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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
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.)
14811 ST. MARY'S LANE, SUITE 148 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.
[X]
At March 23, 2000, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $14.2 million
based on the closing price of such stock on such date of $4.00.
At March 23, 2000, the number of shares outstanding of the registrant's Common
Stock was 14,011,364.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2000 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, 1999.
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TABLE OF CONTENTS
PART I...................................................................... 3
Item 1. and Item 2. Business and Properties............................... 3
Item 3. Legal Proceedings................................................. 22
Item 4. Submission of Matters to a Vote of Security Holders............... 22
Executive Officers of the Registrant...................................... 22
PART II..................................................................... 23
Item 5. Market for Registrant's Common Stock and Related Shareholder
Matters................................................................ 23
Item 6. Selected Financial Data........................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................. 26
Item 7A. Qualitative and Quantitative Disclosures About Market Risk....... 33
Item 8. Financial Statements and Supplementary Data....................... 33
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure............................................... 33
PART III.................................................................... 33
Item 10. Directors and Executive Officers of the Registrant............... 33
Item 11. Executive Compensation........................................... 33
Item 12. Security Ownership of Certain Beneficial Owners and Management... 34
Item 13. Certain Relationships and Related Party Transactions............. 34
PART IV..................................................................... 34
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 34
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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 1999 the Company assembled over 400,000
gross acres under lease or option and acquired 45 3-D seismic surveys with over
1,800 square miles of 3-D data. The Company typically seeks to acquire seismic
permits from landowners that include 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 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 believes is not prospective.
As of December 31, 1999, the Company had 195,464 gross acres under lease or
option, most of which is covered by 3-D seismic data.
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 four years, assuming
sufficient capital resources. In addition, the Company anticipates that as its
existing 3-D seismic data is further evaluated, and 3-D seismic data is acquired
over the balance of its acreage, additional prospects will be generated for
drilling beyond 2003.
The Company's primary drilling targets in the past have been shallow (from
4,000 to 7,000 feet), normally pressured reservoirs that generally involve
moderate cost (typically $150,000 to $400,000 per completed well) and risk. Many
of these drilling prospects also have secondary, 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 to control costs and focus resources
on the higher-value exploratory phase. As of December 31, 1999, the Company
operated 63 producing oil and gas wells, which accounted for 34 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, 1999, the Company participated
in the drilling of 179 gross wells (57.5 net) with a commercial well success
rate of approximately 63 percent. This drilling success contributed to the
Company's total proved reserves as of December 31, 1999 of 40.6 Bcfe with a
PV-10 Value of $51.1 million. During 1999, the Company added 5.5 Bcfe to proved
reserves through drilling, however total proved reserves also increased
approximately 8.5 Bcfe, primarily as a result of improved oil and natural gas
prices, offset by production. The Company's production increased 23 percent from
3,495 MMcfe for the year ended December 31, 1998 to 4,311 MMcfe for the year
ended December 31, 1999, and EBITDA increased 103 percent from $2,422,000 for
the year ended December 31, 1998 to $4,921,000 for the year ended December 31,
1999 due to higher production levels, significantly higher oil and gas sales
prices, and the implementation of cost control measures.
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.
As a result of the increased availability of economic onshore 3-D seismic
surveys and the improvement and increased affordability
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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, 1999,
the Company was actively involved in 41 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 these 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 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 17 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,
1999, the Company operated 63 producing oil and natural gas wells.
The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to use
reliable, high quality, used equipment in place of new equipment to achieve cost
savings. The Company also seeks to minimize cycle time from drilling to hook-up
of wells, thereby accelerating cash flow and improving ultimate project
economics.
The Company seeks to use advanced production techniques to exploit and
expand its reserve base. Following the discovery of
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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 3D 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, 1999
SQ. 2000
MILES POSSIBLE SEISMIC GROSS NET
FOCUS AREA 3D Project OF SEISMIC 3D ACQUISITION ACREAGE ACREAGE
---------- -------------- ------------- ---------------- ------- -------
TEXAS WILCOX AREAS
Cabeza Creek 65 25 3,705 1,815
Buckeye 62 20 6,420 2,932
Metro 30 15 6,601 1,497
Cologne 40 -- 7,134 1,496
Western-Duval 340 -- 936 468
STS 65 -- 6,731 2,212
TEXAS FRIO/VICKSBURG/YEGUA AREAS
Matagorda 51 -- 7,520 4,387
Driscoll 84 -- 6,192 1,479
Ganado 32 -- 13,682 5,680
Western-Starr 320 -- 3,783 2,642
Jones Branch -- 967 302
Rpp Welder 60 -- 8,144 1,853
SOUTHEAST TEXAS AREAS
Cedar Point 30 -- 5,665 1,336
Liberty 52 -- 3,823 1,295
Rusk / Nacogdoches -- 42 23,513 7,538
LOUISIANA AREAS --
North Tigre Lagoon 6 -- 534 107
West Bay -- 6 217 217
------- ------- ------- -------
Subtotal 1,237 108 105,567 37,256
OTHER PROJECTS (24 PROJECTS) 604 -- 89,897 29,569
------- -------- ------- -------
Total 1,841 108 195,464 66,825
======= ======== ======= =======
TEXAS - WILCOX AREAS
The prolific Wilcox trend in South Texas is a primary area of exploration
and development focus for Carrizo. The Company has a total of 754 square miles
of 3D seismic data that covers potential Wilcox formation development
opportunities. Wilcox wells often have relatively deeper targets with higher
reserve potential and higher risk than many of the Company's other wells.
Several key Wilcox project areas are discussed below and represent a significant
portion of the expected 2000 and early 2001 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 the Wilcox J1 prospect well which was drilled in March 2000 and is
currently being completed. The shallow development objectives were completed and
appear to support another well location for immediate consideration while the
deeper exploration section verified sand, hydrocarbons and improved the risk
profile for another test planned in 2000. The Company anticipates drilling
between one and three additional wells during the next 12 months pending
reservoir performance and the sale of promoted interests in the deeper
opportunities to industry partners. 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. The
initial test well has an expected total depth of 15,800 feet and is planned for
drilling during the first half of 2000. If the well is successful, the Company
believes that two additional closures could provide significant follow-up
exploration and development potential. The average working interest owned
by Carizzo in the Buckeye acreage is approximately 46 percent.
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 initial test well is currently
being drilled and has a targeted total depth of approximately 16,500 feet. The
well is primarily a test which, if successful, would attempt to exploit improved
deliverability with modern frac technology and take advantage of expected
improved reservoir properties on top of the structure. In addition, below 15,500
feet, the well will also test a stratigraphically deeper section that the
Company correlates with productive sands in the surrounding area. Two additional
closures along a large regional fault could provide significant follow-up
exploitation potential. Carrizo has approximately a seven percent working
interest in the initial test well and approximately a 20 percent working
interest in the other two potential follow-up structures.
Dewitt County - Metro Project Area
The 30 square mile Metro Project Area is located along the northern and
eastern boundaries of Carrizo's Wilcox area of interest in Dewitt County, Texas.
The Company drilled two successful Wilcox wells in the project area in 1998 and
1999. Offset competitors have recently been successful in testing slightly
deeper stratigraphic intervals, which the Company believes has improved the
probability of success on identified deeper opportunities in the Metro Project
Area. Additional 3D seismic data will be available to Carrizo and its partners
in 2000 to help to further
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define closure elements on prospects both within and peripheral to the original
3D shoot boundaries. Carrizo and its partners plan to drill a Wilcox well to
test the deeper opportunities during 2000. Carrizo has approximately a 25
percent working interest in the project area.
Western Duval Project Area
Carrizo's Western Duval Project Area consists of non-exclusive license
rights to 320 square miles of speculative 3D data along the southern and western
limits of Carrizo's Wilcox area of interest within Webb and Duval Counties,
Texas. The Company is planning to drill a test well during the second quarter of
2000, with potential follow up drilling in the second half of 2000. The Company
expects to identify additional drilling prospects and is working to secure
leases over the areas it believes has the highest potential.
STS Project Area
The STS Project Area is along the updip portion of the Company's Wilcox area
of interest and includes 65 square miles of 3D data straddling LaSalle and
McMullen Counties, Texas. Although numerous formations are found to be
productive in the area (including a 1999 Carrizo Olmos formation discovery), the
Wilcox formation represents an attractive risk/reward target. The Company is
presently focusing on several Wilcox opportunities based upon a successful
initial test well, in which Carrizo has a 22.375 percent working interest,
which recently commenced production at a rate of approximately 100 BOPD. The
Company is planning to drill at least one follow up well and to test at least
one additional structure in 2000. Further appraisal drilling in the Olmos
formation is also being evaluated.
TEXAS FRIO/VICKSBURG/YEGUA AREAS
This combined area trend sometimes overlaps but is generally closer to the
Texas coast than the Wilcox areas discussed above. This is an area of expected
continued focus for Carrizo in 2000 and future years. In any particular target
or prospect, the Frio is usually a shallower formation, while the Yegua and
Vicksburg are generally relatively deeper formations. The Company has a total of
918 square miles of 3D seismic data that covers development potential within the
Frio, Vicksburg and Yegua sands. Several key areas are discussed below which
represent a significant portion of 2000 and 2001 drilling inventory.
Matagorda Project Area
The 51 square mile Matagorda Project Area was an area of significant
drilling activity and success for the Company in 1999. The Company expects to
further develop its leasehold interest in 2000 and beyond. The Company has
drilled six wells to date in the Matagorda Project Area, of which four have been
successful. The "Fondren-Letulle #1" and "Burkhart #1" wells drilled in late
1999, in which the Company has a 30 percent working interest, continue to
produce at a combined rate of 28,200 Mcfe per day as of March 1, 2000. The
Company controls over 5,000 acres under lease in the project area, including a
4,200 acre lease in which the Company has a 96 percent working interest. The
Company plans to drill six wells in the area in 2000. The Company's expected
working interest in these prospects is expected to be approximately 50 percent.
Driscoll Project Area
The Company continued to prioritize and lease the identified Yegua and Frio
prospects in the 84 square mile Driscoll Project Area during 1999. The Company
plans to drill two wells in this area in 2000. This area, which lies in Jim
Wells and Duval counties in Texas has experienced high industry activity in both
the pressured Yegua and shallow Frio formations. The 3D seismic data is being
evaluated for additional processing to further highgrade the numerous
opportunities. Carrizo has approximately a 24 percent working interest in the
project area.
