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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 R