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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, 1998 COMMISSION NO. 0-22915
CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
TEXAS 76-0415919
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
14811 ST. MARY'S LANE, SUITE 148 77079
HOUSTON, TEXAS (Zip Code)
(Principal executive offices)
Registrant's telephone number, including area code: (281) 496-1352
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. _________
At March 26, 1999, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $5.3 million
based on the closing price of such stock on such date of $1 11/32.
At March 26, 1999, the number of shares outstanding of the registrant's
Common Stock was 10,375,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 Annual
Meeting of Shareholders are incorporated by reference in Part III of this Form
10-K. Such definitive proxy statement will be filed with the Securities and
Exchange Commission not later than 120 days subsequent to December 31, 1998.
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TABLE OF CONTENTS
PART I...................................................... 1
Item 1. and Item 2. Business and Properties............... 1
Item 3. Legal Proceedings................................. 22
Item 4. Submission of Matters to a Vote of Security
Holders................................................ 22
Executive Officers of the Registrant...................... 22
PART II..................................................... 23
Item 5. Market for Registrant's Common Stock and Related
Shareholder Matters.................................... 23
Item 6. Selected Financial Data........................... 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 25
Item 7A. Qualitative and Quantitative Disclosures About
Market Risk............................................ 34
Item 8. Financial Statements and Supplementary Data....... 35
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure.................... 35
PART III.................................................... 35
Item 10. Directors and Executive Officers of the
Registrant............................................. 35
Item 11. Executive Compensation........................... 35
Item 12. Security Ownership of Certain Beneficial Owners
and Management......................................... 35
Item 13. Certain Relationships and Related Party
Transactions........................................... 35
PART IV..................................................... 35
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................... 35
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PART I
ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES
GENERAL
Carrizo Oil & Gas, Inc. ("Carrizo" or the "Company") is an independent oil
and gas company engaged in the exploration, development, exploitation and
production of natural gas and crude oil. The Company's operations are currently
focused onshore in proven oil and gas producing trends along the Gulf Coast,
primarily in Texas and Louisiana in the Frio, Wilcox and Vicksburg trends. The
Company believes that the availability of economic onshore 3-D seismic surveys
has fundamentally changed the risk profile of oil and gas exploration in these
regions. Recognizing this change, the Company has aggressively sought to control
significant prospective acreage blocks for targeted 3-D seismic surveys. As of
December 31, 1998, the Company had assembled approximately 407,123 gross acres
under lease or option and acquired 31 3-D seismic surveys. 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 90% 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. The Company expects to acquire or cause to be acquired additional 3-D
seismic data during the remainder of 1999 that will cover most of the remaining
current acreage position.
Carrizo has amassed a large drillsite inventory from the 3-D surveys, with
as many as 280 gross wells that could be drilled over the next four years,
assuming sufficient capital resources. In addition, the Company anticipates that
as its existing 3-D seismic data is further evaluated, and 3-D seismic data is
acquired over the balance of its acreage, additional prospects will be generated
for drilling beyond 2002.
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 $150,000 to $400,000 per completed well) and risk. Many of these
drilling prospects also have secondary, deeper, over-pressured targets which
have greater economic potential but generally involve higher cost (typically $1
million to $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, 1998, the Company operated 75 producing
oil and gas wells, which accounted for 39% of the wells in which the Company had
an interest.
The Company has experienced rapid increases in reserves, production and EBITDA
from its inception in 1993 through 1997 due to the growth of its 3-D based
drilling and development activities. From January 1, 1996 to December 31, 1998,
the Company participated in the drilling of 147 gross wells (51.9 net) with a
commercial well success rate of approximately 67%. This drilling success
contributed to the Company's total proved reserves as of December 31, 1997 of
43.2 Bcfe with a PV-10 Value of $26.1 million. During 1998, the Company added
6.4 Bcfe to proved reserves through drilling and acquisitions, however total
proved reserves decreased to approximately 32.0 Bcfe, with a PV-10 Value of
$18.7 million, as a result of production and 1.4 Bcfe of reserves deemed
uneconomic due to low oil and gas prices at December 31, 1998. While the
Company's production increased 2% from 3,424 MMcfe for the year ended December
31, 1997 to 3,495 MMcfe for the year ended December 31, 1998, EBITDA decreased
from $4,787,000 for the year ended December 31, 1997 to $2,707,000 for the year
ended December 31, 1998 due to significantly lower oil and gas sales prices.
Certain terms used herein relating to the oil and natural gas industry are
defined in "Glossary of Certain Industry Terms" below.
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EXPLORATION APPROACH
The Company's strategy has been to rapidly accumulate large amounts of 3-D
seismic data along prolific, producing trends of the onshore Gulf Coast after
obtaining options to lease areas covered by the data. The Company then uses 3-D
seismic data to identify or evaluate prospects before drilling the prospects
that fit its risk/reward criteria. The Company typically seeks to explore in
locations within its core areas of expertise that it believes have (i) numerous
accumulations of normally pressured reserves at shallow depths and in geologic
traps that are difficult to define without the interpretation of 3-D seismic
data and (ii) the potential for large accumulations of deeper, over-pressured
reserves.
As a result of the increased availability of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company has relied almost exclusively on the interpretation of
3-D seismic data in its exploration strategy. The Company generally does not
invest any substantial portion of the costs for an exploration well without
first interpreting 3-D seismic data. The principal advantage of 3-D seismic data
over traditional 2-D seismic analysis is that it affords the geoscientist the
ability to interpret a three dimensional cube of data representing a specific
project area as compared to interpreting between widely separated two
dimensional vertical profiles. As a consequence, the geoscientist is able to
more fully and accurately evaluate prospective areas, improving the probability
of drilling commercially successful wells in both exploratory and development
drilling. The use of 3-D seismic allows the geoscientist to identify and use
areas of irregular sand geometry to augment or replace structural interpretation
in the identification of potential hydrocarbon accumulations. Additionally,
detailed analysis and correlation of the 3-D seismic response to lithology and
contained fluids assist geoscientists in identifying and prioritizing drilling
targets. Because 3-D analysis is completed over an entire target area cube,
shallow, intermediate and deep objectives can be analyzed. Additionally, the
more precise structural definition allowed by 3-D seismic data combined with
integration of available well and production data assists in the positioning of
new development wells.
The Company has sought to obtain large volumes of 3-D seismic data either
by participating in large seismic data acquisition programs either alone or
pursuant to joint venture arrangements with other energy companies, or through
"group shoots" in which the Company shares the costs and results of seismic
surveys. By participating in joint ventures and group shoots, the Company is
able to share the up-front costs of seismic data acquisition and interpretation,
thereby enabling it to participate in a larger number of projects and diversify
exploration costs and risks. Most of the Company's operations are conducted
through joint operations with industry participants. As of December 31, 1998,
the Company was actively involved in 45 project areas.