Ganado Project Area
The Ganado Project Area is located in Ganado and Wharton Counties, Texas and
targets both amplitude supported Frio and expanded Yegua opportunities. The
initial Frio test well was successfully drilled in February of 2000 and tested
at approximately 750 Mcf per day. Carrizo has a 25 percent working interest in
this well which is expected to commence production in April 2000. The Company
plans to drill additional Frio wells and a Yegua prospect in the area in 2000.
Western-Starr Project Area
The Company has obtained a non-exclusive license to 340 square miles of 3D
seismic data which covers Frio and Vicksburg producing trends in Starr and
Hildalgo Counties. The Company and its working interest partners have drilled 29
wells in the project area since 1996,
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resulting in 20 producing wells. Carrizo is continuing to develop prospects from
this data and acquire leases, and plans to drill at least one Vicksburg test in
2000. Carrizo's working interest in its leases within this project area averages
approximately 50%.
RPP Welder Project Area
Additional reprocessing of the 60 square mile RPP 3-D survey data has
provided additional seismic attributes to help prioritize the numerous Frio and
Vicksburg prospects identified in the project area, which is located in Refugio
and San Patricio Counties, Texas. The Company participated in four wells drilled
in the project area during 1999, of which three were successful. Three to six
additional wells are planned in 2000. Carrizo has an average 17 percent working
interest in the project area.
SOUTHEAST TEXAS AREAS
Carrizo has acquired approximately 82 square miles of 3-D data over its
Southeast Texas project areas which are focused primarily on the Yegua and
Vicksburg formations. The Company expects that these areas will constitute a
significant portion of its 2000 and 2001 drilling programs. Carrizo is
considering additional purchases of 3-D data during 2000 to further exploit
successful trends.
Chambers County - 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 acquired in late 1998 targets the
Vicksburg and lower Frio formations. The initial test well, the "USX Hematite
#1", in which Carrizo has a 14 percent working interest was drilled and
successfully completed in late 1999. The well commenced production at a rate of
over 16,000 Mcfe per day and continues to produce at a rate of 15,200 Mcfe per
day as of March 1, 2000. The Company has identified four additional prospects on
leased acreage which the Company believes exhibit similar seismic signatures
within the same stratigraphic interval as the Hematite well. The Company has a
28 percent working interest in these prospects, the first of which is planned to
spud during the second quarter of 2000.
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 acquired in 1999
in the Liberty Project Area in Liberty County, Texas. An initial Frio test well,
in which the Company has a 43.75 percent working interest, was drilled and
successfully completed in March 2000 and is awaiting pipeline hookup to commence
production. Carrizo is currently evaluating the drilling sequence of four
additional prospects, with the next well expected to spud during April 2000. In
addition, a Cook Mountain sand amplitude-supported prospect is targeted for
drilling in mid 2000. Carrizo is the operator and has approximately an 85
percent working interest in the properties in the project area.
Rusk - Nacogdoches Project Area
Carrizo has acquired 7,538 net acres of leases and options in the Rusk -
Nacogdoches project areas located in Rusk and Cherokee Counties, Texas. The
projects target the James Lime, Travis Peak, Pettet and Cotton Valley
formations. There has been recent successful horizontal drilling activity in the
area by others in addition to vertical James Lime production in the Trawick
field which is adjacent to a portion of the Company's acreage. Carrizo has a 58
percent working interest in the project area and is currently negotiating with
industry partners to sell a portion of the interest in exchange for a drilling
commitment and lease reimbursement. The Company is also considering whether to
acquire certain 3-D seismic data covering a portion of the average held which is
expected to become available in 2000.
LOUISIANA
North Tigre Lagoon
The North Tigre Lagoon prospect well was spud during late March 2000. The
well, located in Vermilion Parish, Louisiana, targets lower Miocene sands.
Carrizo is the operator and has approximately a 25% working interest in this
project area.
West Bay
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Carrizo is currently resolving participation interests with potential
partners and plans to spud the West Bay Prospect well during May of 2000. The
prospect is located in Plaquemine Parish, Louisiana. Carrizo estimates its
average working interest in the properties in this project area at 25 to 50%
depending on the amount of acreage developed.
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 six of these leases. During the year ended December 31, 1999, the
project produced 72 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, 1999 averaged $10.40 per barrel ($1.73 per Mcfe). In response to
lower commodity prices, steam injection was reduced in November 1998. 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 barrel during the year ended December 31, 1999)
than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 1999, the Company had 4.64 million barrels
of proved oil reserves in this project, with 841.9 MBbls of oil 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.
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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 24
additional project areas in various stages of development as of December 31,
1999. 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,
1999 had acquired leases and seismic options covering 89,897 gross 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 my 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
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activities may not be successful, and if unsuccessful, such failure will have a
material adverse effect on the Company's results of operations and financial
condition. There can be no assurance the Company's overall drilling success rate
or its drilling success rate for activity within a particular project area will
not decline. The Company may choose not to acquire option and lease rights prior
to acquiring seismic data and, in many cases, the Company may identify a
prospect or drilling location before seeking option or lease rights in the
prospect or location. Although the Company has identified or budgeted for
numerous drilling prospects, there can be no assurance that such prospects will
ever be leased or drilled (or drilled within the scheduled or budgeted time
frame) or that oil or natural gas will be produced from any such prospects or
any other prospects. In addition, prospects may initially be identified through
a number of methods, some of which do not include interpretation of 3-D or other
seismic data. Wells that are currently in the Company's capital budget may be
based upon statistical results of drilling activities in other 3-D project areas
that the Company believes are geologically similar, rather than on analysis of
seismic or other data. Actual drilling and results are likely to vary from such
statistical results and such variance may be material. Similarly, the Company's
drilling schedule may vary from its capital budget because of future
uncertainties, including those described above. The description of a well as
"budgeted" does not mean that the Company currently has or will have the capital
resources to drill the well. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated net proved oil and natural gas
reserves of the Company and the PV-10 Value of such reserves as of December 31,
1999. The reserve data and the present value as of December 31, 1999 were
prepared by Ryder Scott Company and Fairchild, Ancell & 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, 1999,
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) 1,070 3,807 4,877
Natural gas (MMcf) 10,680 643 11,323
Total proved reserves (MMcfe) 17,100 23,485 40,585
PV-10 Value(1) $ 28,925 $ 22,252 $ 51,177
- ----------
(1) The PV-10 Value as of December 31, 1999 is pre-tax and was determined by
using the December 31, 1999 sales prices, which averaged $23.40 per Bbl of
oil, $2.35 per Mcf of natural gas and $14.63 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, 1999. The prices used in
calculating the estimated future net revenue attributable to proved reserves do
not necessarily reflect market prices for oil and natural gas production
subsequent to December 31, 1999. 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.
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There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Annual Report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions concerning
future oil and natural gas prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of which may in
fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom
prepared by different engineers or by the same engineers but at different times
may vary substantially and such reserve estimates may be subject to downward or
upward adjustment based upon such factors. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. In addition, the 10% discount
factor, which is required by the Commission to be used in calculating discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and natural gas industry in
general.
In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Company conducts successful
exploration and development activities or acquires properties containing proved
reserves, or both, the proved reserves of the Company will decline as reserves
are produced. The Company's future oil and natural gas production is, therefore,
highly dependent upon its level of success in finding or acquiring additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investment to maintain or expand its asset base of
oil and natural gas reserves would be impaired. The failure of an operator of
the Company's wells to adequately perform operations, or such operator's breach
of the applicable agreements, could adversely impact the Company. In addition,
there can be no assurance that the Company's future exploration, development and
acquisition activities will result in additional proved reserves or that the
Company will be able to drill productive wells at acceptable costs. Furthermore,
although the Company's revenues could increase if prevailing prices for oil and
natural gas increase significantly, the Company's finding and development costs
could also increase. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
VOLUMES, PRICES AND OIL & 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,
1997 1998 1999
-------- -------- --------
Production volumes
Oil (MBbls) 113 140 179
Natural gas (MMcf) 2,749 2,655 3,235
Natural gas equivalent (MMcfe) 3,424 3,495 4,311
Average sales prices
Oil (per Bbl) $ 18.66 $ 12.30 $ 16.60
Natural gas (per Mcf) 2.41 2.31 2.23
Natural gas equivalent (per Mcfe) 2.54 2.25 2.37
Average costs (per Mcfe)
Camp Hill operating expenses $ 2.59 $ 2.35 $ 1.73
Other operating expenses 0.54 0.69 0.66
Total operating expenses(1) 0.68 0.79 0.70
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- ----------
(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, 1999, the Company has incurred total
gross development, exploration and acquisition costs of approximately $91.0
million. Total exploration, development and acquisition activities from
inception through December 31, 1999 have resulted in the addition of
approximately 58.0 Bcfe, net to the Company's interest, of proved reserves at an
average finding and development cost of $1.57 per Mcfe.
The Company's finding and development costs have historically fluctuated on
a year-to-year basis. Finding and development costs, as measured annually, may
not be indicative of the Company's ability to economically replace oil and
natural gas reserves because the recognition of costs may not necessarily
coincide with the addition of proved reserves.
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the gross costs
incurred in the purchase of proved and unproved properties and in development
and exploration activities.
YEAR ENDED DECEMBER 31,
---------------------------
1997 1998 1999
------- ------- -------
(IN THOUSANDS)
Acquisition costs
Unproved prospects $14,223 $ 9,619 $ 4,166
Proved properties 5,492 16,197 472
Exploration 9,328 10,429 3,163
Development 2,257 313 937
------- ------- -------
Total costs incurred(1) $31,300 $36,558 $ 8,738
======= ======= =======
- ----------
(1) Excludes capitalized interest on unproved properties of $699,625, and
$291,496, and $1,547,879 for the years ended December 31, 1997, 1998 and
1999, respectively.
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
years ended December 31, 1997, 1998 and 1999. 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, 1999 has resulted in a
commercial success rate of approximately 63%.
