
Basic $ (2.07)
==============
Diluted $ (2.07)
==============
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.
12. 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."
COSTS INCURRED
Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
F-19
59
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1999 2000
----------- ----------- -----------
Property acquisition costs
Unproved $ 9,618,647 $ 4,166,033 $ 6,641,275
Proved 16,196,887 472,229 336,750
Exploration cost 10,429,247 3,163,309 7,843,425
Development costs 313,391 936,855 1,360,800
----------- ----------- -----------
Total costs incurred (1) $36,558,172 $ 8,738,426 $16,182,250
=========== =========== ===========
(1) Excludes capitalized interest on unproved properties of $291,496, $1,547,879 and $3,563,555 for the years ended
December 31, 1998, 1999 and 2000, 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, 1999 and 2000, 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:
BARRELS OF
OIL AND CONDENSATE
AT DECEMBER 31,
--------------------------------------------
1998 1999 2000
---------- ---------- ----------
Proved developed and undeveloped reserves -
Beginning of year 5,169,500 3,647,000 4,877,000
Purchase of oil and gas properties 81,000 -- --
Discoveries and extensions 96,000 113,000 93,000
Revisions (1,559,500) 1,296,000 1,625,000
Production (140,000) (179,000) (198,000)
---------- ---------- ----------
End of year 3,647,000 4,877,000 6,397,000
========== ========== ==========
Proved developed reserves at end of year 1,112,000 1,070,000 1,017,000
========== ========== ==========
F-20
60
THOUSANDS OF CUBIC FEET
OF NATURAL GAS
AT DECEMBER 31,
-----------------------------------------------
1998 1999 2000
----------- ----------- -----------
Proved developed and undeveloped reserves -
Beginning of year 12,142,000 10,155,000 11,323,000
Purchases of oil and gas properties 1,325,000 -- --
Discoveries and extensions 4,039,000 4,820,000 4,179,000
Revisions (4,696,000) (417,000) 1,553,000
Sales of oil and gas properties -- -- (603,000)
Production (2,655,000) (3,235,000) (5,460,000)
----------- ----------- -----------
End of year 10,155,000 11,323,000 10,992,000
=========== =========== ===========
Proved developed reserves at end of year- 9,097,000 10,680,000 10,351,000
=========== =========== ===========
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:
YEAR ENDED DECEMBER 31,
------------------------------------------------
1998 1999 2000
------------ ------------ ------------
Future cash inflows $ 59,095,000 $140,851,000 $266,725,000
Future oil and natural gas operating expenses 28,582,000 46,679,000 126,526,000
Future development costs 4,841,000 12,428,000 14,284,000
Future income tax expenses -- 11,952,000 25,242,000
------------ ------------ ------------
Future net cash flows 25,672,000 69,792,000 100,673,000
10% annual discount for estimating timing of cash flows 6,917,000 27,062,000 30,567,000
------------ ------------ ------------
Standard measure of discounted future net cash flows $ 18,755,000 $ 42,730,000 $ 70,106,000
============ ============ ============
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 1998, 1999 and 2000 future cash flows were $10.15,
$23.40 and $24.85 for oil, respectively and $2.18, $2.35 and $10.34 for natural gas, respectively. As of March 19, 2001
the price of natural gas had fallen to $5.23 per Mcf. 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
61
--------------------------------------------------
1998 1999 2000
------------ ------------ ------------
Changes due to current-year operations -
Sales of oil and natural gas, net of oil
and natural gas operating expenses $ (5,089,000) $ (7,169,000) $(21,893,000)
Extensions and discoveries 5,003,000 9,095,000 26,214,000
Purchases of oil and gas properties 2,889,000 -- --
Changes due to revisions in standardized variables
Prices and operating expenses (5,820,000) 32,560,000 16,686,000
Income taxes 5,098,000 (8,447,000) (14,090,000)
Estimated future development costs 6,757,000 (4,581,000) (1,122,000)
Revision of quantities (9,056,000) 11,770,000 2,921,000
Sales of reserves in place -- -- (254,000)
Accretion of discount 2,607,000 1,876,000 4,736,000
Production rates, timing and other (4,607,000) (11,129,000) 14,178,000
------------ ------------ ------------
Net change (2,218,000) 23,975,000 27,376,000
Beginning of year 20,973,000 18,755,000 42,730,000
------------ ------------ ------------
End of year $ 18,755,000 $ 42,730,000 $ 70,106,000
============ ============ ============
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, extensions 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
62
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
2000 FIRST SECOND THIRD FOURTH
----------- ----------- ----------- -----------
Revenues 4,279,597 5,826,737 8,007,583 8,719,893
Costs and expenses, net $ 3,151,082 $ 3,363,276 $ 3,113,126 $ 5,221,355
----------- ----------- ----------- -----------
Net income 1,128,515 2,463,461 4,894,457 3,498,538
=========== =========== =========== ===========
Diluted net income per share (1) $ 0.08 $ 0.15 $ 0.29 $ 0.20
=========== =========== =========== ===========
1999 FIRST SECOND THIRD FOURTH
----------- ----------- ----------- -----------
Revenues $ 1,842,314 $ 1,925,265 $ 2,537,960 $ 3,898,806
Costs and expenses, net 2,472,668 2,105,581 2,212,791 1,749,011
----------- ----------- ----------- -----------
Net income (loss) (630,354) (180,316) 325,169 2,149,795
=========== =========== =========== ===========
Discount on redemption -- -- -- 21,868,413
Dividends and accretion (788,843) (806,736) (822,553) 774
----------- ----------- ----------- -----------
Net income (loss) available to
common shareholders $(1,419,197) $ (987,052) $ (497,384) $24,018,982
=========== =========== =========== ===========
Diluted net income (loss) per share (1) $ (0.14) $ (0.10) $ (0.05) $ 2.17
=========== =========== =========== ===========
(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
63
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) and 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).
