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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, 1997 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
HOUSTON, TEXAS 77079
(Principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (281) 496-1352
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
At March 25, 1998, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $26.9 million
based on the closing price of such stock on such date of $6.75.
At March 25, 1998, the number of shares outstanding of registrant's Common
Stock was 10,375,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1998 Annual
Meeting of Shareholders to be held on May 20, 1998 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, 1997.
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TABLE OF CONTENTS
PAGE
----
PART I...................................................... 1
Item 1. and Item 2. Business and Properties............... 1
Item 3. Legal Proceedings................................. 23
Item 4. Submission of Matters to a Vote of Security
Holders................................................ 23
Executive Officers of the Registrant...................... 23
PART II..................................................... 24
Item 5. Market for Registrant's Common Stock and Related
Shareholder Matters.................................... 24
Item 6. Selected Financial Data........................... 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of
Operations....................................... 28
Item 8. Financial Statements and Supplementary Data....... 34
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure............... 34
PART III.................................................... 35
Item 10. Directors and Executive Officers of the
Registrant............................................. 35
Item 11. Executive Compensation........................... 35
Item 12. Security Ownership of Certain Beneficial Owners
and Management......................................... 35
Item 13. Certain Relationships and Related Party
Transactions........................................... 35
PART IV..................................................... 35
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................... 35
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PART I
ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES
GENERAL
Carrizo Oil & Gas, Inc. ("Carrizo" or the "Company") is an independent oil
and gas company engaged in the exploration, development, exploitation and
production of natural gas and crude oil. The Company's operations are currently
focused onshore in proven oil and gas producing trends along the Gulf Coast,
primarily in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends. The
Company believes that the availability of economic onshore 3-D seismic surveys
has fundamentally changed the risk profile of oil and gas exploration in these
regions. Recognizing this change, the Company has aggressively sought to control
significant prospective acreage blocks for targeted, proprietary, 3-D seismic
surveys. As of December 31, 1997, the Company had assembled approximately
419,953 gross acres under lease or option. 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.
Approximately 60% of the Company's current acreage position is covered by
3-D seismic data that the Company has acquired, or is in the process of
acquiring, in its first 18 seismic surveys. The Company expects to acquire or
cause to be acquired additional 3-D seismic data during the remainder of 1998
that will cover approximately 80% of its remaining current acreage position.
From the data generated by its first seven proprietary seismic surveys, covering
200 square miles (128,000 acres), 94 drillsites were identified. The Company's
capital budget for 1998 of approximately $43.3 million includes amounts for the
acquisition of additional 3-D seismic data and for the drilling of approximately
150 gross wells (71.8 net) in 1998 with an anticipated 48% average working
interest. 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 1998.
The Company's primary drilling targets have been shallow (from 4,000 to
7,000 feet), normally pressured reservoirs that generally involve moderate cost
(typically $200,000 to $500,000 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 $2 million per completed well) and risk. The Company often 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, 1997, the Company operated 69 producing
oil and gas wells, which accounted for 43% of the wells in which the Company had
an interest.
The Company has experienced rapid increases in reserves, production and
EBITDA since its inception in 1993 due to the growth of its 3-D based drilling
and development activities. From January 1, 1996 to December 31, 1997, the
Company participated in the drilling of 90 gross wells (34.6 net) with a
commercial well success rate of approximately 69%. This drilling success
contributed to the Company's total proved reserves as of December 31, 1997 of
approximately 43.2 Bcfe, with a PV-10 Value of $26.1 million. From inception
through December 31, 1997, the Company's average finding and development cost
was approximately $.95 per Mcfe. The Company's production has increased 79% from
1,916 MMcfe for the year ended December 31, 1996 to 3,424 MMcfe for the year
ended December 31, 1997. EBITDA has also increased significantly from $2,296,000
for the year ended December 31, 1996 to $4,787,000 for the year ended December
31, 1997.
Certain terms used herein relating to the oil and natural gas industry are
defined in "Glossary of Certain Industry Terms" below.
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EXPLORATION APPROACH
The Company generally seeks 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 this
data to identify or evaluate prospects before drilling the prospects that fit
its risk/ reward criteria. The Company typically seeks to explore in locations
within its core areas of expertise that it believes have (i) numerous
accumulations of normally pressured reserves at shallow depths and in geologic
traps that are difficult to define without the interpretation of 3-D seismic
data and (ii) the potential for large accumulations of deeper, over-pressured
reserves.
As a result of the increased availability of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company has relied almost exclusively on the interpretation of
3-D seismic data in its exploration strategy. The Company generally does not
invest any substantial portion of the costs for an exploration well without
first interpreting 3-D seismic data. The principal advantage of 3-D seismic data
over traditional 2-D seismic analysis is that it affords the geoscientist the
ability to interpret a three dimensional cube of data 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. Substantially all of the Company's operations are
conducted through joint operations with industry participants. As of December
31, 1997, the Company was actively involved in 40 project areas. The Company
intends to further increase the number and size of seismic data acquisition
projects in which it participates to accelerate its exploration activities.
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% of
the project area for these proprietary surveys. The size of these surveys has
ranged from 10 to 70 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. Similarly, in identifying specific
drillsites from within a project area, the Company has relied upon
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outside contract geoscientists and joint venture partners who have worked with
the Company's own geoscientists. As of December 31, 1997, over 20 geoscientists
from this network were devoting some or all of their time to identifying project
areas or evaluating drillsites in which the Company expects to have an interest.
Similarly, the Company also utilizes outside independent landmen with expertise
in a particular project area. This outsourcing strategy has enabled the Company
to control costs without maintaining a large internal land and exploration
department.
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 15 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. In some cases,
the Company may thereafter relinquish its operator status in order to
concentrate its resources on exploration activities, especially if the Company
has had successful prior experience with an industry partner acting as operator.
As of December 31, 1997, the Company operated 69 producing oil and natural gas
wells, which ranged in depth from 450 feet to greater than 6,100 feet.
The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to use
reliable, high quality, used equipment in place of new equipment to achieve cost
savings. The Company also seeks to minimize cycle time from drilling to hook-up
of wells, thereby accelerating cash flow and improving ultimate project
economics.
The Company seeks to use advanced production techniques to exploit and
expand its reserve base. Following the discovery of proved reserves, the Company
typically continues to evaluate its producing properties through the use of 3-D
seismic data to locate undrained fault blocks and identify new drilling
prospects and performs further reserve analysis and geological field studies
using computer aided exploration techniques. The Company 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
The Company is currently evaluating approximately 40 exploration project
areas. As of December 31, 1997, the Company had an existing 3-D seismic database
of 930 square miles and was acquiring an additional 240 square miles of data
(totaling 1,170 square miles of 3-D seismic data). To date, all project areas
for which seismic data has been interpreted have yielded multiple prospects and
drillsites. The Company is continuing to receive and interpret data covering
these project areas and believes that each project area has the potential for
additional prospects and drillsites.
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1998 EXPLORATION PROGRAM
SQ. MILES OF 3-D
GROSS SEISMIC DATA AT
ACREAGE DECEMBER 31, 1997
LEASED OR -----------------------
UNDER BUDGETED 1998 AVERAGE
OPTION AT EXISTING FOR BUDGETED AVERAGE NET
DEC. 31, OR BEING ACQUISITION GROSS WORKING REVENUE
PROJECT AREAS 1997 ACQUIRED 1998 WELLS(1) INTEREST(2) INTEREST(2)
------------- --------- -------- ----------- -------- ----------- -----------
TEXAS
Starr/Hidalgo........... 9,186 340(3) -- 6 50.0% 37.5%
Encinitas/Kelsey........ 9,300 32 -- 3 27.5% 23.0%
Buckeye................. 34,303 62 -- 14 50.0% 39.0%
La Rosa................. 8,249 22 -- 6 31.5% 23.6%
Mexican Sweetheart...... 30,795 40 -- 4 25.0% 18.8%
McFaddin Ranch.......... 5,374 15 -- 4 37.5% 28.1%
Cologne................. 18,200 40 -- 23 25.0% 18.8%
South Cabeza Creek...... 7,128 -- 78 4 52.5% 39.4%
Western 325............. -- 320(3) -- 2 50.0% 37.5%
Lance................... 18,536 30 -- 1 25.0% 19.3%
Highway 59.............. 4,995 -- 20 4 20.0% 15.0%
Geronimo................ 29,358 107 -- 4 15.0% 11.3%
RPP Welder.............. 31,182 60 -- 9 15.0% 11.3%
Midway.................. 1,235 -- 15 2 100.0% 75.0%
Lost Bridge............. 5,065 16 -- 6 50.0% 37.5%
Drake 202............... 3,877 20 -- 8 100.0% 80.0%
Metro................... 11,349 20 -- 4 25.0% 18.7%
North Heyser............ 8,100 13 -- 3 47.0% 34.7%
Victoria................ 21,288 -- 60 5 57.0% 42.75%
Matagorda............... 16,093 -- 51 6 87.5% 64.75%
Driscoll Ranch.......... 23,135 -- 80 7 50.0% 37.0%
Other (16 Areas)........ 110,042 33 268 17 66.0% 48.8%
LOUISIANA
North Chalkley.......... 1,130 -- -- 0 18.0% 13.5%
Atchafalaya............. 3,611 -- -- 1 55.4% 41.5%
Live Oak................ 350 -- -- 1 15.0% 10.8%
Other (5 Areas)......... 8,072 -- 14 6 28.7% 21.7%
------- ----- --- ---
Total........... 419,953 1,170 586 150
======= ===== === ===
- ---------------
(1) Consists of (i) identified drill sites included in the Company's 1998
capital budget that are fully evaluated, leased and have been or are
scheduled to be drilled in 1998 and (ii) wells included in the Company's
1998 capital budgets, but as to which 3-D seismic data has either not been
obtained or fully evaluated, or for which the Company has not yet acquired
leases or option rights. A portion of the number of wells indicated is based
upon statistical results of drilling activities in 3-D project areas that
the Company believes are geologically similar.
(2) Anticipated interests based upon ownership or contractual rights as of
December 31, 1997.
(3) Represents non-proprietary "group shoots" in which the Company is a
participant.
Set forth below are descriptions of the Company's key project areas where
it is actively exploring for potential oil and natural gas prospects and in some
cases currently has production. The 3-D surveys the Company is using to analyze
its project areas range from regional, non-proprietary "group shoots" to single
field proprietary surveys. The Company has, in many cases, participated in these
project areas with industry partners to share the up-front costs associated with
obtaining option arrangements with landowners, seismic
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data acquisition and related data interpretation, to mitigate its exploration
risk and to increase the number of projects in which it is able to participate.
Although the Company is currently pursuing prospects within the project
areas described below, and has budgeted to drill the number of wells set forth
in the preceding table, there can be no assurance that these prospects will be
drilled at all or within the expected time frame. In particular, budgeted wells
that are based upon statistical results of drilling activities in other project
areas 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, (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 (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 the identified drillsites
or budgeted wells discussed will, if drilled, encounter reservoirs of
commercially productive oil or natural gas.
The success of the Company will be materially dependent upon the success of
its exploratory drilling program. Exploratory drilling involves numerous risks,
including the risk that no commercially productive oil or natural gas reservoirs
will be encountered. The cost of drilling, completing and operating wells is
often uncertain, and drilling operations may be curtailed, delayed or canceled
as a result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rigs 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 of 2-D seismic
data, exploratory drilling remains a speculative activity. Even when fully
utilized and properly interpreted, 3-D seismic data and other advanced
technologies only assist geoscientists in identifying subsurface structures and
do not enable the interpreter to know whether hydrocarbons are in fact present
in such structures. In addition, the use of 3-D seismic data and other advanced
technologies requires greater predrilling expenditures than traditional drilling
strategies and the Company could incur losses as a result of such expenditures.
The Company's future drilling activities may not be successful, and if
unsuccessful, such failure will have a material adverse effect on the Company's
results of operations and financial condition. There can be no assurance that
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
included 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. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
The reserve data set forth below is based upon the reserve report (the
"Ryder Scott Report") dated February 26, 1998 prepared by Ryder Scott Company,
independent petroleum engineers ("Ryder Scott"), and the reserve report (the
"Fairchild Report" and collectively with the Ryder Scott Report, the "Reserve
Reports") dated February 25, 1998 prepared by Fairchild, Ancell & Wells, Inc.,
independent petroleum
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engineers ("Fairchild"). There are numerous uncertainties in estimating
quantities of proved reserves, including many factors beyond the control of the
Company. See "-- Oil and Natural Gas Reserves."
TEXAS
Starr/Hidalgo Project Area: Frio and Vicksburg Formations
The Starr/Hidalgo Project Area is located in Starr and Hidalgo Counties,
Texas in the Frio and Vicksburg formations. The Company and a partner licensed
approximately 340 square miles of non-proprietary 3-D seismic data that was
delivered during August 1995 and June 1996. More than 70 prospects have been
identified in the shallow Frio trend and the deeper, structurally complex
Vicksburg trend, as well as two large prospects in the relatively unexplored
Eocene trend. As of December 31, 1997, the Company and its partner had leases
covering 9,186 acres in this project area and currently control 25 of these
prospects (11 Frio, 13 Vicksburg and one Eocene). The Company sold a portion of
its interest in six of the deeper and riskier Vicksburg and Eocene prospects to
industry partners. During the six months ended June 30, 1997, the Company's
share of production from wells in this production area was approximately 36
Bbls/d of oil and 3.4 MMcf/d of natural gas. Primarily as a result of the
curtailment of production by the wells in the Wheeler area by the Texas Railroad
Commission, during the quarter ended December 31, 1997, the Company's share of
production from wells in this project area was approximately 12 Bbls/d of oil
and 0.8 MMcf/d natural gas. As of December 31, 1997, the Company and its
partners had drilled a total of 23 wells in this project area, resulting in 15
producing wells. The estimated proved reserves net to the Company for this
project area was 130 MBbls of oil and 1.6 BCF of natural gas at December 31,
1997. The Company and its partners have identified 6 locations that have been or
are budgeted to be drilled during 1998. The Company believes that continuing
interpretation and seismic processing of the Starr/Hidalgo Project Area 3-D
seismic data will result in additional prospects and drilling locations.
Encinitas/Kelsey Project Area: Frio and Vicksburg Formations
The Encinitas/Kelsey Project Area is located in Brooks County, Texas in the
Frio and Vicksburg formations. The Company acquired an interest in leases
covering 9,300 acres in this area in December 1994 to re-develop the property.
Upon acquisition of its interests in this project area, the Company undertook a
comprehensive petrophysical study and acquired a 32 square mile 3-D seismic
survey. This effort has resulted in the identification of numerous Frio and
Vicksburg prospects. During the quarter ended December 31, 1997, the Company's
share of production from wells in this project area was approximately 33 Bbls/d
of oil, 86 Bbls/d of natural gas liquids and 2.5 MMcf/d of natural gas. As of
December 31, 1997, the Company and its partners had drilled a total of 12 wells
in this project area, resulting in 10 producing wells. The estimated proved
reserves net to the Company for this project area was 27.8 MBbls of oil, 192.3
MBbls of natural gas liquids and 3.6 BCF of natural gas at December 31, 1997.
The Company and its partners have identified three locations that are budgeted
to be drilled in 1998.