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YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
1997 1998 1999
-------------------------- -------------------------- --------------------------
GROSS NET GROSS NET GROSS NET
------------ ------------- ------------ ------------- ------------ -------------
Exploratory Wells
Productive 39 15.7 29 9.3 14 2.3
Nonproductive 23 9.4 24 7.0 12 1.6
------------ ------------- ------------ ------------- ------------ -------------
Total 62 25.1 53 16.3 26 3.9
============ ============= ============ ============= ============ =============
Development Wells
Productive 7 1.8 3 1.0 4 0.9
Nonproductive 1 0.6 1 -- 2 0.8
------------ ------------- ------------ ------------- ------------ -------------
Total 8 2.4 4 1.0 6 1.7
============ ============= ============ ============= ============ =============
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, 1999.
COMPANY
OPERATED OTHER TOTAL
-------------------------- -------------------------- --------------------------
GROSS NET GROSS NET GROSS NET
------------- ------------ ------------- ------------ ------------- ------------
Oil 45 43.2 31 9.1 76 52.3
Natural gas 18 10.9 91 24.9 109 35.8
------------- ------------ ------------- ------------ ------------- ------------
Total 63 54.1 122 34.0 185 88.1
============= ============ ============= ============ ============= ============
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 1999. 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 286 33 5,252 1,004 5,538 1,037
Texas 51,399 17,616 117,341 38,831 168,740 56,447
------------- ------------ ------------- ------------ ------------- ------------
Total 51,685 17,649 122,593 39,835 174,278 57,484
============= ============ ============= ============ ============= ============
The table does not include 21,186 gross acres (9,341 net) that the Company
had a right to acquire pursuant to various seismic option agreements at December
31, 1999. 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.
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The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of multiple
outlets near its production in the Texas and Louisiana Gulf Coast. The Company
takes an active role in determining the available pipeline alternatives for each
property based upon historical pricing, capacity, pressure, market
relationships, seasonal variances and long-term viability.
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers. The
availability of a ready market for the Company's oil and natural gas production
depends on the proximity of reserves to, and the capacity of, oil and natural
gas gathering systems, pipelines and trucking or terminal facilities. The
Company delivers natural gas through gas gathering systems and gas pipelines
that it does not own. Federal and state regulation of natural gas and oil
production and transportation, tax and energy policies, changes in supply and
demand and general economic conditions all could adversely affect the Company's
ability to produce and market its oil and natural gas.
The Company from time to time markets its own production where feasible with
a combination of market-sensitive pricing and forward-fixed pricing. Forward
pricing is utilized to take advantage of anomalies in the futures market and to
hedge a portion of the Company's production deliverability at prices exceeding
forecast. All of such hedging transactions provide for financial rather than
physical settlement. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations-General Overview."
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas sold in the
spot market due primarily to seasonality of demand and other factors beyond the
Company's control. Domestic oil prices generally follow worldwide oil prices,
which are subject to price fluctuations resulting from changes in world supply
and demand. The Company continues to evaluate the potential for reducing these
risks by entering into, and expects to enter into, additional hedge transactions
in future years. In addition, the Company may also close out any portion of
hedges that may exist from time to time as determined to be appropriate by
management. At December 31, 1998, there were no open hedge positions. 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.) Total oil and natural gas purchased and
sold under such swap arrangements during the years ended December 31, 1997, 1998
and 1999 were, 0 Bbls, 0 Bbls and 45,200 Bbls, respectively, and 210,000 MMBtu
and 1,760,000 MMBtu, and 2,050,000 MMBtu respectively. Gains (losses) realized
by the Company under such swap arrangements were ($48,000), $167,000 and
($412,000), for the years ended December 31, 1997, 1998 and 1999, respectively.
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,
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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 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% 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
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intended by the FERC to foster competition by, among other things, transforming
the role of interstate pipeline companies from wholesaler marketers of gas to
the primary role of gas transporters. 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 all other merchants. As a result
of the various omnibus rulemaking proceedings in the late 1980s and the
individual pipeline restructuring proceedings of the early to mid-1990s, the
interstate pipelines are now required to provide open and nondiscriminatory
transportation and transportation-related services to all producers, gas
marketing companies, local distribution companies, industrial end users and
other customers seeking service. Through similar orders affecting intrastate
pipelines that provide similar interstate services, the FERC expanded the impact
of open access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (i) the large-scale divestiture
of interstate pipeline-owned gas gathering facilities to affiliated or
non-affiliated companies, (ii) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (iii) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, (iv) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market and (v) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in the
relevant service market. 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 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. Beginning later this year, the FERC
will conduct a scheduled review of the indexing system. Any changes resulting
from that review, however, would not take effect until July 2001.
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. 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. 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
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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.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the operations
of the Company. The EPA and states have been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, the Company does not
believe its operations will be materially adversely affected by any such
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure ("SPCC") and response plans relating
to the possible discharge of oil into surface waters. The Company has
acknowledged the need for SPCC plans at certain of its properties and believes
that it will be able to develop and implement these plans in the near future.
The Oil Pollution Act of 1990, ("OPA") contains numerous requirements relating
to the prevention of and response to oil spills into waters of the United
States. The OPA subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages
arising from a spill, including, but not limited to, the costs of responding to
a release of oil to surface waters. The OPA also requires owners and operators
of offshore facilities that could be the source of an oil spill into federal or
state waters, including wetlands, to post a bond, letter of credit or other form
of financial assurance in amounts ranging from $10 million in specified state
waters to $35 million in federal outer continental shelf waters to cover costs
that could be incurred by governmental authorities in responding to an oil
spill. Such financial assurances may be increased by as much as $150 million if
a formal risk assessment indicates that the increase is warranted. Noncompliance
with OPA may result in varying civil and criminal penalties and liabilities.
Operations of the Company are also subject to the federal Clean Water Act
("CWA") and analogous state laws. In accordance with the CWA, the state of
Louisiana has issued regulations prohibiting discharges of produced water in
state coastal waters effective July 1, 1997. Pursuant to other requirements of
the CWA, the EPA has adopted regulations concerning discharges of storm water
runoff. This program requires covered facilities to obtain individual permits,
participate in a group permit or seek coverage under an EPA general permit.
While certain of its properties may require permits for discharges of storm
water runoff, the Company believes that it will be able to obtain, or be
included under, such permits, where necessary, and make minor modifications to
existing facilities and operations that would not have a material effect on the
Company. Like OPA, the CWA and analogous state laws relating to the control of
water pollution provide varying civil and criminal penalties and liabilities for
releases of petroleum or its derivatives into surface waters or into the ground.
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
17
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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 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 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.
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EMPLOYEES
At December 31, 1999, the Company had 26 full-time employees, including five
geoscientists and four 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 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 whereunder 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."
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20
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.
Mcf/d. One thousand cubic feet 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%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
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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 Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation, without
giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expense and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or gas that is confined by impermeable rock
or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or 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.
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ITEM 3. LEGAL PROCEEDINGS
From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. The Company is not currently a party
to any litigation that it believes could have a material adverse effect on the
financial position or results of operations of the Company.
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 43 President and Chief Executive Officer
Frank A. Wojtek 44 Chief Financial Officer, Vice
President,
Secretary and Treasurer
George F. Canjar 42 Vice President of Exploration
Development
Kendall A. Trahan 49 Vice President of Land
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.
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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
-------------------------- ------------ ------------
September 30, 1997 15 10 15/16
December 31, 1997 17 1/4 7 7/8
March 31, 1998 8 3/4 6 1/16
June 30, 1998 7 1/2 5 1/2
September 30, 1998 5 3/4 2 5/8
December 31, 1998 3 1/16 1 1/8
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
There were approximately 60 shareholders of record (excluding brokerage
firms and other nominees) of the Company's Common Stock as of March 23, 2000.
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% 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."
RECENT 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, 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% 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").
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, 1999, 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,
--------------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues $ 2,428 $ 5,195 $ 8,712 $ 7,859 $ 10,204
Costs and expenses:
Oil and natural gas operating expenses 1,814 2,384 2,334 2,770 3,036
Depreciation, depletion and
amortization 488 1,136 2,358 3,952 4,301
Write-down of oil and gas properties -- -- -- 20,305 --
General and administrative 425 515 1,591 2,667 2,195
-------- -------- -------- -------- --------
Total costs and expenses 2,727 4,035 6,283 29,694 9,532
-------- -------- -------- -------- --------
Operating income (loss) (299) 1,160 2,429 (21,835) 672
Interest expense (net of amounts
capitalized and interest income) (192) (80) (98) 285 13
Other income 24 20 -- -- --
-------- -------- -------- -------- --------
Income (loss) before income taxes (467) 1,100 2,331 (21,550) 685
Deferred income taxes (benefit)(1) -- -- 2,300 (2,218) (1,057)
-------- -------- -------- -------- --------
Net income (loss) before cumulative effect of change
in accounting principle (467) 1,100 31 (19,332) 1,742
Cumulative effect of change in accounting principle -- -- -- -- (78)
-------- -------- -------- -------- --------
Net income (loss)(1)(4) $ (467) $ 1,100 $ 31 $(19,332) $ 1,664
======== ======== ======== ======== ========
Basic earnings (loss) per share (1)(4) $ (0.07) $ 0.15 $ -- $ (2.15) $ 2.00
======== ======== ======== ======== ========
Diluted earnings (loss) per share (1)(4) $ (0.07) $ 0.15 $ -- $ (2.15) $ 2.00
======== ======== ======== ======== ========
Basic weighted average shares outstanding 7,021 7,476 8,639 10,375 10,544
Diluted weighted average shares
outstanding 7,021 7,545 8,810 10,375 10,546
STATEMENTS OF CASH FLOW DATA:
Net cash provided by operating activities $ 406 $ 3,325 $ 3,068 $ 2,387 $ 2,200
Net cash used in investing activities (6,785) (8,221) (28,141) (37,178) (14,179)
Net cash provided by financing activities 6,343 6,319 26,255 32,916 21,457
OTHER OPERATING DATA:
Adjusted EBITDA (2) $ 189 $ 2,296 $ 4,787 $ 2,422 $ 4,921
Operating cash flow (3) 21 2,236 4,689 2,707 4,986
Capital expenditures 6,857 9,480 32,234 36,570 10,286
Debt repayments(5) -- 2,084 20,409 7,950 8,174
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AS OF DECEMBER 31,
--------------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- --------
BALANCE SHEET DATA:
Working capital $ (265) $ (1,025) $ (2,276) $ (5,204) $ 8,338
Property and equipment, net 6,960 15,206 45,083 57,878 64,337
Total assets 7,645 18,869 53,658 64,988 83,666
Long-term debt, including current
maturities 3,480 9,684 7,950 12,056 33,627
Mandatorily redeemable preferred stock -- -- -- 30,731 --
Equity 3,381 4,596 32,895 11,202 40,853
- ----------
(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 writedown of oil and gas
properties.