+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.
+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).
+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 -- Limited Guaranty by Douglas A.P. Hamilton for the benefit
of 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, 1999).
+4.12 -- Notice of Final Agreement with respect to a term loan from
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, 1999).
+4.13 -- Limited Guaranty by Paul B. Loyd, Jr. for the benefit of
Compass Bank (Incorporated herein by reference to Exhibit
4.3 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999).
+4.14 -- Limited Guaranty by Steven A. Webster for the benefit of
Compass Bank (Incorporated herein by reference to Exhibit
4.4 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999).
+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
F-24
64
EXHIBIT
NUMBER DESCRIPTION
------ -----------
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).
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, 2000.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc.
as of December 31, 2000.
+ Incorporated by reference as indicated.
F-25
1
EXHIBIT 4.8
EIGHTH AMENDMENT
TO
FIRST AMENDED, RESTATED, AND COMBINED LOAN AGREEMENT
DATED AUGUST 28, 1997
BY AND BETWEEN CARRIZO OIL & GAS, INC.
AND COMPASS BANK
This Eighth Amendment to the Loan Agreement (this "Eighth Amendment") by and between CARRIZO OIL & GAS,
INC., a Texas corporation (the "Borrower"), and COMPASS BANK, an Alabama state chartered bank, formerly a
Texas chartered bank (the "Bank"), is entered into on this 11th day of November 1999, and shall be effective as of that
date for all purposes.
WITNESSETH:
Borrower and Bank entered into a First Amended, Restated, and Combined Loan Agreement dated August 28, 1997, as
amended by the First Amendment thereto dated December 23, 1997, the Second Amendment thereto dated December
30, 1997, the Third Amendment thereto dated July 30, 1998, the Fourth Amendment thereto dated September 24, 1998,
the Fifth Amendment thereto dated March 22, 1999, the Sixth Amendment thereto dated April 23, 1999 and the Seventh
Amendment thereto dated August 27, 1999 (collectively, the "Loan Agreement"). Capitalized terms used, but not defined
herein, shall have the meanings prescribed therefor in the Loan Agreement.
Borrower has requested that the Loan Agreement be further amended and that the Bank consent to Borrower entering into
a certain subordinated loan transaction otherwise disallowed under certain covenants in the Loan Agreement, and the Bank
has agreed to such requests, subject to the terms and conditions set forth in this Eighth Amendment.
NOW, THEREFORE, in consideration of the mutual promises herein contained, and for other good and valuable
consideration, the receipt and sufficiency of which are acknowledged by Borrower and Bank, and each intending to be
legally bound hereby, the parties agree as follows:
I. Specific Amendments to Loan Agreement.
Article I, Definitions, is hereby amended by adding the following definitions thereto:
"Directors" means, individually and collectively, Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton.
"Directors' Overriding Royalty Interests" means certain overriding royalty interests to be granted by Borrower to the
Directors pursuant to an Assignment of Overriding Royalty Interest in the form of Exhibit "C" attached to the Subordinated
Loan Agreement, to the extent of such interests as described on Exhibit "D" attached to the Eighth Amendment.
1
2
"Eighth Amendment" means the Eighth Amendment to this Agreement executed by Borrower and Bank on November 11,
1999.
"Subordination Agreement" means the Subordination Agreement between the Bank, Borrower and the Directors dated
November 11, 1999 in the form of Exhibit "B" attached to the Eighth Amendment.
"Subordinated Lien Documents" means the (i) Deed of Trust, Assignment of Production, Security Agreement and
Financing Statement,
(ii) the Mortgage, Collateral Assignment, Security Agreement and Financing Statement, and (iii) the UCC-Financing
Statements, all such documents dated November 11, 1999 and evidencing the subordinated liens and security interest
granted by Borrower to the Directors pursuant to the Subordinated Loan Agreement.