Buckeye Project Area: Wilcox, Hockley, Pettus and Yegua Formations
The Buckeye Project Area is located in Live Oak County, Texas. As of
December 31, 1997, the Company and its partner held 13,492 acres under lease and
20,811 acres under option and have acquired an approximately 62 square mile 3-D
seismic survey. The exploration objectives for the Buckeye Project Area are the
shallow zones of the Hockley, Pettus and Yegua formations and the deep zones of
the expanded Upper Wilcox formation. The data for this project area was received
from processing in 1997 and initial interpretation has generated 38 shallow
prospects. During the quarter ended December 31, 1997, the Company's share of
production from wells in this project area was approximately 125 Bbls/d of oil
and 1.7 MMcf/d of natural gas. As of December 31, 1997, the Company and its
partners have drilled 24 wells in this project area, resulting in 17 producing
wells. The estimated proved reserves net to the Company for this project area
was 118.3 MBbls of oil and 1.4 BCF of natural gas at December 31, 1997. The
remaining prospects are planned to be drilled in 1998.
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La Rosa Project Area: Frio Formation
The La Rosa Project Area is located in Refugio County, Texas over a
producing field leasehold of 3,689 acres. The area covers Frio
barrier/strandplain sands productive down to 8,200 feet. Data is currently being
integrated from a 3-D seismic survey over 22 square miles that was conducted by
the Company during the first quarter of 1997. As of December 31, 1997, the
Company's leases covered 3,689 acres and its seismic options covered 4,560 acres
in this project area. During the quarter ended December 31, 1997, the Company's
share of production from wells in this project area was approximately 8 Bbls/d
of oil and 0.2 MMcf/d natural gas. As of December 31, 1997, the Company and its
partners have drilled one well in this project area, resulting in one producing
well. The estimated proved reserves net to the Company for this project area was
10.2 MBbls of oil and 0.2 BCF of natural gas at December 31, 1997. Additional
drilling opportunities within and peripheral to the producing field exist and
are being evaluated for 1998 drilling.
Mexican Sweetheart Project Area: Frio Formation
The Mexican Sweetheart Project Area is located in southwestern Jackson
County, Texas in the Frio producing trend. Secondary objectives for this project
area include the shallow Miocene trend, the downdip Yegua and Wilcox trends. The
area is directly south of successful 3-D seismic projects conducted by the
Company's partners in this project and covers historical field discoveries. The
Company has planned and directed a 40 square mile 3-D seismic survey covering
the project area. The Company will seek to use the 3-D seismic data to identify
shallow objectives, delineate reservoir compartments for drilling of bypassed
reserves and identify flank prospects and deeper, higher risk prospects in the
Yegua and Upper Wilcox trends, which the Company would seek to explore with an
industry partner. As of December 31, 1997, the Company's leases covered 848
acres and its seismic options covered 29,947 acres in this project area.
Interpretation of the 3-D has led to four initial prospects budgeted to be
drilled in 1998.
McFaddin Ranch Project Area: Miocene and Frio Formations
The McFaddin Ranch Project Area is located in Victoria County, Texas in the
Miocene and Frio formations. Data is currently being interpreted from a 15
square mile 3-D seismic survey conducted in the first quarter of 1997. The
Company has identified and budgeted to drill four initial prospects in this
project area during 1998. As of December 31, 1997, the Company's leases in this
project area covered 5,374 acres.
Cologne Project Area: Frio Formation
The Cologne Project Area is located in Goliad and Victoria Counties, Texas
in the Frio formation. A secondary objective for this project area is Wilcox
formations. The area covers several historical field discoveries. A 40 square
mile 3-D seismic survey has been shot over the project area, has been
interpreted and yielded drillsites to evaluate prospectively from the Frio
through the Wilcox formations. As of December 31, 1997, the Company's multiple
seismic options covered 18,200 acres in this project area. Drilling on the 23
identified prospects is expected to begin in April, 1998.
South Cabeza Creek Project Area: Frio Formation to Lower Wilcox Sands
The South Cabeza Creek Project Area is located in Goliad County, Texas in
an area having significant production in the shallow Frio and lower Wilcox
trends. The Company is currently in the process of acquiring seismic options and
leases for participation in a 78 square mile non-exclusive 3-D seismic shoot in
the project area that is currently scheduled to seek to begin in the second
quarter of 1998. The Company intends to use the 3-D seismic data to identify
potential Frio, Vicksburg and Yegua opportunities and to verify and optimize a
Wilcox prospect. The Company currently has 525 acres under lease and 6,603 acres
under seismic option in this project area.
Western 325 Project Area: Wilcox and Jackson-Yegua Formations
The Western 325 Project Area is located in Webb and Duval Counties, Texas
in the Wilcox and Jackson-Yegua formations. The Company and a partner have
joined others in underwriting a non-proprietary 3-D
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seismic data shoot covering approximately 320 square miles in the project area.
Multiple prospects have been identified from data covering approximately 160
square miles that was delivered in 1997. The remainder of the data is currently
expected to be delivered in 1998. The Company has budgeted to drill two wells in
this project area during the second quarter of 1998. The Company believes that
experience gained in the Starr/Hidalgo Project Area may assist in exploration
efforts in the Western 325 Project Area.
Lance Project Area: Frio and Vicksburg Formations
The Lance Project Area is located in Bee County, Texas in an area of
prolific shallow Frio production. The primary exploration objectives in this
project area are the Frio/Vicksburg trends, with secondary objectives in the
deeper Vicksburg, Jackson and Yegua formations. The Company is currently
interpreting data from a 30 square mile 3-D seismic survey completed in the
second half of 1996. As of December 31, 1997, the Company and its partners held
500 acres in leases and 18,036 acres in options. During the quarter ended
December 31, 1997, the Company's share of production from wells in this project
area was approximately 0.03 MMcf/d of natural gas. As of December 31, 1997, the
Company and its partners have drilled six wells in this project area, resulting
in three producing wells. The estimated proved reserves net to the Company for
this project area was 0.09 BCF of natural gas at December 31, 1997. A deeper
Yegua well is planned for May 1998.
Highway 59 Project Area: Frio, Yegua and Wilcox Formations
The Highway 59 Project Area is located in Fort Bend and Wharton Counties,
Texas in an area of several historical field discoveries and production in the
Frio and Yegua formations and in the highly competitive Wharton County Wilcox
trend. A survey design has been completed for a 20 square mile 3-D seismic
survey in the project area, and fieldwork is expected to begin during the third
quarter of 1998. The Company and two large independent industry partners will
seek to use the 3-D seismic data to identify shallow opportunities and to
delineate Yegua and Wilcox prospects identified through the interpretation of
2-D seismic data. As of December 31, 1997, the Company's leases in this project
area covered 4,995 acres.
Geronimo Project Area: Frio Formation
The Geronimo Project Area is located in San Patricio County, Texas in an
area of predominantly Frio production. Numerous fault systems run through the
area, particularly in the basal Frio and Vicksburg formations. A 67 square mile
3-D seismic survey was conducted in 1996, with the initial interpretation of
data generating five prospects. A northeast extension of the initial 3-D seismic
survey covering an additional 40 square miles was later acquired. As of December
31, 1997, the Company's leases covered 10,278 acres and its seismic options
covered 19,080 acres in this project area. During the quarter ended December 31,
1997, the Company's share of production from wells in this project area was
approximately 16 Bbls/d of oil and 0.3 MMcf/d of natural gas. As of December 31,
1997, the Company and its partners had drilled three wells in this project area,
resulting in two producing wells. The estimated proved reserves net to the
Company for this project area was 10.4 MBbls of oil and 0.4 BCF of natural gas
at December 31, 1997. Four additional wells are planned for 1998.
RPP Welder Project Area: Frio and Vicksburg Formations
The RPP Welder Project Area is located in San Patricio and Refugio
Counties, Texas in an area of predominantly upper Frio production and is
adjacent to the Geronimo, Midway and LaRosa Project Areas. Numerous fault
systems run through the area, particularly at the relatively unexplored basal
Frio and Vicksburg levels. The primary producing formations in this area have
historically been Miocene and upper Frio oil objectives. Field operations for a
60 square mile 3-D seismic survey commenced during the second quarter of 1997.
Data was received from processing in March 1998 and interpretation has been
initiated. The Company's leases cover 1,127 acres and its options cover 30,055
acres in this project area.
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Midway Project Area: Frio Formation
The Midway Project Area is located in San Patricio County, Texas in an area
of predominantly Frio production. The area is a southwest extension of the
Geronimo Project Area and includes the Company's producing properties from the
Midway Field along with contiguous leases and seismic option areas. The Company
has designed a 15 square mile 3-D seismic survey in this project area, and field
operations are planned to commence in the third quarter of 1998. As of December
31, 1997, the Company's leases covered 1,235 acres in this project area.
Lost Bridge Project Area: Frio, Yegua and Wilcox Formations
The Lost Bridge Project Area is located in northern Jackson County, Texas
in the Frio, Yegua and Wilcox formations. The area covers several historical
field discoveries and recent Wilcox production. The Company began work in the
third quarter of 1997 on a 16 square mile 3-D seismic survey. The Company will
seek to use the 3-D seismic data to delineate a Yegua prospect identified with
2-D seismic data, identify shallow opportunities and image the deeper Wilcox
trend. The Company's strategy is to drill Frio and Yegua prospects and sell a
portion of its interest in any Wilcox prospects while retaining a carried
interest. The Company is currently interpreting the seismic data over the
project area and has 751 acres under lease and 4,314 acres under option to date.
Drake 202 Project Area: Frio and Vicksburg Formations
The Drake 202 Project Area is located in Bee County, Texas adjacent to the
Lance Project Area. Primary exploration objectives for this project area are the
Frio and Vicksburg formations, as well as deeper, higher risk prospects in the
Yegua formation. In this project area, the Company has seismic options covering
3,877 acres. A 20 square mile 3-D seismic survey is scheduled for April, 1998.
Metro Project Area: Frio, Yegua and Wilcox Formations
The Metro Project Area is located in Dewitt County, Texas in the active
Wilcox producing trend. Target reservoirs include the Frio, Yegua, upper and
middle Wilcox ranging in depth from 3,500 feet to 14,500 feet. A 20 square mile
3-D seismic program has been completed and numerous drilling opportunities have
been identified. The first well was drilled to a depth of 14,500 feet in the
first quarter of 1998 and is currently being completed in the Wilcox formation.
The Company has 2,064 acres under lease and 9,285 gross acres under option.
North Heyser: Miocene And Frio Formations
The North Heyser Project Area is located in Victoria County, Texas. The 3-D
seismic shoot area covers significant historical production and targets
primarily Basal Frio structural traps and extensions to existing area
production. A 13 square mile 3-D seismic program was completed in the fourth
quarter of 1997 and is currently being interpreted. As of December 31, 1997 the
Company had 8,100 acres under seismic option in this project area.
Victoria Project Area: Miocene and Frio Formation
The Victoria Project Area is located in Victoria County, Texas and is
targeting the Miocene to Basal Frio formations. The area includes several
historical field discoveries. A 3-D seismic shoot of approximately 60 square
miles has been initiated with expected completion in May of 1998. Interpretation
of processed data and identification of potential drillsites is scheduled for
the fourth quarter of 1998. As of December 31, 1997, the Company had 5,492 acres
under lease and 15,796 under seismic option in this project area.
Matagorda Project Area: Frio Formations
The Matgorda Project Area is located in Matagorda County, Texas covering
numerous Middle Frio structural opportunities in addition to the Lower Frio
shelf edge expanded section. The Company has
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committed to a non exclusive 3-D seismic shoot covering 51 square miles that is
expected to be initiated in the first quarter of 1998. Interpretation of the 3-D
data and initial drilling is expected to begin in the late third quarter of
1998. The Company has acquired 16,093 acres of seismic options in the project
area.
Driscoll Ranch Project Area: Frio through Yegua Formations
The Driscoll Ranch Project Area is located in Jim Wells and Duval Counties,
Texas. Industry activity in this area is high with substantial activity to the
north and east. Existing 2-D seismic data has generated several leads in the
project area and is being used to optimize the 3-D parameters. Target reservoirs
include the Frio Formation to the Hockley/Pettus/Yegua intervals between 5,000
feet and 8,000 feet. The anticipated area of a planned seismic shoot is
approximately 80 square miles, with acquisition beginning mid 1998. The Company
had 23,135 acres under seismic option as of December 31, 1997 in this project
area.
South Texas Syndicate
The South Texas Syndicate Project Area is located in LaSalle and McMullen
Counties, Texas. Seismic options covering over 88,000 acres are being negotiated
and are expected to be finalized by the first quarter of 1998. Industry activity
in the area has been initiated with 3-D seismic projects both east and west
along trend. Target reservoirs include the Cook Mountain, Queen City, Wilcox,
Edwards and Sligo, ranging in depth from 1,100 feet to 14,500 feet. An initial
phase of 3-D coverage covering approximately 40 square miles is planned for
1998.
LOUISIANA
North Chalkley Project Area: Miogyp Sand
The North Chalkley Project Area is located in Calcasieu and Cameron
Parishes, Louisiana in an area of production from the Miogyp sand trend. The
Company's leases in this project area cover 1,130 acres and control both
upthrown and expanded Miogyp closures against the regional Camerina/Miogyp
expansion fault. An upthrown 2-D supported opportunity was sold to two large
independent oil and natural gas companies for cash and carried working interest
in 1997. The well logged gas pay but was not adequately tested due to mechanical
problems. The Company now has a 45% working interest in the subject leases and
is planning to acquire 3-D seismic data for delineation of drilling future
prospects.
Atchafalaya Project Area: Cib Op-C Sand
The Atchafalaya Project Area is located in Atchafalaya Bay in Louisiana. In
1991, a well was drilled in this fault block resulting in a field discovery at
approximately 17,500 feet. The Company and its partners control 3,611 acres in
this project area under a farm-in agreement and two state leases. The Company's
partners have access to 20 square of 3-D seismic data covering this project
area. As of March 31, 1997, the Company's net estimated proved reserves in this
project area were 308 MBbls of oil and 5.8 Bcf of natural gas, all of which are
undeveloped. The Company subsequently sold down to an approximately 10% carried
interest in the first well that has been spudded in March 1998.
Live Oak Project Area: Chris II Sand
The Live Oak Project Area is located in Vermillion Parish, Louisiana. In
1996, the Company and its partners acquired access to a 20 square mile 3-D
seismic survey. The Company promoted its interest in the project area to two
independents and will be carried to casing point for a 12% interest in the first
well, which should be completed in April 1998. The Company's leases in this
project area cover an aggregate of approximately 350 acres. The well is drilling
as of March 1998.
OTHER PROJECT AREAS
In addition to the project areas described above, the Company had over 23
additional project areas in various stages of development as of December 31,
1997. These project areas are located in the onshore Texas
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and Louisiana Gulf Coast region, as well as one project area in the Cotton
Valley Lime Reef trend. The Company is in the process of evaluating and
acquiring interests with respect to most of these project areas and as of
December 31, 1997 had acquired leases and seismic options covering 118,114
acres. 3-D seismic surveys covering an aggregate of approximately 282 square
miles in these areas are budgeted for acquisition during 1998.