(3) Operating cash flow represents cash flows from operating activities prior to
changes in assets and liabilities.
(4) Net income (loss) 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), use of proceeds from the Company's initial public offering and the
sale of shares of Preferred Stock and the warrants, 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 and other factors detailed herein and in
the Company's other filings with the Securities and Exchange Commission. Should
one or more of these risks or uncertainties materialize, or should underlying
assumptions prove incorrect, actual outcomes may vary materially from those
indicated.
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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 70, 57 and 32 wells in 1997, 1998
and 1999 respectively. The Company has budgeted to drill 45 gross wells (14.1
net) in 2000; however, in order to drill the expected number of wells the
Company will need to obtain additional financing and the actual number of wells
drilled will vary depending upon the Company's ability to obtain this financing,
success of drilling program, weather delays and other factors. If the Company
drills the number of wells it has budgeted for 2000, depreciation, depletion and
amortization are expected to increase and oil and gas operating expenses are
expected to increase over levels incurred in 1999. 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% 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.
RESULTS OF OPERATIONS
Year Ended December 31, 1999 Compared to the Year Ended December 31, 1998
Oil and natural gas revenues for 1999 increased 30% to $10.2 million from
$7.9 million in 1998. Production volumes for natural gas in 1999 increased 22%
to 3235.0 MMcf from 2,655.1 MMcf in 1998. Realized average natural gas prices
decreased 3% to $2.23 per Mcf in 1999 from $2.31 per Mcf in 1998. Production
volumes for oil in 1999 increased 28% 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.
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Average oil prices increased 37% 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% 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% 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.
Interest expense, net of amounts capitalized, for 1999 increased 305% 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 changed from $2.2 million to $1.1 million based on
improvements in the expected results which influence future taxable income. The
Company 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 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 at a
discount resulted in a credit 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.
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Year Ended December 31, 1998 Compared to the Year Ended December 31, 1997
Oil and natural gas revenues for 1998 decreased 10% to $7.9 million from
$8.7 million in 1997. Production volumes for natural gas in 1998 decreased 3% to
2,655.1 MMcf from 2,749.2 MMcf in 1997. Average natural gas prices decreased 4%
to $2.31 per Mcf in 1998 from $2.41 per Mcf in 1997. Production volumes for oil
in 1998 increased 24% to 140 MBbls from 112.5 MBbls in 1997. Average oil prices
decreased 34% to $12.30 per barrel in 1998 from $18.66 per barrel in 1997.
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, 1997 and 1998:
1998 PERIOD
COMPARED TO 1997 PERIOD
DECEMBER 31, INCREASE % INCREASE
1997 1998 (DECREASE) (DECREASE)
------------ ------------ ----------- -----------
Production volumes
Oil and condensate (MBbls) 112.5 140 27.5 24%
Natural gas (MMcf) 2,749.2 2,655.1 (94.1) (3%)
Average sales prices-(1)
Oil and condensate (per Bbl) $ 18.66 $ 12.30 $ (6.36) (34%)
Natural gas (per Mcf) 2.41 2.31 (0.10) (4%)
Operating revenues-
Oil and condensate $ 2,099,699 $ 1,721,162 $ (378,537) (18%)
Natural gas 6,611,955 6,137,340 (474,615) (7%)
------------ ------------ -----------
Total $ 8,711,654 $ 7,858,502 $ (853,152) (10%)
============ ============ ===========
- ----------
(1) Including impact of hedging.
Oil and natural gas operating expenses for 1998 increased 19% to $2.8
million from $2.3 million in 1997. 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, 1996. Operating expenses per equivalent unit in
1998 increased to $.81 per Mcfe from $.68 per Mcfe in 1997. The per unit cost
increased primarily as a result of decreased production of natural gas as wells
naturally decline.
DD&A expense for 1998 increased 68% to $4.0 million from $2.4 million in
1997. This increase was primarily due to the increased production, additional
land, seismic and drilling costs.
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.
General and administrative expense for 1998 increased 68% to $2.7 million
from $1.6 million for 1997 reflecting ramp-up expenses relating to the hiring of
additional technical and administrative staff to handle the Company's increased
level of exploration activities and operations as well as other costs related to
being a public company.
Interest expense for 1998 decreased 94% to $9,000 from $151,000 in 1997.
This decrease was primarily due to lower interest expense in 1998 which allowed
a larger percentage of the interest to be capitalized.
As a result of the adoption of SFAS 109 in the second quarter of 1997, the
Company recorded a one-time non-cash charge to income of $1.6 million to
establish a deferred tax liability.
Dividends and accretion of discount on preferred stock increased to $2.9
million in 1998 from none in 1997 as a result of the sale of preferred stock in
the first quarter of 1998.
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Net income for 1998 decreased to a loss of $22.2 million from income of
$31,000 in 1997 as a result of the factors described above.
LIQUIDITY AND CAPITAL RESOURCES
The Company has made and will be required to make oil and gas capital
expenditures substantially 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 activities exploration
projects.
While the Company believes that the recent financing consummated in December
1999 (see Financing Arrangements below) will provide sufficient capital to carry
out the Company's 2000 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
initial public offering from 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 the Palace
Agreement.
Cash flows provided by operations (after changes in working capital) were
$3.1 million, $2.4 million and $2.2 million for 1997, 1998 and 1999,
respectively. The decrease in cash flows provided by operations in 1998 as
compared to 1997 was due primarily to decreases in commodity prices. 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 Company has budgeted capital expenditures in 2000 of approximately $13.9
million of which $2.3 is expected to be used to fund 3-D seismic surveys and
land acquisitions and $11.6 million of which is expected to be used for drilling
activities in the Company's project areas. The Company has budgeted to drill
approximately 45 gross wells (14.1 net) in 2000. The actual number of wells
drilled and capital expended is dependent upon available financing, cash flow,
drilling rigs 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 $32.2 million, $36.6 and $10.3 million for 1997, 1998 and
1999, respectively. The Company's drilling efforts resulted in the successful
completion of 46 gross wells (17.5 net) in 1997, 31 gross wells (10.3 net) in
1998 and 18 gross wells (3.2 net) in 1999.
FINANCING ARRANGEMENTS
In connection with the 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, 2000, the
aggregate amount of this collateral was approximately $5.5 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
additions 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. Unless
preceded by the Term Loan Maturity Date (as defined below), principal payments
on the term loan are not due until June 1, 2000, whereupon the term loan is
repayable 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.
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, 1998, and 1999,
outstanding revolving credit loans totaled $5,056,000 and $5,876,000,
respectively, with an additional $1,020,000 and $1,208,392, respectively,
available for future borrowings. The outstanding amount of the term loan was
$7,000,000 at December 31, 1998 and 1999. 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, 1998 and 1999. The weighted average interest rates for
1998 and 1999 on the Company Credit Facility were 8 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% per annum. Also in
consideration for the bridge loan, the Company assigned to Messrs. Hamilton,
Webster and Loyd an aggregate 1.0% overriding royalty interest ("ORRI") in the
Huebner #1 and Fondren Letulle #1 wells (combined with the prior assignment, a
2% overriding royalty interest), a .8794% ORRI in Neblett #1 (N.La.Copita), a
1.0466% ORRI in STS 104-5#1, a 1.544% ORRI in USX Hematite #1, a 2.0% ORRI in
Huebner #2 and a 2.0% ORRI in Buckhart #1. On December 15, 1999 the bridge loan
was repaid in its entirety with proceeds from the sale of Common Stock,
Subordinated Notes and Warrants. Such overriding royalty interests are limited
to the well bore and proportionately reduced to the Company's working interest
in the well.
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In December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an
investor group led by CB Capital Investors, L.P. 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% 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.
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 to a specified amount for the year
ended December 31, 2000, and thereafter to an amount equal to the Company's
EBITDA for the immediately prior fiscal year as well as limits on the Company's
ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in
mergers, consolidations, 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 Company expects the remaining proceeds to be 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.
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31
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, 1999, the Company had 26 full-time employees. There will be additional
demands on the Company's financial, technical, operational and administrative
resources and continued reliance by the Company on project partners and
independent contractors, and these strains on resources, additional demands and
continued reliance may negatively affect the Company. The Company's ability to
grow will depend upon a number of factors, including its ability to obtain
leases or options on properties for 3-D seismic surveys, its ability to acquire
additional 3-D seismic data, its ability to identify and acquire new exploratory
sites, its ability to develop existing sites, its ability to continue to retain
and attract skilled personnel, its ability to maintain or enter into new
relationships with project partners and independent contractors, the results of
its drilling program, hydrocarbon prices, access to capital and other factors.
Although the Company intends to continue to upgrade its technical, operational
and administrative resources and to increase its ability to provide internally
certain of the services previously provided by outside sources, there can be no
assurance that it will be successful in doing so or that it will be able to
continue to maintain or enter into new relationships with project partners and
independent contractors. The failure of the Company to continue to upgrade its
technical, operational and administrative resources or the occurrence of
unexpected expansion difficulties, including difficulties in recruiting and
retaining sufficient numbers of qualified personnel to enable the Company to
expand its seismic data acquisition and drilling program, or the reduced
availability of project partners and independent contractors that have
historically provided the Company seismic survey planning and management,
project and prospect generation, land acquisition, drilling and other services,
could have a material adverse effect on the Company's business, financial
condition and results of operations. In addition, the Company has only limited
experience operating and managing field operations, and there can be no
assurances that the Company will be successful in doing so. Any increase in the
Company's activities as an operator will increase its exposure to operating
hazards. See "Business and Properties -- Operating Hazards and Insurance." The
Company's lack of capital will also constrain its ability to grow and achieve
its business strategy. There can be no assurance that the Company will be
successful in achieving growth or any other aspect of its business strategy.
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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" is
effective for fiscal years beginning after June 15, 2000. A Company may also
implement the Statement as of the beginning of any fiscal quarter after
issuance. Statement No. 133 cannot be applied retroactively. Statement No. 133
must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1998 and, at the company's election,
before January 1, 1999. The Company routinely enters into financial instrument
contracts to hedge price risks associated with the sale of crude oil and natural
gas. 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. As a result, adoption
of Statement No. 133 will impact the accounting for and disclosure of the
Company's operations. The Company intends to adopt the provisions of such
statement in accordance with the requirements provided by the statement.