The Company's primary strategy for acreage acquisition is to obtain leasing
options covering large geographic areas in connection with 3-D seismic surveys.
Prior to conducting proprietary surveys, the Company typically seeks to acquire
seismic permits that include options to lease the acreage, thereby ensuring the
price and availability of leases on drilling prospects that may result upon
completing a successful seismic data acquisition program over a project area.
The Company generally attempts to obtain these options covering at least 80% of
the project area for these proprietary surveys. The size of these surveys has
ranged from 10 to 80 square miles. When the Company participates in 3-D group
shoots, it generally seeks prospective leases as quickly as possible following
interpretation of the survey. In connection with some group shoots in which the
Company believes that competition for acreage may be especially strong, the
Company may seek to obtain lease options or leases in prospective areas prior to
the receipt or interpretation of 3-D seismic data.
The Company maintains a flexible and diversified approach to project
identification by focusing on the estimated financial results of a project area
rather than limiting its focus to any one method or source for obtaining leads
for new project areas. The Company's current project areas resulted from leads
developed by its project generation network that includes small, independent
"prospect generators", the Company's joint venture partners and the Company's
internal staff. The Company believes that it has been able to increase the
number of potential projects and reduce its costs through the use of these
outside sources of project generation. When identifying specific drillsites from
within a project area, the Company relies upon its own geoscientists.
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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 16 years of
industry experience, in many cases with major and large independent oil
companies, including Shell Oil Company, Vastar Resources, Inc., Pennzoil Company
and Tenneco Inc.
The Company generally seeks to obtain lease operator status and control
over field operations, and in particular seeks to control decisions regarding
3-D survey design parameters and drilling and completion methods. As of December
31, 1998, the Company operated 75 producing oil and natural gas wells.
The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to use
reliable, high quality, used equipment in place of new equipment to achieve cost
savings. The Company also seeks to minimize cycle time from drilling to hook-up
of wells, thereby accelerating cash flow and improving ultimate project
economics.
The Company seeks to use advanced production techniques to exploit and
expand its reserve base. Following the discovery of 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 45 exploration project areas. As of
December 31, 1998, the Company had an existing 3-D seismic database of 1,673
square miles and was acquiring an additional 98 square miles of data (totaling
1,771 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.
The Company generally groups its exploration projects into four
geographical/geological trends and areas.
TEXAS -- WILCOX/YEGUA TREND
Carrizo has acquired 12 3-D surveys totaling 727 square miles in the
prolific Wilcox trend of south Texas. Eleven of the surveys also include the
Yegua and/or Cook Mountain sections.
TEXAS FRIO/VICKSBURG TREND
Carrizo has acquired 15 3-D surveys totaling 908 square miles in the
Frio/Vickburg productive trend of South Texas. Three of these surveys also have
downdip Wilcox/Yegua exploration potential.
TEXAS -- SOUTHEAST TEXAS AREAS
3-D surveys have been acquired over four areas in Southeast Texas including
Nacogdoches, Liberty and Chambers Counties, totaling 130 square miles.
Exploration targets include Cotton Valley Lime, Yegua/Cook Mountain and Expanded
Frio/Vicksburg. As of December 31, 1998, the Company had received data in two of
these areas.
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LOUISIANA-SOUTH LOUISIANA AREAS
3-D seismic has been acquired over two of the Company's three most
attractive Louisiana areas. In these areas, the Company typically leases ahead
of large speculative surveys then seeks access to relevant data through data
agreements with the seismic contractor.
1999 EXPLORATION AND DEVELOPMENT PROGRAM
SQ. MILES OF 3-D
GROSS SEISMIC DATA AT
ACREAGE DECEMBER 31, 1999
LEASED OR ----------------------
UNDER BUDGETED AVERAGE
OPTION AT EXISTING FOR AVERAGE NET
DECEMBER 31, OR BEING ACQUISITION WORKING REVENUE
PROJECT AREAS 1998 ACQUIRED 1999 INTEREST(1) INTEREST(1)
------------- ------------ -------- ----------- ----------- -----------
TEXAS
Starr/Hidalgo........................ 4,435 340(2) -- 50.0% 37.5%
Encinitas/Kelsey..................... 9,110 32 -- 27.5% 23.0%
Buckeye.............................. 11,946 62(2) -- 65.0% 48.75%
La Rosa.............................. 5,827 22 -- 31.2% 23.6%
Mexican Sweetheart................... 6,182 40 -- 25.0% 18.8%
McFaddin Ranch ...................... 5,374 15 -- 34.4% 25.8%
Cologne.............................. 7,134 40 -- 25.0% 18.8%
South Cabeza Creek................... 3,349 65(2) -- 77.5% 39.4%
Western 325.......................... 499 250(2) -- 50.0% 37.5%
Highway 59........................... 5,633 36 -- 25.0% 15.0%
Geronimo............................. 10,139 107 -- 15.0% 11.3%
RPP Welder........................... 25,633 60 -- 15.0% 11.3%
Cedar Point.......................... 10,112 30 25.0% 18.7%
Felicia/Devers....................... 2,981 52(2) 87.5% 75.0%
Jailhouse............................ 9,400 50 12.5% 9.25%
Scott-Farish......................... 22,811 42 70.0% 52.5%
Higgins.............................. 30,087 66(2) 100.0% 75.0%
Ganado............................... 13,682 32 50.0% 37.5%
Lost Bridge.......................... 4,658 17 -- 70.0% 52.5%
Metro................................ 7,032 30 -- 25.0% 18.7%
South Texas Syndicate................ 38,032 65 -- 44.375% 34.70%
Victoria............................. 3,924 50 -- 50.0% 42.75%
Matagorda............................ 19,870 51(2) 98.0% 73.5%
Driscoll Ranch ...................... 59,000 84 23.88% 17.8%
Other (14 Areas)..................... 84,481 177 -- 53.03% 40.36%
LOUISIANA
Calcasieu............................ 1,342 -- -- 100.0% 75.0%
N. Tigre Lagoon...................... 437 6 -- 100.0% 75.0%
Other (5 Areas)...................... 4,013 -- 6 23.92% 17.94%
------- ----- ---
Total........................ 407,123 1,771 56 49.07% 36.68%
======= ===== ===
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(1) Anticipated interests based on ownership or contractual rights as of
December 31, 1998.