SIGNIFICANT DEVELOPMENT PROJECT -- CAMP HILL
The Company owns interests in eight leases totaling approximately 900 acres
in the Camp Hill field in Anderson County, Texas. The Company currently operates
six of these leases. During the year ended December 31, 1997, the project
produced 110 Bbls/d 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, 1997 averaged $15.54 per barrel ($2.59 per Mcfe). 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 $.71 per barrel during the year ended December 31, 1997)
than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 1997, the Company had 4,697 MBbls of oil of proved
reserves in this project, with 902 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% in its leases in this field
and an average net revenue interest of 74.0%.
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,
1997. The reserve data and the present value as of December 31, 1997 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, 1997,
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 10 of Notes to Financial
Statements.
PROVED RESERVES
-----------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls).......................... 1,146 4,023.5 5,169.5
Natural gas (MMcf).................................. 9,299 2,843 12,142
Total proved reserves (MMcfe)....................... 16,173 26,986 43,159
PV-10 Value(1)...................................... $18,515 $ 7,556 $26,071
- ---------------
(1) The PV-10 Value as of December 31, 1997 is pre-tax and was determined by
using the December 31, 1997 sales prices, which averaged $16.37 per Bbl of
oil, $2.56 per Mcf of natural gas and $10.90 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 Commission.
In accordance with Commission regulations, the reserve reports used oil and
natural gas prices in effect at December 31, 1997. 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, 1997. There can be no assurance that all of the
proved reserves will be produced and sold within the periods
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indicated, that the assumed prices will actually be realized for such production
or that existing contracts will be honored or judicially enforced.
There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Annual Report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions concerning
future oil and natural gas prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of which may in
fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural 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."
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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.
YEAR ENDED DECEMBER 31,
--------------------------
1995 1996 1997
------ ------ ------
PRODUCTION VOLUMES
Oil (MBbls)................................................. 78 107 113
Natural gas (MMcf).......................................... 565 1,273 2,749
Natural gas equivalent (MMcfe).............................. 1,033 1,915 3,424
AVERAGE SALES PRICES
Oil (per Bbl)............................................... $19.64 $21.54 $18.66
Natural gas (per Mcf)....................................... 1.60 2.27 2.41
Natural gas equivalent (per Mcfe)........................... 2.36 2.71 2.54
AVERAGE COSTS (PER MCFE)
Camp Hill operating expenses................................ $ 2.06 $ 3.15 $ 2.59
Other operating expenses.................................... 1.63 0.94 0.54
Total operating expenses(1)................................. 1.76 1.24 0.68
- ---------------
(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, 1997, the Company has incurred total
gross development, exploration and acquisition costs of approximately $47.4
million. Total exploration, development and acquisition activities from
inception through December 31, 1997 have resulted in the addition of
approximately 49.7 Bcfe, net to the Company's interest, of proved reserves at an
average finding and development cost of $.95 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
---------------------------
1995 1996 1997
------ ------ -------
(IN THOUSANDS)
Acquisition costs
Unproved prospects........................................ $ 317 $ 51 $ --
Proved properties......................................... 3,588 1,908 14,820
Exploration................................................. 2,364 4,724 14,223
Development................................................. 209 1,956 2,257
------ ------ -------
Total costs incurred(1)................................ $6,478 $8,639 $31,300
====== ====== =======
- ---------------
(1) Excludes capitalized interest on unproved properties of $117,288,
$422,493 and $699,625 for the years ended December 31, 1995, 1996 and
1997, respectively.
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DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
years ended December 31, 1995, 1996 and 1997. 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. As shown
below, the Company's drilling activity from January 1, 1995 to December 31, 1997
has resulted in a commercial success rate of approximately 69%.
YEAR ENDED DECEMBER 31,
---------------------------------------------
1995 1996 1997
------------ ------------ -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ----
Exploratory Wells
Productive.................................... -- -- 16 6.0 39 15.7
Nonproductive................................. -- -- 4 1.1 23 9.4
----- --- ----- ----
Total................................. -- -- 20 7.1 62 25.1
===== === ===== ====
Development Wells
Productive.................................... -- -- -- -- 7 1.8
Nonproductive................................. -- -- -- -- 1 0.6
----- ----
Total................................. -- -- -- -- 8 2.4
===== ====
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, 1997.
COMPANY OPERATED OTHER
---------------- ------------- TOTAL
GROSS NET GROSS NET GROSS NET
-------- ---- ----- ---- ----- ----
Oil........................................ 56 54.4 24 8.7 80 63.1
Natural gas................................ 13 8.2 68 23.7 81 31.9
--- ---- ---- ---- ---- ----
Total.................................... 69 62.6 92 32.4 161 95.0
=== ==== ==== ==== ==== ====
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 1997. 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...................... -- -- 7,310 2,770 7,310 2,770
Texas.......................... 28,245 11,609 83,130 26,582 111,375 38,191
------ ------ ------ ------ ------- ------
Total................ 28,245 11,609 90,440 29,352 118,685 40,961
====== ====== ====== ====== ======= ======
The table does not include 301,268 gross acres (127,915 net) that the
Company had a right to acquire pursuant to various seismic option agreements at
December 31, 1997. 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.
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MARKETING
The Company's production is marketed to third parties consistent with
industry practices. Typically, oil is sold at the wellhead at field-posted
prices plus a bonus and natural gas is sold under contract at a negotiated price
based upon factors normally considered in the industry, such as distance from
the well to the pipeline, well pressure, estimated reserves, quality of natural
gas and prevailing supply/demand conditions.
The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of multiple
outlets near its production in the Texas and Louisiana Gulf Coast. The Company
takes an active role in determining the available pipeline alternatives for each
property based upon historical pricing, capacity, pressure, market
relationships, seasonal variances and long-term viability.
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers. The
availability of a ready market for the Company's oil and natural gas production
depends on the proximity of reserves to, and the capacity of, oil and natural
gas gathering systems, pipelines and trucking or terminal facilities. The
Company delivers natural gas through gas gathering systems and gas pipelines
that it does not own. Federal and state regulation of natural gas and oil
production and transportation, tax and energy policies, changes in supply and
demand and general economic conditions all could adversely affect the Company's
ability to produce and market its oil and natural gas.
The Company from time to time markets its own production where feasible
with a combination of market-sensitive pricing and forward-fixed pricing.
Forward pricing is utilized to take advantage of anomalies in the futures market
and to hedge a portion of the Company's production deliverability at prices
exceeding forecast. All of such hedging transactions provide for financial
rather than physical settlement. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- General Overview."
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas sold in the
spot market due primarily to seasonality of demand and other factors beyond the
Company's control. Domestic oil prices generally follow worldwide oil prices,
which are subject to price fluctuations resulting from changes in world supply
and demand. The Company continues to evaluate the potential for reducing these
risks by entering into, and expects to enter into, additional hedge transactions
in future years. In addition, the Company may also close out any portion of
hedges that may exist from time to time as determined to be appropriate by
management. At December 31, 1997, natural gas sold under such swap arrangements
was 364,000 MMBtu at an average price of $2.86 per MMBtu relating to first
quarter of 1998 production. Total natural gas purchased and sold under such swap
arrangements during the years ended December 31, 1995, 1996 and 1997 were 40,000
MMBtu, 60,000 MMBtu and 210,000 MMBtu, respectively. Gains (losses) realized by
the Company under such swap arrangements were ($23,466), ($26,887) and $48,000
for the years ended December 31, 1995, 1996 and 1997, respectively. The Company
did not engage in hedging prior to 1995.
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
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natural gas properties and may be able to identify, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. In addition, such companies may be able to
expend greater resources on the existing and changing technologies that the
Company believes are and will be increasingly important to the current and
future success of oil and natural gas companies. The Company's ability to
explore for oil and natural gas prospects and to acquire additional properties
in the future will be dependent upon its ability to conduct its operations, to
evaluate and select suitable properties and to consummate transactions in this
highly competitive environment. The Company believes that its exploration,
drilling and production capabilities and the experience of its management
generally enable it to compete effectively. Many of the Company's competitors,
however, have financial resources and exploration and development budgets that
are substantially greater than those of the Company, which may adversely affect
the Company's ability to compete with these companies.
The oil and gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive pressures
may force the Company to implement such new technologies at substantial cost. In
addition, other oil and gas companies may have greater financial, technical and
personnel resources that allow them to enjoy technological advantages and may in
the future allow them to implement new technologies before the Company. There
can be no assurance that the Company will be able to respond to such competitive
pressures and implement such technologies on a timely basis or at an acceptable
cost. One or more of the technologies currently utilized by the Company or
implemented in the future may become obsolete. In such case, the Company's
business, financial condition and results of operations could be materially
adversely affected. If the Company is unable to utilize the most advanced
commercially available technology, the Company's business, financial condition
and results of operations could be materially and adversely affected.
REGULATION
The availability of a ready market for oil and gas production depends upon
numerous factors beyond the Company's control. These factors include regulation
of oil and natural gas production, federal and state regulations governing
environmental quality and pollution control, state limits on allowable rates of
production by well or proration unit, the amount of oil and natural gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline in the
areas in which the Company may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between owners in a common reservoir, control the
amount 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
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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. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural
Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder
by the Federal Energy Regulatory Commission (the "FERC"). Maximum selling prices
of certain categories of natural gas sold in "first sales," whether sold in
interstate or intrastate commerce, were regulated pursuant to the NGPA. The
Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of not
later than January 1, 1993, all remaining federal price controls from natural
gas sold in "first sales." The FERC's jurisdiction over natural gas
transportation was unaffected by the Decontrol Act. Although sales by producers,
such as the Company, of natural gas and all sales of crude oil, condensate and
natural gas liquids can currently be made at market prices, Congress could
reenact price controls in the future.
The Company's sales of natural gas are affected by the availability, terms
and cost of transportation. The price and terms for access to pipeline
transportation are subject to extensive regulation. In recent years, the FERC
has undertaken various initiatives to increase competition within the natural
gas industry. As a result of initiatives like FERC Order 636, issued in April
1992, the interstate natural gas transportation and marketing system has been
substantially restructured to remove various barriers and practices that
historically limited non-pipeline natural gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most significant
provisions of Order No. 636 require that interstate pipelines provide
transportation separate or "unbundled" from their sales service, and require
that pipelines provide firm and interruptible transportation service on an open
access basis that is equal for all natural gas supplies. In many instances, the
result of Order No. 636 and related initiatives have been to substantially
reduce or eliminate the interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing only storage and transportation services.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
ratemaking methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad inquiry into issues facing the natural gas industry to assist
the FERC in establishing regulatory goals and priorities in the post-Order No.
636 environment. Similarly, the Texas Railroad Commission has been reviewing
changes to its regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers and recently implemented a code
of conduct intended to prevent undue discrimination by intrastate pipelines and
gatherers in favor of their marketing affiliates. Although the changes being
considered by these federal and state regulators would affect the Company only
indirectly, they are intended to further enhance competition in natural gas
markets.
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.
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The Company cannot predict what further action the FERC or state regulators
will take on these matters; however, the Company does not believe that it will
be affected by any action taken materially differently than other natural gas
producers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
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
January 1995, the FERC implemented regulations establishing an indexing system
under which oil pipelines will be able to change their transportation rates,
subject to prescribed ceiling limits. The indexing system generally indexes such
rates to inflation, subject to certain conditions and limitations. The Company
is not able at this time to predict the effects of these regulations, if any, on
the transportation costs associated with oil production from the Company's oil
producing operations.
Environmental Regulations. The Company's operations are subject to numerous
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands within wilderness, wetlands and other protected areas, require
remedial measures to mitigate pollution from former operations, such as pit
closure and plugging abandoned wells, and impose substantial liabilities for
pollution resulting from production and drilling operations. Public interest in
the protection of the environment has increased dramatically in recent years.
The trend of more expansive and stricter environmental legislation and
regulations applied to the oil and natural gas industry could continue,
resulting in increased costs of doing business and consequently affecting
profitability. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes more stringent and costly waste
handling, disposal and cleanup requirements, the business and prospects of the
Company could be adversely affected.
The Company generates wastes that may be subject to the federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S.
Environmental Protection Agency ("EPA") and various state agencies have limited
the approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by the Company's oil and natural gas
operations that are currently exempt from treatment as "hazardous wastes" may in
the future be designated as "hazardous wastes," and therefore be subject to more
rigorous and costly operating and disposal requirements.
The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Although
the Company believes that it has used good operating and waste disposal
practices, prior owners and operators of these properties may not have used
similar practices, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by the Company or on or
under locations where such wastes have been taken for disposal. In addition,
many of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the Company's
control. These properties and the wastes disposed thereon may be subject to the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
RCRA and analogous state laws as well as state laws governing the management of
oil and gas wastes. Under such laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.
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
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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. The Company plans to drill a well
in Louisiana coastal waters. Assuming that production from the planned well is
feasible, the Company will be obligated to comply with these regulations.
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 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
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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 non-operated 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.
EMPLOYEES
At December 31, 1997, the Company had 22 full-time employees, including
four geoscientists and three engineers. As drilling and production activities
increase, the Company intends to hire additional technical, operational and
administrative personnel as appropriate. 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,
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maintenance, dispatching, inspection and testing, 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."
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.
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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.
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.
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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.
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 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....................... 41 President and Chief Executive Officer
Frank A. Wojtek....................... 42 Chief Financial Officer, Vice
President, Secretary and Treasurer
George F. Canjar...................... 39 Vice President of Exploration
Development
Kendall A. Trahan..................... 47 Vice President of Land
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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.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
(a) 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 of fiscal
1997:
QUARTER ENDED HIGH LOW
------------- ---- -----
September 30, 1997.......................................... 15 10 15/16
December 31, 1997........................................... 17 1/4 7 7/8
There were approximately 48 shareholders of record (excluding brokerage
firms and other nominees) of the Company's Common Stock as of March 25, 1998.
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% Series A Preferred Stock, par
value $.01 per share (the "Preferred Stock"), restrict the Company's ability
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to pay dividends. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
(b) Use of Proceeds.
The Company's Registration Statement on Form S-1 (Registration No.
333-29187), as amended, with respect to the initial public offering of shares of
Company's Common Stock was declared effective by the Securities and Exchange
Commission on August 5, 1997. In the Offering, the Company sold 2,500,000 shares
of Common Stock on August 11, 1997 and 375,000 shares of Common Stock on
September 8, 1997 pursuant to the exercise of the underwriters' over-allotment
option.
The net proceeds to the Company from the Offering were $28.1 million. As of
December 31, 1997, the Company has used such net proceeds as follows: (i) to
repay $16.5 million of indebtedness outstanding under the Company's revolving
credit facilities, (ii) to repay $3.2 million of promissory notes outstanding to
certain of the Company's directors and officers and (iii) to provide $8.4
million for capital expenditures. Except as set forth in clause (ii), none of
such payments were direct or indirect payments to directors or officers of the
Company or their associates, to persons owning ten percent or more of any class
of equity securities of the Company or to affiliates of the Company.