Management is currently assessing the financial statement impact; however, such
impact is not ascertainable at this time.
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Company's revenues, future rate of growth, results of operations,
financial condition and ability to borrow funds or obtain additional capital, as
well as the carrying value of its properties, are substantially dependent upon
prevailing prices of oil and natural gas. Historically, the markets for oil and
natural gas have been volatile, and such markets are likely to continue to be
volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of foreign imports and overall economic conditions. It is impossible to
predict future oil and natural gas price movements with certainty. Declines in
oil and natural gas prices may materially adversely affect the Company's
financial condition, liquidity, and ability to finance planned capital
expenditures and results of operations. Lower oil and natural gas prices also
may reduce the amount of oil and natural gas that the Company can produce
economically. Oil and natural gas prices have declined in the recent past and
there can be no assurance that prices will recover or will not decline further.
See "Business and Properties -- Marketing."
The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of this ceiling test generally requires pricing
future revenue at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time. The
Company may be required to write down the carrying value of its oil and natural
gas properties when oil and natural gas prices are depressed or unusually
volatile. 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,
1997, 1998 and 1999 were 0 Bbls, 0 Bbls and 45,200 Bbls, respectively, and
210,000 MMBTU, 1,760,000 MMBTU and 2,050,000 MMBTU, respectively. Income and
(losses)
32
33
realized by the Company under such swap arrangements were $48,000, $167,000 and
$(412,000) for the years ended December 31, 1997, 1998 and 1999, respectively.
The Company had outstanding no hedge positions as of December 31, 1998. At
December 31, 1999, the Company had 300,000 MMBtu and 30,250 Bbls of
outstanding hedge positions (at an average price of $2.23 per MMBtu and $25.60
per Bbl for January through June 2000.) 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% fluctuation in the price received for
oil and gas production would have an approximate $1.0 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 $48,000, and $167,000 and $(412,000)
or $4.38, and $10.54 and $(5.64) per MMBtu for the years ended December 31,
1997, 1998 and 1999, respectively.
INTEREST RATE RISK. The Company's exposure to changes in interest rates
results from its floating rate debt. In regards to its Revolving Credit
Facility, the result of a 10% fluctuation in short-term interest rates would
impact 2000 cash flow by approximately $120,000.
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, 1999 and 1998, and were determined based upon interest rates
currently available to the Company for borrowings with similar terms. Maturities
of the debt are $3,542,742 in 2000, $6,388,953 in 2001, $5,576,000 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.
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 "2000 Proxy Statement") for its 2000
annual meeting of shareholders. The 2000 Proxy Statement will be filed with the
Securities and Exchange Commission (the "Commission") not later than 120 days
subsequent to December 31, 1999.
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 2000 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 1999.
33
34
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference to
the 2000 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 1999.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference to
the 2000 Proxy Statement which will be filed with the Commission not later than
120 days subsequent to December 31, 1999.
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 -- Statement of Resolution Establishing Series of Shares designated 9%
Series A Preferred Stock (Incorporated herein by reference to
Exhibit 3.2 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
+3.3 -- 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 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). The Company is a party to several debt instruments under
which the total amount of securities authorized does not exceed 10%
of the total assets of the Company and its subsidiaries on a
consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b)
of Regulation S-K, the Company agrees
34
35
to furnish a copy of such instruments to the Commission upon
request.
+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 -- 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).
+4.6 -- 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).
+4.7 -- 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).
+4.8 -- 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 -- Incentive Plan of the Company (Incorporated herein by reference to
Exhibit 10.1 to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.2 -- Employment Agreement between the Company and S.P. Johnson IV
(Incorporated herein by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.3 -- Employment Agreement between the Company and Frank A. Wojtek
(Incorporated herein by reference to Exhibit 10.3 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.4 -- Employment Agreement between the Company and Kendall A. Trahan
(Incorporated herein by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.5 -- Employment Agreement between the Company and George Canjar
(Incorporated herein by reference to Exhibit 10.5 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.6 -- Indemnification Agreement between the Company and each of its
directors and executive officers (Incorporated herein by reference
to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
+10.7 -- S Corporation Tax Allocation, Payment and Indemnification Agreement
among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and
Wojtek (Incorporated herein by reference to Exhibit 10.8 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.8 -- S Corporation Tax Allocation, Payment and Indemnification Agreement
among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson,
Hamilton and Wojtek (Incorporated herein by reference to Exhibit
10.9 to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
35
36
+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, 1999).
+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, Ancell & Wells, Inc.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 1999.
99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of
December 31, 1999.
- ----------
+ Incorporated by reference as indicated.
REPORTS ON FORM 8-K
On December 3, 1999, the Company filed a Current Report on Form 8-K to
report under Item 5 thereof that it had signed agreements relating to certain
of the transactions later describe in the December 22, 1999 Form 8-K.
On December 22, 1999, the Company filed a Current Report on Form 8-K to
report under Item 5 thereof of the following transactions:
(a) the sale of $22,000.00 face value 9% Senior Subordinated Notes due 2007.
(b) the sale of 3,634,364 shares of the Company's Common Stock for $2.20 per
share.
(c) the sale of Warrants to purchase up to 2,760,189 shares of the Company's
Common Stock at $2.20 per share.
(d) the repurchase of all the Company's outstanding Preferred Stock, the
repurchase of 750,000 of the Company's outstanding Warrants and the
reduction of the exercise price of the remaining 250,000 Warrants from
$11.50 to $4.00 per share.
(e) the Company's execution of a securities purchase agreement, a
Shareholders' Agreement, new and amended registration rights agreements,
a compliance sideletter, amendments to employment agreements, bylaws and
certain other agreements.
(f) the execution of the Ninth Amendment to the First Amended Restated and
Combined Loan Agreement dated August 28, 1997, between the Company and
Compass Bank.
36
37
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CARRIZO OIL & GAS, INC.
By: /s/ FRANK A. WOJTEK
-------------------------------------
Frank A. Wojtek
Chief Financial Officer, Vice President,
Secretary and Treasurer
Date: March 30, 2000.
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 30, 2000
-------------------- Officer and Director (Principal
S. P. Johnson IV Executive Officer)
/s/ FRANK A. WOJTEK Chief Financial Officer, Vice March 30, 2000
------------------- President, Secretary, Treasurer
Frank A. Wojtek and Director (Principal
Financial Officer and Principal
Accounting Officer)
/s/ STEVEN A. WEBSTER Chairman of the Board March 30, 2000
---------------------
Steven A. Webster
/s/ DOUGLAS A. P. HAMILTON Director March 30, 2000
--------------------------
Douglas A. P. Hamilton
/s/ PAUL B. LOYD, JR. Director March 30, 2000
---------------------
Paul B. Loyd, Jr.
/s/ CHRISTOPHER C. BEHRENS Director March 30, 2000
--------------------------
Christopher C. Behrens
/s/ ARNOLD L. CHAVKIN Director March 30, 2000
--------------------------
Arnold L. Chavkin
37
38
CARRIZO OIL & GAS, INC.
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Carrizo Oil & Gas, Inc. --
Report of Independent Public Accountants.......................................... F-2
Balance Sheets, December 31, 1998 and 1999........................................ F-3
Statements of Operations for the Years Ended December 31, 1997, 1998 and
1999.......................................................................... F-4
Statements of Shareholders' Equity for the Years Ended December 31, 1997, 1998
and 1999....................................................................... F-5
Statements of Cash Flows for the Years Ended December 31, 1997, 1998 and 1999...... F-6
Notes to Financial Statements...................................................... F-7
F-1
39
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, 1998 and 1999, and the related
statements of operations, shareholders' equity and cash flows for each of the
three years in the period ended December 31, 1999. 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, 1998 and 1999, and the results of its operations and cash flows for each of
the three years in the period ended December 31, 1999, 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 17, 2000
F-2
40
CARRIZO OIL & GAS, INC.
BALANCE SHEETS
ASSETS
As of December 31,
----------------------------
1998 1999
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents $ 1,187,656 $ 11,345,618
Accounts receivable, net of allowance
for doubtful accounts of $480,000 at December 31, 1999 4,227,365 4,424,283
Advances to operators 1,192,079 1,266,770
Other current assets 117,614 487,398
------------ ------------
Total current assets 6,724,714 17,524,069
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and gas properties) (Note 3) 57,878,191 64,336,738
DEFERRED INCOME TAXES -- 820,252
OTHER ASSETS 385,127 985,315
------------ ------------
$ 64,988,032 $ 83,666,374
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 7,886,536 $ 4,095,567
Accrued liabilities 2,004,536 481,239
Advances for joint operations 387,420 1,066,203
Current maturities of long-term debt 930,000 3,542,742
------------ ------------
Total current liabilities 11,208,492 9,185,751
LONG-TERM DEBT 11,126,000 33,627,265
COMMITMENTS AND CONTINGENCIES (Note 6)
MANDATORILY REDEEMABLE PREFERRED STOCK (10,000,000
shares authorized with 320,110.53 shares issued and outstanding
at December 31, 1998)(Note 8)
Issued and outstanding 30,730,695 --
Dividends payable 720,360 --
SHAREHOLDERS' EQUITY:
Warrants (1,000,000 and 3,010,189 outstanding at December 31, 1998 and
1999, respectively) 300,000 765,047
Common stock (40,000,000 shares authorized with 10,375,000 and 14,011,364
issued and outstanding at December 31, 1998 and 1999, respectively) (Note 8) 103,750 140,114
Additional paid in capital 32,845,727 62,608,343
Accumulated deficit (21,907,082) (22,660,146)
Deferred compensation (139,910) --
------------ ------------
11,202,485 40,853,358
------------ ------------
$ 64,988,032 $ 83,666,374
============ ============
The accompanying notes are an integral part of these financial statements.
F-3
41
CARRIZO OIL & GAS, INC.