"Subordinated Loan Agreement" means that certain letter loan agreement between Borrower and the Directors dated
November 11, 1999 in the form attached as Exhibit "C" to the Eighth Amendment.
"Subordinated Promissory Note" means that certain promissory note dated November 11, 1999 executed by Borrower
payable to Douglas A.P. Hamilton, as collateral agent for each of the Directors, in the form attached as Exhibit "A" to the
Subordinated Loan Agreement.
Article I, Definitions, is hereby amended by revising the definition of "Loan Documents" by adding the clause "including the
Subordination Agreement" immediately after the word "Agreement" on the fourth line of that definition.
Article III, Conditions, is hereby amended by adding the following
Section 3.22.
3.22 Conditions Precedent in Connection with the Eighth Amendment. The Eighth Amendment shall not be binding on the
Bank until satisfaction of the following conditions precedent:
(a) Receipt of Eighth Amendment and Compliance Certificate. Bank shall have received multiple fully executed
counterparts of the Eighth Amendment, as requested by Bank, and the Compliance Certificate duly executed by an
authorized officer for Borrower.
(b) Additional Loan Documents. Bank shall have received multiple fully executed counterparts of the Subordination
Agreement and certain other Security Instruments, including (i) a Deed of Trust, Security Agreement, Financing Statement
and Assignment of Production, (ii) a First Amendment to Deed of Trust, Security Agreement, Financing Statement and
Assignment of Production, (iii) a Second Amendment to Security Agreement, (iv) UCC - Financing Statements, and (v)
any other Security Instruments reasonably requested by Bank, all in form and substance satisfactory to Bank, to evidence
the security interests in the additional Borrowing Base Oil and Gas Properties described on
2
3
Exhibit A to the Eighth Amendment, which are added to the Borrowing Base Properties pursuant to the Eighth
Amendment.
(c) Accuracy of Representations and Warranties and No Event of Default. The representations and warranties contained in
Article IV of the Loan Agreement shall be true and correct in all material respects on the date of the Eighth Amendment
with the same effect as though such representations and warranties had been made on such date; and no Event of Default
shall have occurred and be continuing or will have occurred upon the execution of the Eighth Amendment.
(d) Legal Matters Satisfactory to Special Counsel to Bank. All legal matters incident to the consummation of the
transactions contemplated by the Eighth Amendment shall be satisfactory to the firm of Porter & Hedges, L.L.P., special
counsel for Bank.
(e) Legal Fees. All legal fees and expenses owed by Bank to Porter & Hedges, L.L.P. in connection with the Loan
Agreement shall have been paid by Borrower. Such unpaid fees and expenses for which invoices have been sent to
Borrower through October 1999 total $10,509.32. In addition, Borrower shall have paid the legal fees and expenses
incurred by Bank to such counsel in connection with the Eighth Amendment through October 1999 in the amount of
$5,150.00 for which an invoice will be delivered to Borrower upon its signing of the Eighth Amendment.
(f) No Material Adverse Change. No material adverse change shall have occurred since the date of this Agreement in the
condition, financial or otherwise, of Borrower.
Article V, Affirmative Covenants, is hereby amended by adding the following new Section 5.37:
5.37 Unsatisfied Title Issues. Prior to January 15, 2000, Borrower shall cure or shall cause to be cured all unsatisfied title
issues relating to the additional Borrowing Base Oil and Gas Properties added to the Borrowing Base pursuant to the
Eighth Amendment as described on those certain letters dated October 21, 1999 and October 22, 1999 from Bank's
counsel, Porter & Hedges, L.L.P., to Borrower.
Section 6.01, Other Indebtedness, as amended by the Seventh Amendment, is hereby further amended by deleting the
word "and" immediately preceding clause (e) and adding the following clause (f) at the end of that Section:
and (f) the Indebtedness evidenced by the Subordinated Promissory Note dated November 11, 1999 executed by
Borrower and payable the order of Douglas A.P. Hamilton as collateral agent for each of the Directors evidencing the
obligations of Borrower pursuant to the Subordinated Loan Agreement.
3
4
Schedule 1.01(a) of the Loan Agreement, as previously amended and/or supplemented, is hereby amended by adding
thereto the Borrowing Base Oil and Gas Properties described on Exhibit "A" attached to this Eighth Amendment.
4
5
II Certain Consents. Bank consents to Borrower:
A. Entering into the Subordinated Loan Agreement and executing the Subordinated Promissory Note evidencing
Borrower's obligations to the Directors pursuant to the Subordinated Loan Agreement, the terms of such notes thereby
limited and restricted by the Subordination Agreement;
B. Granting certain subordinated liens in the Borrowing Base Oil and Gas Properties pursuant to the Subordinated Lien
Documents in favor of the Directors to the extent provided for in the Subordinated Loan Agreement, the terms of such lien
documents thereby limited and restricted by the Subordination Agreement; and
C. Granting of the Directors' Overriding Royalty Interests in certain of the Borrowing Base Oil and Gas Properties to the
extent provided for in the Subordinated Loan Agreement, provided that any such overriding royalty interests shall be
limited to the interests and the wells described on Exhibit "D" attached to this Eighth Amendment, calculated as set forth in
Subordinated Loan Agreement.