RECENT SALES OF UNREGISTERED SECURITIES
On January 8, 1998, the Company consummated the transactions contemplated
by the Stock Purchase Agreement dated January 8, 1998 (the "Purchase Agreement")
among the Company, Enron Capital & Trade Resources Corp., a Delaware corporation
("Enron"), and Joint Energy Development Investments II, a Delaware limited
partnership ("JEDI II"). Such transactions included (i) the payment by Enron and
JEDI II of an aggregate purchase price of $30,000,000, (ii) the sale of 75,000
shares of Preferred Stock, the terms of which are set forth in the Statement of
Resolution Establishing Series of Shares designated 9% Series A Preferred Stock,
to Enron and 225,000 shares of Preferred Stock to JEDI II, (iii) the grant of
warrants (the "Warrants") to purchase 250,000 and 750,000 shares of Common Stock
to Enron and JEDI II, respectively, and (iv) the execution and delivery of the
Shareholders' Agreement dated January 8, 1998 among the Company, S.P. Johnson
IV, Frank A. Wojtek, Steven A. Webster, Paul B. Loyd, Jr., Douglas A.P.
Hamilton, DAPHAM Partnership L.P., the Douglas A.P. Hamilton 1997 GRAT, Enron
and JEDI II.
The Warrants are exercisable during the period beginning January 8, 1999
and ending January 8, 2005 for the purchase of an aggregate of 1,000,000 shares
of Common Stock (the "Warrant Shares") at an exercise price of $11.50 per share,
subject to certain adjustments. Each Warrant may be exercised by (i) paying the
exercise price (A) in cash or (B) by surrender to the Company of shares of
Preferred Stock or (ii) exercising the Warrant for a number of net Warrant
Shares equal to (x) the number of Warrant Shares issuable upon exercise of the
Warrant multiplied by the difference between the average market price of the
Common Stock during the 20 trading day period preceding the date of exercise and
the exercise price divided by (y) the average market price of the Common Stock
during the 20 trading day period preceding the date of exercise. In addition,
with the consent of the Company, the holder of the Warrant may receive a cash
payment equal to the number of Warrant Shares for which the Warrant is exercised
multiplied by the difference between the average market price of the Common
Stock during the 20 trading day period preceding the date of exercise and the
exercise price.
The number of Warrant Shares and exercise price are subject to adjustment
in certain circumstances, including (i) if the Company makes a distribution of
shares of Common Stock, subdivides or combines its outstanding shares of Common
Stock or issues any shares of its capital stock or distributes other assets in a
reclassification or reorganization of the 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 of the Common Stock, subject to certain exceptions, and (iii)
if the Company engages in a consolidation, merger or business combination with,
or sells all or substantially all of its assets to, another corporation.
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The sale of the shares of Preferred Stock and the Warrants pursuant to the
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 any public offering.
ITEM 6. SELECTED FINANCIAL DATA
The financial information of the Company set forth below for the period
from inception of operations (September 24, 1993) through December 31, 1993, and
for each of the four years ended December 31, 1997, 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.
PERIOD
ENDED YEAR ENDED DECEMBER 31,
DECEMBER 31, ------------------------------------------
1993 1994 1995 1996 1997
-------------- ------ ------- ------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues........ $ 5 $ 596 $ 2,428 $ 5,195 $ 8,712
Costs and expenses:
Oil and natural gas operating
expenses....................... 20 518 1,814 2,384 2,334
Depreciation, depletion and
amortization................... 1 98 488 1,136 2,358
General and administrative........ 24 238 425 515 1,591
----- ------ ------- ------- ----------
Total costs and
expenses................ 45 854 2,727 4,035 6,283
----- ------ ------- ------- ----------
Operating income (loss)............. (40) (258) (299) 1,160 2,429
Interest expense (net of amounts
capitalized)...................... -- (7) (192) (80) (98)
Other income........................ -- 6 24 20 --
----- ------ ------- ------- ----------
Income (loss) before income taxes... (40) (259) (467) 1,100 2,331
----- ------ ------- ------- ----------
Deferred income taxes(1)............ -- -- -- -- 2,300
----- ------ ------- ------- ----------
Net income (loss)(1)................ $ (40) $ (259) $ (467) $ 1,100 $ 31
===== ====== ======= ======= ==========
Basic (loss) earnings per
share(1).......................... $0.00 $(0.04) $ (0.07) $ 0.15 $ 0.00
===== ====== ======= ======= ==========
Diluted (loss) earnings per
share(1).......................... $0.00 $(0.04) $ (0.07) $ 0.15 $ 0.00
===== ====== ======= ======= ==========
Basic weighted average shares
outstanding....................... 5,210 6,501 7,021 7,476 8,639
Diluted weighted average shares
outstanding....................... 5,210 6,501 7,021 7,545 8,810
STATEMENTS OF CASH FLOW DATA:
Net cash provided by (used in)
operating activities.............. $ 12 $ (258) $ 406 $ 3,325 $ 3,068
Net cash used in investing
activities........................ (118) (819) (6,785) (8,221) (28,141)
Net cash provided by financing
activities........................ 106 1,183 6,343 6,319 26,255
OTHER OPERATING DATA:
EBITDA(2)(4)........................ $ (41) $ (158) $ 189 $ 2,296 $ 4,787
Operating cash flow(3)(4)........... (41) (159) 21 2,236 4,689
Capital expenditures................ 113 819 6,857 9,480 32,234
Debt repayments(5).................. -- -- -- 2,084 20,409
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AS OF DECEMBER 31,
----------------------------------------------
1993 1994 1995 1996 1997
---- ------ ------ ------- -------
BALANCE SHEET DATA:
Working capital............................... $(52) $ 152 $ (265) $(1,025) $(2,276)
Property and equipment, net................... 113 803 6,960 15,206 45,083
Total assets.................................. 130 1,057 7,645 18,869 53,658
Long-term debt, including current
maturities.................................. -- 533 3,480 9,684 7,950
Equity........................................ 65 452 3,381 4,596 32,895
- ---------------
(1) From inception of operation to May 16, 1997, Carrizo and the other entities
combined in a series of transactions pursuant to which a number of
affiliated entities were combined with the Company in connection with its
initial public offering (the "Combination Transactions") were not required
to pay federal income taxes due to their status as partnerships or 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.
(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization.
(3) Operating cash flow represents cash flows from operating activities prior to
changes in assets and liabilities.
(4) 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.
(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 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, budgeted expenditures, 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" "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
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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.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL OVERVIEW
The Company began operations in September 1993 and initially focused on the
acquisition of producing properties. As a result of the increasing availability
of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic
data and options to lease substantial acreage in 1995 and began to drill its 3-D
based prospects in 1996. The Company drilled 20 wells in 1996 and 70 wells in
1997. The Company expects such increases to continue and has budgeted to drill a
total of 150 gross wells (71.8 net) in 1998. As a result, depreciation,
depletion and amortization, oil and gas operating expenses and production are
expected to increase. The Company has typically retained the majority of its
interests in shallow, normally pressured prospects and sold a portion of its
interests in deeper, over-pressured prospects.
The financial statements set forth herein are prepared on the basis of a
combination of Carrizo and the entities that were a party to the Combination
Transactions. Carrizo and the entities combined with it in the Combination
Transactions were not required to pay federal income taxes due to their status
as partnerships or Subchapter S corporations, which are not subject to federal
income taxation. Instead, taxes for such periods were paid by the shareholders
and partners of such entities. On May 16, 1997, Carrizo terminated its status as
an S corporation and thereafter became subject to federal income taxes. In
accordance with SFAS No. 109, "Accounting for Income Taxes," the Company was
required to establish a deferred tax liability in the second quarter of 1997
which resulted in a noncash charge to income of approximately $1.6 million.
The Company has primarily grown through the internal development of
properties within its exploration project areas, although the Company acquired
properties with existing production in the Camp Hill Project in late 1993, the
Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company
made these acquisitions through the use of limited partnerships with Carrizo or
Carrizo Production, Inc. as the general partner. However, as operations have
expanded, the Company has increasingly funded its activities through bank
borrowings and cash flow from operations in order to retain a greater portion of
the interests it develops.
Prior to the Offering, Carrizo conducted its oil and natural gas operations
directly, with industry partners and through the following affiliated entities:
Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd.,
Carrizo Partners Ltd. and Placedo Partners Ltd. Concurrently with the closing of
the Offering, Combination Transactions were closed. The Combination Transactions
consisted of the following: (i) Carrizo Production, Inc. merged into Carrizo;
(ii) Carrizo acquired Encinitas Partners Ltd. in two steps: (a) Carrizo acquired
the limited partner interests in Encinitas Partners Ltd. held by certain of the
Company's directors and (b) Encinitas Partners Ltd. merged into Carrizo; (iii)
La Rosa Partners Ltd. merged into Carrizo; and (iv) Carrizo Partners Ltd. merged
into Carrizo. As a result of the merger of Carrizo and Carrizo Partners Ltd.,
Carrizo became the owner of all of the partnership interest in Placedo Partners
Ltd.
The Company uses the full-cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including any general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit-of-production method. To
the extent that such capitalized costs in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate) of estimated future net after-tax cash
flows from proved oil and gas reserves, such excess costs are charged to
operations. The Company has not been required to make any such write-downs. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date. The ceiling test for many full cost companies, including Carrizo, could be
negatively impacted by prolonged unfavorable oil and gas prices. The
deterioration of prices from year-end levels could result in the Company
recording a first quarter 1998 non-cash charge to earnings related to its oil
and gas properties.
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RESULTS OF OPERATIONS
Year Ended December 31, 1997 Compared to the Year Ended December 31, 1996
Oil and natural gas revenues for 1997 increased 68% to $8.7 million from
$5.2 million in 1996. Production volumes for natural gas in 1997 increased 116%
to 2,749.2 MMcf from 1,272.5 MMcf in 1996. Average natural gas prices increased
6% to $2.41 per Mcf in 1997 from $2.27 per Mcf in 1996. Production volumes for
oil in 1997 increased 5% to 112.5 MBbls from 107.3 MBbls in 1996. Average oil
prices decreased 13% to $18.66 per barrel in 1997 from $21.54 per barrel in
1996. The increase in oil and natural gas production was due primarily to new
wells being successfully drilled and completed during 1997, along with
recompletions of existing wells.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1996 and 1997:
1997 PERIOD COMPARED TO
1996 PERIOD
DECEMBER 31, -----------------------
----------------------- INCREASE % INCREASE
1996 1997 (DECREASE) (DECREASE)
---- ---- ---------- ----------
Production volumes
Oil and condensate (MBbls)......... 107.3 112.5 5.2 5%
Natural gas (MMcf)................. 1,272.5 2,749.2 1,476.7 116%
Average sales prices(1)
Oil and condensate (per Bbl)....... $ 21.54 $ 18.66 $ (2.88) (13)%
Natural gas (per Mcf).............. 2.27 2.41 0.14 6%
Operating revenues
Oil and condensate................. $2,310,798 $2,099,699 $ (211,099) (9)%
Natural gas........................ 2,883,911 6,611,955 3,728,044 129%
---------- ---------- ----------
Total...................... $5,194,709 $8,711,654 $3,516,945 68%
========== ========== ==========
- ---------------
(1) Including impact of hedging.
Oil and natural gas operating expenses for 1997 decreased 2% to $2.3
million from $2.4 million in 1996. Oil and natural gas operating expenses
decreased primarily as a result of cost reductions in older wells and the
addition of lower cost production in new oil and gas wells drilled and completed
since December 31, 1995. Operating expenses per equivalent unit in 1997
decreased to $.68 per Mcfe from $1.24 per Mcfe in 1996. The per unit cost
decreased as a result of increased production of natural gas, which had lower
per unit operating costs.
DD&A expense for 1997 increased 118% to $2.4 million from $1.1 million in
1996. This increase was primarily due to the increased production, additional
seismic and drilling costs and depreciation on 3-D computer equipment and
related software.
General and administrative expense for 1997 increased 209% to $1.6 million
from $515,000 for 1996 reflecting ramp-up expenses relating to the hiring of
additional technical and administrative staff to handle the Company's increased
level of drilling and operations, and expenses related to the initial public
offering.
Interest expense for 1997 increased 90% to $151,000 from $80,000 in 1996.
This increase was primarily due to the increase in capital expenditures and
related debt levels in anticipation of the initial public offering.
As a result of the adoption of SFAS 109 in the second quarter of 1997, the
Company recorded a one-time non-cash charge to income of $1.6 million to
establish a deferred tax liability.
Net income for 1997 decreased to $31,000 from $1.1 million in 1996 as a
result of the factors described above.
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32
Year Ended December 31, 1996 Compared to the Year Ended December 31, 1995
Oil and natural gas revenues for 1996 increased 114% to $5.2 million from
$2.4 million in 1995. Production volumes for natural gas in 1996 increased 125%
to 1,272.5 MMcf from 565.3 MMcf in 1995. Average natural gas prices increased
42% to $2.27 per Mcf in 1996 from $1.60 per Mcf in 1995. Production volumes for
oil in 1996 increased 38% to 107.3 MBbls from 77.6 MBbls in 1995. Average oil
prices increased 10% to $21.54 per barrel in 1996 from $19.64 per barrel in
1995. The increase in oil and natural gas production was due primarily to new
wells being successfully drilled and completed during 1996, along with
recompletions of existing wells. Also contributing to the increase in oil and
gas revenues from 1995 to 1996 was the acquisition of the La Rosa properties.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1995 and 1996:
1996 PERIOD COMPARED
DECEMBER 31, TO 1995 PERIOD
----------------------- -----------------------
1995 1996 INCREASE % INCREASE
---- ---- ---------- ----------
Production volumes
Oil and condensate (MBbls)......... 77.6 107.3 29.7 38%
Natural gas (MMcf)................. 565.3 1,272.5 707.2 125%
Average sales prices(1)
Oil and condensate (per Bbl)....... $ 19.64 $ 21.54 $ 1.90 10%
Natural gas (per Mcf).............. 1.60 2.27 0.67 42%
Operating revenues
Oil and condensate................. $1,524,002 $2,310,798 $ 786,796 52%
Natural gas........................ 904,046 2,883,911 1,979,865 219%
---------- ---------- ----------
Total...................... $2,428,048 $5,194,709 $2,766,661 114%
========== ========== ==========
- ---------------
(1) Including impact of hedging.
Oil and natural gas operating expenses for 1996 increased 31% to $2.4
million from $1.8 million in 1995. Oil and natural gas operating expenses
increased due to increased production generated from new oil and gas wells
drilled and completed since December 31, 1995, as well as the acquisitions of
the La Rosa and Encinitas properties. Operating expenses per equivalent unit in
1996 decreased to $1.24 per Mcfe from $1.76 per Mcfe in 1995. The per unit cost
decreased as a result of increased production of natural gas which had lower per
unit operating costs.
DD&A expense for 1996 increased 133% to $1.1 million from $488,000 in 1995.
This increase was due to the increase in oil and gas production as well as a 25%
increase in the depletion rate (to $0.59 per Mcfe in 1996 from $0.47 per Mcfe in
1995). The increased depletion rate was primarily caused by increased
exploration expenditures attributable to 3-D seismic surveys performed for new
wells drilled and completed since December 31, 1995.
General and administrative expense for 1996 increased 21% to $515,000 from
$425,000 for 1995 due primarily to an increase in salary expense as a result of
the addition of new employees.
Interest expense for 1996 decreased 59% to $80,000 from $192,000 in 1995.
This decrease was primarily due to the increase in interest capitalized
consistent with increases in capital expenditures.