STATEMENTS OF OPERATIONS
For the Year Ended December 31,
--------------------------------------------
1997 1998 1999
------------ ------------ ------------
OIL AND NATURAL GAS REVENUES $ 8,711,654 $ 7,858,502 $ 10,204,345
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below) 2,334,009 2,769,595 3,035,610
Depreciation, depletion and amortization 2,358,256 3,951,548 4,301,268
Write-down of oil and gas properties -- 20,305,448 --
General and administrative 1,590,358 2,667,234 2,195,364
------------ ------------ ------------
Total costs and expenses 6,282,623 29,693,825 9,532,242
------------ ------------ ------------
OPERATING INCOME (LOSS) 2,429,031 (21,835,323) 672,103
OTHER INCOME AND EXPENSES:
Interest income 53,417 293,736 47,494
Interest expense (713,999) (300,083) (1,549,205)
Interest expense, related parties (137,067) -- (33,454)
Capitalized interest 699,625 291,496 1,547,879
------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES 2,331,007 (21,550,174) 684,817
INCOME TAXES (Note 5) 2,300,267 (2,218,027) (1,057,208)
------------ ------------ ------------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 30,740 (19,332,147) 1,742,025
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE -- -- (77,731)
NET OF INCOME TAXES ------------ ------------ ------------
NET INCOME (LOSS) $ 30,740 $(19,332,147) $ 1,664,294
============ ============ ============
DISCOUNT ON REDEMPTION OF PREFERRED STOCK
(Note 8) -- -- 21,868,413
DIVIDENDS AND ACCRETION ON PREFERRED STOCK -- (2,940,625) (2,417,358)
------------ ------------ ------------
NET INCOME (LOSS) AVAILABLE TO
COMMON SHAREHOLDERS $ 30,740 $(22,272,772) $ 21,115,349
============ ============ ============
BASIC AND DILUTED EARNINGS (LOSS)
PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE (Note 2) $ -- $ (2.15) $ 2.01
============ ============ ============
CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE
NET OF INCOME TAXES $ -- $ -- $ (0.01)
============ ============ ============
BASIC AND DILUTED EARNINGS (LOSS)
PER COMMON SHARE (Note 2) $ -- $ (2.15) $ 2.00
============ ============ ============
BASIC WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING (Note 2) 8,638,699 10,375,000 10,544,365
============ ============ ============
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING (Note 2) 8,809,572 10,375,000 10,546,251
============ ============ ============
The accompanying notes are an integral part of these financial statements.
F-4
42
CARRIZO OIL & GAS, INC.
STATEMENTS OF SHAREHOLDERS' EQUITY (NOTES 1 AND 2)
WARRANTS COMMON STOCK
----------------------- ----------------------- ADDITIONAL RETAINED
PAID IN EARNINGS DEFERRED SHAREHOLDERS'
NUMBER AMOUNT SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION EQUITY
---------- ----------- ----------- ----------- ----------- ------------ ------------- -------------
BALANCE, January 1,
1997 -- $ -- 7,500,000 $ 75,000 $ 4,186,000 $ 334,950 $ -- $ 4,595,950
Net income -- -- -- -- -- 30,740 -- 30,740
Distributions -- -- -- -- (90,000) -- -- (90,000)
Common stock issued -- -- 2,875,000 28,750 28,050,049 -- -- 28,078,799
Deferred compensations
related to certain
stock options -- -- -- -- 699,678 -- (699,678) --
Amortization of
deferred compensation -- -- -- -- -- -- 279,872 279,872
---------- ----------- ----------- ----------- ----------- ------------ ------------- ------------
BALANCE, December 31,
1997 -- $ -- 10,375,000 $ 103,750 $32,845,727 $ 365,690 $ (419,806) $ 32,895,361
Net loss -- -- -- -- -- (19,332,147) -- (19,332,147)
Warrants issued 1,000,000 300,000 -- -- -- -- -- 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 1,000,000 $ 300,000 10,375,000 $ 103,750 $32,845,727 $(21,907,082) $ (139,910) $ 11,202,485
Net income -- -- -- -- -- 1,664,294 -- 1,664,294
Warrants issued 2,760,189 690,047 -- -- -- -- -- 690,047
Warrants cancelled (750,000) (225,000) -- -- 225,000 -- -- --
Common stock issued -- -- 3,636,364 36,364 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 3,010,189 $ 765,047 14,011,364 $ 140,114 $62,608,343 $(22,660,146) $ -- $ 40,853,358
========== =========== =========== =========== =========== ============ ============= ============
The accompanying notes are an integral part of these financial statements.
F-5
43
CARRIZO OIL & GAS, INC.
STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1998 1999
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (loss) $ 30,740 $(19,332,147) $ 1,664,294
Adjustment to reconcile net income (loss) to net
cash provided by operating activities -
Depreciation, depletion and amortization 2,358,256 3,951,548 4,301,268
Discount accretion -- -- 3,537
Interest payable in kind -- -- 48,822
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 (2,300,267) (1,085,216)
Changes in assets and liabilities -
Accounts receivable (1,819,598) (591,861) (196,918)
Other current assets (93,161) (8,981) (369,784)
Other assets -- (249,175) (746,556)
Accounts payable 475,268 416,447 26,580
Accrued liabilities (183,845) 195,788 (1,523,298)
------------ ------------ ------------
Net cash provided by operating
activities 3,067,927 2,386,800 2,200,460
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - accrual basis (32,234,351) (36,569,773) (10,286,305)
Adjustment to cash basis 5,911,784 (1,233,970) (3,817,547)
Advances to operators (1,817,990) 625,911 (74,691)
Advances for joint operations -- 387,420 678,783
------------ ------------ ------------
Net cash used in investing activities (28,140,557) (36,790,412) (13,499,760)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of common stock 28,078,799 -- 7,705,567
Net proceeds from sale of preferred stock
and warrants -- 28,810,431 690,047
Net proceeds from debt issuance 18,544,454 12,056,000 31,235,257
Debt repayments (20,408,934) (7,950,000) (8,173,609)
Proceeds from related party notes 130,545 -- 2,000,000
Redemption of preferred stock -- -- (12,000,000)
Capital distributions (90,000) -- --
------------ ------------ ------------
Net cash provided by financing activities 26,254,864 32,916,431 21,457,262
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 1,182,234 (1,487,181) 10,157,962
CASH AND CASH EQUIVALENTS, beginning of year 1,492,603 2,674,837 1,187,656
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, end of year $ 2,674,837 $ 1,187,656 $ 11,345,618
============ ============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ 151,441 $ 8,587 $ 31,243
============ ============ ============
The accompanying notes are an integral part of these financial statements.
F-6
44
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 or is in the process of acquiring 1,841 square miles of 3-D seismic
data. Additionally, the Company has assembled approximately 195,464 gross acres
under lease or option.
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
the exploration and development of its significant 3-D seismic data and its
acreage under lease or option 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 curtail its planned drilling program.
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.
SALE OF SENIOR SUBORDINATED NOTES, COMMON STOCK AND WARRANTS
In December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to
an investor group led by CB Capital Investors, L.P. 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% 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 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 Company expects the remaining proceeds to be used 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. As of December 31, 1998 and 1999, the Company
also capitalized as oil and natural gas properties $279,896 and $139,910,
respectively, of deferred compensation related to stock options granted to
personnel directly associated with exploration activities. (See Note 7.)
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
F-7
45
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
1997, 1998 and 1999, was $0.69, $1.06 and $1.00, 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 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 1997 or 1999. 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 $300,005 and
$985,315 as of December 31, 1998 and 1999, 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 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 1997, 1998, and 1999 were 0 Bbls, 0
Bbls and 45,200 Bbls, respectively, and 210,000 MMBtu, 1,760,000 MMBtu, and
2,050,000 MMBtu, respectively. Hedging gains (losses) are included in oil and
natural gas revenues and amounted to $48,000, $167,000 and ($412,000) for the
years ended December 31, 1997, 1998 and 1999, respectively. At December 31,
1998, the Company had no outstanding hedged positions. 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.
INCOME TAXES
Through May 15, 1997, Carrizo and its affiliated entities had elected to be
treated as S Corporations under the Internal Revenue Code or were otherwise not
taxed as entities for federal income tax purposes. The taxable income or loss
was therefore allocated to the equity owners of Carrizo and the affiliated
entities. The Company entered into tax indemnification agreements with the
founders of the Company pertaining to periods in which the Company was an S
Corporation.
F-8
46
On May 16, 1997, Carrizo terminated its status as an S corporation and
thereafter became subject to federal income taxes. The Company, beginning with
the termination of its tax exempt status, provides income taxes for the
difference in the tax and financial reporting bases of its assets and
liabilities in accordance with Statement of Financial Accounting Standards
("SFAS") No. 109, "Accounting for Income Taxes." The termination of its tax
exempt status in 1997 required the Company to establish a deferred tax
liability, which resulted in a one-time noncash charge to income in 1997 of
$1,623,000. Had Carrizo been a taxpaying entity prior to May 17, 1997, its net
income and earnings per share would have been as follows:
Unaudited
Pro Forma
1997
-----------
Net income (after pro forma income taxes of $816,852) $ 1,514,155
===========
Diluted earnings per share $ 0.17
===========
Weighted average diluted number of common shares outstanding 8,809,572
===========
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. Oil and natural gas reserve estimates, which are the
basis for unit-of-production depletion and the ceiling test, are inherently
imprecise and are expected to change as future information becomes available.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.