III Certain Waivers. Bank hereby waives compliance with the negative covenants of the Loan Agreement, including the
provisions of Section 6.01, 6.04 and 6.06 of the Loan Agreement, solely to the extent that any such covenants would be
breached by the closing of the transaction evidenced by the Subordinated Loan Agreement to the extent but only to the
extent that such transaction is described in the Subordinated Loan Agreement.
IV Partial Releases of Liens. Upon the satisfaction of all the conditions set forth in this Eighth Amendment and the
Subordinated Loan Agreement, Bank shall, if necessary and at the expense of Borrower, execute and deliver to Borrower
a partial release sufficient to allow Borrower to grant the Directors' Overriding Royalty Interests, listed on Exhibit D
attached hereto, except for the Huebner #1 Well and the Fondren Le Tulle #1 Well for which the Directors' Overriding
Royalty Interests have been assigned contemporaneously with this Eighth Amendment. If the assignment of such overriding
royalty interests causes the net revenue interests of Borrower that were mortgaged or pledged to Bank to be less than as
set forth in the applicable mortgage instruments, such reduction will not be deemed to constitute a breach of any
representation or warranty INSOFAR BUT ONLY INSOFAR as the reduction is caused by the assignment of such
overriding royalty interests, provided that if any of such assignments cause a reduction in the Borrowing Base such that a
Loan Excess results, Borrower shall cure such Loan Excess as provided in Section 2.09 of the Loan Agreement.
V Reaffirmation of Representations and Warranties. To induce Bank to enter into this Eighth Amendment, Borrower
hereby reaffirms, as of the date hereof, its representations and warranties contained in Article IV of the Loan Agreement
and in all other documents executed pursuant thereto, and additionally represents and warrants as follows:
5
6
A. The execution and delivery of this Eighth Amendment and the performance by Borrower of its obligations under this
Eighth Amendment are within Borrower's power, have been duly authorized by all necessary corporate action, have
received all necessary governmental approval (if any shall be required), and do not and will not contravene or conflict with
any provision of law or of the articles of incorporation, charter or bylaws of Borrower or of any agreement binding upon
Borrower.
B. The Loan Agreement as amended by this Eighth Amendment, represents the legal, valid and binding obligations of
Borrower, enforceable against Borrower in accordance with its terms, subject as to enforcement only to bankruptcy,
insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally.
C. No Event of Default or Unmatured Event of Default has occurred and is continuing as of the date hereof.
VI Defined Terms. Except as amended hereby, terms used herein that are defined in the Loan Agreement shall have the
same meanings in this Eighth Amendment.
VII Reaffirmation of Loan Agreement. This Eighth Amendment shall be deemed to be an amendment to the Loan
Agreement, and the Loan Agreement, as further amended hereby, is hereby ratified, approved and confirmed in each and
every respect. All references to the Loan Agreement herein and in any other document, instrument, agreement or writing
shall hereafter be deemed to refer to the Loan Agreement as amended hereby.
VIII Entire Agreement. The Loan Agreement, as hereby further amended, embodies the entire agreement between
Borrower and Bank and supersedes all prior proposals, agreements and understandings relating to the subject matter
hereof. Borrower certifies that it is relying on no representation, warranty, covenant or agreement except for those set forth
in the Loan Agreement as hereby further amended and the other documents previously executed or executed of even date
herewith.
IX Governing Law. THIS EIGHTH AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS AND THE APPLICABLE LAWS OF THE
UNITED STATES OF AMERICA. This Eighth Amendment has been entered into in Harris County, Texas, and it shall be
performable for all purposes in Harris County, Texas. Courts within the State of Texas shall have jurisdiction over any and
all disputes between Borrower and Bank, whether in law or equity, including, but not limited to, any and all disputes arising
out of or relating to this Eighth Amendment or any other Loan Document; and venue in any such dispute whether in federal
or state court shall be laid in Harris County, Texas.
X Severability. Whenever possible each provision of this Eighth Amendment shall be interpreted in such manner as to be
effective and valid under applicable law, but if any provision of this Eighth Amendment shall be prohibited by or invalid
under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating
the remainder of such provision or the remaining provisions of this Eighth Amendment.
6
7
XI Execution in Counterparts. Each party hereto acknowledges that this Agreement may be executed in several
counterparts by each party at different times and in different locations; that each separate counterpart bearing the signature
of any party may be effectively delivered to the other parties by the delivery of an electronic facsimile sent via telecopier;
that each party so delivering any such counterpart shall be bound by its facsimile signature thereon; and that the signature
pages from counterparts signed by each party may be collated into one or more copies of this agreement, which shall
constitute one and the same agreement among all parties hereto.