(2) 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
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partners to share the up-front costs associated with obtaining option
arrangements with landowners, seismic 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, there can be no assurance that these prospects will be
drilled at all or within the expected time frame. In some project areas, the
Company has budgeted for wells that are based upon statistical results of
drilling activities in other project areas; these wells are subject to greater
uncertainties than wells for which drillsites have been identified. The final
determination with respect to the drilling of any identified drillsites or
budgeted wells will be dependent on a number of factors, including (i) the
results of exploration efforts and the acquisition, review and analysis of the
seismic data, (ii) the availability of sufficient capital resources by the
Company and the other participants for the drilling of the prospects (not all of
which resources are currently available), (iii) the approval of the prospects by
other participants after additional data has been compiled, (iv) the economic
and industry conditions at the time of drilling, including prevailing and
anticipated prices for oil and natural gas and the availability of drilling rigs
and crews, (v) the financial resources and results of the Company and its
partners and (vi) the availability of leases on reasonable terms and permitting
for the prospect. There can be no assurance that these projects can be
successfully developed or that any identified drillsites or budgeted wells
discussed will, if drilled, encounter reservoirs of commercially productive oil
or natural gas. The Company may seek to sell or reduce all or a portion of its
interest in a project area or with respect to prospects or wells within a
project area.
The success of the Company will be materially dependent upon the success of
its exploratory drilling program. Exploratory drilling involves numerous risks,
including the risk that no commercially productive oil or natural gas reservoirs
will be encountered. The cost of drilling, completing and operating wells is
often uncertain, and drilling operations my be curtailed, delayed or canceled as
a result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rights and the delivery of
equipment. Although the Company believes that its use of 3-D seismic data and
other advanced technologies should increase the probability of success of its
exploratory wells and should reduce average finding costs through elimination of
prospects that might otherwise be drilled solely on the basis 2-D seismic data,
exploratory drilling remains a speculative activity. Even when fully utilized
and properly interpreted, 3-D seismic data and other advanced technologies only
assist geoscientists in identifying subsurface structures and do not enable the
interpreter to know whether hydrocarbons are in fact present in such structures.
In addition, the use of 3-D seismic data and other advanced technologies
requires greater predrilling expenditures than traditional drilling strategies
and the Company could incur losses as a result of such expenditures. The
Company's future drilling activities may not be successful, and if unsuccessful,
such failure will have a material adverse effect on the Company's results of
operations and financial condition. There can be no assurance the Company's
overall drilling success rate or its drilling success rate for activity within a
particular project area will not decline. The Company may choose not to acquire
option and lease rights prior to acquiring seismic data and, in many cases, the
Company may identify a prospect or drilling location before seeking option or
lease rights in the prospect or location. Although the Company has identified or
budgeted for numerous drilling prospects, there can be no assurance that such
prospects will ever be leased or drilled (or drilled within the scheduled or
budgeted time frame) or that oil or natural gas will be produced from any such
prospects or any other prospects. In addition, prospects may initially be
identified through a number of methods, some of which do not include
interpretation of 3-D or other seismic data. Wells that are currently in the
Company's capital budget may be based upon statistical results of drilling
activities in other 3-D project areas that the Company believes are geologically
similar, rather than on analysis of seismic or other data. Actual drilling and
results are likely to vary from such statistical results and such variance may
be material. Similarly, the Company's drilling schedule may vary from its
capital budget because of future uncertainties, including those described above.
The description of a well as "budgeted" does not mean that the Company currently
has or will have the capital resources to drill the well. See "Management's
Discussion and Analysis of financial Condition and Results of Operations."
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The reserve data set forth below is based upon the reserve report (the
"Ryder Scott Report") dated February 19, 1999 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 March 11, 1999 prepared by Fairchild, Ancell & Wells, Inc.,
independent petroleum engineers ("Fairchild"). The 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 -- WILCOX/YEGUA TRENDS
Buckeye Project Area: Jackson and Wilcox Formations
The Buckeye Project Area is located in Live Oak County, Texas. As of
December 31, 1998, the Company and its partner currently hold 11,946 acres under
lease. The approximately 62 square mile 3-D seismic survey has led to the
successful exploitation of shallow zones of the Hockley, Pettus and Yegua
formations. In addition, deeper zones within the expanded Wilcox section have
been identified within four prospect closures. Lease control is complete and the
first test well is budgeted to be drilled in 1999, depending on available
financing for both the Company and its partners. During the quarter ended
December 31, 1998, the Company's share of production from wells in this project
area averaged approximately 100 barrels per day of oil and 1.1 MMcf per day of
natural gas. As of December 31, 1998, the Company and its partners have drilled
32 wells in this project area, resulting in 25 producing wells. The estimated
proved reserves net to the Company for this project area were 90 MBbls of oil
and 1.2 BCF of natural gas at December 31, 1998.
South Cabeza Creek Project Area: Frio, Yegua and Wilcox Formations
The South Cabeza Creek Project Area is located in Goliad County, Texas in
an area having significant production in the shallow Frio and Wilcox trends. The
Company has received 65 square miles of data from a non exclusive shoot
completed in December of 1998. Several Wilcox prospects and shallow lead areas
have been defined from the 3-D interpretation. The initial prospect is budgeted
to be drilled in 1999, depending on available financing for both the Company and
its partners. The Company and its partners had 1,926 acres under lease and 1,423
acres under seismic option as of December 31, 1998.
Western 325 Project Area: Wilcox and Jackson 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 seismic data shoot covering
approximately 320 square miles in the project area. Multiple prospects have been
identified from data received to date. The Company is currently attempting to
acquire land control over what it believes are the highest potential prospects
identified so far.
Highway 59 Project Area: 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 cooperative shoot effort resulted in access to 36 square miles of 3-D
seismic to define both Wilcox and Yegua/Cook Mountain prospects. The drilling of
the initial well is budgeted for 1999, depending on available financing for both
the Company and its partners. The well is designed to test a highside Wilcox
closure as well as gain information within the Yegua.
Metro Project Area: 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 30 square mile
3-D seismic program has been completed and numerous drilling opportunities have
been identified. The Company has participated in two successful shallow wells,
one successful upper Wilcox well and is currently drilling a follow up
development well to the 1998 Wilcox discovery. The Company has budgeted the
drilling of two additional shallow wells and one additional Wilcox well in 1999
depending upon
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available financing for the Company and its partners. The Company and its
partners had 7,032 acres under lease as of December 31, 1998.
South Texas Syndicate: Oligocene through Jurassic Formations
The South Texas Syndicate Project Area is located in LaSalle and McMullen
Counties, Texas. A 65 square mile 3-D survey has been completed with data
received in December 1998. Ten prospect areas have been identified from the
Wilcox through the Jurassic. Land control over these areas has been completed
and drilling of the initial well is budgeted in 1999, depending on the available
financing for both the Company and its partners. The Company and its partners
had 38,032 acres under option as of December 31, 1998.
Driscoll Project Area: Frio through Yegua Formations
The Driscoll 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. Eighty-four square miles of 3-D seismic data was acquired in
1998 and interpretation began in November 1998. Numerous structural closures in
the Yegua have been identified and lease options are being exercised in
preparation for drilling. The Company has budgeted to drill two wells in 1999,
depending on the available financing for both the Company and its partners. The
Company and its partners had 59,000 acres under option as of December 31, 1998.