Net income for 1996 increased to $1.1 million from a loss of $467,000 in
1995 as a result of the factors described above.
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LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of liquidity have included proceeds from the
Offering and from the sale of shares of Preferred Stock and the Warrants as
discussed below, funds generated by operations, equity capital contributions and
borrowings, primarily under revolving credit facilities.
Cash flows provided by operations (after changes in working capital) were
$406,000, $3.3 million and $3.1 million for 1995, 1996 and 1997, respectively.
The increase in cash flows provided by operations in 1996 as compared to 1995
was due primarily to increased revenues from production. The decrease in cash
flows provided by operations in 1997 as compared to 1996 was due primarily to
increase accounts receivable relating to joint interest billings and prepayments
on upcoming outside operated drilling projects.
The Company has budgeted capital expenditures in 1998 of approximately
$43.3 million. Of this amount, $18.6 million is expected to be used to fund 3-D
seismic surveys and land acquisitions and $24.7 million of which is expected to
be used for drilling activities in the Company's project areas. The Company
budgeted to drill approximately 150 gross wells (71.8 net) in 1998. Actual
amounts of capital expenditures and number of wells drilled may differ
significantly from such estimates.
The Company has continued to reinvest a substantial portion of its cash
flows into increasing its 3-D prospect portfolio, improving its 3-D seismic
interpretation technology and funding its drilling program. Oil and gas capital
expenditures were $6.6 million, $9.1 million and $32.0 million for 1995, 1996
and 1997, respectively. The Company's drilling efforts resulted in the
successful completion of 18 gross wells (6.9 net) in 1996 and 46 gross wells
(17.5 net) during 1997.
The Company has experienced and expects to continue to experience
substantial working capital requirements primarily due to the Company's active
exploration and development programs and, to a much lesser extent, its
technology enhancement programs. While the Company believes that the net
proceeds from the Offering, net proceeds from the sale of shares of Preferred
Stock and the Warrants, cash flow from operations and borrowings under the
Company's credit facility should allow the Company to implement its present
business strategy during 1998, additional financing may be required in the
future to fund the Company's growth, development and exploration program and
continued technological enhancement. In the event such capital resources are not
available to the Company, its exploration and other activities may be curtailed.
FINANCING ARRANGEMENTS
In connection with the Offering, the Company entered into an amended
revolving credit agreement with Compass Bank (the "Company Credit Facility"),
which provides for a maximum loan amount of $25 million, subject to borrowing
base limitations. Prior to the Offering, the Company utilized various credit
facilities as well as borrowings from certain directors and officers of the
Company. Except for the Company Credit Facility, all of these facilities and
borrowings were terminated with the close of the Offering. Under the Company
Credit Facility, the principal outstanding is due and payable upon maturity in
June 1999 with interest due monthly. The interest rate for borrowings is
calculated at a floating rate based on the Compass index rate or LIBOR plus 2
percent. The Company's obligations are secured by certain of its oil and gas
properties and cash or cash equivalents included in the borrowing base.
Under the Company Credit Facility, Compass, in its sole discretion, will
make semiannual borrowing base determinations based upon the proved oil and
natural gas properties of the Company. Compass may redetermine the borrowing
base and the monthly borrowing base reduction at any time and from time to time.
The Company may also request borrowing base redeterminations in addition to its
required semiannual reviews at the Company's cost. As of December 31, 1997, the
borrowing base was $5,450,000 and borrowings outstanding were $4,950,000.
Amounts outstanding under this facility were repaid in the first quarter of
1998.
The Company is subject to certain covenants under the terms of the Company
Credit Facility, including, but not limited to, (a) maintenance of specified
tangible net worth and (b) maintenance of a ratio of quarterly cash flow (net
income plus depreciation and other noncash charges, less noncash income) to
quarterly debt service (payments made for principal in connection with the
credit facility plus payments made for principal
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34
other than in connection with such credit facility) of no less than 1.25 to
1.00. The Company Credit Facility also places restrictions on, among other
things, (a) incurring additional indebtedness, loans and liens, (b) changing the
nature of business or business structure, (c) selling assets and (d) paying
dividends.
In December 1997, the Company and Compass entered into an amendment to the
Company Credit Facility that provides for a term loan of $3 million. Interest
for borrowings under the term loan was calculated at a floating rate based on
the Company's index rate plus 2 percent. The amount outstanding under the term
loan as of December 31, 1997 was $3 million. Amounts outstanding under the term
loan were repaid in January 1998.
In January 1998, the Company consummated the sale of 300,000 shares of
Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to
affiliates of Enron Corp. The net proceeds received by the Company from this
transaction were approximately $28.8 million. A portion of the proceeds were
used to repay indebtedness, as described above. The remaining balance is
expected to be used primarily for oil and natural gas exploration and
development activities in Texas and Louisiana. The Preferred Stock provides for
annual cumulative dividends of $9.00 per share, payable quarterly in cash or, at
the option of the Company until January 15, 2002, in additional shares of
Preferred Stock.
The Preferred Stock is required to be redeemed by the Company (i) on
January 8, 2005, or (ii) after a request for redemption from the holders of at
least 30,000 shares of the Preferred Stock (or, if fewer than such number of
shares of Preferred Stock are outstanding, all of the outstanding shares of
Preferred Stock) and the occurrence of the following events: (a) the Company has
failed at any point in time to declare and pay any two dividends in the amount
then due and payable on or before the date the second of such dividends is due
and such dividends remain unpaid at such time, (b) the Company breaches certain
other covenants concerning the payment of dividends or other distributions on or
redemption or acquisition of shares of its capital stock ranking at parity with
or junior to the Preferred Stock, (c) for two consecutive fiscal quarterly
periods the quarterly Cash Flow (as defined below) of the Company is less than
the amount of the dividends accrued in respect to the Preferred Stock, (d) the
Company fails to pay certain amounts due on indebtedness for borrowed money or
there has otherwise been an acceleration of such indebtedness for borrowed
money, (e) there is a violation of the Shareholders' Agreement that is not
waived or (f) the Company sells, leases, exchanges or otherwise disposes of all
or substantially all of its property and assets which transaction does not
provide for the redemption of the Series A Preferred Stock. "Cash Flow" means
net income prior to preferred dividends and accretion (i) plus (to the extent
included in net income prior to preferred dividends and accretion) depreciation,
depletion and amortization and other non-cash charges and losses on the sale of
property (ii) minus non-cash income items and required principal payments on
indebtedness for borrowed money with a maturity from the original date of
incurrence of such indebtedness of six months or greater (excluding voluntary
prepayments and refinancings, but including prepayments (other than in
connection with refinancings) which would otherwise be due under such
indebtedness within a 60-day period following the date of such prepayment). The
Preferred Stock also may be redeemed at the option of the Company at any time in
whole or in part. All redemptions are at a price per share, together with
dividends accumulated and unpaid to the date of redemption, decreasing over time
from an initial rate of $104.50 per share to $100.00 per share.
A description of the Preferred Stock and the transactions relating to the
Purchase Agreement may be found in the Company's Current Report on Form 8-K
dated January 8, 1998.
EFFECTS OF INFLATION AND CHANGES IN PRICE.
The Company's results of operations and cash flows are affected by changing
oil and gas prices. If the price of oil and gas increases (decreases), there
could be a corresponding increase (decrease) in the operating cost that the
Company is required to bear for operations, as well as an increase (decrease) in
revenues. Inflation has had a minimal effect on the Company.
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35
ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY
The Company's rapid growth has placed, and is expected to continue to
place, a significant strain on the Company's financial, technical, operational
and administrative resources. The Company has relied in the past and expects to
continue to rely on project partners and independent contractors that have
provided the Company with seismic survey planning and management, project and
prospect generation, land acquisition, drilling and other services. At December
31, 1997, the Company had 22 full-time employees. As the Company increases the
number of projects it is evaluating or in which it is participating, there will
be additional demands on the Company's financial, technical, operational and
administrative resources and continued reliance by the Company on project
partners and independent contractors, and these strains on resources, additional
demands and continued reliance may negatively affect the Company. The Company's
ability to continue its growth will depend upon a number of factors, including
its ability to obtain leases or options on properties for 3-D seismic surveys,
its ability to acquire additional 3-D seismic data, its ability to identify and
acquire new exploratory sites, its ability to develop existing sites, its
ability to continue to retain and attract skilled personnel, its ability to
maintain or enter into new relationships with project partners and independent
contractors, the results of its drilling program, hydrocarbon prices, access to
capital and other factors. Although the Company intends to continue to upgrade
its technical, operational and administrative resources and to increase its
ability to provide internally certain of the services previously provided by
outside sources, there can be no assurance that it will be successful in doing
so or that it will be able to continue to maintain or enter into new
relationships with project partners and independent contractors. The failure of
the Company to continue to upgrade its technical, operational and administrative
resources or the occurrence of unexpected expansion difficulties, including
difficulties in recruiting and retaining sufficient numbers of qualified
personnel to enable the Company to expand its seismic data acquisition and
drilling program, or the reduced availability of project partners and
independent contractors that have historically provided the Company seismic
survey planning and management, project and prospect generation, land
acquisition, drilling and other services, could have a material adverse effect
on the Company's business, financial condition and results of operations. In
addition, the Company has only limited experience operating and managing field
operations, and there can be no assurances that the Company will be successful
in doing so. Any increase in the Company's activities as an operator will
increase its exposure to operating hazards. See "Business and
Properties -- Operating Hazards and Insurance." There can be no assurance that
the Company will be successful in achieving growth or any other aspect of its
business strategy.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.
In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, which is a new standard of accounting for stock-based compensation that
establishes a fair value method of accounting for awards granted after December
31, 1995, under stock compensation plans. SFAS No. 123 encourages, but does not
require, companies to adopt the fair value method of accounting in place of the
existing method of accounting for stock-based compensation, whereupon
compensation costs are recognized only in situations where stock compensation
plans award intrinsic value to recipients at the date of grant. The Company has
elected not to adopt the fair value accounting of SFAS No. 123 and will account
for any plans under Accounting Principles Board (APB) Opinion No. 25, under
which no compensation costs have been recognized.
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Company's revenues, future rate of growth, results of operations,
financial condition and ability to borrow funds or obtain additional capital, as
well as the carrying value of its properties, are substantially dependent upon
prevailing prices of oil and natural gas. Historically, the markets for oil and
natural gas have been volatile, and such markets are likely to continue to be
volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East,
33
36
the foreign supply of oil and natural gas, the price of foreign imports and
overall economic conditions. It is impossible to predict future oil and natural
gas price movements with certainty. Declines in oil and natural gas prices may
materially adversely affect the Company's financial condition, liquidity,
ability to finance planned capital expenditures and results of operations. Lower
oil and natural gas prices also may reduce the amount of oil and natural gas
that the Company can produce economically. See "Business and
Properties -- Marketing."
The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of this "ceiling" test generally requires pricing
future revenue at the unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time. The
Company may be required to write down the carrying value of its oil and natural
gas properties when oil and natural gas prices are depressed or unusually
volatile. If a write-down is required, it would result in a charge to earnings,
but would not impact cash flow from operating activities. Once incurred, a
write-down of oil and natural gas properties is not reversible at a later date.
In order to reduce its exposure to short-term fluctuations in the price of
oil and natural gas, the Company periodically enters into hedging arrangements.
The Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in oil and natural gas
prices. Such hedging arrangements may expose the Company to risk of financial
loss in certain circumstances, including instances where production is less than
expected, the Company's customers fail to purchase contracted quantities of oil
or natural gas or a sudden, unexpected event materially impacts oil or natural
gas prices. In addition, the Company's hedging arrangements limit the benefit to
the Company of increases in the price of oil and natural gas. Total natural gas
purchased and sold under swap arrangements during the years ended December 31,
1995, 1996 and 1997 was 40,000 MMBtu, 60,000 MMBtu and 210,000 MMBtu,
respectively. Income and (losses) realized by the Company under such swap
arrangements were ($23,466), ($26,887) and $48,000 for the years ended December
31, 1995, 1996 and 1997, respectively. The Company did not engage in hedging
prior to 1995. See "Business and Properties -- Marketing."
YEAR 2000
The Company is assessing the impact of the Year 2000 issue on its
operations, including the development and implementation of project plans and
cost estimates required to make its information systems infrastructure Year 2000
complaint. Based on existing information, the Company believes that anticipated
spending necessary to become Year 2000 compliant will not have a material effect
on the financial position, cash flows or results of operations of the Company,
nor will the Year 2000 issues cause any material adverse effect on the future
business operations of the Company. There can be no assurance, however, as to
the ultimate effect of the Year 2000 issue on the Company.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
The requirements of Item 7A under regulations of the Securities and
Exchange Commission are at this time not required or are not applicable and
therefore have been omitted.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is included elsewhere in this report.
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
34
37
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1 -- Election of Directors" and to the
information under the caption "Section 16(a) Reporting Delinquencies" in the
Company's definitive Proxy Statement (the "1998 Proxy Statement") for its annual
meeting of shareholders to be held on May 20, 1998. The 1998 Proxy Statement
will be filed with the Securities and Exchange Commission (the "Commission") not
later than 120 days subsequent to December 31, 1997.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference
to the 1998 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1997.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference
to the 1998 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1997.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 1998 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1997.
35
38
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A)(1) FINANCIAL STATEMENTS
THE RESPONSE TO THIS ITEM IS SUBMITTED IN A SEPARATE SECTION OF THIS
REPORT.
(A)(2) FINANCIAL STATEMENT SCHEDULES
All schedules and other statements for which provision is made in the
applicable regulations of the Commission have been omitted because they are not
required under the relevant instructions or are inapplicable.
(A)(3) EXHIBITS
+2.1 -- Combination Agreement by and among the Company, Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa
Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr.,
Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton
and Frank A. Wojtek dated as of June 6, 1997
(Incorporated herein by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
3.1 -- Amended and Restated Articles of Incorporation of the
Company.
3.2 -- Statement of Resolution Establishing Series of Shares
designated 9% Series A Preferred Stock.
+3.3 -- Amended and Restated Bylaws of the Company, as amended by
Amendment No. 1 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Registration Statement on
Form 8-A (Registration No. 000-22915).
+4.1 -- First Amended, Restated, and Combined Loan Agreement
between the Company and Compass Bank dated August 28,
1997 (Incorporated herein by reference to Exhibit 4.1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997).
4.2 -- First Amendment to First Amended, Restated, and Combined
Loan Agreement between the Company and Compass Bank dated
December 23, 1997.
4.3 -- Second Amendment to First Amended, Restated, and Combined
Loan Agreement between the Company and Compass Bank dated
December 30, 1997.
-- The Company is a party to several debt instruments under
which the total amount of securities authorized does not
exceed 10% of the total assets of the Company and its
subsidiaries on a consolidated basis. Pursuant to
paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the
Company agrees to furnish a copy of such instruments to
the Commission upon request.
+10.1 -- Incentive Plan of the Company (Incorporated herein by
reference to Exhibit 10.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+10.2 -- Employment Agreement between the Company and S.P. Johnson
IV (Incorporated herein by reference to Exhibit 10.2 to
the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.3 -- Employment Agreement between the Company and Frank A.
Wojtek (Incorporated herein by reference to Exhibit 10.3
to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.4 -- Employment Agreement between the Company and Kendall A.