XII Section Captions. Section captions used in this Eighth Amendment are for convenience of reference only, and shall not
affect the construction of this Eighth Amendment.
XIII Successors and Assigns. This Eighth Amendment shall be binding upon Borrower and Bank and their respective
successors and assigns, and shall inure to the benefit of Borrower and Bank, and the respective successors and assigns of
Bank.
XIV Non-Application of Chapter 346 of Texas Finance Codes. In no event shall Chapter 346 of the Texas Finance Code
(which regulates certain revolving loan accounts and revolving tri-party accounts) apply to this Loan Agreement as hereby
further amended or any other Loan Documents or the transactions contemplated hereby.
XV Notice. THIS EIGHTH AMENDMENT TOGETHER WITH THE LOAN AGREEMENT, AND THE OTHER
LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE
PARTIES.
IN WITNESS WHEREOF, the parties hereto have caused this Eighth Amendment to be duly executed as of the day and
year first above written.
BANK BORROWER
COMPASS BANK CARRIZO OIL & GAS, INC.
By: By:
-------------------------------- --------------------------------
Kathleen J. Bowen Frank A. Wojtek
Vice President Vice President
7
8
EXHIBIT "A"
PROPERTY DESCRIPTION
I. WELLS-MATAGORDA COUNTY, TEXAS
================================================================================
NET REVENUE
PROPERTY INTEREST WORKING INTEREST INTEREST
WELL NAME DESCRIPTION HOLDER PERCENTAGE PERCENTAGE
--------------------------------------------------------------------------------
================================================================================
II. LEASES-MATAGORDA COUNTY, TEXAS
I. WELLS-SAN PATRICIO COUNTY, TEXAS
================================================================================
NET REVENUE
PROPERTY INTEREST WORKING INTEREST INTEREST
WELL NAME DESCRIPTION HOLDER PERCENTAGE PERCENTAGE
--------------------------------------------------------------------------------
================================================================================
II. LEASES-SAN PATRICIO COUNTY, TEXAS
8
9
EXHIBIT "B"
FORM OF SUBORDINATION AGREEMENT
9
10
EXHIBIT "C"
FORM OF SUBORDINATED LOAN AGREEMENT
10
11
EXHIBIT "D"
DIRECTOR'S OVERRIDING ROYALTY INTERESTS
1
12
COMPLIANCE CERTIFICATE
I, Frank A. Wojtek, Vice President of CARRIZO OIL & GAS, INC. (the "Company"), pursuant to Section 3.22 of the
First Amended, Restated, and Combined Loan Agreement dated as of August 28, 1997, as amended, by and among
COMPASS BANK ("Bank") and the Company (the "Agreement") do hereby certify, as of the date hereof, that to my
knowledge:
1. No Event of Default (as defined in the Agreement) has occurred and is continuing, and no Unmatured Event of Default
(as defined in the Agreement) has occurred and is continuing;
2. No material adverse change has occurred in the business prospects, financial condition, or the results of operations of
the Company since the date of the previous Financial Statements (as defined in the Agreement) provided to Bank;
3. Each of the representations and warranties of the Company contained in Article IV of the Agreement is true and correct
in all respects.
This certificate is executed this 11th day of November 1999.
Frank A. Wojtek
2
1
EXHIBIT 21.1
The Company has no subsidiaries.
1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K, into
the Company's previously filed Registration Statements on Form S-8 File No. 333-35245 and No. 333-55838.
ARTHUR ANDERSEN LLP
Houston, Texas
March 28, 2001
1
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Registration No.
333-35245 and 333-55838; the "Registration Statement") of Carrizo Oil & Gas, Inc., a Texas corporation (the
"Company"), relating to the 1997 Incentive Plan of the Company of information contained in our reserve report that is
summarized as of December 31, 2000 in our summary letter dated February 23, 2001, relating to the oil and gas reserves
and revenue, as of December 31, 2000, of certain interests of the Company.
We hereby consent to all references to such reports, letters and/or to this firm in each of the Registration Statement and the
Prospectus to which the Registration Statement relates, and further consent to our being named as an expert in each of the
Registration Statement and the Prospectus to which the Registration Statement relates.
[Signature of Ryder Scott Company]
Ryder Scott Company Petroleum Engineers
Houston, Texas
March 27, 2001
1
EXHIBIT 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Registration No.
333-35245 and 333-55838; the "Registration Statement") of Carrizo Oil & Gas, Inc., a Texas corporation (the
"Company"), relating to the 1997 Incentive Plan of the Company of information contained in our reserve report that is
summarized as of December 31, 2000 in our summary letter dated February, 20, 2001, relating to the oil and gas reserves
and revenue, as of December 31, 2000, of certain interests of the Company.