Scott/Farish Ranch Project Area: Frio/Jackson/Wilcox Formations
The Scott/Farish Ranch Project Area is located in Bee County, Texas and
targets structural and stratigraphic traps in the Frio through Yegua intervals
with deeper prospectivity in the Wilcox Formations. Approximately 42 square
miles of data was acquired in 1998 with interpretation beginning February 1999.
Over 10 shallow prospects have been identified along with one deeper Wilcox
prospect. Leasing is currently underway with drilling of the initial prospect
budgeted for late 1999, depending on available financing for both the Company
and its partners. As of December 31, 1998, the Company and its partners had
22,811 acres under option.
TEXAS -- FRIO/VICKSBURG TRENDS
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 were
identified in the shallow Frio trend and the deeper, structurally complex
Vicksburg trend. As of December 31, 1998, the Company and its partner had leases
covering 3,715 acres and options covering 720 acres in this project. During
1997, production from the Company's wells in the Wheeler area was curtailed by
the Texas Railroad Commission. The Company has sought to return the production,
however the curtailment is presently continuing. The Company estimates that it
has 4,000 Mcfe/d of production shut-in as of December 31, 1998. The Company's
share of production from wells in this project area during 1998 was
approximately 30 Bbls/d of oil and 1.5 MMcf/d natural gas. As of December 31,
1998, the Company and its partners had drilled a total of 27 wells in this
project area, resulting in 18 producing wells. The estimated proved reserves net
to the Company for this project area was 100 MBbls of oil and 1.7 Bcf of natural
gas at December 31, 1998. The Company and its partners have identified four
locations that have been or are budgeted to be drilled during 1999, depending on
available financing for both the Company and its partners. 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.
Mexican Sweetheart Project Area: Frio Yegua/ Formations
The Mexican Sweetheart Project Area is located in southwestern Jackson
County, Texas in the Frio producing trend and proximate to successful industry
activity in the expanded Yegua. The 40 square mile shoot has identified shallow
Frio prospects as well as two approximately 1,000 acre Yegua prospects. Both
lead
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areas are lease controlled and the initial prospect is budgeted to be drilled in
1999, depending on available financing for both the Company and its partners. As
of December 31, 1998, the Company and its partners had 6,182 acres under lease.
Cologne Project Area: Frio and Wilcox Formations
The Cologne Project Area is located in Goliad and Victoria Counties, Texas
in the Frio and Wilcox formations. A 40 square mile 3-D seismic survey has been
shot over the project area, has been interpreted and yielded drillsites to
evaluate prospectivity from the Frio through the Wilcox formations. As of
December 31, 1998, the Company had drilled five successful Frio wells in six
attempts. In addition, three large highside Wilcox structures covering over
2,500 areas have been identified and leased. The first of these structures is
budgeted to be drilled in 1999, depending on available financing for both the
Company and its partners. As of December 31, 1998, the Company and its partner's
leasehold covered 7,134 acres.
Matagorda Project Area: Frio Formation
The Matagorda Project Area is located in Matagorda County, Texas covering
numerous Middle Frio structural opportunities in addition to the Lower Frio
expanded section. The preliminary data from the 3-D has identified over ten
prospects from the Middle and Lower Frio. Options are currently being exercised
in preparation for drilling in third quarter of 1999. The Company has budgeted
to drill as many as three to five wells in this project area in 1999, depending
on available financing for both the Company and its partners. The Company had
acquired 1,756 acres of leasehold and lease options covering 18,114 acres as of
December 31, 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. The 15 square mile 3-D seismic survey has yielded
seven prospect areas targeting the upper through basal Frio. One unsuccessful
well was drilled in 1998. All additional prospect areas are leased and a minimum
of two additional drillsites have been identified. As of December 31, 1998, the
Company and its partners had leases in this area covering 5,374 acres.
TEXAS -- SOUTHEAST TEXAS AREAS
Felicia/Devers Project Area: Frio Yegua Cook Mountain Formations
The Felicia/Devers Project Area is located in Liberty County, Texas and
targets amplitude supported Frio and structural-stratigraphic targets in the
Yegua and Cook Mountain Formations. The 3-D seismic survey was acquired in 1998
with 52 square miles of data in house for interpretation in February 1999. Over
10 prospects have been identified to date and leasing is currently underway for
initial drilling budgeted to commence in late 1999, depending on available
financing for both the Company and its partners. As of December 31, 1998, the
Company had 2,981 acres under lease or option.
Cedar Point Project Area: Lower Frio to Vicksburg Formations
The Cedar Point Project Area is located in Chambers County adjacent to
Trinity Bay and targets the lower Frio and Vicksburg Formations. The 30 square
mile 3-D seismic was acquired in 1998 and delivered for interpretation in
September 1998. Over 14 prospects have been identified within the Frio,
Vicksburg and Yegua Formations. The primary prospects are lease controlled and
initial drilling is budgeted for late 1999, depending on available financing for
both the Company and its partners. As of December 31, 1998, the Company and its
partners had 10,112 acres under seismic option.
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LOUISIANA -- SOUTH LOUISIANA AREAS
North Tigre Lagoon Prospect: Vermilion Parish
The North Tigre Lagoon Prospect lies in the prolific lower Miocene
producing trend of Southwest Louisiana. The prospect targets normally pressured
Rob. C., Rob. C. 2 and Siph. D. Sands. The Company has budgeted to drill a test
well in 1999, depending on available financing for both the Company and its
partners.
West Bay Prospect: Plaquemines Parish, Louisiana
The West Bay Prospect is located in the prolific upper and middle Miocene
producing trend of Southeast Louisiana. It lies proximate to successful industry
activity in the West Bay Field complex. The prospect targets normally pressured
upper Miocene sands. The Company has budgeted to drill a test well in 1999,
depending on available financing for both the Company and its partners.
Ursa Minor Prospect: Cameron Parish, Louisiana
The prospect is located in the prolific Miocene producing trend of
Southwest Louisiana. The prospective play is a series of stratigraphic traps,
with associated seismic amplitude anomalies, located on the north flank of a
major, regional salt withdrawal minibasin. The prospect targets normally
pressured middle Miocene sands between 4,000 feet and 8,000 feet. The Company
has budgeted to drill a test well in 1999, depending on available financing for
both the Company and its partners.
OTHER PROJECT AREAS
In addition to the project areas described above, the Company has 19
additional project areas in various stages of development as of December 31,
1998. These project areas are located in the onshore Texas and Louisiana Gulf
Coast regions, 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, 1998 had acquired leases
and seismic options covering 88,494 acres. 3-D seismic surveys covering an
aggregate of approximately 6 square miles are budgeted for acquisition during
1999.