EARNINGS PER SHARE
Supplemental earnings per share information is provided below:
F-9
47
FOR THE YEAR ENDED DECEMBER 31
-------------------------------------------------------------------------------
INCOME SHARES
------------------------------------ -----------------------------------------
1997 1998 1999 1997 1998 1999
-------- ------------ ------------ ----------- ------------ -----------
Net income (loss) before
cumulative effect of change
in accounting principle $ 30,740 $(19,332,147) $ 1,742,025
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 30,740 (22,272,772) 21,193,080 8,638,699 10,375,000 10,544,365
Stock options -- -- -- 170,873 -- 1,886
-------- ------------ ------------ ----------- ------------ -----------
Diluted earnings per share
before cumulative effect of
change in accounting principle
Net Income (loss) available
to common shareholders
plus assumed conversions $ 30,740 $(22,272,772) $ 21,193,080 8,809,572 10,375,000 10,546,251
======== ============ ============ =========== ============ ============
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) 8,638,699 10,375,000 10,544,365
Stock Options -- -- -- 170,873 -- 1,886
-------- ------------ ------------ ----------- ------------ -----------
Diluted earnings per share of
cumulative effect of change
in accounting principle
Net loss available to
common shareholders
plus assumed conversions $ -- $ -- $ (77,731) 8,809,572 10,375,000 10,546,251
======== ============ ============ =========== ============ ============
Net income (loss) $ 30,740 $(19,332,147) $ 1,664,294
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 30,740 (22,272,772) 21,115,349 8,638,699 10,375,000 10,544,365
Stock options -- -- -- 170,873 -- 1,886
-------- ------------ ------------ ----------- ------------ -----------
Diluted earnings per share
Net income (loss) available to
common shareholders plus
assumed conversions $ 30,740 $(22,272,772) $ 21,115,349 8,809,572 10,375,000 10,546,251
======== ============ ============ =========== ============ ============
----------------------------------
PER-SHARE AMOUNT
----------------------------------
1997 1998 1999
---------- --------- --------
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
========== ========= ========
Stock options
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
========== ========= ========
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
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
========== ========= ========
Stock options
Diluted earnings per share
Net income (loss) available to
common shareholders plus
assumed conversions $ -- $ (2.15) $ 2.00
========== ========= ========
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. During the years ended December 31, 1997, 1998 and 1999,
respectively, the Company had outstanding 250,000, 443,550 and 799,620 stock
options, respectively, and warrants to purchase 1,000,000 and 3,010,189 shares
of common stock at December 31, 1998 and 1999, respectively, which were
antidilutive and were therefore 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 both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimatable. 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
F-10
48
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" is
effective for fiscal years beginning after June 15, 2000. A Company may also
implement the Statement as of the beginning of any fiscal quarter after
issuance. Statement No. 133 cannot be applied retroactively. Statement No. 133
must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1998 and, at the company's election,
before January 1, 1999. The Company routinely enters into financial instrument
contracts to hedge price risks associated with the sale of crude oil and natural
gas. 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. As a result, adoption
of Statement No. 133 will impact the accounting for and disclosure of the
Company's operations. The Company intends to adopt the provisions of such
statement in accordance with the requirements provided by the statement.
Management is currently assessing the financial statement impact; however, such
impact is not determinable at this time.
3. PROPERTY AND EQUIPMENT
At December 31, 1998 and 1999, property and equipment consisted of the
following:
DECEMBER 31,
----------------------------
1998 1999
------------ ------------
Proved oil and natural gas properties $ 48,390,909 $ 57,719,508
Unproved oil and natural gas properties 37,060,418 38,145,486
Other equipment 295,854 308,402
------------ ------------
Total property and equipment 85,747,181 96,173,396
Accumulated depreciation, depletion and amortization (27,868,990) (31,836,658)
------------ ------------
Property and equipment, net $ 57,878,191 $ 64,336,738
============ ============
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 $38,145,486 of unproved property costs at
December 31, 1999 being excluded from the amortizable base, $11,817,865,
$22,161,588 and $4,166,033 were incurred in 1997, 1998 and 1999, respectively.
The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next two years.
4. INCOME TAXES
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,
----------------------------------------
1997 1998 1999
----------- ----------- -----------
Provision at the statutory tax rate $ 816,852 $(7,542,561) $ 240,488
Increase (decrease) in valuation allowance pertaining
to expected net operating loss utilization -- 5,324,534 (1,297,696)
Increase resulting from change in tax exempt status 1,483,415 -- --
----------- ----------- -----------
Income tax provision (benefit) $ 2,300,267 $(2,218,027) $(1,057,208)
=========== =========== ===========
F-11
49
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, 1998 and 1999, the tax effects of these temporary
differences resulted principally from the following:
AS OF DECEMBER 31,
--------------------------
1998 1999
----------- -----------
Deferred income tax asset:
Statutory depletion carryfoward $ 78,159 $ 78,159
Timing differences and
net operating losses 10,091,730 11,305,810
Valuation allowance (8,255,902) (7,843,009)
----------- -----------
1,913,987 3,540,960
Deferred income tax liabilities:
Intangible drilling costs 1,378,171 1,378,171
Capitalized interest 535,816 1,077,573
----------- -----------
1,913,987 2,455,744
----------- -----------
Net deferred income tax asset $ -- $ 1,085,216
=========== ===========
The net deferred income tax asset is classified as follows:
AS OF DECEMBER 31,
-------------------------
1998 1999
-------- ----------
Other current assets $ -- $ 264,964
Deferred income taxes -- 820,252
-------- ----------
$ -- $1,085,216
======== ==========
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 the deferred tax asset, net of the valuation
allowance, will be fully realized. The Company has net operating loss
carryforwards totaling approximately $12 million which begin expiring in 2012.
5. LONG-TERM DEBT:
At December 31, 1998 and 1999, long-term debt consisted of the following:
AS OF DECEMBER 31,
----------------------------
1998 1999
------------ ------------
Credit facility:
Borrowing base facility $ 5,056,000 $ 5,876,000
Term loan facility 7,000,000 7,000,000
Senior subordinated notes -- 19,226,082
Senior subordinated notes,
related parties -- 2,136,230
Vendor notes payable -- 2,931,695
------------ ------------
12,056,000 37,170,007
Less: current maturities (930,000) (3,542,742)
------------ ------------
$ 11,126,000 33,627,265
============ ============
In connection with the Offering, Carrizo amended its existing credit
facility with Compass Bank ("Compass"), to provide for a maximum loan amount of
$25 million, subject to borrowing base limitations. Under this facility, the
principal outstanding is due and payable upon maturity in January 2002, with
interest due monthly. This facility was subsequently amended 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"). 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.
F-12
50
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, 1998 and 1999, amounts outstanding under the Borrowing Base
Facility totaled $5,056,000 and $5,876,000, respectively, with an additional
$1,020,000 and $1,208,392, respectively, available for future borrowings. The
Borrowing Base totaled $7,308,382 at December 31, 1999. The Borrowing Base
Facility was also available for letters of credit, one of which has been issued
for $224,000 at December 31, 1998 and 1999. The weighted average interest rates
for 1998 and 1999 on the Facility were 8 and 9 percent, respectively. Certain
members of the Board of Directors have provided $4 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.
The Company had $7,000,000 outstanding under the Term Loan at December 31, 1998.
In March 1999, the Company borrowed an additional $2 million on the term loan
portion of the Company Credit Facility, increasing outstanding borrowings under
the Term Loan to $9 million. 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. In December 1999, the additional $2 million under the term loan
was repaid with proceeds from the sale of subordinated notes, common stock and
warrants leaving $7,000,000 outstanding at December 31, 1999. 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.
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.
In November 1999, certain members of the Board of Directors provided a
bridge loan in the amount of $2,000,000 to the Company secured by certain oil
and natural gas properties. This bridge loan bore interest at 14% 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 December 1999, the Company consummated the sale of $22 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") to an
investor group led by CB Capital Investors, L.P. which included certain members
of the Board of Directors. As discussed in Note 7, 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.
Interest is payable quarterly beginning March 31, 2000. The Company may elect to
increase the amount of the Subordinated Notes for 60% of the interest which
would otherwise be payable in cash. Such Senior Subordinated Notes had a fair
market value at December 31, 1999 (16 days subsequent to issuance) of
approximately $22 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 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.
Estimated maturities of long-term debt are $3,542,742 in 2000,
$6,388,953 in 2001, $5,576,000 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 at December 31, 1999 and bear interest at rates of 8 percent to 10
percent. The weighted average interest rates of such notes was 9 percent in
1999.
F-13
51
6. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
At December 31, 1999, Carrizo was obligated under a noncancelable operating
lease for office space. Rent expense for the years ended December 31, 1997, 1998
and 1999, was $80,000, $108,700 and $108,700, respectively. The Company is
obligated for remaining lease payments in 2000 of $54,350.
7. SHAREHOLDERS' EQUITY
On June 4, 1997, the board of directors authorized a 521-for-1 split of the
Company's common stock and increased the number of authorized shares to 40
million shares of common stock and 10 million shares of preferred stock. All
common share amounts presented in these financial statements are presented on a
retroactive, post-split basis.
In December 1999, 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. 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 an 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 $279,896 and $139,910 being recorded in the
years ended December 31, 1998 and 1999, respectively.
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, 1999:
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 12/31/99 LIFE IN YEARS PRICE AT 12/31/99 PRICE
- ------------------------------------ ----------- ------------- -------- ----------- --------
$1.75-2.00 182,500 9.54 $ 1.96 -- --
$3.60 222,120 6.97 $ 3.60 222,120 $ 3.60
$6.00-7.00 172,500 8.44 $ 6.17 57,500 $ 6.17
$11.00 250,000 7.40 $ 11.00 166,667 $ 11.00
F-14
52
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. Had
compensation cost been determined consistent with SFAS No. 123 "Accounting for
Stock Based Compensation" for all options, the Company's net income and earnings
per share would have been as follows:
1997 1998 1999
-------- ------------- ------------
Net income (loss) available to
common shareholders
As reported $ 30,740 $ (22,272,772) $ 21,115,349
Pro forma $(75,582) $ (23,020,534) $ 20,292,252
Diluted earnings (loss) per share
As reported $ -- $ (2.15) $ 2.00
Pro forma $ (0.01) $ (2.22) $ 1.94
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 1997, 1998 and 1999: risk free interest rate of 6.26%, 5.81% and 6.81%
respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 39.4%, 80.6% and 70.0%, respectively.
The Company may grant options ("Incentive Plan Options") to purchase up to
1,000,000 shares under the Incentive Plan and has granted options on 605,000
shares through December 31, 1999. Under the Incentive Plan, the option exercise
price equals the stock market price on the date of grant. Options granted under
the plan vest ratably over three years and have a term of ten years. Through
December 31, 1999, no stock options had been exercised. A summary of the status
of the Company's stock options at December 31, 1997, 1998 and 1999 is presented
in the table below:
1997
------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year 138,825 $ 3.60 $3.60
Granted (Pre-IPO Options) 83,295 $ 3.60 $3.60
Granted (Incentive Plan Options) 250,000 $ 11.00 $11.00
---------- --------
Outstanding at end of year 472,120 $ 7.52 $3.60 - 11.00
========== ========
Exercisable at end of year 120,315 $ 3.60
Weighted average of fair value of
options granted during year $ 6.90
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 year $ 3.00
F-15
53
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
========== ========
Exercisable at end of year 446,286 $ 6.70
Weighted average of fair value of
options granted during the year $ 1.34
8. 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 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 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.
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 is $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, 1997.