We hereby consent to all references to such reports, letters and/or to this firm in each of the Registration Statement and the
Prospectus to which the Registration Statement relates, and further consent to our being named as an expert in each of the
Registration Statement and the Prospectus to which the Registration Statement relates.
[Signature of Fairchild & Wells, Inc.]
Fairchild & Wells, Inc.
Houston, Texas
March 27, 2001
1
EXHIBIT 99.1
March 26, 2001
Carrizo Oil & Gas, Inc.
14811 St. Mary's Lane, Suite 148
Houston, Texas 77079
Gentlemen:
At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain
leasehold and royalty interests of Carrizo Oil & Gas, Inc. (Carrizo) as of December 31, 2000. The subject properties are
located in the states of Louisiana and Texas. The income data were estimated using the Securities and Exchange
Commission (SEC) guidelines for future price and cost parameters.
The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. December
31, 2000 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from December 31, 2000 prices. Therefore, volumes of reserves actually recovered
and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The
results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
CARRIZO OIL & GAS, INC.
As of December 31, 2000
Proved
--------------------------------------------------------------------
Developed
------------------------------- Total
Producing Non-Producing Undeveloped Proved
------------ ------------- ------------ ------------
NET REMAINING RESERVES
Oil/Condensate - Barrels 106,119 71,216 14,019 191,354
Plant Products - Barrels 41,684 63,727 18,835 124,246
Gas - MMCF 5,240 4,479 528 10,247
INCOME DATA
Future Gross Revenue $ 54,289,396 $ 44,288,765 $ 6,136,551 $104,714,712
Deductions 5,374,409 3,807,824 1,170,218 10,352,451
------------ ------------ ------------ ------------
Future Net Income (FNI) $ 48,914,987 $ 40,480,941 $ 4,966,333 $ 94,362,261
Discounted FNI @ 10% $ 42,128,326 $ 26,805,201 $ 3,863,236 $ 72,796,763
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of
cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 2
The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct
costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net
of salvage. The future net income is before the deduction of state and federal income taxes and general administrative
overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on
hand or undistributed income. No attempt was made to quantify or otherwise account for any accumulated gas production
imbalances that may exist. Gas reserves account for approximately 94 percent and liquid hydrocarbon reserves account for
the remaining 6 percent of total future gross revenue from proved reserves.
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's
Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The definitions of
proved reserves are included in the section entitled "Reserve Definitions" which is attached with this report.
Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in
the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled, and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have
been assured will definitely be developed.
The proved developed non-producing reserves included herein are comprised of shut-in and behind pipe categories. The
various reserve status categories are defined in the section entitled "Reserve Definitions" which is attached with this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other
methods were used in certain cases where characteristics of the data indicated such other methods were more appropriate
in our opinion. The reserves estimated by the performance method utilized extrapolations of various historical data in those
cases where such data were definitive. Reserves were estimated by the volumetric method in those cases where there were
inadequate historical performance data to establish a definitive trend or where the use of production performance data as a
basis for the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or
may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more
or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future
operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those wells now on production. Test data and other
related information were used to estimate the anticipated initial production rates for those wells or locations which are not
currently producing. If no production decline trend has been established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated
rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 3
trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated
to commence at an anticipated date furnished by Carrizo.
In general, we estimate that future gas production rates limited by allowables or marketing conditions will continue to be the
same as the average rate for the latest available 12 months of actual production until such time that the well or wells are
incapable of producing at this rate. The well or wells were then projected to decline at their decreasing delivery capacity
rate. Our general policy on estimates of future gas production rates is adjusted when necessary to reflect actual gas market
conditions in specific cases.
The future production rates from wells now on production may be more or less than estimated because of changes in
market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start
producing earlier or later than anticipated in our estimates of their future production rates.
HYDROCARBON PRICES
Carrizo furnished us with hydrocarbon prices in effect at December 31, 2000 and with its forecasts of future prices which
take into account SEC and Financial Accounting Standards Board (FASB) rules, current market prices, contract prices,
and fixed and determinable price escalations where applicable.
In accordance with FASB Statement No. 69, December 31, 2000 market prices were determined using the daily oil price
or daily gas sales price ("spot price") adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade,
transportation, gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB specifications,
changes in market prices subsequent to December 31, 2000 were not considered in this report.
For hydrocarbon products sold under contract, the contract price including fixed and determinable escalations, exclusive of
inflation adjustments, was used until expiration of the contract. Upon contract expiration, the price was adjusted to the
current market price for the area and held at this adjusted price to depletion of the reserves.
COSTS
Operating costs for the leases and wells in this report are based on the operating expense reports of Carrizo and include
only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general
and administrative costs allocated directly to the leases and wells under terms of operating agreements. No deduction was
made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and
exploration and development prepayments that are not charged directly to the leases or wells.