CAMP HILL PROJECT
The Company owns interests in eight leases totaling approximately 900 gross
acres in the Camp Hill field in Anderson County, Texas. The Company currently
operates six of these leases. During the year ended December 31, 1998, the
project produced 97 barrels per day of 19 API gravity oil. The project produces
from a depth of 500 feet and utilizes a tertiary steam drive as an enhanced oil
recovery process. Although efficient at maximizing oil recovery, the steam drive
process is relatively expensive to operate because natural gas or produced crude
is burned to create the steam injectant. Lifting costs during the year ended
December 31, 1998 averaged $14.10 per barrel ($2.35 per Mcfe). In response to
lower commodity prices, steam injection was reduced in November 1998, resulting
in fourth quarter lifting costs of $11.35 per barrel. Because profitability
increases when natural gas prices drop relative to oil prices, the project is a
natural hedge against decreases in natural gas prices relative to oil prices.
The crude oil produced, although viscous, commands a higher price (an average
premium of $.75 per barrel during the year ended December 31, 1998) than West
Texas intermediate crude due to its suitability as a lube oil feedstock. As of
December 31, 1998, the Company had 3,290 MBbls of oil of proved reserves in this
project, with 837 MBbls of oil currently developed reflecting a loss of 1,372
MBbls of reserves deemed uneconomic at year end due to low oil prices. 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%.
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JONES BRANCH PROPERTIES
During November, 1998 the Company acquired an interest in four oil and gas
producing properties along with rights to participate in certain exploration
prospects (primarily in the Wilcox formation) in Wharton County, Texas and
associated rights of access to certain 2-D and 3-D seismic data and related
information and other related assets. The Company has an average working
interest of 31.3% and an average net revenue interest of 23.7%. The wells were
producing at a combined rate of 1,994 Mcf per day and 152 Bbls of condensate per
day during December 1998.
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,
1998. The reserve data and the present value as of December 31, 1998 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, 1998,
see the Reserve Reports included as exhibits to this Annual Report on Form 10-K.
The PV-10 Value was prepared using constant prices as of the calculation date,
discounted at 10% per annum on a pretax basis, and is not intended to represent
the current market value of the estimated oil and natural gas reserves owned by
the Company. For further information concerning the present value of future net
revenue from these proved reserves, see Note 12 of Notes to Financial
Statements.
PROVED RESERVES
---------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls)............................ 1,112 2,535 3,647
Natural gas (MMcf).................................... 9,097 1,058 10,155
Total proved reserves (MMcfe)......................... 15,770 16,266 32,036
PV-10 Value(1)........................................ $15,154 $ 3,601 $18,755
- ---------------
(1) The PV-10 Value as of December 31, 1998 is pre-tax and was determined by
using the December 31, 1998 sales prices, which averaged $10.15 per Bbl of
oil, $2.18 per Mcf of natural gas and $8.24 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, 1998. 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, 1998. There can be no assurance that all of the
proved reserves will be produced and sold within the periods indicated, that the
assumed prices will actually be realized for such production or that existing
contracts will be honored or judicially enforced.
There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Annual Report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions concerning
future oil and natural gas prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of which may in
fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural 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
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downward or upward adjustment based upon such factors. Actual production,
revenues and expenditures with respect to the Company's reserves will likely
vary from estimates, and such variances may be material. In addition, the 10%
discount factor, which is required by the Commission to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with the Company or the oil and natural gas industry
in general.
In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Company conducts successful
exploration and development activities or acquires properties containing proved
reserves, or both, the proved reserves of the Company will decline as reserves
are produced. The Company's future oil and natural gas production is, therefore,
highly dependent upon its level of success in finding or acquiring additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investment to maintain or expand its asset base of
oil and natural gas reserves would be impaired. The failure of an operator of
the Company's wells to adequately perform operations, or such operator's breach
of the applicable agreements, could adversely impact the Company. In addition,
there can be no assurance that the Company's future exploration, development and
acquisition activities will result in additional proved reserves or that the
Company will be able to drill productive wells at acceptable costs. Furthermore,
although the Company's revenues could increase if prevailing prices for oil and
natural gas increase significantly, the Company's finding and development costs
could also increase. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE
The following table sets forth certain information regarding the production
volumes of, average sales prices received for and average production costs
associated with the Company's sales of oil and natural gas for the periods
indicated. The table includes the impact of hedging activities.
YEAR ENDED DECEMBER 31,
------------------------
1996 1997 1998
------ ------ ------
Production volumes
Oil (MBbls).............................................. 107 113 140
Natural gas (MMcf)....................................... 1,273 2,749 2,655
Natural gas equivalent (MMcfe)........................... 1,915 3,424 3,495
Average sales prices
Oil (per Bbl)............................................ $21.54 $18.66 $12.30
Natural gas (per Mcf).................................... 2.27 2.41 2.31
Natural gas equivalent (per Mcfe)........................ 2.71 2.54 2.25
Average costs (per Mcfe)
Camp Hill operating expenses............................. $ 3.15 $ 2.59 $ 2.35
Other operating expenses................................. 0.94 0.54 0.69
Total operating expenses(1).............................. 1.24 0.68 0.79
- ----------
(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, 1998, the Company has incurred total
gross development, exploration and acquisition costs of approximately $80.7
million. Total exploration, development and acquisition activities from
inception through December 31, 1998 have resulted in the addition of
approximately 52.5 Bcfe, net to the Company's interest, of proved reserves at an
average finding and development cost of $1.54 per Mcfe.
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The Company's finding and development costs have historically fluctuated on
a year-to-year basis. Finding and development costs, as measured annually, may
not be indicative of the Company's ability to economically replace oil and
natural gas reserves because the recognition of costs may not necessarily
coincide with the addition of proved reserves.
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the gross
costs incurred in the purchase of proved and unproved properties and in
development and exploration activities.
YEAR ENDED DECEMBER 31,
---------------------------------
1996 1997 1998
------ -------------- -------
(IN THOUSANDS)
Acquisition costs
Unproved prospects................................. $ 51 $14,223 $ 9,619
Proved properties.................................. 1,908 5,492 16,197
Exploration.......................................... 4,724 9,328 10,429
Development.......................................... 1,956 2,257 313
------ ------- -------
Total costs incurred(1).................... $8,639 $31,300 $36,558
====== ======= =======
- ----------
(1) Excludes capitalized interest on unproved properties of $422,493, $699,625
and $291,496 for the years ended December 31, 1996, 1997 and 1998,
respectively.
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
years ended December 31, 1996, 1997 and 1998. 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, 1996 to December 31, 1998
has resulted in a commercial success rate of approximately 67%.
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1997 1998
----------- ------------ ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- ---- ----- ----
Exploratory Wells
Productive.................................. 16 6.0 39 15.7 29 9.3
Nonproductive............................... 4 1.1 23 9.4 24 7.0
-- --- -- ---- -- ----
Total............................... 20 7.1 62 25.1 53 16.3
== === == ==== == ====
Development Wells
Productive.................................. -- -- 7 1.8 3 1.0
Nonproductive............................... -- -- 1 0.6 1 --
-- --- -- ---- -- ----
Total............................... -- -- 8 2.4 4 1.0
== === == ==== == ====
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, 1998.