F-16
54
YEAR ENDED DECEMBER 31,
-----------------------------
1997 1998
----------- -------------
Pro forma revenues $ 8,718,736 $ 9,198,212
=========== =============
Pro forma net income (loss) $ 33,237 $ (18,523,141)
=========== =============
Pro forma net income (loss) per share:
Basic $ -- $ (2.07)
=========== =============
Diluted $ -- $ (2.07)
=========== =============
11. RELATED-PARTY TRANSACTIONS
In August 1996, the Company entered into the Master Technical Services
Agreement (the MTS Agreement) with Reading & Bates Development Co. (R&B), which
is a subsidiary of R&B Falcon Corporation, a company that was created by the
merger of Falcon Drilling, Inc. and Reading & Bates Corporation. Mr. Loyd, a
member of the board of the Company, was the chairman of the board, president,
chief executive officer and a director of Reading & Bates Corporation. Under the
MTS Agreement, certain employees of the Company provide engineering and
technical services to R&B at market rates in connection with R&B's technical
service, procurement and construction projects in offshore drilling and floating
production. The Company provided $103,161 in service fees under this agreement
in 1997. No services were performed under this agreement in 1998 or 1999.
The Company had an agreement with Loyd & Associates Inc., which is owned by
Paul Loyd, a director of Carrizo, and Frank Wojtek, vice president, chief
financial officer and a director of Carrizo, to provide certain financial
consulting and administrative services at market rates to the Company. Payments
were made monthly and total payments to Loyd & Associates Inc. for services
rendered were $38,113 in 1997. These expenditures were included in general and
administrative expenses for each year. This arrangement was terminated in
August, 1997 concurrent with the Company's initial public offering.
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 are members of the Board of Directors of both the
Company and R & B Falcon Corporation ("R & B"). In addition, Mr. Loyd was the
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.
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:
YEAR ENDED DECEMBER 31,
---------------------------------------
1997 1998 1999
----------- ----------- -----------
Property acquisition costs
Unproved $14,222,674 $ 9,618,647 $ 4,166,033
Proved 5,491,839 16,196,887 472,229
Exploration cost 9,328,210 10,429,247 3,163,309
Development costs 2,257,375 313,391 936,855
----------- ----------- -----------
Total costs incurred (1) $31,300,098 $36,558,172 $ 8,738,426
=========== =========== ===========
- ----------
(1) Excludes capitalized interest on unproved properties of $699,625, $291,496
and 1,547,879 for the years ended December 31, 1997, 1998 and 1999,
respectively.
F-17
55
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, 1998 and 1999,
and the related discounted future net cash flows before income taxes are based
on estimates prepared by Ryder Scott Company and Fairchild, Ancell & 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,
--------------------------------------
1997 1998 1999
---------- ---------- ----------
Proved developed and undeveloped reserves -
Beginning of year 3,895,000 5,169,500 3,647,000
Purchase of oil and gas properties -- 81,000 --
Discoveries 285,000 82,000 101,000
Extensions 1,102,000 14,000 12,000
Revisions -- (1,559,500) 1,296,000
Production (112,500) (140,000) (179,000)
---------- ---------- ----------
End of year 5,169,500 3,647,000 4,877,000
========== ========== ==========
Proved developed reserves at end of year 1,146,000 1,112,000 997,000
========== ========== ==========
F-18
56
THOUSANDS OF CUBIC FEET
OF NATURAL GAS
AT DECEMBER 31,
-----------------------------------------
1997 1998 1999
----------- ----------- -----------
Proved developed and undeveloped reserves -
Beginning of year 12,148,000 12,142,000 10,155,000
Purchases of oil and gas properties 7,696,000 1,325,000 --
Discoveries and extensions 6,946,000 4,039,000 4,820,000
Revisions (7,190,000) (4,696,000) (417,000)
Sales of oil and gas properties (4,709,000) -- --
Production (2,749,000) (2,655,000) (3,235,000)
----------- ----------- -----------
End of year 12,142,000 10,155,000 11,323,000
=========== =========== ===========
Proved developed reserves at end of year 9,299,000 9,097,000 7,030,000
=========== =========== ===========
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,
------------------------------------------
1997 1998 1999
------------ ------------ ------------
Future cash inflows $103,842,000 $ 59,095,000 $140,851,000
Future oil and natural gas operating expenses 55,484,000 28,582,000 46,679,000
Future development costs 13,230,000 4,841,000 12,428,000
Future income tax expenses 6,870,000 -- 11,952,000
------------ ------------ ------------
Future net cash flows 28,258,000 25,672,000 69,792,000
10% annual discount for estimating timing of cash flows 7,285,000 6,917,000 27,062,000
------------ ------------ ------------
Standard measure of discounted future net cash flows $ 20,973,000 $ 18,755,000 $ 42,730,000
============ ============ ============
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 1997, 1998 and 1999 future cash flows
were $16.37, $10.15 and $23.40 for oil, respectively and $2.56, $2.18 and $2.35
for natural gas, respectively. Future operating expenses and development costs
are computed primarily by the Company's petroleum engineers by estimating the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves at the end of the year, based on year end costs and
assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax
basis and applicable tax credits. 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.
F-19
57
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:
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1998 1999
------------ ------------ ------------
Changes due to current-year operations -
Sales of oil and natural gas, net of oil
and natural gas operating expenses $ (6,378,000) $ (5,089,000) $ (7,169,000)
Extensions and discoveries 16,074,000 5,003,000 9,095,000
Purchases of oil and gas properties 6,954,000 2,889,000 --
Changes due to revisions in standardized variables
Prices and operating expenses (29,115,000) (5,820,000) 32,560,000
Income taxes 11,410,000 5,098,000 (8,447,000)
Estimated future development costs (2,683,000) 6,757,000 (4,581,000)
Revision of quantities (3,449,000) (9,056,000) 11,770,000
Sales of reserves in place (3,933,000) -- --
Accretion of discount 4,634,000 2,607,000 1,876,000
Production rates (timing) and other (5,562,000) (4,607,000) (11,129,000)
------------ ------------ ------------
Net change (12,048,000) (2,218,000) 23,975,000
Beginning of year 33,021,000 20,973,000 18,755,000
------------ ------------ ------------
End of year $ 20,973,000 $ 18,755,000 $ 42,730,000
============ ============ ============
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-20
58
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
FIRST SECOND THIRD FOURTH
------------ ------------ ------------ ------------
1999
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
============ ============ ============ ============
1998
Revenues $ 2,338,882 $ 1,848,765 $ 1,508,897 $ 2,161,958
Costs and expenses, net 2,153,347 1,955,539 2,004,086 21,077,677
------------ ------------ ------------ ------------
Net income (loss) $ 185,535 $ (106,774) $ (495,189) $(18,915,719)
============ ============ ============ ============
Dividends and accretion (670,494) (741,444) (756,595) (772,091)
------------ ------------ ------------ ------------
Net Income (loss) available
To common shareholders $ (489,959) $ (848,218) $ (1,251,784) $(19,687,810)
============ ============ ============ ============
Diluted net income (loss)
per share (1) $ (0.05) $ (0.08) $ (0.12) $ (1.90)
============ ============ ============ ============
- ----------
(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-21
59
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, 1997
(Incorporated herein by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the
Company.
+3.2 -- Statement of Resolution Establishing Series of Shares
designated 9% Series A Preferred Stock.
+3.3 -- 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,
1997 (Incorporated herein by reference to Exhibit 4.1
to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997).
+4.2 -- First Amendment to First Amended, Restated, and
Combined Loan Agreement between the Company and Compass
Bank dated December 23, 1997.
+4.3 -- Second Amendment to First Amended, Restated, and
Combined Loan Agreement between the Company and Compass
Bank dated December 30, 1997.
-- The Company is a party to several debt instruments
under which the total amount of securities authorized
does not exceed 10% of the total assets of the Company
and its subsidiaries on a consolidated basis. Pursuant
to paragraph 4(iii)(A) of Item 601(b) of Regulation
S-K, the Company agrees to furnish a copy of such
instruments to the Commission upon request.
+10.1 -- Incentive Plan of the Company (Incorporated herein by
reference to Exhibit 10.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+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.
+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)).
60
+10.8 -- S Corporation Tax Allocation, Payment and
Indemnification Agreement among Carrizo Production,
Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and
Wojtek (Incorporated herein by reference to Exhibit
10.9 to the Company's Registration Statement on Form
S-1 (Registration No. 333-29187)).
+10.9 -- Form of Amendment to Executive Officer Employment
Agreement. (Incorporated herein by reference to Exhibit
99.3 to the Company's Current Report on Form 8-K dated
January 8, 1998).
+10.10 -- Amended Enron Warrant Certificates (Incorporated
herein by reference to Exhibit 4.1 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.11 -- Securities Purchase Agreement dated December 15, 1999
among the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P.
Hamilton and Steven A. Webster (Incorporated herein by
reference to Exhibit 99.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).
+10.12 -- Shareholders Agreement dated December 15, 1999 among
the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P.
Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A.
Wojtek and DAPHAM Partnership, L.P. (Incorporated
herein by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.13 -- Warrant Agreement dated December 15, 1999 among
the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd, Jr., Douglas A.P.
Hamilton and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.14 -- Registration Rights Agreement dated December 15, 1999
among the Company, CB Capital Investors, L.P. and
Mellon Ventures, L.P. (Incorporated herein by reference
to Exhibit 99.4 to the Company's Current Report on Form
8-K dated December 15, 1999).
+10.15 -- Amended and Restated Registration Rights Agreement
dated December 15, 1999 among the Company, Paul B.
Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster,
S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to
Exhibit 99.5 to the Company's Current Report on Form
8-K dated December 15, 1999).
+10.16 -- Compliance Sideletter dated December 15, 1999 among the
Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to
Exhibit 99.6 to the Company's Current Report on Form
8-K dated December 15, 1999).
+10.17 -- Form of Amendment to Executive Officer Employment
Agreement (Incorporated herein by reference to Exhibit
99.7 to the Company's Current Report on Form 8-K dated
December 15, 1999).
+10.18 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 to
the Company's Current Report on Form 8-K dated December
15, 1999).
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, Ancell & Wells, Inc.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report of Ryder Scott Company
Petroleum Engineers as of December 31, 1999.
99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells
Inc. as of December 31, 1999.
- ----------
+ Incorporated by reference as indicated.