Trahan (Incorporated herein by reference to Exhibit 10.4
to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
36
39
+10.5 -- Employment Agreement between the Company and George Canjar (Incorporated herein by reference
to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
10.6 -- Indemnification Agreement between the Company and each of its directors and executive
officers.
+10.7 -- Registration Rights Agreement by and among the Company, Paul B. Loyd, Jr., Steven A. Webster,
S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1997
(Incorporated herein by reference to Exhibit 10.7 to the Company's Registration Statement on
Form S-1 (Registration No. 333-29187)).
+10.8 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and
Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference to
Exhibit 10.8 to the Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.9 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production,
Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by
reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1 (Registration
No. 333-29187)).
+10.10 -- Stock Purchase Agreement dated January 8, 1998 among the Company, Enron Capital & Trade
Resources Corp. and Joint Energy Development Investments II Limited Partnership.
(Incorporated herein by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K
dated January 8, 1998).
+10.11 -- Warrant Certificates (Incorporated herein by reference to Exhibit 4.2 to the Company's
Current Report on Form 8-K dated January 8, 1998.)
+10.12 -- Shareholders' Agreement dated January 8, 1998 among the Company, S.P. Johnson IV, Frank A.
Wojtek, Steven A. Webster, Paul B. Loyd, Jr., Douglas A.P. Hamilton, DAPHAM Partnership,
L.P., The Douglas A.P. Hamilton 1997 GRAT, Enron Capital & Trade Resources Corp. and Joint
Energy Development Investments II Limited Partnership. (Incorporated herein by reference to
Exhibit 99.2 to the Company's Current Report on Form 8-K dated January 8, 1998).
+10.13 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by
reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated January 8, 1998).
23.1 -- Consent of Arthur Andersen LLP.
23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
23.3 -- Consent of Fairchild, Ancell & Wells, Inc.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 1997.
99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells, Inc. as of December 31, 1997.
- ---------------
+ Incorporated by reference as indicated.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the last quarter of the period
covered by this Annual Report on Form 10-K.
37
40
CARRIZO OIL & GAS, INC.
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Carrizo Oil & Gas, Inc. --
Report of Independent Public Accountants.................. F-2
Balance Sheets, December 31, 1996 and 1997................ F-3
Statements of Operations for the Years Ended December 31,
1995, 1996 and 1997.................................... F-4
Statements of Stockholders' Equity for the Years Ended
December 31, 1995, 1996 and 1997....................... F-5
Statements of Cash Flows for the Years Ended December 31,
1995, 1996 and 1997.................................... F-6
Notes to Financial Statements............................. F-7
F-1
41
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and
Board of Directors of
Carrizo Oil & Gas, Inc.:
We have audited the accompanying balance sheets of Carrizo Oil & Gas, Inc.
(a Texas corporation) as of December 31, 1996 and 1997, and the related
statements of operations, stockholders' equity and cash flows for each of the
three years in the period ended December 31, 1997. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of December
31, 1996 and 1997, and the results of its operations and cash flows for each of
the three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
March 6, 1998
F-2
42
CARRIZO OIL & GAS, INC
BALANCE SHEETS
AS OF DECEMBER 31,
--------------------------
1996 1997
----------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 1,492,603 $ 2,674,837
Accounts receivable, trade................................ 1,654,032 1,794,175
Accounts receivable, joint interest owners................ 82,296 1,841,329
Accounts receivable from related parties.................. 79,578 --
Advances to operators..................................... -- 1,817,990
Other current assets...................................... 15,472 108,633
----------- -----------
Total current assets.............................. 3,323,981 8,236,964
PROPERTY AND EQUIPMENT, net (full-cost method of accounting
for oil and gas properties)............................... 15,205,587 45,082,833
OTHER ASSETS................................................ 339,789 338,638
----------- -----------
$18,869,357 $53,658,435
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade................................... $ 4,326,299 $10,433,479
Other current liabilities................................. 22,976 79,328
----------- -----------
Total current liabilities......................... 4,349,275 10,512,807
NOTES PAYABLE TO RELATED PARTIES............................ 2,773,935 --
LONG-TERM DEBT.............................................. 6,910,000 7,950,000
DEFERRED INCOME TAXES....................................... -- 2,300,267
OTHER LONG-TERM LIABILITIES................................. 240,197 --
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value (10,000,000 shares
authorized with none issued and outstanding)........... -- --
Common stock, $0.01 par value (40,000,000 shares
authorized with 7,500,000 and 10,375,000 issued and
outstanding at December 31, 1996 and 1997,
respectively).......................................... 75,000 103,750
Additional paid-in capital................................ 4,186,000 32,845,727
Retained earnings......................................... 334,950 365,690
Deferred compensation..................................... -- (419,806)
----------- -----------
4,595,950 32,895,361
----------- -----------
$18,869,357 $53,658,435
=========== ===========
The accompanying notes are an integral part of these financial statements.
F-3
43
CARRIZO OIL & GAS, INC.
STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------
1995 1996 1997
---------- ---------- ----------
OIL AND NATURAL GAS REVENUES............................ $2,428,048 $5,194,709 $8,711,654
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below)............... 1,813,406 2,384,145 2,334,009
Depreciation, depletion and Amortization.............. 487,949 1,135,797 2,358,256
General and administrative............................ 425,198 514,644 1,590,358
---------- ---------- ----------
Total costs and Expenses...................... 2,726,553 4,034,586 6,282,623
---------- ---------- ----------
OPERATING INCOME (LOSS)................................. (298,505) 1,160,123 2,429,031
OTHER INCOME AND EXPENSES:
Interest income....................................... -- -- 53,417
Interest expense...................................... (274,585) (312,409) (713,999)
Interest expense, related parties..................... (35,059) (189,881) (137,067)
Capitalized interest.................................. 117,288 422,493 699,625
Other income.......................................... 24,251 19,525 --
---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES....................... (466,610) 1,099,851 2,331,007
INCOME TAXES............................................ -- -- 2,300,267
---------- ---------- ----------
NET INCOME (LOSS)....................................... $ (466,610) $1,099,851 $ 30,740
========== ========== ==========
BASIC EARNINGS (LOSS) PER SHARE (Note 2)................ $ (0.07) $ 0.15 $ 0.00
========== ========== ==========
DILUTED EARNINGS (LOSS) PER SHARE (Note 2).............. $ (0.07) $ 0.15 $ 0.00
========== ========== ==========
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (Note 2).................................. 7,020,951 7,475,650 8,638,699
========== ========== ==========
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (Note 2).................................. 7,020,951 7,545,063 8,809,572
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
F-4
44
CARRIZO OIL & GAS, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
(NOTES 1 AND 2)
COMMON STOCK ADDITIONAL RETAINED TOTAL
--------------------- PAID-IN EARNINGS DEFERRED STOCKHOLDERS'
SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION EQUITY
---------- -------- ----------- ---------- ------------ --------------
BALANCE, January 1, 1995......... 6,590,601 $ 65,906 $ 684,094 $ (298,291) $ -- $ 451,709
Net loss....................... -- -- -- (466,610) -- (466,610)
Distributions.................. -- -- (104,000) -- -- (104,000)
Common stock issued to
unitholders.................. 860,699 8,607 3,491,393 -- -- 3,500,000
---------- -------- ----------- ---------- --------- -----------
BALANCE, December 31, 1995....... 7,451,300 74,513 4,071,487 (764,901) -- 3,381,099
Net income..................... -- -- -- 1,099,851 -- 1,099,851
Distributions.................. -- -- (335,000) -- -- (335,000)
Common stock issued to
unitholders.................. 48,700 487 449,513 -- -- 450,000
---------- -------- ----------- ---------- --------- -----------
BALANCE, December 31, 1996....... 7,500,000 75,000 4,186,000 334,950 -- 4,595,950
Net income..................... -- -- -- 30,740 -- 30,740
Distributions.................. -- -- (90,000) -- -- (90,000)
Public offering................ 2,875,000 28,750 28,050,049 -- -- 28,078,799
Deferred compensation related
to certain stock options..... -- -- 699,678 -- (699,678) --
Amortization of deferred
compensation................. -- -- -- -- 279,872 279,872
---------- -------- ----------- ---------- --------- -----------
BALANCE, December 31, 1997....... 10,375,000 $103,750 $32,845,727 $ 365,690 $(419,806) $32,895,361
========== ======== =========== ========== ========= ===========
The accompanying notes are an integral part of these financial statements.
F-5
45
CARRIZO OIL & GAS, INC.
STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1996 1997
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................. $ (466,610) $ 1,099,851 $ 30,740
Adjustment to reconcile net income (loss) to net
cash provided by (used in) operating
activities --
Depreciation, depletion and amortization....... 487,949 1,135,797 2,358,256
Deferred income taxes.......................... -- -- 2,300,267
Changes in assets and liabilities --
Accounts receivable............................ (245,365) (1,457,950) (1,819,598)
Other current assets........................... (9,433) 322 (93,161)
Accounts payable, trade........................ 518,166 2,422,257 475,268
Interest payable to related parties and other
current liabilities.......................... 120,946 125,164 (183,845)
----------- ----------- -----------
Net cash provided by operating
activities.............................. 405,653 3,325,441 3,067,927
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -- accrual basis............. (6,857,057) (9,479,561) (32,234,351)
Adjustment to cash basis.......................... 71,664 1,258,132 5,911,784
Advances to operators............................. -- -- (1,817,990)
----------- ----------- -----------
Net cash used in investing activities..... (6,785,393) (8,221,429) (28,140,557)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of stock................... -- -- 28,078,799
Proceeds from debt issuance....................... 2,083,684 6,910,000 18,544,454
Debt repayments................................... -- (2,083,684) (20,408,934)
Proceeds from related party notes payable......... 863,696 1,377,739 130,545
Capital contributions............................. 3,500,000 450,000 --
Capital distributions............................. (104,000) (335,000) (90,000)
----------- ----------- -----------
Net cash provided by financing
activities.............................. 6,343,380 6,319,055 26,254,864
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS....................................... (36,360) 1,423,067 1,182,234
CASH AND CASH EQUIVALENTS, beginning of
year.............................................. 105,896 69,536 1,492,603
----------- ----------- -----------
CASH AND CASH EQUIVALENTS, end of year.............. $ 69,536 $ 1,492,603 $ 2,674,837
=========== =========== ===========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts
capitalized)................................... $ 122,471 $ -- $ 151,441
The accompanying notes are an integral part of these financial statements.
F-6
46
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS, COMBINATION AND OFFERING:
NATURE OF OPERATIONS
Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its
affiliates and predecessors, the Company) is an independent energy company
engaged in the exploration, development, exploitation and production of oil and
natural gas. It's operations are focused on Texas and Louisiana Gulf Coast
trends, primarily the Frio, Wilcox and Vicksburg trends. The Company has
acquired or is in the process of acquiring 1,170 square miles of 3-D seismic
data. Additionally, the Company has assembled approximately 419,953 gross acres
under lease or option.
THE COMBINATION
Carrizo was formed in 1993 and is the surviving entity after a series of
combination transactions (the Combination). The Combination included the
following transactions: (a) Carrizo Production, Inc. (a Texas corporation and an
affiliated entity with ownership identical to Carrizo) was merged into Carrizo
and the outstanding shares of capital stock of Carrizo Production, Inc. were
exchanged for an aggregate of 343,000 shares of common stock of Carrizo (the
Common Stock); (b) Carrizo acquired Encinitas Partners Ltd. (a Texas limited
partnership of which Carrizo Production, Inc. served as the general partner) as
follows: Carrizo acquired from the shareholders who serve as directors of
Carrizo (the Founders) their limited partner interests in Encinitas Partners
Ltd. for an aggregate consideration of 468,533 shares of Common Stock and, on
the same date, Encinitas Partners Ltd. was merged into Carrizo and the
outstanding limited partner interests in Encinitas Partners Ltd. were exchanged
for an aggregate of 860,699 shares of Common Stock; (c) La Rosa Partners Ltd. (a
Texas limited partnership of which Carrizo served as the general partner) was
merged into Carrizo and the outstanding limited partner interests in La Rosa
Partners Ltd. were exchanged for an aggregate of 48,700 shares of Common Stock;
and (d) Carrizo Partners Ltd. (a Texas limited partnership of which Carrizo
served as the general partner) was merged into Carrizo and the outstanding
limited partner interests in Carrizo Partners Ltd. were exchanged for an
aggregate of 569,068 shares of Common Stock.
The Combination was accounted for as a reorganization of entities as
prescribed by Securities and Exchange Commission (SEC) Staff Accounting Bulletin
47 because of the high degree of common ownership among, and the common control
of, the combining entities. Accordingly, the accompanying financial statements
have been prepared using the historical costs and results of operations of the
affiliated entities. There were no significant differences in accounting methods
or their application among the combining entities. All intercompany balances
have been eliminated. Certain reclassifications have been made to prior period
amounts to conform to the current period's financial statement presentation.
INITIAL PUBLIC OFFERING
Simultaneous with the Combination, the Company completed its initial public
offering (the Offering) of 2,875,000 shares of its common stock at a public
offering price of $11.00 per share. The Offering provided the Company with
proceeds of approximately $28.1 million, net of expenses.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
OIL AND NATURAL GAS PROPERTIES
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. No general and administrative costs were
capitalized in 1995 or 1996. During the year ended December 31, 1997, the
Company capitalized as oil and natural gas properties $279,872 of deferred
compensation related to stock options granted to personnel directly associated
with exploration activities (See Note 7).
F-7
47
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Oil and natural gas properties are amortized based on the
unit-of-production method using estimates of proved reserve quantities.
Investments in unproved properties are not amortized until proved reserves
associated with the projects can be determined or until impairment occurs.
Unevaluated properties are evaluated quarterly for impairment on a
property-by-property basis. If the results of an assessment indicate that the
properties are impaired, the amount of impairment is added to the proved oil and
natural gas property costs to be amortized. The amortizable base includes
estimated future development costs and, where significant, dismantlement,
restoration and abandonment costs, net of estimated salvage values. The
depletion rate per thousand cubic feet equivalent (Mcfe) for 1995, 1996, 1997,
was $0.47, $0.59, and $0.69, respectively.
Dispositions of oil and gas properties are accounted for as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves.
The net capitalized costs of proved oil and gas properties are subject to a
"ceiling test," which limits such costs to the estimated present value,
discounted at a 10 percent interest rate, of future net cash flows from proved
reserves, based on current economic and operating conditions. If net capitalized
costs exceed this limit, the excess is charged to operations through
depreciation, depletion and amortization. No write-down of the Company's oil and
natural gas assets was necessary in 1995, 1996 or 1997.
Depreciation of other property and equipment is provided using the
straight-line method based on estimated useful lives ranging from five to 10
years.
FINANCING COSTS
Offering costs of $11,992 through December 31, 1997 have been deferred and
are anticipated to be applied against Preferred Stock offering proceeds (see
Note 9). Long-term debt financing costs of $47,194 and $226,247 as of December
31, 1996 and 1997, respectively, are capitalized as deferred assets and are
being amortized over the term of the loans.
STATEMENTS OF CASH FLOWS
For statement of cash flow purposes, all highly liquid investments with
original maturities of three months or less are considered to be cash
equivalents.
FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash, receivables, payables
and long-term debt. The carrying amount of cash, receivables and payables
approximates fair value because of the short-term nature of these items. The
carrying amount of long-term debt approximates fair value as the individual
borrowings bear interest at floating market interest rates.
HEDGING ACTIVITIES
The Company periodically enters into hedging arrangements to manage price
risks related to oil and natural gas sales and not for speculative purposes. The
Company's hedging arrangements apply only to a portion of its anticipated
production, provide only partial price protection against declines in oil and
natural gas prices and limit potential gains from future increases in prices.
For financial reporting purposes, gains and losses related to hedging are
recognized as income when the hedged transaction occurs. Historically, gains and
losses from hedging activities have not been material. Total oil and natural gas
quantities hedged in 1995, 1996 and 1997 were 9,000 Bbls, 3,000 Bbls and 0 Bbls,
respectively, and 40,000 MMBtu, 60,000 MMBtu, and 210,000 MMBtu, respectively.
At December 31, 1997, the Company had 364,000 MMBtu of outstanding hedged
positions (at an average price of $2.86 per MMBtu for first quarter 1998
production.) These instruments had a fair value market of $250,000 as of
December 31, 1997.
F-8
48
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
INCOME TAXES
Through May 15, 1997, Carrizo and its affiliated entities either had
elected to be treated as S Corporations under the Internal Revenue Code or were
otherwise not taxed as entities for federal income tax purposes. The taxable
income or loss was therefore allocated to the equity owners of Carrizo and the
affiliated entities. Accordingly, no provision was made for income taxes in the
accompanying historical financial statements for the years ended December 31,
1995 and 1996.
On May 16, 1997, Carrizo terminated its status as an S corporation and
thereafter became subject to federal income taxes. The Company, beginning with
the termination of its tax exempt status, provides income taxes for the
difference in the tax and financial reporting bases of its assets and
liabilities in accordance with Statement of Financial Accounting Standards
("SFAS") No. 109, "Accounting for Income Taxes." The termination of its tax
exempt status in 1997 required the Company to establish a deferred tax
liability, which resulted in a one-time noncash charge to income in 1997 of
$1,623,000. The Company has entered into tax indemnification agreements with the
founders of the Company pertaining to periods in which the Company was an S
Corporation. Had Carrizo been a taxpaying entity prior to May 17, 1997, its net
income and earnings per share would have been as follows:
PRO FORMA
------------------------
1996 1997
---------- ----------
(UNAUDITED)
Net income (after unaudited pro forma income taxes of
$395,946 and $816,852 in 1996 and 1997, respectively...... $ 703,905 $1,514,155
========== ==========
Basic and diluted earnings per share........................ $ 0.09 $ 0.17
========== ==========
Weighted average diluted number of common shares
outstanding............................................... 7,545,063 8,809,572
========== ==========
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates. Significant
estimates include depreciation, depletion and amortization of proved oil and
natural gas properties. Oil and natural gas reserve estimates, which are the
basis for unit-of-production depletion and the ceiling test, are inherently
imprecise and are expected to change as future information becomes available.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables.
EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 128 "Earnings Per Share." The Company adopted this standard effective
December 15, 1997. As a result of the simple nature of the Company's capital
structure, this adoption had no impact on the calculation of earnings per share.
F-9
49
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Basic earnings per share represents the amount of earnings available to
each share of common stock outstanding during the period. Diluted earnings per
share represents the amount of earnings for the period available to each share
of common stock outstanding during the period plus each share that would have
been outstanding assuming the issuance of common shares for all potentially
dilutive common shares outstanding during the period. For Carrizo, the
difference between basic and diluted earnings per share for all periods is stock
options. For certain periods in 1997, the Company had outstanding 250,000 stock
options which were antidilutive or have not been included in the calculation as
the exercise price exceeded the market value. Historical earnings per share for
the years 1995 and 1996 reflect the effects of the Company's stock split and the
issuance of shares in the Combination, applied retroactively to the date that
the corresponding partnership units were issued.
3. PROPERTY AND EQUIPMENT:
At December 31, 1996 and 1997, property and equipment consisted of the
following:
DECEMBER 31,
--------------------------
1996 1997
----------- -----------
Proved oil and natural gas properties..................... $ 9,217,027 $26,994,076
Unproved oil and natural gas properties................... 7,455,698 21,678,368
Other equipment........................................... 62,073 225,069
----------- -----------
Total property and equipment.................... 16,734,798 48,897,513
Accumulated depreciation, depletion and amortization...... (1,529,211) (3,814,680)
----------- -----------
Property and equipment, net............................... $15,205,587 $45,082,833
=========== ===========
Oil and natural gas properties not subject to amortization consist of the
cost of undeveloped leaseholds, undesignated seismic costs, exploratory wells in
progress, and secondary recovery projects before the assignment of proved
reserves. These costs are reviewed periodically by management for impairment,
with the impairment provision included in the cost of oil and natural gas
properties subject to amortization. Factors considered by management in its
impairment assessment include drilling results by the Company and other
operators, the terms of oil and natural gas leases not held by production,
production response to secondary recovery activities and available funds for
exploration and development. Of the $21,678,368 of unproved property costs at
December 31, 1997 being excluded from the amortizable base, $1,421,642,
$2,269,807 and $17,986,919 were incurred in 1995, 1996 and 1997, respectively.
The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next three years.
4. INCOME TAXES
Actual income tax expense differs from income tax expense computed by
applying the U. S. federal statutory corporate rate of 35 percent to pretax
income as follows:
YEAR ENDED
DECEMBER 31,
1997
------------
Provision at the statutory tax rate......................... $ 816,852
Increase resulting from election to forgo tax exempt
status.................................................... 1,483,415
----------
$2,300,267
==========
F-10
50
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Deferred income tax assets and liabilities result from temporary
differences in the recognition of income and expenses for financial reporting
purposes and for tax purposes. At December 31, 1997, the tax effects of these
temporary differences, resulted principally from the following:
DECEMBER 31,
1997
------------
Deferred income tax asset:
Statutory depletion carryforward.......................... $ 78,159
Deferred income tax liabilities:
Intangible drilling costs................................. 1,944,634
Capitalized interest...................................... 433,792
----------
2,378,426
----------
Deferred income tax liability..................... $2,300,267
==========
5. LONG-TERM DEBT:
At December 31, 1996 and 1997, notes payable and long-term debt consisted
of the following:
DECEMBER 31,
------------------------
1996 1997
---------- ----------
Notes payable to shareholders (due April, 1998)............. $2,773,935 $ --
Bridge Loan payable to Compass Bank......................... -- 3,000,000
$10 million revolving credit facility (due June 1, 1998).... 2,910,000 --
$25 million revolving credit facility (due June 1, 1999).... 4,000,000 4,950,000
---------- ----------
$9,683,935 $7,950,000
========== ==========
In June 1996, the Company entered into a $10 million revolving credit
facility with Compass Bank (the Encinitas Facility). Proceeds from this facility
were used to pay off an existing loan from Texas Commerce Bank (TCB) as well as
fund exploration and development activities. The facility was subject to a
borrowing base calculation and had a commitment of $3,350,000 with $2,910,000
outstanding at December 31, 1996. The facility was also available for letters of
credit, one of which was issued for $224,000. The Encinitas Facility was repaid
with proceeds from the Offering.
In December 1996, Carrizo entered into a separate $25 million revolving
credit facility with Compass Bank, which was subject to a borrowing base
determination, and total commitment was $6 million at December 31, 1996.
Interest on this facility was the prime rate as defined by Compass Bank plus .75
percent, and the borrowings were due on June 1, 1998.
In connection with the Offering, Carrizo amended the revolving credit
facility with Compass Bank, (the "Company Credit Facility"), to provide for a
maximum loan amount of $25 million, subject to borrowing base limitations. Under
the Company Credit Facility, the principal outstanding was due and payable upon
maturity in June 1999 with interest due monthly. The interest rate for
borrowings is calculated at a floating rate based on the Compass index rate or
LIBOR plus 2 percent. The Company's obligations are secured by certain of its
oil and gas properties and cash and cash equivalents included in the borrowing
base.
Under the Company Credit Facility, Compass, in its sole discretion, will
make semiannual borrowing base determinations based upon the proved oil and
natural gas properties of the Company. Compass may redetermine the borrowing
base and the monthly borrowing base reduction at any time and from time to time.
The Company may also request borrowing base redeterminations in addition to its
required semiannual reviews at the Company's cost.
F-11
51
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Proceeds from this facility were used to provide working capital for
exploration and development activity. Substantially all of Carrizo's oil and
natural gas property and equipment was pledged as collateral under this
facility. At December 31, 1996, and 1997, borrowings under this facility totaled
$4,000,000 and $4,950,000, respectively, with an additional $2,000,000 and
$276,000, respectively, available for future borrowings. The facility was also
available for letters of credit, one of which had been issued for $224,000 at
December 31, 1997. The weighted average interest rate for 1996 and 1997 on the
Facility was 9 percent.
The Company is subject to certain covenants under the terms of the Company
Credit Facility, including but not limited to (a) maintenance of specified
tangible net worth and (b) maintenance of a ratio of quarterly cash flow (net
income plus depreciation and other noncash expenses, less noncash net income) to
quarterly debt service (payments made for principal in connection with each
credit facility plus payments made for principal other than in connection with
such credit facility) of no less than 1.25 to 1.00. The Company Credit Facility
also place restrictions on, among other things, (a) incurring additional
indebtedness, guaranties, loans and liens, (b) changing the nature of business
or business structure, (c) selling assets and (d) paying dividends.
In December 1997, the Company entered into a term loan facility with
Compass Bank bearing interest at 10.5% and due June 1, 1998 (the Bridge Loan).
Proceeds from the facility were used to fund continuing exploration activities
until the Company had completed its Preferred Stock sale discussed in Note 9. At
December 31, 1997, $3,000,000 was outstanding under the Bridge loan. The Bridge
Loan was due the earlier of April 1998 or concurrent with the Preferred Stock
sale.
The Company had outstanding borrowings from certain shareholders totaling
$2,773,935 at December 31, 1996. These loans bore interest at the TCB prime
rate, and were repaid in August 1997 out of the proceeds of the Offering.
Accrued interest on shareholder borrowings at December 31, 1996 was included in
other long-term liabilities.
All amounts outstanding under the Company's debt facilities were refinanced
in January 1998 with the proceeds from the Preferred Stock sale. As a result,
all debt at December 31, 1997 has been classified as long term.
6. COMMITMENTS AND CONTINGENCIES:
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
At December 31, 1997, Carrizo was obligated under a noncancelable operating
lease for office space. Rent expense for the years ended December 31, 1995, 1996
and 1997, was $7,600, $14,900 and $80,000, respectively. Following is a schedule
of the remaining future minimum lease payments under this lease:
1998............................................. $ 108,700
1999............................................. $ 108,700
2000............................................. $ 54,350
7. STOCKHOLDERS' EQUITY:
On June 4, 1997, the board of directors authorized a 521-for-1 split of the
Company's stock and increased the number of authorized shares to 40 million
shares of common stock and 10 million shares of preferred stock. All share
amounts presented in these financial statements are presented on a retroactive,
post-split basis.
F-12
52
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
On July 19, 1996, and March 1, 1997, the Company entered into separate
stock option agreements (the "Pre-IPO Options") with two executives of Carrizo
whereby such employees were granted the option to purchase 138,825 shares and
83,295 shares of Carrizo common stock, respectively, at an exercise price of
$3.60 per share. The options vest ratably through August 1, 1998, and March 1,
1999, respectively.
The Company did not record any compensation expense related to the July,
1996 options because the related exercise price was at or above the estimated
fair value of Carrizo's common stock at the time such options were granted. In
connection with an initial public offering, the Company recorded deferred
compensation related to the March 1997 stock option agreement as additional
paid-in capital and an offsetting contra-equity account. This compensation
accrual is based on the difference between the option price and the fair value
of Carrizo's common stock when the options were granted (using an estimate of
the initial public offering common stock price as an estimate of fair value).
The deferred compensation is amortized in the period in which the options vest,
which resulted in $279,972 being recorded in the year ended December 31, 1997.
In June of 1997, the Company established the Incentive Plan of Carrizo Oil
& Gas, Inc. ("the Incentive Plan"). The Company accounts for this plan under APB
Opinion No. 25, under which no compensation cost has been recognized. Had
compensation cost been determined consistent with SFAS No. 123 for all options,
the Company's net income and earnings per share would have been reduced to the
following pro forma amounts:
1996 1997
---------- ---------
Net income (loss)..................... As reported $1,099,851 $ 30,740
Pro forma $1,038,490 $(193,722)
Diluted net income (loss) per share... As reported $ 0.14 $ --
Pro forma $ 0.13 $ (.02)
The Company may grant options ("Incentive Plan Options") to purchase up to
1,000,000 shares under the Incentive Plan and has granted options on 250,000
shares through December 31, 1997. Under the Incentive Plan, the option exercise
price equals the stock market price on the date of grant. Options granted under
the plan vest ratably over three years and have a term of ten years. A summary
of the status of the Company's stock options at December 31, 1996 and 1997 is
presented in the table below:
1996
-------------------------------------------
WEIGHTED AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
------- ---------------- --------
Outstanding at beginning of year............. -- --
Granted (Pre-IPO Options).................... 138,825 $3.60 $0-3.60
------- -----
Outstanding at end of year................... 138,825 $3.60 $0-3.60
======= =====
Exercisable at end of year................... 46,275
Weighted average fair value per share of
options granted during the year............ $ 2.21
F-13
53
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
1997
--------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
------- -------- -----------
Outstanding at beginning of year............... 138,825 $3.60 $ 0-3.60
Granted (Pre-IPO Options)...................... 83,295 $3.60 $ 0-3.60
Granted (Incentive Plan Options)............... 250,000 11.00 $ 0-11.00
------- -----
Outstanding at end of year..................... 472,120 $7.52 $3.60-11.00
======= =====
Exercisable at end of year..................... 120,315
Weighted average fair value per share of
options granted during the year.............. $ 6.91
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in both 1996 and 1997: risk free interest rate of 6.82% and 6.26%
respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 30% and 39.4%, respectively.
8. RELATED-PARTY TRANSACTIONS:
In August 1996, the Company entered into the Master Technical Services
Agreement (the MTS Agreement) with Reading & Bates Development Co. (R&B), which
is a subsidiary of R&B Falcon Corporation, a company that was created by the
merger of Falcon Drilling Company, Inc. and Reading & Bates Corporation. Paul
Loyd, a member of the board of the Company, was the chairman of the board,
president, chief executive officer and a director of Reading & Bates
Corporation. Under the MTS Agreement, certain employees of the Company provide
engineering and technical services to R&B at market rates in connection with
R&B's technical service, procurement and construction projects in offshore
drilling and floating production. The Company billed $117,726 and $103,161 in
service fees under this agreement in 1996 and 1997, respectively.
The Company had an agreement with Loyd & Associates Inc., which is owned by
Paul Loyd, a director of Carrizo, and Frank Wojtek, vice president, chief
financial officer and a director of Carrizo, to provide certain financial
consulting and administrative services at market rates to the Company. Payments
were made monthly and total payments to Loyd & Associates Inc. for services
rendered were $60,000, $60,000 and $38,113 in 1995, 1996 and 1997, respectively.