COMPANY
OPERATED OTHER TOTAL
------------ ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- -----
Oil......................................... 55 53.3 31 10.9 86 64.2
Natural gas................................. 20 11.8 84 26.7 104 38.5
-- ---- --- ---- --- -----
Total............................. 75 65.1 115 37.6 190 102.7
== ==== === ==== === =====
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ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 1998. 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................... 302 33 5,505 2,393 5,807 2,426
Texas....................... 32,664 11,691 123,643 38,623 156,307 50,314
------ ------ ------- ------ ------- ------
Total............. 32,966 11,724 129,148 41,016 162,114 52,740
====== ====== ======= ====== ======= ======
The table does not include 245,009 gross acres (114,362 net) that the
Company had a right to acquire pursuant to various seismic option agreements at
December 31, 1998. Under the terms of its option agreements, the Company
typically has the right for a period of one year, subject to extensions, to
exercise its option to lease the acreage at predetermined terms. The Company's
lease agreements generally terminate if wells have not been drilled on the
acreage within a period of three years.
MARKETING
The Company's production is marketed to third parties consistent with
industry practices. Typically, oil is sold at the wellhead at field-posted
prices plus a bonus and natural gas is sold under contract at a negotiated price
based upon factors normally considered in the industry, such as distance from
the well to the pipeline, well pressure, estimated reserves, quality of natural
gas and prevailing supply/demand conditions.
The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of multiple
outlets near its production in the Texas and Louisiana Gulf Coast. The Company
takes an active role in determining the available pipeline alternatives for each
property based upon historical pricing, capacity, pressure, market
relationships, seasonal variances and long-term viability.
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers. The
availability of a ready market for the Company's oil and natural gas production
depends on the proximity of reserves to, and the capacity of, oil and natural
gas gathering systems, pipelines and trucking or terminal facilities. The
Company delivers natural gas through gas gathering systems and gas pipelines
that it does not own. Federal and state regulation of natural gas and oil
production and transportation, tax and energy policies, changes in supply and
demand and general economic conditions all could adversely affect the Company's
ability to produce and market its oil and natural gas.
The Company from time to time markets its own production where feasible
with a combination of market-sensitive pricing and forward-fixed pricing.
Forward pricing is utilized to take advantage of anomalies in the futures market
and to hedge a portion of the Company's production deliverability at prices
exceeding forecast. All of such hedging transactions provide for financial
rather than physical settlement. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations-General Overview."
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
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other factors beyond the Company's control. Domestic oil prices generally follow
worldwide oil prices, which are subject to price fluctuations resulting from
changes in world supply and demand. The Company continues to evaluate the
potential for reducing these risks by entering into, and expects to enter into,
additional hedge transactions in future years. In addition, the Company may also
close out any portion of hedges that may exist from time to time as determined
to be appropriate by management. At December 31, 1998, there were no open hedge
positions. Total natural gas purchased and sold under such swap arrangements
during the years ended December 31, 1996, 1997 and 1998 were 60,000 MMBtu,
210,000 MMBtu and 1,760,000 MMBTU, respectively. Gains (losses) realized by the
Company under such swap arrangements were ($26,887), ($48,000) and $167,000 for
the years ended December 31, 1996, 1997 and 1998, respectively.
COMPETITION AND TECHNOLOGICAL CHANGES
The Company encounters competition from other oil and natural gas companies
in all areas of its operations, including the acquisition of exploratory
prospects and proven properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of its
competitors are large, well-established companies with substantially larger
operating staffs and greater capital resources than those of the Company and
which, in many instances, have been engaged in the oil and natural gas business
for a much longer time than the Company. Such companies may be able to pay more
for exploratory prospects and productive oil and natural gas properties and may
be able to identify, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources permit.
In addition, such companies may be able to expend greater resources on the
existing and changing technologies that the Company believes are and will be
increasingly important to the current and future success of oil and natural gas
companies. The Company's ability to explore for oil and natural gas prospects
and to acquire additional properties in the future will be dependent upon its
ability to conduct its operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment. The
Company believes that its exploration, drilling and production capabilities and
the experience of its management generally enable it to compete effectively.
Many of the Company's competitors, however, have financial resources and
exploration and development budgets that are substantially greater than those of
the Company, which may adversely affect the Company's ability to compete with
these companies.
The oil and gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive pressures
may force the Company to implement such new technologies at substantial cost. In
addition, 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
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natural gas between owners in a common reservoir, control the amount of oil and
natural gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are subject to the jurisdiction of
various federal, state and local agencies. The Company is also subject to
changing and extensive tax laws, the effects of which cannot be predicted. The
following discussion summarizes the regulation of the United States oil and gas
industry. The Company believes that it is in substantial compliance with the
various statutes, rules, regulations and governmental orders to which the
Company's operations may be subject, although there can be no assurance that
this is or will remain the case. Moreover, such statutes, rules, regulations and
government orders may be changed or reinterpreted from time to time in response
to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect the Company's
results of operations and financial condition. The following discussion is not
intended to constitute a complete discussion of the various statutes, rules,
regulations and governmental orders to which the Company's operations may be
subject.
Regulation of Oil and Natural Gas Exploration and Production. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells that may
be drilled in and the unitization or pooling of oil and gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units, and therefore more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and natural gas the Company can produce
from its wells and may limit the number of wells or the locations at which the
Company can drill. The regulatory burden on the oil and gas industry increases
the Company's costs of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended and reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.
Regulation of Sales and Transportation of Natural Gas. Federal legislation
and regulatory controls have historically affected the price of natural gas
produced by the Company and the manner in which such production is transported
and marketed. Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission (the "FERC") regulates the interstate transportation and the sale in
interstate commerce for resale of natural gas. The FERC's jurisdiction over
interstate natural gas sales was substantially modified by the Natural Gas
Policy Act, under which the FERC continued to regulate the maximum selling
prices of certain categories of gas sold in "first sales" in interstate and
intrastate commerce. Effective January 1, 1993, however, the Natural Gas
Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for
all "first sales" of natural gas, including all sales by the Company of its own
production. As a result, all of the Company's domestically produced natural gas
may now be sold at market prices, subject to the terms of any private contracts
which may be in effect. The FERC's jurisdiction over natural gas transportation
was not affected by the Decontrol Act.