Development costs were furnished to us by Carrizo and are based on authorizations for expenditure for the proposed
work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties
where abandonment costs net of salvage are significant. At the request of Carrizo, their estimate of zero abandonment
costs after salvage value for onshore properties was used in this report. Ryder Scott has not performed a detailed study of
the abandonment costs nor the salvage value and makes no warranty for Carrizo's estimate.
Current costs were held constant throughout the life of the properties.
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 4
GENERAL
While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and
other costs relating to such production may also increase or decrease from existing levels, such changes were, in
accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
The estimates of reserves presented herein were based upon a detailed study of the properties in which Carrizo owns an
interest; however, we have not made any field examination of the properties. No consideration was given in this report to
potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up
damages, if any, caused by past operating practices. Carrizo has informed us that they have furnished us all of the
accounts, records, geological and engineering data, and reports and other data required for this investigation. The
ownership interests, prices, and other factual data furnished by Carrizo were accepted without independent verification.
The estimates presented in this report are based on data available through December 2000.
Carrizo has assured us of their intent and ability to proceed with the development activities included in this report, and that
they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.
Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this
study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.
This report was prepared for the exclusive use and sole benefit of Carrizo Oil & Gas, Inc. The data, work papers, and
maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of
further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
Michael F. Stell, P.E.
Vice President
MFS/sw
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 5
PETROLEUM RESERVES DEFINITIONS
INTRODUCTION
Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations
from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on
the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these
data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications,
either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further
sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It
should be noted that Securities and Exchange Commission Regulation S-K prohibits the disclosure of estimated quantities
of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the
Commission.
Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic
conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage
or processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all
methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples
of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of
miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as
petroleum technology continues to evolve.
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:
PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas,
and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements,
but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive
formation test. The area of a reservoir considered proved includes:
(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 6
(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on
the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the engineering analysis on which the project or program was
based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such
sources.
PROVED DEVELOPED OIL AND GAS RESERVES. Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas
expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing
the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has confirmed through production response that
increased recovery will be achieved.
PROVED UNDEVELOPED RESERVES. Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can
be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by
actual tests in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters
relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the
following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff's view on specific
questions pertaining to proved oil and gas reserves.
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 7
Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if
geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years
under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering
data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved
reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses
which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test.
(extracted from SAB-35)
In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved
recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure
maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late
stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be
appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review
estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the
registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered
in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not
clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report
such reserves separately and describe the nature of the ownership. (extracted from SAB-35)
The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should
be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas
reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices,
costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)
Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as
bearing the Commission's official approval; they represent interpretations and practices followed by the Division of
Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal
securities laws.
SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS)
In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress
(WPC), developed reserves may be sub-categorized as producing or non-producing.
PRODUCING. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are
open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the
improved recovery project is in operation.
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 8
NON-PRODUCING. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in
reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which
have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market
interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be
recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the
start of production.
UNPROVED RESERVES (SPE/WPC DEFINITIONS)
Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but
technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved
reserves may be further classified as probable reserves and possible reserves.
Unproved reserves may be estimated assuming future economic conditions different from those prevailing at the time of the
estimate. The effect of possible future improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and possible classifications.
PROBABLE RESERVES. Probable reserves are those unproved reserves which analysis of geological and engineering
data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should
be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of estimated proved
plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where
sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing
or proved reserves in the area,
(3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had
been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been
established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and
(b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the
formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the
subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment,
re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful
in wells which exhibit similar behavior in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an
alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.
POSSIBLE RESERVES. Possible reserves are those unproved reserves which analysis of geological and engineering data
suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used,
there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of
estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on geological interpretations, could possibly exist
beyond areas classified as probable, (2) reserves in formations that appear to be
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Carrizo Oil & Gas, Inc.
March 26, 2001
Page 9
petroleum bearing based on log and core analysis but may not be productive at commercial rates, (3) incremental reserves
attributed to infill drilling that are subject to technical uncertainty, (4) reserves attributed to improved recovery methods
when (a) a project or pilot is planned but not in operation and
(b) rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial, and
(5) reserves in an area of the formation that appears to be separated from the proved area by faulting and geological
interpretation indicates the subject area is structurally lower than the proved area.
1
EXHIBIT 99.2
[FAIRCHILD AND WELLS, INC. LETTERHEAD]
February 20, 2001
Carrizo Oil & Gas, Inc.
14701 St. Mary's Lane, Suite 800
Houston, Texas 77079
RE: RESERVES EVALUATION TO THE INTERESTS OF CARRIZO OIL & GAS CORP.
HEAVY OIL PROPERTIES, ANDERSON COUNTY, TEXAS
Gentlemen:
Fairchild and Wells, Inc. (FAW) has performed an engineering evaluation to estimate proved reserves and future cash
flows from heavy oil (steamflood) properties to the interests of Carrizo Oil & Gas Corporation in Anderson County,
Texas. This evaluation was authorized by Mr. S.P. Johnson IV, President of Carrizo Oil & Gas Corporation (Carrizo).