These expenditures were included in general and administrative expenses for each
year. This arrangement was terminated in August, 1997 concurrent with the
Company's initial public offering.
9. SUBSEQUENT EVENT:
SALES OF PREFERRED STOCK AND WARRANTS
In January 1998, the Company consummated the sale of 300,000 shares of
Preferred Stock and Warrants to purchase 1,000,000 shares of Common Stock to
affiliates of Enron Corp. The net proceeds received by the Company from this
transaction were approximately $28.8 million. A portion of the proceeds were
used to repay indebtedness, as described in Note 5, above. The remaining
proceeds are expected to be used primarily for oil and natural gas exploration
and development activities in Texas and Louisiana. The Preferred Stock provides
for annual cumulative dividends of $9.00 per share, payable quarterly in cash
or, at the option of the Company until January 15, 2002, in additional shares of
Preferred Stock. The Warrants, which had a fair value at issuance of $0.30 per
share, will be accreted through the term of the Preferred Stock. Had the
F-14
54
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Preferred Stock sale been completed as of December 31, 1997, the Company's pro
forma capitalization would have been as follows:
CAPITALIZATION AT
DECEMBER 31, 1997
---------------------------
ACTUAL PRO FORMA
----------- -----------
Bridge Loan................................................. $ 3,000,000 $ --
Company Credit Facility..................................... 4,950,000 --
Mandatorily Redeemable Preferred Stock...................... -- 28,500,000
----------- -----------
7,950,000 28,500,000
Stockholders' Equity........................................ 32,895,000 33,195,000
----------- -----------
Total Capitalization........................................ $40,845,000 $61,695,000
=========== ===========
The Preferred Stock is required to be redeemed by the Company (i) on
January 8, 2005, or (ii) after a request for redemption from the holders of at
least 30,000 shares of the Preferred Stock (or, if fewer than such number of
shares of Preferred Stock are outstanding, all of the outstanding shares of
Preferred Stock) and the occurrence of certain events. The Preferred Stock also
may be redeemed at the option of the Company at any time in whole or in part.
All redemptions are at a price per share, together with dividends accumulated
and unpaid to the date of redemption, decreasing over time from an initial rate
of $104.50 per share to $100 per share. The Warrants (i) enable the holders to
purchase 1,000,000 shares of Common Stock at a price of $11.50 per share
(payable in cash, by "cashless exercise" and certain other methods), subject to
adjustments, (ii) expire after a seven-year term, and (iii) are exercisable
after one year.
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT
AND PRODUCTION ACTIVITIES (UNAUDITED):
The following disclosures provide unaudited information required by SFAS
No. 69, "Disclosures About Oil and Gas Producing Activities."
COSTS INCURRED
Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:
YEAR ENDED DECEMBER 31
-------------------------------------
1995 1996 1997
---------- ---------- -----------
Property acquisition costs --
Unproved...................................... $ 316,820 $ 50,720 $ --
Proved........................................ 3,588,173 1,907,890 14,820,049
Exploration cost................................ 2,364,056 4,724,102 14,222,674
Development costs............................... 208,696 1,955,917 2,257,375
---------- ---------- -----------
Total costs incurred(1)............... $6,477,745 $8,638,629 $31,300,098
========== ========== ===========
- ---------------
(1) Excludes capitalized interest on unproved properties of $117,288, $422,493
and $699,625 for the years ended December 31, 1995, 1996 and 1997,
respectively.
OIL AND NATURAL GAS RESERVES
Proved reserves are estimated quantities of oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
F-15
55
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
economic and operating conditions. Proved developed reserves are proved reserves
that can reasonably be expected to be recovered through existing wells with
existing equipment and operating methods.
Proved oil and natural gas reserve quantities at December 31, 1996 and
1997, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company and Fairchild, Ancell &
Wells, Inc., independent petroleum engineers. Such estimates have been prepared
in accordance with guidelines established by the Securities and Exchange
Commission. Amounts at December 31, 1995, and for the periods then ended were
rolled back from December 31, 1996, balances, ignoring the impact of revisions
of estimates during those periods, if any.
The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:
BARRELS OF
OIL AND CONDENSATE
AT DECEMBER 31,
---------------------------------
1995 1996 1997
--------- --------- ---------
Proved developed and undeveloped reserves --
Beginning of year................................. 3,785,000 3,810,000 3,895,000
Purchases of oil and gas properties............... 103,000 12,000 --
Discoveries....................................... -- 180,000 285,000
Extensions........................................ -- -- 1,102,000
Production........................................ (78,000) (107,000) (112,500)
--------- --------- ---------
End of year......................................... 3,810,000 3,895,000 5,169,500
========= ========= =========
Proved developed reserves at end of year............ 1,100,000 1,048,000 1,146,000
========= ========= =========
THOUSANDS OF CUBIC FEET OF
NATURAL GAS
AT DECEMBER 31,
-----------------------------------
1995 1996 1997
--------- ---------- ----------
Proved developed and undeveloped reserves --
Beginning of year............................... 272,000 5,437,000 12,148,000
Purchases of oil and gas properties............. 5,730,000 338,000 7,696,000
Discoveries and extensions...................... -- 7,646,000 6,946,000
Revisions....................................... -- -- (7,190,000)
Sales of oil and gas properties................. -- -- (4,709,000)
Production...................................... (565,000) (1,273,000) (2,749,000)
--------- ---------- ----------
End of year....................................... 5,437,000 12,148,000 12,142,000
========= ========== ==========
Proved developed reserves at end of year.......... 3,810,000 8,110,000 9,299,000
========= ========== ==========
F-16
56
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows relating to
the Company's ownership interests in proved oil and natural gas reserves as of
year-end is shown below:
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1996 1997
----------- ------------ ------------
Future cash inflows......................... $77,739,000 $126,155,000 $103,842,000
Future oil and natural gas operating
expenses.................................. 43,529,000 47,675,000 55,484,000
Future development costs.................... 7,918,000 9,375,000 13,230,000
Future income tax expenses.................. 7,163,000 19,864,000 6,870,000
----------- ------------ ------------
Future net cash flows....................... 19,129,000 49,241,000 28,258,000
10% annual discount for estimating timing of
cash flows................................ 7,148,000 16,220,000 7,285,000
----------- ------------ ------------
Standardized measure of discounted future
net cash flows............................ $11,981,000 $ 33,021,000 $ 20,973,000
=========== ============ ============
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Prices used in computing year end 1996 and 1997 future cash flows were $20.88
and $16.37 for oil, respectively and $3.69 and $2.56 for natural gas,
respectively. Such prices declined significantly in the first quarter of 1998.
The ceiling test for many full cost companies, including Carrizo, could be
negatively impacted by prolonged unfavorable oil and gas prices. A deterioration
of prices from year-end levels could result in the Company recording a first
quarter 1998 non-cash charge to earnings related to its oil and gas properties.
Future operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the Company's proved oil and natural gas reserves at
the end of the year, based on the year-end costs and assuming continuation of
existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax
basis and applicable tax credits. A discount factor of 10 percent was used to
reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties. An
estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the
time value of money and the risks inherent in reserve estimates.
F-17
57
CARRIZO OIL & GAS, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
CHANGE IN STANDARDIZED MEASURE
Changes in the standardized measure of future net cash flows relating to
proved oil and natural gas reserves are summarized below:
YEAR ENDED DECEMBER 31,
------------------------------------------
1995 1996 1997
----------- ----------- ------------
Changes due to current-year operations --
Sales of oil and natural gas, net of oil
and natural gas operating expenses.... $ (614,000) $(2,811,000) $ (6,378,000)
Extensions and discoveries............... -- 19,641,000 16,074,000
Purchases of oil and gas properties...... 2,770,000 2,079,000 6,954,000
Changes due to revisions in standardized
variables --
Prices and operating expenses............ 6,343,000 9,781,000 (29,115,000)
Income taxes............................. (1,307,000) (8,834,000) 11,410,000
Estimated future development costs....... -- (670,000) (2,683,000)
Quantities............................... -- -- (3,449,000)
Sales of reserves in place............... -- -- (3,933,000)
Accretion of discount.................... 968,000 1,647,000 4,634,000
Production rates (timing) and other...... (2,677,000) 207,000 (5,562,000)
----------- ----------- ------------
Net change................................. 5,483,000 21,040,000 (12,048,000)
Beginning of year.......................... 6,498,000 11,981,000 33,021,000
----------- ----------- ------------
End of year................................ $11,981,000 $33,021,000 $ 20,973,000
=========== =========== ============
Sales of oil and natural gas, net of oil and natural gas operating
expenses, are based on historical pretax results. Sales of oil and natural gas
properties, extensions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pretax
discounted basis.
F-18
58
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
FIRST SECOND THIRD FOURTH
---------- ----------- ---------- ----------
1997
Revenues................................... $1,853,170 $ 2,311,854 $2,069,237 $2,477,393
Expenses, net.............................. 1,137,554 3,675,879 1,787,800 2,079,681
---------- ----------- ---------- ----------
Net Income................................. $ 715,616 $(1,364,025) $ 281,437 $ 397,712
========== =========== ========== ==========
Diluted Net Income (Loss) Per
Share(1)(2)............................. $ 0.09 $ (0.18) $ 0.03 $ 0.04
========== =========== ========== ==========
1996
Revenues................................... $ 790,513 $ 1,428,139 $1,588,354 $1,387,703
Expenses, net.............................. 646,166 1,085,439 1,085,781 1,277,472
---------- ----------- ---------- ----------
Net Income................................. $ 144,347 $ 342,700 $ 502,573 $ 110,231
========== =========== ========== ==========
Diluted Net Income Per Share(1)(2)......... $ 0.02 $ 0.04 $ 0.07 $ 0.01
========== =========== ========== ==========
- ---------------
(1) The sum of individual quarterly net income per common share may not agree
with year-to-date net income per common share as each period's computation
is based on the weighted average number of common shares outstanding during
that period.
(2) Net income per common share amounts have been restated to conform to the
provisions of SFAS No. 128, "Earnings Per Share."
59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CARRIZO OIL & GAS, INC.
By: /s/ FRANK A. WOJTEK
----------------------------------
Frank A. Wojtek
Chief Financial Officer, Vice
President,
Secretary and Treasurer
Date: March 31, 1998.
Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
NAME CAPACITY DATE
---- -------- ----
/s/ S.P. JOHNSON IV President, Chief Executive Officer March 31, 1998
- ----------------------------------------------------- and Director (Principal
S.P. Johnson IV Executive Officer)
/s/ FRANK A. WOJTEK Chief Financial Officer, Vice March 31, 1998
- ----------------------------------------------------- President, Secretary, Treasurer
Frank A. Wojtek and Director (Principal
Financial Officer and Principal
Accounting Officer)
/s/ STEVEN A. WEBSTER Chairman of the Board March 31, 1998
- -----------------------------------------------------
Steven A. Webster
/s/ DOUGLAS A. P. HAMILTON Director March 31, 1998
- -----------------------------------------------------
Douglas A. P. Hamilton
/s/ PAUL B. LOYD, JR. Director March 31, 1998
- -----------------------------------------------------
Paul B. Loyd, Jr.
60
EXHIBIT INDEX
+2.1 -- Combination Agreement by and among the Company, Carrizo
Production, Inc., Encinitas Partners Ltd., La Rosa
Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr.,
Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton
and Frank A. Wojtek dated as of June 6, 1997
(Incorporated herein by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
3.1 -- Amended and Restated Articles of Incorporation of the
Company.
3.2 -- Statement of Resolution Establishing Series of Shares
designated 9% Series A Preferred Stock.
+3.3 -- Amended and Restated Bylaws of the Company, as amended by
Amendment No. 1 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Registration Statement on
Form 8-A (Registration No. 000-22915).
+4.1 -- First Amended, Restated, and Combined Loan Agreement
between the Company and Compass Bank dated August 28,
1997 (Incorporated herein by reference to Exhibit 4.1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997).
4.2 -- First Amendment to First Amended, Restated, and Combined
Loan Agreement between the Company and Compass Bank dated
December 23, 1997.
4.3 -- Second Amendment to First Amended, Restated, and Combined
Loan Agreement between the Company and Compass Bank dated
December 30, 1997.
-- The Company is a party to several debt instruments under
which the total amount of securities authorized does not
exceed 10% of the total assets of the Company and its
subsidiaries on a consolidated basis. Pursuant to
paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the
Company agrees to furnish a copy of such instruments to
the Commission upon request.
+10.1 -- Incentive Plan of the Company (Incorporated herein by
reference to Exhibit 10.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+10.2 -- Employment Agreement between the Company and S.P. Johnson
IV (Incorporated herein by reference to Exhibit 10.2 to
the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.3 -- Employment Agreement between the Company and Frank A.
Wojtek (Incorporated herein by reference to Exhibit 10.3
to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.4 -- Employment Agreement between the Company and Kendall A.
Trahan (Incorporated herein by reference to Exhibit 10.4
to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.5 -- Employment Agreement between the Company and George
Canjar (Incorporated herein by reference to Exhibit 10.5
to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
10.6 -- Indemnification Agreement between the Company and each of
its directors and executive officers.
+10.7 -- Registration Rights Agreement by and among the Company,
Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV,
Douglas A.P. Hamilton and Frank A. Wojtek dated as of
June 6, 1997 (Incorporated herein by reference to Exhibit
10.7 to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
61
+10.8 -- S Corporation Tax Allocation, Payment and Indemnification
Agreement among the Company and Messrs. Loyd, Webster,
Johnson, Hamilton and Wojtek (Incorporated herein by
reference to Exhibit 10.8 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+10.9 -- S Corporation Tax Allocation, Payment and Indemnification
Agreement among Carrizo Production, Inc. and Messrs.
Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated
herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.10 -- Stock Purchase Agreement dated January 8, 1998 among the
Company, Enron Capital & Trade Resources Corp. and Joint
Energy Development Investments II Limited Partnership.
(Incorporated herein by reference to Exhibit 99.1 to the
Company's Current Report on Form 8-K dated January 8,
1998).
+10.11 -- Warrant Certificates (Incorporated herein by reference to
Exhibit 4.2 to the Company's Current Report on Form 8-K
dated January 8, 1998.)
+10.12 -- Shareholders' Agreement dated January 8, 1998 among the
Company, S.P. Johnson IV, Frank A. Wojtek, Steven A.
Webster, Paul B. Loyd, Jr., Douglas A.P. Hamilton, DAPHAM
Partnership, L.P., The Douglas A.P. Hamilton 1997 GRAT,
Enron Capital & Trade Resources Corp. and Joint Energy
Development Investments II Limited Partnership.
(Incorporated herein by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K dated January 8,
1998).
+10.13 -- Form of Amendment to Executive Officer Employment
Agreement. (Incorporated herein by reference to Exhibit
99.3 to the Company's Current Report on Form 8-K dated
January 8, 1998).
23.1 -- Consent of Arthur Andersen LLP.
23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
23.3 -- Consent of Fairchild, Ancell & Wells, Inc.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report of Ryder Scott Company
Petroleum Engineers as of December 31, 1997.
99.2 -- Summary of Reserve Report of Fairchild, Ancell & Wells,
Inc. as of December 31, 1997.
- ---------------
+ Incorporated by reference as indicated.