The Company's natural gas sales are affected by intrastate and interstate
gas transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes were intended by the FERC to foster competition by,
among other things, transforming the role of interstate pipeline companies from
wholesaler marketers of gas to the primary role of gas transporters. All gas
marketing by the pipelines was required to be divested to a marketing affiliate,
which operates separately from the transporter and in direct competition with
all other merchants. As a result of the various omnibus rulemaking proceedings
in the late 1980s and the individual pipeline restructuring proceedings of the
early to mid-1990s, the interstate pipelines are now required to provide open
and
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nondiscriminatory transportation and transportation-related services to all
producers, gas marketing companies, local distribution companies, industrial end
users and other customers seeking service. Through similar orders affecting
intrastate pipelines that provide similar interstate services, the FERC expanded
the impact of open access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (i) the large-scale divestiture
of interstate pipeline-owned gas gathering facilities to affiliated or
non-affiliated companies, (ii) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (iii) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, (iv) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market and (v) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in the
relevant service market. It remains to be seen what effect the FERC's other
activities will have on access to markets, the fostering of competition and the
cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. The Company believes
these changes generally have improved the Company's access to markets while, at
the same time, substantially increasing competition in the natural gas
marketplace. The Company cannot predict what new or different regulations the
FERC and other regulatory agencies may adopt, or what effect subsequent
regulations may have on the Company's activities.
In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures which,
if enacted, would significantly affect the petroleum industry. At the present
time, it is impossible to predict what proposals, if any, might actually be
enacted by Congress or the various state legislatures and what effect, if any,
such proposals might have on the Company. Similarly, and despite the trend
toward federal deregulation of the natural gas industry, whether or to what
extent that trend will continue, or what the ultimate effect will be on the
Company's sales of gas, cannot be predicted.
The Company owns certain natural gas pipelines that it believes meet the
standards the FERC has used to establish a pipeline's status as a gatherer not
subject to FERC jurisdiction under the NGA. State regulation of gathering
facilities generally includes various safety, environmental, and in some
circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. Natural gas gathering may receive greater regulatory
scrutiny at both state and federal levels in the post-Order No. 636 environment.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. The price the Company receives from the sale of these products
may be affected by the cost of transporting the products to market. Effective as
of January 1, 1995, the FERC implemented regulations generally grandfathering
all previously approved interstate transportation rates and establishing an
indexing system for those rates by which adjustments are made annually based on
the rate of inflation, subject to certain conditions and limitations. These
regulations may tend to increase the cost of transporting oil and natural gas
liquids by interstate pipeline, although the annual adjustments may result in
decreased rates in a given year. These regulations have generally been approved
on judicial review. The Company is not able at this time to predict the effects
of these regulations, if any, on the transportation costs associated with oil
production from the Company's oil producing operations.
Environmental Regulations. The Company's operations are subject to numerous
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the
16
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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 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
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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 from, among other
things, injury or loss of life, severe damage to or destruction of property,
natural resources and equipment, pollution or other environmental damage,
cleanup responsibilities, regulatory investigation and penalties and suspension
of operations. In addition, the Company may be liable for environmental damages
caused by previous owners of property purchased and leased by the Company. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
exploration, development or acquisitions or result in the loss of the Company's
properties. In accordance with customary industry practices, the Company
maintains insurance against some, but not all, of such risks and losses. The
Company does not carry business interruption insurance or protect against loss
of revenues. There can be no assurance that any insurance obtained by the
Company will be adequate to cover any losses or liabilities. The Company cannot
predict the continued availability of insurance or the availability of insurance
at premium levels that justify its purchase. The occurrence of a significant
event not fully insured or indemnified against could materially and adversely
affect the Company's financial condition and operations. The Company may elect
to self-insure if management believes that the cost of insurance, although
available, is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. The occurrence of an
event not fully covered by insurance could have a material adverse effect on the
financial condition and results of operations of the Company. The Company
participates in a substantial percentage of its wells on a nonoperated basis,
which may limit the Company's ability to control the risks associated with oil
and natural gas operations.
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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, 1998, the Company had 28 full-time employees, including six
geoscientists and four engineers. The Company believes that its relationships
with its employees are good.
In order to optimize prospect generation and development, the Company
utilizes the services of independent consultants and contractors to perform
various professional services, particularly in the areas of 3-D seismic data
mapping, acquisition of leases and lease options, construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testings, are generally provided by independent contractors. The
Company believes that this use of third party service providers has enhanced its
ability to contain general and administrative expenses.
The Company depends to a large extent on the services of certain key
management personnel, the loss of, any of which could have a material adverse
effect on the Company's operations. The Company does not maintain key-man life
insurance with respect to any of its employees.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used
herein. All volumes of natural gas referred to herein are stated at the legal
pressure base of the state or area where the reserves exist and at 60 degrees
Fahrenheit and in most instances are rounded to the nearest major multiple.
After payout. With respect to an oil or gas interest in a property, refers
to the time period after which the costs to drill and equip a well have been
recovered.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Bbls/d. Stock tank barrels per day.
Bcf. Billion cubic feet.
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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.
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,
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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.
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.
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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....................... 42 President and Chief Executive Officer
Frank A. Wojtek....................... 43 Chief Financial Officer, Vice
President,
Secretary and Treasurer
George F. Canjar...................... 41 Vice President of Exploration
Development
Kendall A. Trahan..................... 48 Vice President of Land
Set forth below is a description of the backgrounds of each of the
executive officers of the Company:
S.P. Johnson IV has served as the President, Chief Executive Officer and a
director of the Company since December 1993. Prior to that, he worked 15 years
for Shell Oil Company. His managerial positions included Operations
Superintendent, Manager of Planning and Finance and Manager of Development
Engineering. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in
Mechanical Engineering from the University of Colorado.
Frank A. Wojtek has served as the Chief Financial Officer, Vice President,
Secretary, Treasurer and a director of the Company since 1993. In addition, from
1992 to 1997, Mr. Wojtek was the Assistant to the Chairman of the Board of
Reading & Bates Corporation ("Reading & Bates") (an offshore drilling company).
Mr. Wojtek also holds the positions of Vice President and Secretary /Treasurer
for Loyd and Associates, Inc. (a private financial consulting and investment
banking firm). Mr. Wojtek held the positions of Vice President and Chief
Financial Officer of Griffin-Alexander Drilling Company from 1984 to 1987,
Treasurer of Chiles-Alexander International Inc. from 1987 to 1989 and Vice
President and Chief Financial Officer of India Offshore Inc. from 1989 to 1992,
all of which are companies in the offshore drilling industry. Mr. Wojtek is a
Certified Public Accountant and holds a B.B.A. in Accounting from the University
of Texas.
George F. Canjar has been head of the Company's exploration activities
since joining the Company in July 1996 and was elected Vice President of
Exploration Development in June 1997. Prior thereto he worked for over 15 years
for Shell Oil Company and its overseas affiliates where he held various
technical and managerial positions, including Technical Manager-Geology &
Petrophysics, Section Head Geology & Seismology and Team Leader for numerous
integrated production, development, exploration and project
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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
The Company's common stock, par value $0.01 per share (the "Common Stock"),
has been publicly traded through the Nasdaq National Market tier of The Nasdaq
Stock Market under the symbol CRZO since the Company's initial public offering
(the "Offering") effective August 6, 1997. The following table sets forth the
quarterly high and low bid prices for each indicated quarter.