Projections of the anticipated future annual oil production and future cash flows have also been prepared utilizing property
development schedules provided by Carrizo. The reserves and future cash flows to the evaluated interests were based on
economic parameters and operating conditions considered applicable and are pursuant to the financial reporting
requirements of the Securities and Exchange Commission (SEC). December, 2000 hydrocarbon prices were used in the
preparation of this report and current costs were held constant throughout the life of the properties.
The results of the study are summarized below.
SUMMARY
ESTIMATED PROVED RESERVES AND FUTURE CASH FLOWS
CAMP HILL FIELD ANDERSON COUNTY, TEXAS
TO THE INTERESTS OF CARRIZO OIL & GAS CORP.
EFFECTIVE 1/1/2001
Future
Cash Flows, Before NPI (M$)
Net ---------------------------------
Reserves Mbbls Undiscounted Discounted at 10%
-------------- ------------ -----------------
Proved Producing
18 Pattern Leases 695.9 6,109.0 5,122.9
10 Pattern Lease 143.5 963.6 844.7
-------- -------- --------
Total Proved Producing 839.4 7,072.6 5,967.6
Proved Undeveloped
Delaney A Lease 704.6 3,328.9 2,023.9
Temple Eastex C Lease 1,359.5 8,478.6 5,066.0
Moore A Lease 405.5 2,146.0 936.6
Moore B Lease 93.8 558.6 299.3
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Carrizo Oil & Gas, Inc.
February 20, 2001 Page 2
Hanks Lease 137.1 998.6 534.7
C. Rosson 1,906.2 6,533.6 2,235.1
Royall 759.9 2,435.6 321.2
-------- -------- --------
Total Proved Undeveloped 5,366.6 24,479.8 11,416.9
Total Proved 6,206.0 31,552.5 17,384.5
FUTURE CASH FLOW - TOTAL PROJECT BY YEAR
(AFTER NET PROFITS INTEREST)
Future
Cash Flows After NPI (M$)
-----------------------------------
Year Undiscounted Discounted at 10%
---- ------------ -----------------
2001 132.6 126.5
2002 3,063.7 2,655.6
2003 2,701.8 2,129.0
2004 2,381.4 1,705.9
2005 2,894.8 1,885.2
2006 2,733.9 1,618.5
2007 3,184.0 1,713.6
2008 1,908.8 934.0
2009 891.7 396.6
2010 1,125.5 455.1
2011 3,007.6 1,105.6
2012 1,250.9 418.0
2013 884.2 268.6
2014 220.1 60.6
2015 453.5 113.9
2016 311.0 71.0
2017 292.7 60.7
2018 357.5 67.4
2019 536.7 92.0
2020 257.4 40.1
2021 268.1 38.0
2022 444.7 57.3
2023 159.7 18.7
2024 8.1 0.9
TOTAL 29,470.4 16,033.0
The estimated reserves and future cash flows shown in this report are for proved developed producing and proved
undeveloped reserves. Our estimates do not include any value which
3
Carrizo Oil & Gas, Inc.
February 20, 2001 Page 3
might be attributed to interests in undeveloped acreage beyond those tracts for which reserves have been assigned.
In performance of this evaluation, we have relied upon information furnished by Carrizo with respect to property interests
owned, production from such properties, current costs of operation and development, current prices for production,
agreements relating to current and future operations and sale of production. With respect to the technical files supplied by
Carrizo, we have accepted the authenticity and sufficiency of the data contained therein.
Future cash flow is presented after deducting production taxes and after deducting future capital costs and operating
expenses, but before consideration of Federal income taxes. The future cash flow has been discounted at an annual rate of
10 percent to determine its "present worth." The present worth is shown to indicate the effect of time on the value of
money and should not be construed as being the fair market value of the properties Our estimates of future revenue do not
include any salvage value for the lease and well equipment
Fairchild and Wells, Inc. expresses no opinion as to the fair market value of the evaluated properties.
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or
may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more
or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the actual
sales rates and the prices actually received for the reserves along with the costs incurred in recovering such reserves may
vary from those assumptions included in this report. Also, estimates of reserves may increase or decrease as a result of
future operations.
In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as
to which legal or accounting, rather than engineering, interpretation may be controlling. As in all aspects of oil and gas
evaluation, there are uncertainties inherent in the interpretation of engineering data and, therefore, our conclusions
necessarily represent only informed professional judgments.
The titles to the properties have not been examined by Fairchild and Wells, Inc. nor has the actual degree or type of
interest owned been independently confirmed. We are independent petroleum engineers and geologists; we do not own an
interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together
with our engineering work sheets are maintained on file in our office and are available for review.
It has been a pleasure to serve you by preparing this engineering evaluation.
Yours very truly,
Fairchild and Wells, Inc.