QUARTER ENDED HIGH LOW
------------- ---- ---
September 30, 1997.......................................... 15 10 15/16
December 31, 1997........................................... 17 1/4 7 7/8
March 31, 1998.............................................. 8 3/4 6 1/16
June 30, 1998............................................... 7 1/2 5 1/2
September 30, 1998.......................................... 5 3/4 2 5/8
December 31, 1998........................................... 3 1/16 1 1/8
There were approximately 60 shareholders of record (excluding brokerage
firms and other nominees) of the Company's Common Stock as of March 26, 1999.
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 to
pay dividends. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources."
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ITEM 6. SELECTED FINANCIAL DATA
The financial information of the Company set forth below for each of the
five years ended December 31, 1998, has been derived from the audited combined
financial statements of the Company. The following table also sets forth certain
pro forma income taxes, net income and net income per share information. The
information should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the audited
financial statements of the Company and the related notes thereto included
elsewhere herein.
YEAR ENDED DECEMBER 31,
------------------------------------------------
1994 1995 1996 1997 1998
------ ------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues................ $ 596 $ 2,428 $ 5,195 $ 8,712 $ 7,859
Costs and expenses:
Oil and natural gas operating expenses.... 518 1,814 2,384 2,334 2,770
Depreciation, depletion and
amortization........................... 98 488 1,136 2,358 3,952
Write-down of oil and gas properties...... -- -- -- -- 20,305
General and administrative................ 238 425 515 1,591 2,667
------ ------- ------- -------- --------
Total costs and expenses.......... 854 2,727 4,035 6,283 29,694
------ ------- ------- -------- --------
Operating income (loss)..................... (258) (299) 1,160 2,429 (21,835)
Interest expense (net of income and amounts
capitalized).............................. (7) (192) (80) (98) 285
Other income................................ 6 24 20 -- --
------ ------- ------- -------- --------
Income (loss) before income taxes........... (259) (467) 1,100 2,331 (21,550)
Deferred income taxes(1).................... -- -- -- 2,300 (2,218)
------ ------- ------- -------- --------
Net income (loss)(1)........................ $ (259) $ (467) $ 1,100 $ 31 $(19,332)
====== ======= ======= ======== ========
Basic (loss) earnings per share(1).......... $(0.04) $ (0.07) $ 0.15 $ 0.00 $ (2.15)
====== ======= ======= ======== ========
Diluted (loss) earnings per share(1)........ $(0.04) $ (0.07) $ 0.15 $ 0.00 $ (2.15)
====== ======= ======= ======== ========
Basic weighted average shares outstanding... 6,501 7,021 7,476 8,639 10,375
Diluted weighted average shares
outstanding............................... 6,501 7,021 7,545 8,810 10,375
STATEMENTS OF CASH FLOW DATA:
Net cash provided by (used in) operating
activities................................ $ (258) $ 406 $ 3,325 $ 3,068 $ 2,774
Net cash used in investing activities....... (819) (6,785) (8,221) (28,141) (37,178)
Net cash provided by financing activities... 1,183 6,343 6,319 26,255 32,916
OTHER OPERATING DATA:
EBITDA (2)(4)............................... $ (158) $ 189 $ 2,296 $ 4,787 $ 2,707
Operating cash flow (3)(4).................. (159) 21 2,236 4,689 2,422
Capital expenditures........................ 819 6,857 9,480 32,234 36,570
Debt repayments(5).......................... -- -- 2,084 20,409 7,950
AS OF DECEMBER 31,
------------------------------------------------
1994 1995 1996 1997 1998
------ ------- ------- -------- --------
BALANCE SHEET DATA:
Working capital............................. $ 152 $ (265) $(1,025) $ (2,276) $ (5,204)
Property and equipment, net................. 803 6,960 15,206 45,083 57,878
Total assets................................ 1,057 7,645 18,869 53,658 64,988
Long-term debt, including current
maturities................................ 533 3,480 9,684 7,950 12,056
Mandatorily redeemable preferred stock...... -- -- -- -- 30,731
Equity...................................... 452 3,381 4,596 32,895 11,202
- ----------
(1) On May 16, 1997, Carrizo and a number of affiliated entities were combined
with the Company in a series of transactions in connection with its initial
public offering (the "Combination Transactions"). Prior to that date,
Carrizo and those other entities were not required to pay federal income
taxes due to their status as partnerships or Subchapter S corporations. The
amounts shown reflect pro forma income
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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 5 to the Company's financial
statements.
(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization and writedown of oil and gas
properties.
(3) Operating cash flow represents cash flows from operating activities prior to
changes in assets and liabilities.
(4) 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 net revenue interests, prospects
budgeted and other future capital expenditures, risk profile of oil and gas
exploration, acquisition of 3-D seismic data (including number, timing and size
of projects), use of proceeds from the Company's initial public offering and the
sale of shares of Preferred Stock and the warrants, expected production or
reserves, increases in reserves, acreage, working capital requirements, hedging
activities, the ability of expected sources of liquidity to implement its
business strategy, future hiring, future exploration activity and any other
statements regarding future operations, financial results, business plans and
cash needs and other statements that are not historical facts are forward
looking statements. When used in this document, the words "anticipate,"
"budgeted", "potential" "estimate," "expect," "may," "project," "believe" and
similar expressions are intended to be among the statements that identify
forward looking statements. Such statements involve risks and uncertainties,
including, but not limited to, those relating to the Company's dependence on its
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, the Company's dependence on its key personnel, factors
that affect the Company's ability to manage its growth and achieve its business
strategy, risks relating to its limited operating history, technological
changes, significant capital requirements of the Company, the potential impact
of government regulations, litigation, competition, the uncertainty of reserve
information and future net revenue estimates, property acquisition risks and
other factors detailed herein and in the Company's other filings with the
Securities and Exchange Commission. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual outcomes may vary materially from those indicated.
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, 70 and 56 wells in 1996, 1997
and 1998 respectively. The Company has budgeted to drill a range of between 18
to 44 gross wells (4.6 to 17.8 net) in 1999; however, in order to drill more
than the minimum expected number of wells the Company will need to obtain
additional
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financing and the actual number of wells drilled will vary depending upon the
Company's ability to obtain this financing, weather delays and other factors. If
the Company drills the number of wells it has budgeted for 1999, depreciation,
depletion and amortization are expected to decrease and oil and gas operating
expenses are expected to increase over levels incurred in 1998. The Company has
typically retained the majority of its interests in shallow, normally pressured
prospe